Battalion Oil (BATL) 10-Q 9 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 06, 2019
Document and Entity Information
Entity Registrant Name	HALCON RESOURCES CORP
Entity Central Index Key	0001282648
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		164,256,015
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 51,923	$ 49,100
Other	(7)	155
Total operating revenues	51,916	49,255
Production:
Lease operating	14,186	4,915
Workover and other	2,646	1,361
Taxes other than income	2,893	3,029
Gathering and other	14,869	6,422
Restructuring	11,271	101
General and administrative	4,608	15,210
Depletion, depreciation and accretion	29,975	15,991
Full cost ceiling impairment	275,239
(Gain) loss on sale of oil and natural gas properties		3,679
(Gain) loss on sale of Water Assets	885
Total operating expenses	356,572	50,708
Income (loss) from operations	(304,656)	(1,453)
Other income (expenses):
Net gain (loss) on derivative contracts	(64,799)	5,903
Interest expense and other	(12,589)	(7,048)
Total other income (expenses)	(77,388)	(1,145)
Income (loss) before income taxes	(382,044)	(2,598)
Income tax benefit (provision)	45,485
Net income (loss)	$ (336,559)	$ (2,598)
Net income (loss) per share of common stock:
Basic (in dollars per share)	$ (2.12)	$ (0.02)
Diluted (in dollars per share)	$ (2.12)	$ (0.02)
Weighted average common shares outstanding:
Basic (in shares)	158,549	153,884
Diluted (in shares)	158,549	153,884
Oil
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 45,517	$ 43,069
Natural gas
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	1,461	2,319
Natural gas liquids
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 4,945	$ 3,712

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 195	$ 46,866
Accounts receivable	41,399	35,718
Receivables from derivative contracts	11,223	57,280
Prepaids and other	8,640	4,788
Total current assets	61,457	144,652
Oil and natural gas properties (full cost method):
Evaluated	1,594,171	1,470,509
Unevaluated	927,618	971,918
Gross oil and natural gas properties	2,521,789	2,442,427
Less - accumulated depletion	(943,512)	(639,951)
Net oil and natural gas properties	1,578,277	1,802,476
Other operating property and equipment:
Other operating property and equipment	158,188	130,251
Less - accumulated depreciation	(9,942)	(8,388)
Net other operating property and equipment	148,246	121,863
Other noncurrent assets:
Receivables from derivative contracts	4,844	12,437
Operating lease right of use assets	4,879
Funds in escrow and other	1,135	2,181
Total assets	1,798,838	2,083,609
Current liabilities:
Accounts payable and accrued liabilities	137,016	157,848
Liabilities from derivative contracts	20,086	3,768
Operating lease liabilities	1,868
Asset retirement obligations		126
Current portion of long-term debt	105,000
Total current liabilities	263,970	161,742
Long-term debt, net	613,493	613,105
Other noncurrent liabilities:
Liabilities from derivative contracts	7,341	9,139
Asset retirement obligations	6,971	6,788
Operating lease liabilities	3,095
Deferred income taxes	50,305	95,791
Commitments and contingencies (Note 10)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 164,320,437 and 160,612,852 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively	16	16
Additional paid-in capital	1,088,545	1,095,367
Retained earnings (accumulated deficit)	(234,898)	101,661
Total stockholders' equity	853,663	1,197,044
Total liabilities and stockholders' equity	$ 1,798,838	$ 2,083,609

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
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	164,320,437	160,612,852
Common stock, shares outstanding	164,320,437	160,612,852

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Total
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)			(2,598)	(2,598)
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 (in shares)	1,922
Long-term incentive plan forfeitures (in shares)	(74)
Stock-based compensation		4,066		4,066
Balances at Mar. 31, 2018	$ 16	1,081,105	53,104	1,134,225
Balances (in shares) at Mar. 31, 2018	160,469
Increase (Decrease) in Stockholders' Equity
Net income (loss)			(16,274)	(16,274)
Long-term incentive plan grants (in shares)	320
Long-term incentive plan forfeitures (in shares)	(136)
Reduction in shares to cover individuals' tax withholding		(262)		(262)
Reduction in shares to cover individuals' tax withholding (in shares)	(53)
Stock-based compensation		5,194		5,194
Balances at Jun. 30, 2018	$ 16	1,086,037	36,830	1,122,883
Balances (in shares) at Jun. 30, 2018	160,600
Increase (Decrease) in Stockholders' Equity
Net income (loss)			(81,837)	(81,837)
Long-term incentive plan grants (in shares)	84
Long-term incentive plan forfeitures (in shares)	(8)
Stock-based compensation		5,404		5,404
Balances at Sep. 30, 2018	$ 16	1,091,441	(45,007)	1,046,450
Balances (in shares) at Sep. 30, 2018	160,676
Increase (Decrease) in Stockholders' Equity
Net income (loss)			146,668	146,668
Long-term incentive plan forfeitures (in shares)	(43)
Reduction in shares to cover individuals' tax withholding		(39)		(39)
Reduction in shares to cover individuals' tax withholding (in shares)	(20)
Stock-based compensation		3,965		3,965
Balances at Dec. 31, 2018	$ 16	1,095,367	101,661	1,197,044
Balances (in shares) at Dec. 31, 2018	160,613
Increase (Decrease) in Stockholders' Equity
Net income (loss)			(336,559)	(336,559)
Long-term incentive plan grants (in shares)	4,153
Long-term incentive plan forfeitures (in shares)	(193)
Reduction in shares to cover individuals' tax withholding		(406)		(406)
Reduction in shares to cover individuals' tax withholding (in shares)	(253)
Stock-based compensation		(6,416)		(6,416)
Balances at Mar. 31, 2019	$ 16	$ 1,088,545	$ (234,898)	$ 853,663
Balances (in shares) at Mar. 31, 2019	164,320

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (336,559)	$ (2,598)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	29,975	15,991
Full cost ceiling impairment	275,239
(Gain) loss on sale of oil and natural gas properties		3,679
(Gain) loss on sale of Water Assets	885
Deferred income tax provision (benefit)	(45,485)
Stock-based compensation, net	(6,782)	3,581
Unrealized loss (gain) on derivative contracts	68,169	(11,113)
Amortization of deferred loan costs	404	292
Amortization of discount and premium	55	132
Other income (expense)	1,408	106
Change in assets and liabilities:
Accounts receivable	(3,414)	(5,213)
Prepaids and other	(2,876)	108
Accounts payable and accrued liabilities	(17,853)	(17,547)
Net cash provided by (used in) operating activities	(36,834)	(12,582)
Cash flows from investing activities:
Oil and natural gas capital expenditures	(81,068)	(127,885)
Proceeds received from sales of oil and natural gas properties		(4,034)
Acquisition of oil and natural gas properties	(2,809)	(132,464)
Other operating property and equipment capital expenditures	(30,553)	(30,721)
Proceeds received from sale of other operating property and equipment		1,899
Funds held in escrow and other	(1)	157
Net cash provided by (used in) investing activities	(114,431)	(293,048)
Cash flows from financing activities:
Proceeds from borrowings	124,000	206,000
Repayments of borrowings	(19,000)
Debt issuance costs		(3,371)
Common stock issued		63,480
Offering costs and other	(406)	(2,475)
Net cash provided by (used in) financing activities	104,594	263,634
Net increase (decrease) in cash and cash equivalents	(46,671)	(41,996)
Cash and cash equivalents at beginning of period	46,866	424,071
Cash and cash equivalents at end of period	195	382,075
Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$ (43)	$ 210

FINANCIAL STATEMENT PRESENTATIO

FINANCIAL STATEMENT PRESENTATION	3 Months Ended
	Mar. 31, 2019
FINANCIAL STATEMENT PRESENTATION
FINANCIAL STATEMENT PRESENTATION	1. FINANCIAL STATEMENT PRESENTATION 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 unaudited condensed consolidated financial state ments 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 p ortfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company’s management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on March 12, 2019. Please refer to the notes in the 2018 Annual Report on Form 10-K when reviewing interim financial results. Use of Estimates The preparation of the Company’s unaudited condensed 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 unaudited condensed 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, 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 unaudited condensed consolidated financial statements. Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements. Ability to Continue as a Going Concern The Company’s strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in the Company divesting producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin. The Company’s drilling activities since acquiring the assets required significant capital expenditure outlays to replace lost production and related EBITDA. These and other factors adversely impacted the Company’s ability to comply with its debt covenants under the Senior Credit Agreement. Anticipating that it might be challenging to comply with the covenants under the Senior Credit Agreement, the Company has periodically sought and obtained amendments and consents from the lenders under the Senior Credit Agreement. Most recently, on May 8, 2019, the Company entered into an amendment to the Senior Credit Agreement in which its lenders waived compliance with the Consolidated Total Net Debt to EBITDA Ratio covenant contained in the Senior Credit Agreement for the three months ended March 31, 2019, while raising the applicable margin on the Company’s borrowings and imposing certain reporting and other obligations upon the Company. The waiver extends, as to compliance at March 31, 2019, until August 1, 2019; provided that it may be terminated on July 1, 2019 by the majority lenders in their sole discretion and earlier upon the occurrence of certain other events (an Early Termination). The lenders under the Senior Credit Agreement concurrently redetermined the borrowing base to $225.0 million, a reduction from $275.0 million at December 31, 2018. At March 31, 2019, the Company had borrowings of $105.0 million outstanding under the Senior Credit Agreement. The Company’s current internal projections show that it will not be in compliance with the Consolidated Total Net Debt to EBITDA Ratio and the Current Ratio covenants in certain future periods, beginning with the three months ended June 30, 2019. The Company sought amendment of the covenants for the twelve month period following the issuance date of the unaudited condensed consolidated financial statements included in this report, which the lenders did not approve. As a consequence, if the Company fails to comply with the financial covenants under the Senior Credit Agreement for the three months ended June 30, 2019, as projected,or there is an Early Termination, it will be in default under the Senior Credit Agreement. An Event of Default (as defined in the Senior Credit Agreement) would permit the lenders to accelerate any indebtedness outstanding under the Senior Credit Agreement, making it immediately due and payable. If the indebtedness under the Senior Credit Agreement is accelerated, then an Event of Default (as defined in the indenture governing the Company’s senior notes) under the senior notes would occur, which, if continued beyond any applicable cure period, would result in the entire principal under the senior notes being due and payable immediately. If the lenders, and subsequently noteholders, accelerate the outstanding indebtedness (the aggregate principal amount of which was approximately $730.0 million as of March 31, 2019), all such indebtedness will become immediately due and payable. The Company currently does not have sufficient liquidity to repay those amounts. In addition, should amounts under the Senior Credit Agreement become due and payable, the Company’s derivatives that are in a net liability position could also become due and payable. As a result of the Company’s expected inability to comply with its Consolidated Total Net Debt to EBITDA Ratio and its Current Ratio covenants contained in its Senior Credit Agreement within one year from the issuance date of the unaudited condensed consolidated financial statements for the three months ended March 31, 2019, the Company has determined that there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern. The Company has engaged advisors to evaluate strategic and financial alternatives and is pursuing options to maintain sufficient liquidity and to address its Senior Credit Agreement covenant compliance, including (i) working with the bank syndicate to amend the Senior Credit Agreement and/or obtain waivers of covenant compliance for future periods, (ii) seeking alternative sources of capital, (iii) divesting assets, (iv) exploring strategic merger and acquisition options and (v) reducing operating costs. There can be no assurance that the Company will be able to comply with the covenants in its Senior Credit Agreement, that the lenders will provide any covenant relief or fail to exercise their right to Early Termination or that the Company will be able to obtain alternative financing on a timely basis and on satisfactory terms, or at all. In addition, no assurance can be given that any such financing, if obtained, will be adequate to meet its capital needs and support its business plans while paying or refinancing the existing debt obligations. If alternative financing cannot be obtained on a timely basis and on satisfactory terms, then the Company’s operations would be materially negatively impacted. Accordingly, the Company classified outstanding borrowings under its Senior Credit Agreement as a current liability on its unaudited condensed consolidated balance sheet as of March 31, 2019. The unaudited condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material. 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 March 31, 2019 and December 31, 2018, allowances for doubtful accounts were approximately $0.1 million and $0.2 million, respectively. 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. The Company reviews its other operating property and equipment for impairment in accordance with Accounting Standards Codification (ASC) No. 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. Leases Effective January 1, 2019, the Company accounts for leases in accordance with ASC No. 842, Leases, (ASC 842). The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset. The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in "Operating lease right of use assets" and "Operating lease liabilities" on our unaudited condensed consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date. Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise. The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company's operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Variable lease payments associated with the Company's leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as "Gathering and other" or "General and administrative" in our unaudited condensed consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases. The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case-by-case basis. The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, a corresponding adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the unaudited condensed consolidated statements of operations. The Company elected not to recognize right of use assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short-term leases as an expense on a straight-line basis over the lease term. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases. Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics). Restructuring During the three months ended March 31, 2019, four executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, the Company had reductions in its workforce due to a decrease in drilling and developmental activities planned for 2019. Consequently, for the three months ended March 31, 2019, the Company incurred approximately $11.3 million in severance costs which were recorded in “ Restructuring ” on the unaudited condensed consolidated statements of operations. 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. In the fourth quarter of 2018, the Company began selling its crude oil to SCM while the gathering system was under construction. The gathering system was completed and placed into service in March 2019. For the three months ended March 31, 2019, the Company earned $39.2 million from SCM under the crude oil gathering agreement and as of March 31, 2019 recorded an $11.2 million receivable from SCM for its crude oil sales. Certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM. Ares also controls other funds which 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 three months ended March 31, 2019, the Company earned $0.2 million from Salt Creek under the gas purchase and processing agreement and as of March 31, 2019 recorded a $0.8 million receivable from Salt Creek for its natural gas sales. 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. Pipeline Testing Services In February 2019, the Company entered into an agreement with Cima Inspection LLC (Cima), a company specializing in advanced, non-destructive methods of testing pipes and tubing, pursuant to which Cima will inspect various Company gathering and transportation assets. One of the Company's directors owns a minority interest in Cima and currently serves, without compensation, as its chief executive officer. The engagement of Cima was the result of a lengthy process during which Halcón investigated the most cost-effective method of conducting testing on its gathering and transportation assets. Halcón considered the performance and cost of various alternatives and solicited proposals from third parties before determining that Cima's proposal offered the most timely cost efficient solution to the Company's needs. As a result of the relationship of one of the Company's directors with Cima, the process by which the Company determined Cima's proposal to be superior to others, as well as the terms of the agreement, were evaluated and approved by the Audit Committee and the disinterested members of Halcón's board, in a vote that excluded that director 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. For the three months ended March 31, 2019, the Company incurred charges of approximately $0.3 million for services provided by Cima. As of March 31, 2019, the Company recorded a $0.2 million payable to Cima. The payable is recorded in “ Accounts payable and accrued liabilities ,” on the Company’s unaudited condensed consolidated balance sheet. Charter of Aircraft In the ordinary course of business, Halcón occasionally chartered a private aircraft for business use. Floyd C. Wilson, Halcón’s former Chairman, Chief Executive Officer and President, indirectly owns an aircraft which the Company chartered from time to time. During 2019, 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, and subsequently by the disinterested members of the Company's board 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 three months ended March 31, 2019, the Company paid approximately $0.2 million related to use of the aircraft indirectly owned by Mr. Wilson during 2018. In 2019, the Company terminated all charter arrangements with Mr. Wilson relating to the use of his aircraft. Recently Issued Accounting Pronouncements In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective approach as of the adoption date. See "Leases" above and Note 2, “Leases,” below for further details.

LEASES

LEASES	3 Months Ended
	Mar. 31, 2019
LEASES
LEASES	2. LEASES Adoption of Accounting Standards Codification 842, Leases On January 1, 2019, the Company adopted ASC 842 using the modified retrospective approach as of the adoption date. Reporting periods beginning after January 1, 2019 are presented under ASC 842, while prior period amounts are not adjusted and continue to be reported under the accounting standards in effect for those periods. The table below details the impact of adoption on the Company’s unaudited condensed consolidated balance sheet as of January 1, 2019 (in thousands): Impact of adoption December 31, 2018 of ASC 842 January 1, 2019 Other noncurrent assets: Operating lease right of use assets $ — $ 5,462 $ 5,462 Current liabilities: Accounts payable and accrued liabilities $ 157,848 $ (85) $ 157,763 Operating lease liabilities — 2,103 2,103 Other noncurrent liabilities: Operating lease liabilities — 3,444 3,444 Practical Expedients The Company elected the following practical expedients for transition to, and ongoing accounting under, ASC 842: i) the Company does not separate lease and non-lease components of a contract, ii) the Company does not reassess whether expired or existing contracts contain leases, nor does it reassess the lease classification for expired or existing leases and does not reassess whether previously capitalized initial direct costs would qualify for capitalization under ASC 842, iii) the Company applies a single discount rate to a portfolio of leases with reasonably similar characteristics and iv) the Company does not assess whether existing or expired land easements that were not previously accounted for as leases are or contain a lease under ASC 842. Leases The Company leases equipment and office space under operating leases. The operating leases have initial lease terms ranging from 1 to 5 years, some of which include options to extend or renew the leases for one year. Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. The table below summarizes the Company’s leases for the three months ended March 31, 2019 (in thousands, except years and discount rate): Three Months Ended March 31, 2019 Lease cost Operating lease costs $ 644 Short-term lease costs 5,718 Variable lease costs 425 Total lease costs $ 6,787 Other information Cash paid for amounts included in the measurement of lease liabilities — Operating cash flows from operating leases $ 1,229 Right-of-use assets obtained in exchange for new operating lease liabilities 5,462 Weighted-average remaining lease term — operating leases 3.6 years Weighted-average discount rate—operating leases 4.83 % Future minimum lease payments associated with the Company's non-cancellable operating leases for office space and equipment as of March 31, 2019, are presented in the table below (in thousands): March 31, 2019 Remaining period in 2019 $ 1,672 2020 1,360 2021 876 2022 574 2023 585 Thereafter 345 Total operating lease payments 5,412 Less: discount to present value 449 Total operating lease liabilities 4,963 Less: current operating lease liabilities 1,868 Noncurrent operating lease liabilities $ 3,095 Prior to the adoption of ASC 842, future obligations, including variable nonlease components, associated with the Company's non-cancellable operating leases for office space and equipment as of December 31 , 2018 , are presented in the table below (in thousands): December 31, 2018 2019 $ 3,792 2020 2,350 2021 1,899 2022 968 2023 999 Thereafter 599 Total operating lease payments $ 10,607

OPERATING REVENUES

OPERATING REVENUES	3 Months Ended
	Mar. 31, 2019
OPERATING REVENUES
OPERATING REVENUES	3. OPERATING REVENUES Revenue Recognition Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, that are collected by the Company from a customer, are excluded from revenue. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Because the Company’s performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $30.7 million and $26.4 million as of March 31, 2019 and December 31, 2018, 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): Three Months Ended March 31, 2019 2018 Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 45,517 $ 43,069 Natural gas 1,461 2,319 Natural gas liquids 4,945 3,712 Total oil, natural gas and natural gas liquids sales 51,923 49,100 Other (7) 155 Total operating revenues $ 51,916 $ 49,255 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 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” on the unaudited condensed consolidated statements of operations. Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as “Gathering and other” on the unaudited condensed consolidated statement of operations. Settlement statements for the Company’s natural gas and natural gas liquids production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. Historically, differences between the Company’s estimates and the actual revenue received have not been material. Payment under the Company’s natural gas gathering and processing contracts is typically due on or before the fifth day of the second month following the delivery month.

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	3 Months Ended
	Mar. 31, 2019
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES	4. 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 additional 6.75% senior notes due 2025 and common stock, which are discussed in Note 6, “ Debt ,” and Note 11, “ Stockholders' Equity ,” respectively. Monument Draw Assets (Ward and Winkler Counties, Texas) On January 9, 2018, the Company purchased acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) that is prospective for the Wolfcamp and Bone Spring formations from a private company for $108.2 million in cash. 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 $211.9 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 recognized a gain of $118.1 million on the sale of the Water Assets on the unaudited condensed consolidated statements of operations in “(Gain) loss on sale of Water Assets.” The gain on the sale was reduced during the three months ended March 31, 2019 by approximately $0.9 million as a result of customary post-closing adjustments.

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	3 Months Ended
	Mar. 31, 2019
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES	5. 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, 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. At March 31, 2019, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended March 31, 2019 of the West Texas Intermediate (WTI) crude oil spot price of $63.06 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended March 31, 2019 of the Henry Hub natural gas price of $3.07 per million British thermal units (MMBtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at March 31, 2019 exceeded the ceiling amount by $275.2 million ($217.4 million after taxes) which resulted in a ceiling test impairment charge of that amount for the quarter. The impairment was recorded in “Full cost ceiling test impairment” on the unaudited condensed consolidated statements of operations. The ceiling test impairment was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and the Company’s intent to expend capital only on its most economic areas. As such, the Company identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019. At March 31, 2018, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended March 31, 2018 of the WTI crude oil spot price of $53.49 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended March 31, 2018 of the Henry Hub natural gas price of $3.00 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at March 31, 2018 did not exceed the ceiling amount. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company’s ceiling test calculations and impairment analyses in future periods. On September 7, 2017, the Company and certain of its subsidiaries sold 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 for a total adjusted sales price of approximately $1.39 billion (the Williston Divestiture). Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the 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 $3.7 million during the three months ended March 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 (loss) was recorded in “Gain (loss) on sale of oil and natural gas properties,” on the Company’s unaudited condensed consolidated statements of operations.

DEBT

DEBT	3 Months Ended
	Mar. 31, 2019
DEBT
DEBT	6. DEBT As of March 31, 2019 and December 31, 2018, the Company’s current and long-term debt consisted of the following (in thousands): March 31, December 31, 2019 2018 Senior revolving credit facility (1) $ 105,000 $ — 6.75% senior notes due 2025 (2) 613,493 613,105 $ 718,493 $ 613,105 (1) Outstanding borrowings under the Company’s Senior Credit Agreement as of March 31, 2019 were classified as a current liability. See “Senior Revolving Credit Facility” below for more details. (2) Amount includes a $7.0 million and $7.2 million unamortized discount at March 31, 2019 and December 31, 2018, respectively, associated with the 2025 Notes. Amount includes a $5.2 million and $5.4 million unamortized premium at March 31, 2019 and December 31, 2018, respectively, associated with the Additional 2025 Notes. Additionally, these amounts are net of $9.7 million and $10.1 million unamortized debt issuance costs at March 31, 2019 and December 31, 2018, 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 have agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a current borrowing base of $225.0 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 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins 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 Consolidated Total Net Debt to EBITDA Ratio (as defined in the Senior Credit Agreement), which was recently revised by the H2S Consent, the Severance and Office Payments Consent and the Eighth 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 March 31, 2019, the Company had $105.0 million of indebtedness outstanding and approximately $1.8 million letters of credit outstanding. Under a borrowing base of $225.0 million, the Company had $118.2 million of borrowing capacity available under the Senior Credit Agreement. On May 8, 2019, the Company entered into the Eighth Amendment (the Eighth Amendment) to the Senior Credit Agreement which, among other things, (i) waives any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increases interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) limits the Company's Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provides for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver will terminate and an Event of Default (as defined in the Senior Credit Agreement) will occur on August 1, 2019 unless certain requirements are satisfied and the lenders opt not to exercise their right to terminate the waiver earlier on July 1, 2019. 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 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. After giving effect to the H2S Consent, the Severance and Office Payments Consent, and the waiver contained in the Eighth Amendment, at March 31, 2019, the Company was in compliance with the financial covenants under the Senior Credit Agreement. However, the Company’s current internal projections show that it will not be in compliance with the Consolidated Total Net Debt to EBITDA Ratio and the Current Ratio covenants in certain future periods, beginning with the three months ended June 30, 2019. As described in Note 1 , “Financial Statement Presentation”, the Company classified outstanding borrowings under its Senior Credit Agreement as a current liability within “Current portion of long-term debt” on its unaudited condensed consolidated balance sheet as of March 31, 2019. 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, and for general corporate purposes. 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 100% 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. 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 4, “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. The remaining unamortized discount on the 2025 Notes was $7.0 million at March 31, 2019. The unamortized premium on the Additional 2025 Notes was $5.2 million at March 31, 2019. 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. At March 31, 2019 and December 31, 2018, the Company had approximately $10.7 million and $11.1 million, respectively, of unamortized debt issuance costs. The debt issuance costs for the Company’s Senior Credit Agreement are presented in “Prepaids and other” and the debt issuance costs for the Company’s senior unsecured debt are presented in “Long-term debt, net” on the unaudited condensed consolidated balance sheets.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2019
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	7. FAIR VALUE MEASUREMENTS Pursuant to ASC 820, Fair Value Measurements (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 unaudited condensed 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 March 31, 2019 and December 31, 2018 (in thousands): March 31, 2019 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 16,067 $ — $ 16,067 Liabilities Liabilities from derivative contracts $ — $ 27,427 $ — $ 27,427 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 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” on the unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8, “Derivative and Hedging Activities,” for additional discussion of derivatives. The Company’s derivative contracts are with major financial and commodity hedging 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 receivables and accounts payables approximate 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 instrument as of March 31, 2019 and December 31, 2018 (excluding discounts, premiums and debt issuance costs) (in thousands): March 31, 2019 December 31, 2018 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes $ 625,005 $ 376,566 $ 625,005 $ 458,210 The fair value of the Company’s fixed interest debt instrument was calculated using Level 2 criteria. The fair value of the Company’s senior notes is based on quoted market prices from trades of such debt. The Company follows the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments;and therefore, the Company has designated these liabilities as Level 3. See Note 9, “ 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	3 Months Ended
	Mar. 31, 2019
DERIVATIVE AND HEDGING ACTIVITIES
DERIVATIVE AND HEDGING ACTIVITIES	8. 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 unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed 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 or commodity hedging institutions deemed by management as competent and competitive market makers. As of March 31, 2019, 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 price index under which the 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 unaudited condensed consolidated statements of operations. At March 31, 2019, the Company had 56 open commodity derivative contracts summarized in the following tables: six natural gas collar arrangements, seven natural gas basis swaps, five natural gas liquids swaps, 17 crude oil basis swaps, 15 crude oil collar arrangements, two crude oil puts, two crude oil calls, one crude oil WTI NYMEX roll and one crude oil swap. 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. All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2019 and December 31, 2018 (in thousands): Asset derivative contracts Liability derivative contracts Derivatives not designated as hedging contracts under ASC 815 Balance sheet location March 31, 2019 December 31, 2018 Balance sheet location March 31, 2019 December 31, 2018 Commodity contracts Current assets — receivables from derivative contracts $ 11,223 $ 57,280 Current liabilities—liabilities from derivative contracts $ (20,086) $ (3,768) Commodity contracts Other noncurrent assets—receivables from derivative contracts 4,844 12,437 Other noncurrent liabilities—liabilities from derivative contracts (7,341) (9,139) Total derivatives not designated as hedging contracts under ASC 815 $ 16,067 $ 69,717 $ (27,427) $ (12,907) The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations (in thousands): Amount of gain or (loss) recognized in income on derivative contracts for the Location of gain or (loss) recognized in Three Months Ended March 31, Derivatives not designated as hedging contracts under ASC 815 income on derivative contracts 2019 2018 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts $ (68,169) $ 11,113 Realized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts 3,370 (5,210) Total net gain (loss) on derivative contracts $ (64,799) $ 5,903 At March 31, 2019 and December 31, 2018, the Company had the following open crude oil and natural gas derivative contracts: March 31, 2019 Floors Ceilings Basis Differential Volume in Price / Weighted Price / Weighted Price / Weighted Mmbtu’s/ Price Average Price Average Price Average Period Instrument Commodity Bbl’s Range Price Range Price Range Price April 2019 - June 2019 Basis Swap Crude Oil 182,000 $ — $ — $ — $ — $ (1.00) - $ (1.18) $ (1.09) April 2019 - June 2019 Collars Crude Oil 182,000 50.00 - 51.00 50.50 55.00 - 56.00 55.50 April 2019 - September 2019 Basis Swap Crude Oil 366,000 (6.20) - (7.60) (6.90) April 2019 - December 2019 Basis Swap Natural Gas 7,012,500 (1.05) - (1.40) (1.18) April 2019 - December 2019 Basis Swap Crude Oil 1,464,000 (0.98) - (6.50) (3.95) April 2019 - December 2019 Collars Crude Oil 2,475,000 50.00 - 58.00 53.76 55.20 - 63.00 60.41 April 2019 - December 2019 Collars Natural Gas 6,600,000 2.52 - 2.70 2.60 3.00 - 3.10 3.01 April 2019 - December 2019 Swap Natural Gas Liquid 1,100,000 29.08 - 30.15 29.33 April 2019 - December 2019 WTI NYMEX ROLL Crude Oil 1,375,000 0.35 0.35 April 2019 - December 2019 Swap Crude Oil 483,967 56.80 56.80 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 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 January 2020 - December 2020 Swap Crude Oil 620,549 56.80 56.80 January 2021 - December 2021 Swap Crude Oil 611,537 56.80 56.80 January 2022 - March 2022 Swap Crude Oil 152,104 56.80 56.80 December 31, 2018 Floors Ceilings Basis Differential Volume in Price / Weighted Price / Weighted Price / Weighted Mmbtu’s/ Price Average Price Average Price Average Period Instrument Commodity Bbl’s Range Price Range Price Range Price January 2019 - March 2019 Calls Crude Oil 1,350,000 $ — $ — $ 62.64 $ 62.64 $ — $ — January 2019 - March 2019 Calls Crude Oil (1,350,000) 58.64 58.64 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - June 2019 Collars Crude Oil 181,000 51.00 51.00 56.00 56.00 January 2019 - September 2019 Basis Swap Crude Oil 546,000 (6.20) - (7.60) (6.90) January 2019 - December 2019 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 The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed 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 March 31, 2019 and December 31, 2018 (in thousands): Derivative Assets Derivative Liabilities Offsetting of Derivative Assets and Liabilities March 31, 2019 December 31, 2018 March 31, 2019 December 31, 2018 Gross Amounts Presented in the Consolidated Balance Sheet $ 16,067 $ 69,717 $ (27,427) $ (12,907) Amounts Not Offset in the Consolidated Balance Sheet (12,807) (10,263) 12,807 10,263 Net Amount $ 3,260 $ 59,454 $ (14,620) $ (2,644) The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	3 Months Ended
	Mar. 31, 2019
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS	9. 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 unaudited condensed 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 unaudited condensed 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 for the period indicated below (inclusive of the current portion) (in thousands): Liability for asset retirement obligations as of December 31, 2018 $ 6,914 Liabilities settled and divested (229) Additions 186 Accretion expense 100 Liability for asset retirement obligations as of March 31, 2019 $ 6,971

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2019
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	10. COMMITMENTS AND CONTINGENCIES Commitments As of March 31, 2019, the Company has the following active drilling rig commitments (in thousands): March 31, 2019 Remaining period in 2019 $ 1,321 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 1,321 As of March 31, 2019, termination of the Company’s active drilling rig commitments would require early termination penalties of $1.1 million, which would be in lieu of paying the remaining active drilling rig commitments of $1.3 million. As of March 31, 2019, the Company has the following rig termination commitments (in thousands): March 31, 2019 Remaining period in 2019 $ — 2020 3,000 2021 — 2022 — 2023 — Thereafter — Total $ 3,000 As of March 31, 2019, the Company has the following purchase commitments related to equipment (in thousands): March 31, 2019 Remaining period in 2019 $ 7,997 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 7,997 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 March 31, 2019, 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. 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 unaudited condensed consolidated operating results, financial position or cash flows.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	3 Months Ended
	Mar. 31, 2019
STOCKHOLDERS' EQUITY
STOCKHOLDERS' EQUITY	11. STOCKHOLDERS’ EQUITY Common Stock 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 March 31, 2019 and December 31, 2018, a maximum of 1.1 million and 4.9 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 to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. For the three months ended March 31, 2019 and 2018 the Company recognized a credit of $6.8 million and expense of $3.6 million, respectively, related to stock-based compensation. Stock-based compensation expense is recorded as a component of “General and administrative” on the unaudited condensed consolidated statements of operations. During the three months ended March 31, 2019, four senior executives departed the Company. In accordance with the terms of these senior executives’ employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the three months ended March 31, 2019, the Company recognized an incremental reduction to stock-based compensation expense of $8.4 million associated with these modifications. 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. No stock options were granted during the three months ended March 31, 2019. At March 31, 2019, the Company had $1.5 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 0.8 years. During the three months ended March 31, 2018, the Company granted stock options under the Plan covering 1.2 million shares of common stock to employees of the Company. These stock options have an exercise price of $5.65 per share. During the three months ended March 31, 2018, the Company received $0.3 million from the exercise of stock options. At March 31, 2018, the Company had $13.1 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.2 years. 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. During the three months ended March 31, 2019, the Company granted 4.2 million shares of restricted stock under the Plan to employees of the Company. These restricted shares were granted at $1.29 per share. At March 31, 2019, the Company had $8.2 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.8 years. During the three months ended March 31, 2018, the Company granted 1.9 million shares of restricted stock under the Plan to employees of the Company. These restricted shares were granted at $5.65 per share. At March 31, 2018, the Company had $12.5 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.7 years.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	3 Months Ended
	Mar. 31, 2019
EARNINGS PER COMMON SHARE
EARNINGS PER COMMON SHARE	12. EARNINGS PER COMMON SHARE The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts): Three Months Ended March 31, 2019 2018 Basic: Net income (loss) $ (336,559) $ (2,598) Weighted average basic number of common shares outstanding 158,549 153,884 Basic net income (loss) per share of common stock $ (2.12) $ (0.02) Diluted: Net income (loss) $ (336,559) $ (2,598) Weighted average basic number of common shares outstanding 158,549 153,884 Common stock equivalent shares representing shares issuable upon: Exercise of stock options Anti-dilutive Anti-dilutive Exercise of warrants Anti-dilutive Anti-dilutive Vesting of restricted shares Anti-dilutive Anti-dilutive Weighted average diluted number of common shares outstanding 158,549 153,884 Diluted net income (loss) per share of common stock $ (2.12) $ (0.02) Common stock equivalents, including stock options, restricted shares and warrants totaling 14.9 million shares for the three months ended March 31, 2019 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. Common stock equivalents, including stock options, restricted shares and warrants totaling 13.2 million shares for the three months ended March 31, 2018 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	3 Months Ended
	Mar. 31, 2019
ADDITIONAL FINANCIAL STATEMENT INFORMATION
ADDITIONAL FINANCIAL STATEMENT INFORMATION	13. ADDITIONAL FINANCIAL STATEMENT INFORMATION Certain balance sheet amounts are comprised of the following (in thousands): March 31, December 31, 2019 2018 Accounts receivable: Oil, natural gas and natural gas liquids revenues $ 30,705 $ 26,432 Joint interest accounts 7,470 7,369 Other 3,224 1,917 $ 41,399 $ 35,718 Prepaids and other: Prepaids $ 3,646 $ 3,503 Income tax receivable 1,250 1,250 Debt issuance costs 976 — Other 2,768 35 $ 8,640 $ 4,788 Funds in escrow and other: Funds in escrow $ 573 $ 570 Other 562 1,611 $ 1,135 $ 2,181 Accounts payable and accrued liabilities: Trade payables $ 55,668 $ 68,959 Accrued oil and natural gas capital costs 40,492 41,461 Revenues and royalties payable 20,241 20,526 Accrued interest expense 6,343 16,971 Accrued employee compensation 2,729 3,421 Accrued lease operating expenses 11,152 6,292 Other 391 218 $ 137,016 $ 157,848

FINANCIAL STATEMENT PRESENTAT_2

FINANCIAL STATEMENT PRESENTATION (Policies)	3 Months Ended
	Mar. 31, 2019
FINANCIAL STATEMENT PRESENTATION
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 unaudited condensed consolidated financial state ments 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 p ortfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company’s management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on March 12, 2019. Please refer to the notes in the 2018 Annual Report on Form 10-K when reviewing interim financial results.
Use of Estimates	Use of Estimates The preparation of the Company’s unaudited condensed 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 unaudited condensed 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, 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 unaudited condensed consolidated financial statements. Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.
Ability to Continue as a Going Concern	Ability to Continue as a Going Concern The Company’s strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in the Company divesting producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin. The Company’s drilling activities since acquiring the assets required significant capital expenditure outlays to replace lost production and related EBITDA. These and other factors adversely impacted the Company’s ability to comply with its debt covenants under the Senior Credit Agreement. Anticipating that it might be challenging to comply with the covenants under the Senior Credit Agreement, the Company has periodically sought and obtained amendments and consents from the lenders under the Senior Credit Agreement. Most recently, on May 8, 2019, the Company entered into an amendment to the Senior Credit Agreement in which its lenders waived compliance with the Consolidated Total Net Debt to EBITDA Ratio covenant contained in the Senior Credit Agreement for the three months ended March 31, 2019, while raising the applicable margin on the Company’s borrowings and imposing certain reporting and other obligations upon the Company. The waiver extends, as to compliance at March 31, 2019, until August 1, 2019; provided that it may be terminated on July 1, 2019 by the majority lenders in their sole discretion and earlier upon the occurrence of certain other events (an Early Termination). The lenders under the Senior Credit Agreement concurrently redetermined the borrowing base to $225.0 million, a reduction from $275.0 million at December 31, 2018. At March 31, 2019, the Company had borrowings of $105.0 million outstanding under the Senior Credit Agreement. The Company’s current internal projections show that it will not be in compliance with the Consolidated Total Net Debt to EBITDA Ratio and the Current Ratio covenants in certain future periods, beginning with the three months ended June 30, 2019. The Company sought amendment of the covenants for the twelve month period following the issuance date of the unaudited condensed consolidated financial statements included in this report, which the lenders did not approve. As a consequence, if the Company fails to comply with the financial covenants under the Senior Credit Agreement for the three months ended June 30, 2019, as projected,or there is an Early Termination, it will be in default under the Senior Credit Agreement. An Event of Default (as defined in the Senior Credit Agreement) would permit the lenders to accelerate any indebtedness outstanding under the Senior Credit Agreement, making it immediately due and payable. If the indebtedness under the Senior Credit Agreement is accelerated, then an Event of Default (as defined in the indenture governing the Company’s senior notes) under the senior notes would occur, which, if continued beyond any applicable cure period, would result in the entire principal under the senior notes being due and payable immediately. If the lenders, and subsequently noteholders, accelerate the outstanding indebtedness (the aggregate principal amount of which was approximately $730.0 million as of March 31, 2019), all such indebtedness will become immediately due and payable. The Company currently does not have sufficient liquidity to repay those amounts. In addition, should amounts under the Senior Credit Agreement become due and payable, the Company’s derivatives that are in a net liability position could also become due and payable. As a result of the Company’s expected inability to comply with its Consolidated Total Net Debt to EBITDA Ratio and its Current Ratio covenants contained in its Senior Credit Agreement within one year from the issuance date of the unaudited condensed consolidated financial statements for the three months ended March 31, 2019, the Company has determined that there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern. The Company has engaged advisors to evaluate strategic and financial alternatives and is pursuing options to maintain sufficient liquidity and to address its Senior Credit Agreement covenant compliance, including (i) working with the bank syndicate to amend the Senior Credit Agreement and/or obtain waivers of covenant compliance for future periods, (ii) seeking alternative sources of capital, (iii) divesting assets, (iv) exploring strategic merger and acquisition options and (v) reducing operating costs. There can be no assurance that the Company will be able to comply with the covenants in its Senior Credit Agreement, that the lenders will provide any covenant relief or fail to exercise their right to Early Termination or that the Company will be able to obtain alternative financing on a timely basis and on satisfactory terms, or at all. In addition, no assurance can be given that any such financing, if obtained, will be adequate to meet its capital needs and support its business plans while paying or refinancing the existing debt obligations. If alternative financing cannot be obtained on a timely basis and on satisfactory terms, then the Company’s operations would be materially negatively impacted. Accordingly, the Company classified outstanding borrowings under its Senior Credit Agreement as a current liability on its unaudited condensed consolidated balance sheet as of March 31, 2019. The unaudited condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.
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 March 31, 2019 and December 31, 2018, allowances for doubtful accounts were approximately $0.1 million and $0.2 million, respectively.
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. The Company reviews its other operating property and equipment for impairment in accordance with Accounting Standards Codification (ASC) No. 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.
Leases	Leases Effective January 1, 2019, the Company accounts for leases in accordance with ASC No. 842, Leases, (ASC 842). The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset. The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in "Operating lease right of use assets" and "Operating lease liabilities" on our unaudited condensed consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date. Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise. The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company's operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Variable lease payments associated with the Company's leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as "Gathering and other" or "General and administrative" in our unaudited condensed consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases. The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case-by-case basis. The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, a corresponding adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the unaudited condensed consolidated statements of operations. The Company elected not to recognize right of use assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short-term leases as an expense on a straight-line basis over the lease term. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases. Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics).
Restructuring	Restructuring During the three months ended March 31, 2019, four executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, the Company had reductions in its workforce due to a decrease in drilling and developmental activities planned for 2019. Consequently, for the three months ended March 31, 2019, the Company incurred approximately $11.3 million in severance costs which were recorded in “ Restructuring ” on the unaudited condensed consolidated statements of operations.
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. In the fourth quarter of 2018, the Company began selling its crude oil to SCM while the gathering system was under construction. The gathering system was completed and placed into service in March 2019. For the three months ended March 31, 2019, the Company earned $39.2 million from SCM under the crude oil gathering agreement and as of March 31, 2019 recorded an $11.2 million receivable from SCM for its crude oil sales. Certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM. Ares also controls other funds which 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 three months ended March 31, 2019, the Company earned $0.2 million from Salt Creek under the gas purchase and processing agreement and as of March 31, 2019 recorded a $0.8 million receivable from Salt Creek for its natural gas sales. 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. Pipeline Testing Services In February 2019, the Company entered into an agreement with Cima Inspection LLC (Cima), a company specializing in advanced, non-destructive methods of testing pipes and tubing, pursuant to which Cima will inspect various Company gathering and transportation assets. One of the Company's directors owns a minority interest in Cima and currently serves, without compensation, as its chief executive officer. The engagement of Cima was the result of a lengthy process during which Halcón investigated the most cost-effective method of conducting testing on its gathering and transportation assets. Halcón considered the performance and cost of various alternatives and solicited proposals from third parties before determining that Cima's proposal offered the most timely cost efficient solution to the Company's needs. As a result of the relationship of one of the Company's directors with Cima, the process by which the Company determined Cima's proposal to be superior to others, as well as the terms of the agreement, were evaluated and approved by the Audit Committee and the disinterested members of Halcón's board, in a vote that excluded that director 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. For the three months ended March 31, 2019, the Company incurred charges of approximately $0.3 million for services provided by Cima. As of March 31, 2019, the Company recorded a $0.2 million payable to Cima. The payable is recorded in “ Accounts payable and accrued liabilities ,” on the Company’s unaudited condensed consolidated balance sheet. Charter of Aircraft In the ordinary course of business, Halcón occasionally chartered a private aircraft for business use. Floyd C. Wilson, Halcón’s former Chairman, Chief Executive Officer and President, indirectly owns an aircraft which the Company chartered from time to time. During 2019, 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, and subsequently by the disinterested members of the Company's board 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 three months ended March 31, 2019, the Company paid approximately $0.2 million related to use of the aircraft indirectly owned by Mr. Wilson during 2018. In 2019, the Company terminated all charter arrangements with Mr. Wilson relating to the use of his aircraft.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective approach as of the adoption date. See "Leases" above and Note 2, “Leases,” below for further details.

LEASES (Tables)

LEASES (Tables)	3 Months Ended
	Mar. 31, 2019
Schedule of Company's leases	The table below summarizes the Company’s leases for the three months ended March 31, 2019 (in thousands, except years and discount rate): Three Months Ended March 31, 2019 Lease cost Operating lease costs $ 644 Short-term lease costs 5,718 Variable lease costs 425 Total lease costs $ 6,787 Other information Cash paid for amounts included in the measurement of lease liabilities — Operating cash flows from operating leases $ 1,229 Right-of-use assets obtained in exchange for new operating lease liabilities 5,462 Weighted-average remaining lease term — operating leases 3.6 years Weighted-average discount rate—operating leases 4.83 %
Schedule of future minimum lease payments associated with the Company's non-cancellable operating leases for office space and equipment	Future minimum lease payments associated with the Company's non-cancellable operating leases for office space and equipment as of March 31, 2019, are presented in the table below (in thousands): March 31, 2019 Remaining period in 2019 $ 1,672 2020 1,360 2021 876 2022 574 2023 585 Thereafter 345 Total operating lease payments 5,412 Less: discount to present value 449 Total operating lease liabilities 4,963 Less: current operating lease liabilities 1,868 Noncurrent operating lease liabilities $ 3,095
Schedule of future obligations, including variable nonlease components, associated with the Company's non-cancellable operating leases for office space and equipment	Prior to the adoption of ASC 842, future obligations, including variable nonlease components, associated with the Company's non-cancellable operating leases for office space and equipment as of December 31 , 2018 , are presented in the table below (in thousands): December 31, 2018 2019 $ 3,792 2020 2,350 2021 1,899 2022 968 2023 999 Thereafter 599 Total operating lease payments $ 10,607
Leases
Schedule of impact of adoption on the Company's unaudited condensed consolidated balance sheet	The table below details the impact of adoption on the Company’s unaudited condensed consolidated balance sheet as of January 1, 2019 (in thousands): Impact of adoption December 31, 2018 of ASC 842 January 1, 2019 Other noncurrent assets: Operating lease right of use assets $ — $ 5,462 $ 5,462 Current liabilities: Accounts payable and accrued liabilities $ 157,848 $ (85) $ 157,763 Operating lease liabilities — 2,103 2,103 Other noncurrent liabilities: Operating lease liabilities — 3,444 3,444

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	3 Months Ended
	Mar. 31, 2019
OPERATING REVENUES
Schedule of disaggregation of revenues by major product	The following table disaggregates the Company’s revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company's single basin operations, for the periods indicated (in thousands): Three Months Ended March 31, 2019 2018 Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 45,517 $ 43,069 Natural gas 1,461 2,319 Natural gas liquids 4,945 3,712 Total oil, natural gas and natural gas liquids sales 51,923 49,100 Other (7) 155 Total operating revenues $ 51,916 $ 49,255

DEBT (Tables)

DEBT (Tables)	3 Months Ended
	Mar. 31, 2019
DEBT
Schedule of current and long-term debt	As of March 31, 2019 and December 31, 2018, the Company’s current and long-term debt consisted of the following (in thousands): March 31, December 31, 2019 2018 Senior revolving credit facility (1) $ 105,000 $ — 6.75% senior notes due 2025 (2) 613,493 613,105 $ 718,493 $ 613,105 (1) Outstanding borrowings under the Company’s Senior Credit Agreement as of March 31, 2019 were classified as a current liability. See “Senior Revolving Credit Facility” below for more details. (2) Amount includes a $7.0 million and $7.2 million unamortized discount at March 31, 2019 and December 31, 2018, respectively, associated with the 2025 Notes. Amount includes a $5.2 million and $5.4 million unamortized premium at March 31, 2019 and December 31, 2018, respectively, associated with the Additional 2025 Notes. Additionally, these amounts are net of $9.7 million and $10.1 million unamortized debt issuance costs at March 31, 2019 and December 31, 2018, respectively. Refer to “6.75% Senior Notes” below for further details.

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2019
FAIR VALUE MEASUREMENTS
Schedule of fair value of the Company's financial assets and liabilities	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of March 31, 2019 and December 31, 2018 (in thousands): March 31, 2019 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 16,067 $ — $ 16,067 Liabilities Liabilities from derivative contracts $ — $ 27,427 $ — $ 27,427 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
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 instrument as of March 31, 2019 and December 31, 2018 (excluding discounts, premiums and debt issuance costs) (in thousands): March 31, 2019 December 31, 2018 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes $ 625,005 $ 376,566 $ 625,005 $ 458,210

DERIVATIVE AND HEDGING ACTIVI_2

DERIVATIVE AND HEDGING ACTIVITIES (Tables)	3 Months Ended
	Mar. 31, 2019
DERIVATIVE AND HEDGING ACTIVITIES
Summary of location and fair value of derivative contracts	The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2019 and December 31, 2018 (in thousands): Asset derivative contracts Liability derivative contracts Derivatives not designated as hedging contracts under ASC 815 Balance sheet location March 31, 2019 December 31, 2018 Balance sheet location March 31, 2019 December 31, 2018 Commodity contracts Current assets — receivables from derivative contracts $ 11,223 $ 57,280 Current liabilities—liabilities from derivative contracts $ (20,086) $ (3,768) Commodity contracts Other noncurrent assets—receivables from derivative contracts 4,844 12,437 Other noncurrent liabilities—liabilities from derivative contracts (7,341) (9,139) Total derivatives not designated as hedging contracts under ASC 815 $ 16,067 $ 69,717 $ (27,427) $ (12,907)
Summary of the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts	The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations (in thousands): Amount of gain or (loss) recognized in income on derivative contracts for the Location of gain or (loss) recognized in Three Months Ended March 31, Derivatives not designated as hedging contracts under ASC 815 income on derivative contracts 2019 2018 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts $ (68,169) $ 11,113 Realized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts 3,370 (5,210) Total net gain (loss) on derivative contracts $ (64,799) $ 5,903
Schedule of open derivative contracts	March 31, 2019 Floors Ceilings Basis Differential Volume in Price / Weighted Price / Weighted Price / Weighted Mmbtu’s/ Price Average Price Average Price Average Period Instrument Commodity Bbl’s Range Price Range Price Range Price April 2019 - June 2019 Basis Swap Crude Oil 182,000 $ — $ — $ — $ — $ (1.00) - $ (1.18) $ (1.09) April 2019 - June 2019 Collars Crude Oil 182,000 50.00 - 51.00 50.50 55.00 - 56.00 55.50 April 2019 - September 2019 Basis Swap Crude Oil 366,000 (6.20) - (7.60) (6.90) April 2019 - December 2019 Basis Swap Natural Gas 7,012,500 (1.05) - (1.40) (1.18) April 2019 - December 2019 Basis Swap Crude Oil 1,464,000 (0.98) - (6.50) (3.95) April 2019 - December 2019 Collars Crude Oil 2,475,000 50.00 - 58.00 53.76 55.20 - 63.00 60.41 April 2019 - December 2019 Collars Natural Gas 6,600,000 2.52 - 2.70 2.60 3.00 - 3.10 3.01 April 2019 - December 2019 Swap Natural Gas Liquid 1,100,000 29.08 - 30.15 29.33 April 2019 - December 2019 WTI NYMEX ROLL Crude Oil 1,375,000 0.35 0.35 April 2019 - December 2019 Swap Crude Oil 483,967 56.80 56.80 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 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 January 2020 - December 2020 Swap Crude Oil 620,549 56.80 56.80 January 2021 - December 2021 Swap Crude Oil 611,537 56.80 56.80 January 2022 - March 2022 Swap Crude Oil 152,104 56.80 56.80 December 31, 2018 Floors Ceilings Basis Differential Volume in Price / Weighted Price / Weighted Price / Weighted Mmbtu’s/ Price Average Price Average Price Average Period Instrument Commodity Bbl’s Range Price Range Price Range Price January 2019 - March 2019 Calls Crude Oil 1,350,000 $ — $ — $ 62.64 $ 62.64 $ — $ — January 2019 - March 2019 Calls Crude Oil (1,350,000) 58.64 58.64 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - June 2019 Collars Crude Oil 181,000 51.00 51.00 56.00 56.00 January 2019 - September 2019 Basis Swap Crude Oil 546,000 (6.20) - (7.60) (6.90) January 2019 - December 2019 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
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 March 31, 2019 and December 31, 2018 (in thousands): Derivative Assets Derivative Liabilities Offsetting of Derivative Assets and Liabilities March 31, 2019 December 31, 2018 March 31, 2019 December 31, 2018 Gross Amounts Presented in the Consolidated Balance Sheet $ 16,067 $ 69,717 $ (27,427) $ (12,907) Amounts Not Offset in the Consolidated Balance Sheet (12,807) (10,263) 12,807 10,263 Net Amount $ 3,260 $ 59,454 $ (14,620) $ (2,644)

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	3 Months Ended
	Mar. 31, 2019
ASSET RETIREMENT OBLIGATIONS
Schedule of activity related to ARO liability	The Company recorded the following activity related to its ARO liability for the period indicated below (inclusive of the current portion) (in thousands): Liability for asset retirement obligations as of December 31, 2018 $ 6,914 Liabilities settled and divested (229) Additions 186 Accretion expense 100 Liability for asset retirement obligations as of March 31, 2019 $ 6,971

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	3 Months Ended
	Mar. 31, 2019
COMMITMENTS AND CONTINGENCIES
Schedule of active drilling rig commitments	As of March 31, 2019, the Company has the following active drilling rig commitments (in thousands): March 31, 2019 Remaining period in 2019 $ 1,321 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 1,321
Schedule of rig termination commitments	As of March 31, 2019, the Company has the following rig termination commitments (in thousands): March 31, 2019 Remaining period in 2019 $ — 2020 3,000 2021 — 2022 — 2023 — Thereafter — Total $ 3,000
Schedule of purchase commitments related to equipment	As of March 31, 2019, the Company has the following purchase commitments related to equipment (in thousands): March 31, 2019 Remaining period in 2019 $ 7,997 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 7,997

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	3 Months Ended
	Mar. 31, 2019
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): Three Months Ended March 31, 2019 2018 Basic: Net income (loss) $ (336,559) $ (2,598) Weighted average basic number of common shares outstanding 158,549 153,884 Basic net income (loss) per share of common stock $ (2.12) $ (0.02) Diluted: Net income (loss) $ (336,559) $ (2,598) Weighted average basic number of common shares outstanding 158,549 153,884 Common stock equivalent shares representing shares issuable upon: Exercise of stock options Anti-dilutive Anti-dilutive Exercise of warrants Anti-dilutive Anti-dilutive Vesting of restricted shares Anti-dilutive Anti-dilutive Weighted average diluted number of common shares outstanding 158,549 153,884 Diluted net income (loss) per share of common stock $ (2.12) $ (0.02)

ADDITIONAL FINANCIAL STATEMEN_2

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2019
ADDITIONAL FINANCIAL STATEMENT INFORMATION
Schedule of additional financial statement information, balance sheet	Certain balance sheet amounts are comprised of the following (in thousands): March 31, December 31, 2019 2018 Accounts receivable: Oil, natural gas and natural gas liquids revenues $ 30,705 $ 26,432 Joint interest accounts 7,470 7,369 Other 3,224 1,917 $ 41,399 $ 35,718 Prepaids and other: Prepaids $ 3,646 $ 3,503 Income tax receivable 1,250 1,250 Debt issuance costs 976 — Other 2,768 35 $ 8,640 $ 4,788 Funds in escrow and other: Funds in escrow $ 573 $ 570 Other 562 1,611 $ 1,135 $ 2,181 Accounts payable and accrued liabilities: Trade payables $ 55,668 $ 68,959 Accrued oil and natural gas capital costs 40,492 41,461 Revenues and royalties payable 20,241 20,526 Accrued interest expense 6,343 16,971 Accrued employee compensation 2,729 3,421 Accrued lease operating expenses 11,152 6,292 Other 391 218 $ 137,016 $ 157,848

FINANCIAL STATEMENT PRESENTAT_3

FINANCIAL STATEMENT PRESENTATION (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)segment	Mar. 31, 2018USD ($)
Basis of Presentation and Principles of Consolidation
Number of operating segments | segment	1
Allowance for doubtful accounts | $	$ 0.1	$ 0.2

FINANCIAL STATEMENT PRESENTAT_4

FINANCIAL STATEMENT PRESENTATION - Ability to Continue as a Going Concern (Details) - Senior revolving credit facility - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Current borrowing capacity	$ 225	$ 275
Amount outstanding	105
Outstanding indebtedness in case of default	$ 730

FINANCIAL STATEMENT PRESENTAT_5

FINANCIAL STATEMENT PRESENTATION - Other Operating Property and Equipment (Details)	3 Months Ended
	Mar. 31, 2019
Gas gathering systems
Other operating property and equipment
Estimated useful lives	30 years
Gas treating systems
Other operating property and equipment
Estimated useful lives	20 years
Buildings
Other operating property and equipment
Estimated useful lives	20 years
Automobiles
Other operating property and equipment
Estimated useful lives	3 years
Computers
Other operating property and equipment
Estimated useful lives	3 years
Computer software
Other operating property and equipment
Estimated useful lives	5 years
Fixtures, furniture and equipment
Other operating property and equipment
Estimated useful lives	5 years
Trailers
Other operating property and equipment
Estimated useful lives	7 years
Heavy equipment | Minimum
Other operating property and equipment
Estimated useful lives	8 years
Heavy equipment | Maximum
Other operating property and equipment
Estimated useful lives	10 years

FINANCIAL STATEMENT PRESENTAT_6

FINANCIAL STATEMENT PRESENTATION - Restructuring (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)employee
Restructuring
Number of executives resigned | employee	4
Severance Costs | $	$ 11.3

FINANCIAL STATEMENT PRESENTAT_7

FINANCIAL STATEMENT PRESENTATION - Related Party Transactions (Details) - USD ($) $ in Millions	Jul. 27, 2018	Nov. 16, 2017	Mar. 31, 2019
Chairman, Chief Executive Officer and President
Related Party Transactions
Amount incurred			$ 0.2
SCM Crude, LLC
Related Party Transactions
Term	15 years
Amount earned			39.2
Receivable from related party			11.2
Minimum percentage of funds controlled by related party	10.00%
Salt Creek Midstream, LLC
Related Party Transactions
Term		15 years
Amount earned			0.2
Receivable from related party			0.8
Minimum percentage of funds controlled by related party		10.00%
Cima
Related Party Transactions
Amount incurred			0.3
Cima | Accounts payable and accrued liabilities
Related Party Transactions
Amount payable			$ 0.2

LEASES (Details)

LEASES (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Other noncurrent assets:
Operating lease right of use assets	$ 4,879	$ 5,462
Current liabilities:
Accounts payable and accrued liabilities	137,016	157,763	$ 157,848
Operating lease liabilities	1,868	2,103
Other noncurrent liabilities:
Operating lease liabilities	$ 3,095	3,444
Lessee, Operating Lease, Existence of Option to Extend [true/false]	true
Renewal term	1 year
Lease cost
Operating lease costs	$ 644
Short-term lease costs	5,718
Variable lease costs	425
Total lease costs	6,787
Other information
Operating cash flows from operating leases	1,229
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 5,462
Weighted-average remaining lease term - operating leases	3 years 7 months 6 days
Weighted-average discount rate - operating leases	4.83%
Minimum
Other noncurrent liabilities:
Initial lease term	1 year
Maximum
Other noncurrent liabilities:
Initial lease term	5 years
As reported under ASC 840 | Leases
Current liabilities:
Accounts payable and accrued liabilities			$ 157,848
Impact of adoption of ASC 842 | Leases
Other noncurrent assets:
Operating lease right of use assets		5,462
Current liabilities:
Accounts payable and accrued liabilities		(85)
Operating lease liabilities		2,103
Other noncurrent liabilities:
Operating lease liabilities		$ 3,444

LEASES - Reported under ASC 842

LEASES - Reported under ASC 842 and ASC 840 (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Future minimum lease payments for non-cancellable operating leases
Remaining period in 2019	$ 1,672
2020	1,360
2021	876
2022	574
2023	585
Thereafter	345
Total operating lease payment	5,412
Less: discount to present value	449
Total operating lease liabilities	4,963
Less: current operating lease liabilities	1,868	$ 2,103
Noncurrent operating lease liabilities	$ 3,095	$ 3,444
Prior to the adoption of ASC 842, future obligations for non-cancellable operating leases
2019			$ 3,792
2020			2,350
2021			1,899
2022			968
2023			999
Thereafter			599
Total operating lease payments			$ 10,607

OPERATING REVENUES - Revenue Re

OPERATING REVENUES - Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	$ 51,923	$ 49,100
Other	(7)	155
Total operating revenues	51,916	49,255
Oil
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	45,517	43,069
Natural gas
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	1,461	2,319
Natural gas liquids
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	4,945	$ 3,712
Accounts receivable
Disaggregation of operating revenue
Due from contracts with customers	$ 30,700		$ 26,400

ACQUISITIONS AND DIVESTITURES -

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

ACQUISITIONS AND DIVESTITURES-M

ACQUISITIONS AND DIVESTITURES-Monument Draw Assets (Details) $ in Millions	Jan. 09, 2018USD ($)
Northern Tract | Ward County Assets
ACQUISITIONS AND DIVESTITURES
Purchase price	$ 108.2

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES - Water Infrastructure Assets (Details) - Water Infrastructure Assets - Purchase and Sale Agreement - USD ($) $ in Millions	Dec. 20, 2018	Oct. 01, 2018	Mar. 31, 2019	Mar. 31, 2019
ACQUISITIONS AND DIVESTITURES
Sale price of asset in cash	$ 211.9
Incentives payable per year if certain thresholds are met		$ 25
Deferred period of sale price based on certain thresholds		5 years
(Gain) loss on sale of Water Assets
ACQUISITIONS AND DIVESTITURES
Gain (loss) from sale of other operating property and equipment			$ 0.9	$ 118.1

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Details) $ in Thousands	Mar. 31, 2018$ / MMBTU$ / bbl	Sep. 07, 2017USD ($)subsidiary	Mar. 31, 2019USD ($)$ / MMBTU$ / bbl	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Ceiling Limitation Disclosures
First day average of the (WTI) crude oil spot price (in dollars per barrel) | $ / bbl	53.49		63.06
First day average of the Henry Hub natural gas price (in dollars per Mmbtu) | $ / MMBTU	3		3.07
Book value of oil and natural gas properties exceeding ceiling limit			$ 275,200
Book value of oil and natural gas properties exceeding ceiling limit after tax			217,400
Unevaluated property cost of Hackberry draw area transferred to full cost pool			$ 51,000
Percentage of ownership interest sold		100.00%
No of subsidiaries whose ownership interest sold | subsidiary		2
Adjusted sale price		$ 1,390,000
Gain (loss) from sale of other operating property and equipment				$ (3,679)	$ 485,900

DEBT (Details)

DEBT (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Feb. 16, 2017
Current and long-term debt
Long-term debt, current	$ 105,000
Long-term debt, non-current	613,493	$ 613,105
Debt	718,493	613,105
Unamortized debt issuance costs	10,700	11,100
8.625% senior secured second lien notes due 2020
Current and long-term debt
Interest rate (as a percent)			8.625%
6.75% senior notes due 2025
Current and long-term debt
Long-term debt, non-current	$ 613,493	$ 613,105
Interest rate (as a percent)	6.75%	6.75%	6.75%
Unamortized discount	$ 7,000	$ 7,200
Unamortized premium related to debt issued	5,200	5,400
Additional 2025 Notes
Current and long-term debt
Unamortized debt issuance costs	9,700	$ 10,100
Unamortized premium related to debt issued	5,200
Senior revolving credit facility
Current and long-term debt
Long-term debt, current	$ 105,000

DEBT - Senior Facility (Details

DEBT - Senior Facility (Details) $ in Millions	May 08, 2019USD ($)	Feb. 15, 2019	Sep. 07, 2017USD ($)item	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Senior revolving credit facility
Current and long-term debt
Maximum borrowing capacity			$ 1,000
Current borrowing capacity				$ 225	$ 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				105
Letters of credit outstanding				1.8
Borrowing capacity available				$ 118.2
Senior revolving credit facility | Minimum
Current and long-term debt
Current Ratio			1
Eighth Amendment To Senior Credit Agreement | Maximum
Current and long-term debt
Cash balance limit	$ 5
Eighth Amendment To Senior Credit Agreement | ABR - based | Minimum
Current and long-term debt
Applicable margin (as a percent)	1.75%
Eighth Amendment To Senior Credit Agreement | ABR - based | Maximum
Current and long-term debt
Applicable margin (as a percent)	2.75%
Eighth Amendment To Senior Credit Agreement | Euro-dollar based | Minimum
Current and long-term debt
Applicable margin (as a percent)	2.75%
Eighth Amendment To Senior Credit Agreement | Euro-dollar based | Maximum
Current and long-term debt
Applicable margin (as a percent)	3.75%
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending March 31, 2019
Current and long-term debt
Total Net Indebtedness Leverage Ratio initial period		5
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending June 30, 2019
Current and long-term debt
Total Net Indebtedness Leverage Ratio initial period		4.75
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending September 30, 2019
Current and long-term debt
Total Net Indebtedness Leverage Ratio initial period		4.5
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending December 31, 2019
Current and long-term debt
Total Net Indebtedness Leverage Ratio initial period		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 Indebtedness Leverage Ratio initial period		4

DEBT - 6.75% Senior Notes (Deta

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, 2019	Dec. 31, 2018
Current and long-term debt
Accrued interest expense						$ 6,343	$ 16,971
Accrued and unpaid interest		$ 4,100
6.75% senior notes due 2025
Current and long-term debt
Principal amount			$ 850,000		$ 850,000	$ 625,005	$ 625,005
Interest rate (as a percent)					6.75%	6.75%	6.75%
Net proceeds from issuance					$ 834,100
Redemption price of debt instrument (as a percent)		103.00%
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						$ 7,000	$ 7,200
Unamortized premium related to debt issued						5,200	$ 5,400
Additional 2025 Notes
Current and long-term debt
Principal amount	$ 200,000
Net proceeds from issuance	$ 202,400
Issue price as a percentage of par value	103.00%
Unamortized premium related to debt issued						$ 5,200
8.625% senior secured second lien notes due 2020
Current and long-term debt
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

DEBT - Debt Maturities and Debt

DEBT - Debt Maturities and Debt Issuance Costs (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Debt Issuance Costs
Unamortized debt issuance costs	$ 10.7	$ 11.1

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Assets
Asset transfers between levels	$ 0	$ 0
Liabilities
Liability transfers between levels	0	0
Recurring | Total
Assets
Receivables from derivative contracts	16,067	69,717
Liabilities
Liabilities from derivative contracts	27,427	12,907
Recurring | Level 2
Assets
Receivables from derivative contracts	16,067	69,717
Liabilities
Liabilities from derivative contracts	$ 27,427	$ 12,907

FAIR VALUE MEASUREMENTS - Estim

FAIR VALUE MEASUREMENTS - Estimated FV (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Sep. 07, 2017	Feb. 16, 2017
8.625% senior secured second lien notes due 2020
Fair value measurements
Interest rate (as a percent)				8.625%
6.75% senior notes due 2025
Fair value measurements
Interest rate (as a percent)	6.75%	6.75%		6.75%
Principal amount	$ 625,005	$ 625,005	$ 850,000	$ 850,000
Total | 6.75% senior notes due 2025
Fair value measurements
Estimated fair value of debt	$ 376,566	$ 458,210

DERIVATIVE AND HEDGING ACTIVI_3

DERIVATIVE AND HEDGING ACTIVITIES - Number of Contracts (Details) - Derivatives not designated as hedging contracts - Commodity contracts - item	Mar. 31, 2019	Dec. 31, 2018
Derivative and hedging activities
Number of open commodity derivative contracts	56	86
Collars | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts	6	9
Collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	15	31
Basis Swap | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts	7	7
Basis Swap | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	17	26
Put options | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	2	2
Call option | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	2	4
WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	1	1
Swap | Natural gas liquids
Derivative and hedging activities
Number of open commodity derivative contracts	5	6
Swap | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	1

DERIVATIVE AND HEDGING ACTIVI_4

DERIVATIVE AND HEDGING ACTIVITIES - Location in Balance Sheets (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Derivative and hedging activities
Asset derivative contracts	$ 16,067	$ 69,717
Liability derivative contracts	(27,427)	(12,907)
Derivatives not designated as hedging contracts
Derivative and hedging activities
Asset derivative contracts	16,067	69,717
Liability derivative contracts	(27,427)	(12,907)
Derivatives not designated as hedging contracts | Commodity contracts | Current assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	11,223	57,280
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	4,844	12,437
Derivatives not designated as hedging contracts | Commodity contracts | Current liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts	(20,086)	(3,768)
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts	$ (7,341)	$ (9,139)

DERIVATIVE AND HEDGING ACTIVI_5

DERIVATIVE AND HEDGING ACTIVITIES - Realized Unrealized (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative and hedging activities
Total net gain (loss) on derivative contracts	$ (64,799)	$ 5,903
Derivatives not designated as hedging contracts | Commodity contracts | Other Income Expense
Derivative and hedging activities
Unrealized gain (loss) on commodity contracts	(68,169)	11,113,000
Realized gain (loss) on commodity contracts	3,370	(5,210,000)
Total net gain (loss) on derivative contracts	$ (64,799)	$ 5,903,000

DERIVATIVE AND HEDGING ACTIVI_6

DERIVATIVE AND HEDGING ACTIVITIES - Open Contracts (Details) - Commodity contracts	Mar. 31, 2019$ / bblbbl	Dec. 31, 2018MMBTU$ / MMBTU$ / bblbbl
January 2019 - March 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		90,000
Floors (in dollars per Mmbtu's/Bbl's)		46.75
Ceilings (in dollars per Mmbtu's/Bbl's)		51.75
January 2019 - March 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		46.75
Ceilings (in dollars per Mmbtu's/Bbl's)		51.75
January 2019 - March 2019 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,350,000
Ceilings (in dollars per Mmbtu's/Bbl's)		62.64
January 2019 - March 2019 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		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 | $ / MMBTU		(6.20)
January 2019 - September 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential | $ / MMBTU		(7.60)
January 2019 - September 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential | $ / MMBTU		(6.90)
January 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		3,650,000
January 2019 - December 2019 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		50
Ceilings (in dollars per Mmbtu's/Bbl's)		55.20
January 2019 - December 2019 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		58
Ceilings (in dollars per Mmbtu's/Bbl's)		63
January 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		53.87
Ceilings (in dollars per Mmbtu's/Bbl's)		60.07
January 2019 - December 2019 | Collars | Natural gas
Derivative and hedging activities
Volume in Bbl's | bbl		8,760,000
January 2019 - December 2019 | Collars | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		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)		2.70
Ceilings (in dollars per Mmbtu's/Bbl's)		3.10
January 2019 - December 2019 | Collars | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		2.60
Ceilings (in dollars per Mmbtu's/Bbl's)		3.01
January 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		2,448,000
January 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		(0.98)
January 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		(6.50)
January 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(2.80)
January 2019 - December 2019 | Basis Swap | Natural gas
Derivative and hedging activities
Volume in Bbl's | bbl		9,307,500
January 2019 - December 2019 | Basis Swap | Natural gas | Minimum
Derivative and hedging activities
Basis Differential		(1.05)
January 2019 - December 2019 | Basis Swap | Natural gas | Maximum
Derivative and hedging activities
Basis Differential		(1.40)
January 2019 - December 2019 | Basis Swap | Natural gas | Weighted Average
Derivative and hedging activities
Basis Differential		(1.18)
January 2019 - December 2019 | Swap | Natural gas liquids
Derivative and hedging activities
Volume in Bbl's | bbl		1,460,000
January 2019 - December 2019 | Swap | Natural gas liquids | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		29.08
January 2019 - December 2019 | Swap | Natural gas liquids | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		30.15
January 2019 - December 2019 | Swap | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		29.33
January 2019 - December 2019 | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Mmbtu's | MMBTU		1,825,000
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		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) | $ / MMBTU		0.35
April 2019 - June 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	182,000	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 | Minimum
Derivative and hedging activities
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 | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	51
Ceilings (in dollars per Mmbtu's/Bbl's)	56
April 2019 - June 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50.50	50
Ceilings (in dollars per Mmbtu's/Bbl's)	55.50	55
April 2019 - June 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	182,000
April 2019 - June 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(1)
April 2019 - June 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(1.18)
April 2019 - June 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(1.09)
April 2019 - September 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	366,000
April 2019 - September 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(6.20)
April 2019 - September 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(7.60)
April 2019 - September 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(6.90)
April 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,475,000	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 | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50
Ceilings (in dollars per Mmbtu's/Bbl's)	55.20
April 2019 - December 2019 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	58
Ceilings (in dollars per Mmbtu's/Bbl's)	63
April 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	53.76	55
Ceilings (in dollars per Mmbtu's/Bbl's)	60.41	62.85
April 2019 - December 2019 | Collars | Natural gas
Derivative and hedging activities
Volume in Bbl's | bbl	6,600,000
April 2019 - December 2019 | Collars | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	2.52
Ceilings (in dollars per Mmbtu's/Bbl's)	3
April 2019 - December 2019 | Collars | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	2.70
Ceilings (in dollars per Mmbtu's/Bbl's)	3.10
April 2019 - December 2019 | Collars | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	2.60
Ceilings (in dollars per Mmbtu's/Bbl's)	3.01
April 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	1,464,000
April 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(0.98)
April 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(6.50)
April 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(3.95)
April 2019 - December 2019 | Basis Swap | Natural gas
Derivative and hedging activities
Volume in Bbl's | bbl	7,012,500
April 2019 - December 2019 | Basis Swap | Natural gas | Minimum
Derivative and hedging activities
Basis Differential	(1.05)
April 2019 - December 2019 | Basis Swap | Natural gas | Maximum
Derivative and hedging activities
Basis Differential	(1.40)
April 2019 - December 2019 | Basis Swap | Natural gas | Weighted Average
Derivative and hedging activities
Basis Differential	(1.18)
April 2019 - December 2019 | Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	483,967
Floors (in dollars per Mmbtu's/Bbl's)	56.80
April 2019 - December 2019 | Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	56.80
April 2019 - December 2019 | Swap | Natural gas liquids
Derivative and hedging activities
Volume in Bbl's | bbl	1,100,000
April 2019 - December 2019 | Swap | Natural gas liquids | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	29.08
April 2019 - December 2019 | Swap | Natural gas liquids | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	30.15
April 2019 - December 2019 | Swap | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	29.33
April 2019 - December 2019 | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	1,375,000
Floors (in dollars per Mmbtu's/Bbl's)	0.35
April 2019 - December 2019 | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	0.35
July 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	552,000	552,000
July 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	55
July 2019 - December 2019 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55	55
Ceilings (in dollars per Mmbtu's/Bbl's)	69	69
July 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	53	53
Ceilings (in dollars per Mmbtu's/Bbl's)	61	61
July 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		460,000
July 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		(2.40)
July 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		(6.50)
July 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(5.68)
October 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	92,000	92,000
Floors (in dollars per Mmbtu's/Bbl's)	51	51
Ceilings (in dollars per Mmbtu's/Bbl's)	56	56
October 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	51	51
Ceilings (in dollars per Mmbtu's/Bbl's)	56	56
October 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	460,000	460,000
October 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	3.45	3.45
October 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	4	4
October 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	3.72	3.72
October 2019 - December 2019 | Swap | Natural gas liquids
Derivative and hedging activities
Volume in Bbl's | bbl		92,000
Floors (in dollars per Mmbtu's/Bbl's)		32.50
October 2019 - December 2019 | Swap | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		32.50
January 2020 - December 2020 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	549,000	549,000
Floors (in dollars per Mmbtu's/Bbl's)	50	50
Ceilings (in dollars per Mmbtu's/Bbl's)	70	70
January 2020 - December 2020 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50	50
Ceilings (in dollars per Mmbtu's/Bbl's)	70	70
January 2020 - December 2020 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	3,294,000	3,294,000
January 2020 - December 2020 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	2	2
January 2020 - December 2020 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	4	4
January 2020 - December 2020 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	2.95	2.95
January 2020 - December 2020 | Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	620,549
Floors (in dollars per Mmbtu's/Bbl's)	56.80
January 2020 - December 2020 | Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	56.80
January 2020 - December 2020 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,342,400	2,342,400
Ceilings (in dollars per Mmbtu's/Bbl's)	70	70
January 2020 - December 2020 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	70	70
January 2020 - December 2020 | Put options | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	915,000	915,000
Floors (in dollars per Mmbtu's/Bbl's)	55	55
January 2020 - December 2020 | Put options | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55	55
January 2021 - December 2021 | Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	611,537
Floors (in dollars per Mmbtu's/Bbl's)	56.80
January 2021 - December 2021 | Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	56.80
January 2022 - March 2022 | Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	152,104
Floors (in dollars per Mmbtu's/Bbl's)	56.80
January 2022 - March 2022 | Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	56.80

DERIVATIVE AND HEDGING ACTIVI_7

DERIVATIVE AND HEDGING ACTIVITIES - Netting Arrangements (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Derivative Assets
Gross Amounts Presented in the Consolidated Balance Sheet	$ 16,067	$ 69,717
Amounts Not Offset in the Consolidated Balance Sheet	(12,807)	(10,263)
Net Amount	3,260	59,454
Derivative Liabilities
Gross Amounts Presented in the Consolidated Balance Sheet	(27,427)	(12,907)
Amounts Not Offset in the Consolidated Balance Sheet	12,807	10,263
Net Amount	$ (14,620)	$ (2,644)

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Activity related to ARO liability
Liability for asset retirement obligations at the beginning of the period	$ 6,914
Liabilities settled and divested	(229)
Additions	186
Accretion expense	100
Liability for asset retirement obligations at the end of the period	$ 6,971

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)item
Purchase commitments related to equipment
Remaining period in 2019	$ 7,997
Total	7,997
Drilling rig commitments
Obligations under drilling rig commitments
Remaining period in 2019	1,321
Total	1,321
Non-cancelable termination penalties	1,100
Drilling rig commitments	1,300
Rig termination commitments
Obligations under rig termination and stacking fees commitments
2020	3,000
Total	$ 3,000
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

STOCKHOLDERS' EQUITY-Common sto

STOCKHOLDERS' EQUITY-Common stock and warrants (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Feb. 09, 2018	Mar. 31, 2019	Dec. 31, 2018	Sep. 09, 2016
Stockholders' equity
Shares issued	9.2
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001	$ 0.0001
Share price (in dollars per share)	$ 6.90
Net proceeds issuance of common stock	$ 60.4
Equivalent number shares of the warrants				4.7
Warrants Issued to Former Holders of Unsecured and Convertible Notes
Stockholders' equity
Equivalent number shares of the warrants				4.7
Exercise price (in dollars per share)				$ 14.04

STOCKHOLDERS' EQUITY - Incentiv

STOCKHOLDERS' EQUITY - Incentive Plans (Details) shares in Millions, $ in Millions	Apr. 06, 2017shares	Mar. 31, 2019USD ($)employeeshares	Mar. 31, 2018USD ($)	Dec. 31, 2018shares	Sep. 09, 2016shares
Stock-based compensation
Senior executives who departed | employee		4
General and administrative
Stock-based compensation
Compensation expense recorded | $		$ (6.8)	$ 3.6
2016 Incentive Plan
Stock-based compensation
Incremental reduction to stock-based compensation expense | $		$ 8.4
2016 Incentive Plan | Common Stock
Stock-based compensation
Aggregate number of shares available	19				10
Increase in shares available for issuance	9
Number of calculation days for which shares will be available for issuance	20 days
Maximum number of shares that remained reserved for issuance under the Plan		1.1		4.9

STOCKHOLDERS' EQUITY - Stock Op

STOCKHOLDERS' EQUITY - Stock Options (Details) - 2016 Incentive Plan - Stock options $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)shares	Mar. 31, 2018USD ($)$ / sharesshares
Stock-based compensation
Granted (in shares) | shares	0	1,200,000
Granted (in dollars per share) | $ / shares		$ 5.65
Proceeds from exercise of stock options		$ 0.3
Unrecognized compensation expense stock option	$ 1.5	$ 13.1
Weighted average remaining vesting period	9 months 18 days	1 year 2 months 12 days
Employee
Stock-based compensation
Vesting period	3 years
Percentage of awards vesting on the annual anniversary date of the grant	33.33
Expiration term	10 years

STOCKHOLDERS' EQUITY - Restrict

STOCKHOLDERS' EQUITY - Restricted Stock (Details) - 2016 Incentive Plan - Restricted Stock - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Stock-based compensation
Grant date price (in dollars per share)	$ 1.29	$ 5.65
Unrecognized compensation expense other than options	$ 8.2	$ 12.5
Weighted average remaining vesting period	1 year 9 months 18 days	1 year 8 months 12 days
Employees and non-employee directors
Stock-based compensation
Number of shares granted	4.2	1.9
Employee
Stock-based compensation
Vesting period	3 years
Percentage of awards other than options vesting on the annual anniversary date of the grant	33.33%
Non-employee director
Stock-based compensation
Vesting period	6 months

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Basic:
Net income (loss)	$ (336,559)	$ (2,598)
Weighted average basic number of common shares outstanding	158,549	153,884
Basic net income (loss) per share of common share (in dollars per share)	$ (2.12)	$ (0.02)
Diluted:
Net income (loss)	$ (336,559)	$ (2,598)
Weighted average basic number of common shares outstanding	158,549	153,884
Weighted average diluted number of common shares outstanding	158,549	153,884
Diluted net income (loss) per share of common stock (in dollars per share)	$ (2.12)	$ (0.02)
Common stock equivalents excluded from computation of diluted earnings per share of common stock because of anti-dilutive effect	14,900	13,200

ADDITIONAL FINANCIAL STATEMEN_3

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$ 30,705		$ 26,432
Joint interest accounts	7,470		7,369
Other	3,224		1,917
Total	41,399		35,718
Prepaids and other:
Prepaids	3,646		3,503
Income tax receivable	1,250		1,250
Debt issuance costs	976
Other	2,768		35
Total	8,640		4,788
Funds in escrow and other:
Funds in escrow	573		570
Other	562		1,611
Total	1,135		2,181
Accounts payable and accrued liabilities:
Trade payables	55,668		68,959
Accrued oil and natural gas capital costs	40,492		41,461
Revenues and royalties payable	20,241		20,526
Accrued interest expense	6,343		16,971
Accrued employee compensation	2,729		3,421
Accrued lease operating expenses	11,152		6,292
Other	391		218
Total	$ 137,016	$ 157,763	$ 157,848