Battalion Oil (BATL) 10-Q 8 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 02, 2018
Document and Entity Information
Entity Registrant Name	HALCON RESOURCES CORP
Entity Central Index Key	1,282,648
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
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		160,669,329
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Oil, natural gas and natural gas liquids sales:
Other	$ 350	$ 363	$ 613	$ 1,386
Total operating revenues	61,595	96,953	166,265	352,688
Production:
Lease operating	5,275	17,798	15,504	58,822
Workover and other	1,478	3,644	4,795	22,213
Taxes other than income	3,557	6,846	9,812	29,149
Gathering and other	18,404	10,886	30,782	34,640
Restructuring		1,275	128	2,080
General and administrative	19,731	39,195	49,196	86,966
Depletion, depreciation and accretion	20,310	35,940	52,397	100,788
(Gain) loss on sale of oil and natural gas properties	1,331	(491,830)	7,235	(727,520)
Total operating expenses	70,086	(376,246)	169,849	(392,862)
Income (loss) from operations	(8,491)	473,199	(3,584)	745,550
Other income (expenses):
Net gain (loss) on derivative contracts	(60,406)	(22,415)	(66,603)	28,139
Interest expense and other	(12,940)	(19,330)	(30,522)	(63,808)
Gain (loss) on extinguishment of debt		(29,167)		(86,065)
Total other income (expenses)	(73,346)	(70,912)	(97,125)	(121,734)
Income (loss) before income taxes	(81,837)	402,287	(100,709)	623,816
Income tax benefit (provision)		17,000		5,000
Net income (loss)	(81,837)	419,287	(100,709)	628,816
Non-cash preferred dividend				(48,007)
Net income (loss) available to common stockholders	$ (81,837)	$ 419,287	$ (100,709)	$ 580,809
Net income (loss) per share of common stock:
Basic (in dollars per share)	$ (0.52)	$ 2.85	$ (0.64)	$ 4.56
Diluted (in dollars per share)	$ (0.52)	$ 2.82	$ (0.64)	$ 4.52
Weighted average common shares outstanding:
Basic (in shares)	158,011	146,944	156,628	127,458
Diluted (in shares)	158,011	148,490	156,628	128,410
Total oil, natural gas and natural gas liquids sales
Oil, natural gas and natural gas liquids sales:
Total operating revenues	$ 61,245	$ 96,590	$ 165,652	$ 351,302
Oil
Oil, natural gas and natural gas liquids sales:
Total operating revenues	53,918	88,256	145,743	319,472
Natural gas
Oil, natural gas and natural gas liquids sales:
Total operating revenues	1,407	2,886	5,286	15,051
Natural gas liquids
Oil, natural gas and natural gas liquids sales:
Total operating revenues	$ 5,920	$ 5,448	$ 14,623	$ 16,779

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 137	$ 424,071
Accounts receivable	46,764	36,416
Receivables from derivative contracts	16,553	677
Prepaids and other	10,969	10,628
Total current assets	74,423	471,792
Oil and natural gas properties (full cost method):
Evaluated	1,362,136	877,316
Unevaluated	982,922	765,786
Gross oil and natural gas properties	2,345,058	1,643,102
Less - accumulated depletion	(617,075)	(570,155)
Net oil and natural gas properties	1,727,983	1,072,947
Other operating property and equipment:
Other operating property and equipment	188,321	101,282
Less - accumulated depreciation	(9,136)	(4,092)
Net other operating property and equipment	179,185	97,190
Other noncurrent assets:
Receivables from derivative contracts	2,794
Funds in escrow and other	1,915	1,691
Total assets	1,986,300	1,643,620
Current liabilities:
Accounts payable and accrued liabilities	141,377	131,087
Liabilities from derivative contracts	86,176	19,248
Current portion of asset retirement obligation	149
Total current liabilities	227,702	150,335
Long-term debt, net	667,726	409,168
Other noncurrent liabilities:
Liabilities from derivative contracts	37,459	7,751
Asset retirement obligations	6,963	4,368
Commitments and contingencies (Note 9)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 160,676,356 and 149,379,491 shares issued and outstanding as of September 30, 2018 and December 31, 2017, respectively	16	15
Additional paid-in capital	1,091,441	1,016,281
Retained earnings (accumulated deficit)	(45,007)	55,702
Total stockholders' equity	1,046,450	1,071,998
Total liabilities and stockholders' equity	$ 1,986,300	$ 1,643,620

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2018	Dec. 31, 2017
Stockholders' equity:
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares issued	160,676,356	149,379,491
Common stock, shares outstanding	160,676,356	149,379,491

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Preferred Stock	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Total
Balances at Dec. 31, 2016		$ 9	$ 592,663	$ (479,984)	$ 112,688
Balances (in shares) at Dec. 31, 2016		92,991
Increase (Decrease) in Stockholders' Equity
Net income (loss)				189,352	189,352
Sale of preferred stock			352,048		352,048
Sale of preferred stock (in shares)	6
Preferred beneficial conversion feature			48,007		48,007
Offering costs			(11,829)		(11,829)
Long-term incentive plan forfeitures (in shares)		(41)
Reduction in shares to cover individuals' tax withholding			(17)		(17)
Reduction in shares to cover individuals' tax withholding (in shares)		(2)
Stock-based compensation			8,539		8,539
Balances at Mar. 31, 2017		$ 9	989,411	(290,632)	698,788
Balances (in shares) at Mar. 31, 2017	6	92,948
Balances at Dec. 31, 2016		$ 9	592,663	(479,984)	112,688
Balances (in shares) at Dec. 31, 2016		92,991
Increase (Decrease) in Stockholders' Equity
Net income (loss)					628,816
Balances at Sep. 30, 2017		$ 15	1,013,141	148,832	1,161,988
Balances (in shares) at Sep. 30, 2017		149,666
Balances at Mar. 31, 2017		$ 9	989,411	(290,632)	698,788
Balances (in shares) at Mar. 31, 2017	6	92,948
Increase (Decrease) in Stockholders' Equity
Net income (loss)				20,177	20,177
Conversion of preferred stock		$ 6	(6)
Conversion of preferred stock (in shares)	(6)	55,180
Offering costs			(90)		(90)
Long-term incentive plan grants (in shares)		2,022
Long-term incentive plan forfeitures (in shares)		(48)
Stock-based compensation			13,154		13,154
Balances at Jun. 30, 2017		$ 15	1,002,469	(270,455)	732,029
Balances (in shares) at Jun. 30, 2017		150,102
Increase (Decrease) in Stockholders' Equity
Net income (loss)				419,287	419,287
Long-term incentive plan forfeitures (in shares)		(143)
Reduction in shares to cover individuals' tax withholding			(1,828)		(1,828)
Reduction in shares to cover individuals' tax withholding (in shares)		(293)
Stock-based compensation			12,500		12,500
Balances at Sep. 30, 2017		$ 15	1,013,141	148,832	1,161,988
Balances (in shares) at Sep. 30, 2017		149,666
Increase (Decrease) in Stockholders' Equity
Net income (loss)				(93,130)	(93,130)
Long-term incentive plan forfeitures (in shares)		(266)
Reduction in shares to cover individuals' tax withholding			(150)		(150)
Reduction in shares to cover individuals' tax withholding (in shares)		(21)
Stock-based compensation			3,290		3,290
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
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)					(100,709)
Balances at Sep. 30, 2018		$ 16	1,091,441	(45,007)	1,046,450
Balances (in shares) at Sep. 30, 2018		160,676
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

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income (loss)	$ (100,709)	$ 628,816
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	52,397	100,788
(Gain) loss on sale of oil and natural gas properties	7,235	(727,520)
Stock-based compensation, net	12,241	33,548
Unrealized loss (gain) on derivative contracts	77,524	(11,010)
Amortization of deferred loan costs	1,022	1,306
Amortization of discount and premium	235	2,358
Loss (gain) on extinguishment of debt		86,065
Accrued settlements on derivative contracts	3,292	(673)
Other income (expense)	(1,978)	(4,132)
Change in assets and liabilities:
Accounts receivable	(7,498)	37,950
Prepaids and other	(341)	(5,231)
Accounts payable and accrued liabilities	(6,711)	(40,043)
Net cash provided by (used in) operating activities	36,709	102,222
Cash flows from investing activities:
Oil and natural gas capital expenditures	(369,304)	(218,880)
Proceeds received from sale of oil and natural gas properties	1,647	1,901,578
Acquisition of oil and natural gas properties	(333,470)	(916,676)
Acquisition of other operating property and equipment		(25,538)
Other operating property and equipment capital expenditures	(79,389)	(25,474)
Proceeds received from sale of other operating property and equipment	2,236	21,291
Funds held in escrow and other	153	1,459
Net cash provided by (used in) investing activities	(778,127)	737,760
Cash flows from financing activities:
Proceeds from borrowings	293,000	1,349,000
Repayments of borrowings	(32,000)	(1,497,826)
Cash payments to Noteholders		(70,903)
Debt issuance costs	(4,013)	(17,220)
Preferred stock issued		400,055
Common stock issued	63,480
Offering costs and other	(2,983)	(13,765)
Net cash provided by (used in) financing activities	317,484	149,341
Net increase (decrease) in cash and cash equivalents	(423,934)	989,323
Cash and cash equivalents at beginning of period	424,071	24
Cash and cash equivalents at end of period	137	989,347
Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$ 2,519	(28,481)
Accretion of non-cash preferred dividend		$ 48,007

FINANCIAL STATEMENT PRESENTATIO

FINANCIAL STATEMENT PRESENTATION	9 Months Ended
	Sep. 30, 2018
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 1, 2018. Please refer to the notes in the 2017 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 the Company’s management, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of the fair values of assets acquired and liabilities assumed in connection with the Pecos County Acquisition and the fair value of assets sold in connection with the Williston Divestiture and the El Halcón Divestiture (see Note 3, “Acquisitions and Divestitures, ” for information on the Pecos County Acquisition, the Williston Divestiture and the El Halcón Divestiture), including the gains on sales recorded and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s 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. 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 September 30, 2018 and December 31, 2017, allowances for doubtful accounts were approximately $0.1 million and $0.7 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 and water gathering systems, thirty years; water disposal and recycling facilities, gas treating systems and buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, the lesser of the 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. Income Taxes On December 22, 2017, Staff Accounting Bulletin No. 118 (SAB 118) was issued to address the application of accounting principles generally accepted in the United States in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Cuts Job Act of 2017. In accordance with SAB 118, the Company has determined that the $280.9 million income tax provision and corresponding decrease in the Company's valuation allowance was a provisional amount and a reasonable estimate for the year ended December 31, 2017. Any subsequent adjustments to these amounts will be recorded to current tax benefit (provision) in the fourth quarter of 2018, when the analysis is complete. Related Party Transactions 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 natural gas 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 and nine months ended September 30, 2018, the Company received zero and $0.4 million from Salt Creek under the gas purchase and processing agreement. Certain funds under the control of Ares Management LLC (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 common 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, also serves on the board of directors of Salt Creek’s parent company. Crude Oil Gathering Agreement On July 27, 2018, a subsidiary of the Company entered into a crude oil gathering agreement with SCM Crude, LLC (SCM) pursuant to which the Company agreed to dedicate, for a term of 15 years, production of crude oil from its currently owned, or later acquired acreage in designated areas in Ward and Winkler Counties, Texas (excluding certain specific wells) for the receipt, gathering and transportation on a gathering system to be designed, engineered and constructed by SCM. The gathering system is expected to be operational by December 31, 2018. The agreement with SCM was the culmination of a lengthy process during which the Company analyzed the most effective method of gathering and transportation of its future oil production in these areas. During the course of its investigation, the Company considered a variety of alternatives and solicited and received numerous third party proposals. The Company received and evaluated proposals from eleven companies covering some or all of its oil production in the region and determined that among the proposals it received, SCM’s was superior for economic and strategic reasons. Because certain funds under the control of Ares are the majority owners and controlling parties of SCM, the Audit Committee of the board of directors of the Company and the disinterested members of the Company’s board of directors evaluated and approved (in a vote that excluded the Company director who is employed by Ares) the process by which the Company determined the SCM proposal to be superior to other alternatives, as well as the principal terms of the agreement, in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company’s website at www.halconresources.com ) and the Company’s procedures for the review and approval of transactions with related parties. Ares also controls other funds which own in excess of ten percent (10%) of the common stock of the Company. No Ares fund that is a stockholder of the Company has an interest in SCM but one of the Company’s directors, who is employed by Ares, also serves on the board of directors of SCM’s parent company. Charter of Aircraft In the ordinary course of its business, the Company occasionally charters a private aircraft for business use. Floyd C. Wilson, Halcón's Chairman, Chief Executive Officer and President, owns an aircraft which the Company has chartered from time to time. For a portion of 2017, Mr. Wilson's aircraft was managed by an independent air charter company unaffiliated with both Mr. Wilson and Halcón. The aircraft in the air charter company's fleet are available to the public for charter based upon a standard fee schedule established by the air charter company, with the fees dependent primarily upon the type and size of the aircraft utilized and the duration of the flight. Because the air charter company established fees for the use of the aircraft in its fleet, Mr. Wilson did not receive any greater benefit from Halcón's charter of the aircraft indirectly owned by him than he would have if any third party were to charter the aircraft. During the course of 2017, Mr. Wilson terminated the independent air charter company and removed his aircraft from the charter company's fleet, pending his search for a new charter company to manage his aircraft. During the search period for a new charter company, fees for the use of Mr. Wilson's aircraft by the Company were based upon comparable costs that the Company would have incurred in chartering the same type and size of aircraft from an independent third party utilizing data from several independent third party aircraft leasing companies. The terms for this use were evaluated and approved by the Audit Committee of the Company, and subsequently by the disinterested members of the Company's board of directors upon the recommendation of the Audit Committee, in accordance with the Company's procedures for the review and approval of transactions with related parties. During the three and nine months ended September 30, 2018, the Company paid approximately $0.2 million and $0.8 million, respectively, to Mr. Wilson for the Company use of the aircraft. As of September 30, 2018, the Company recorded a $0.1 million payable to Mr. Wilson. The payable is recorded in "Accounts payable and accrued liabilities , " on the Company's unaudited condensed consolidated balance sheet. Recently Issued Accounting Pronouncements In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). For public business entities, ASU 2017-01 is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2017. The amendments in this ASU should be applied prospectively on or after the effective date. The ASU was issued to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The Company applied the provisions of ASU 2017-01 to the acquisition of the West Quito Draw Properties, which is discussed further in Note 3, “Acquisitions and Divestitures . ” In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) (ASU 2016-15). For public business entities, ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and early adoption is permitted. The areas for simplification in this ASU involve addressing eight specific classification issues in the statement of cash flows. An entity should apply the amendments in this ASU using a retrospective transition method. The adoption of ASU 2016-15 did not have an impact on the Company’s unaudited condensed consolidated statement of cash flows. In February 2016, the FASB issued 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 and early adoption is permitted. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In January 2018, ASU 2016-02 was updated with ASU No. 2018-01, Lease (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842 (ASU 2018-01), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases . An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. An entity that does not elect this practical expedient should evaluate all existing or expired land easements in connection with the adoption of the new lease requirements in Topic 842 to assess whether they meet the definition of a lease. In July 2018, ASU 2016-02 was updated with ASU No. 2018-11, Targeted Improvements to ASC 842 , which provides entities with relief from the costs of implementing certain aspects of the new leasing standard. Specifically, under the amendments in ASU 2018-11, (1) entities may elect not to recast the comparative periods presented when transitioning to ASC 842 and (2) lessors may elect not to separate lease and nonlease components when certain conditions are met. Before ASU 2018-11 was issued, transition to the new lease standard required application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. As of September 30, 2018, the Company had approximately $18.5 million of contractual obligations related to its non-cancelable leases and drilling contracts, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under the new leasing standard. In addition, the Company is implementing an accounting software solution to facilitate compliance with the new lease accounting requirements, as well as continuing to analyze its processes and internal controls surrounding its leases. At this time, the Company cannot reasonably estimate the financial statement impact of the adoption of ASU 2016-02; however, the unaudited condensed consolidated balance sheets will be impacted due to the recognition of right-of-use assets and lease liabilities that are not recognized under the current lease accounting guidance. The Company will adopt ASU 2016-02 on January 1, 2019. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08, and collectively with ASU 2014-09, ASC 606), which provides further clarification on the principal versus agent evaluation. The Company adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. See Note 2, “ Operating Revenues ,” for further details.

OPERATING REVENUES

OPERATING REVENUES	9 Months Ended
	Sep. 30, 2018
OPERATING REVENUES
OPERATING REVENUES	2. OPERATING REVENUES Adoption of ASC 606, Revenue from Contracts with Customers On January 1, 2018, the Company adopted ASC 606 using the modified retrospective approach applied to all contracts as of the date of adoption. Reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported under the accounting standards in effect for those periods. The adoption of ASC 606 resulted in offsetting changes to revenues and expenses associated with certain natural gas gathering and processing agreements, and therefore there was no cumulative effect of applying ASC 606 to the opening balance of “ Retained earnings (accumulated deficit) .” The net impact of adopting ASC 606 for the three and nine months ended September 30, 2018 was a decrease of $0.2 million and $0.6 million to “ Natural gas ” and an offsetting decrease of $0.2 million and $0.6 million to “Gathering and other , ” respectively, on the unaudited condensed consolidated statements of operations. These changes result from principal versus agent considerations under ASC 606 for the Company's natural gas gathering and processing arrangements in place with midstream companies. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity's processing plant, the Company is the principal and the midstream entity is the agent in the sale transaction with the third party purchaser of processed commodities. In these instances, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers through the gathering and treating process and presented as " Natural gas " or " Natural gas liquids " and any fees incurred to gather or process the natural gas are presented as " Gathering and other ." Revenue Recognition Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Because the Company's performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $37.1 million and $24.1 million as of September 30, 2018 and December 31, 2017, respectively, as "Accounts receivable" on the unaudited condensed consolidated balance sheets. Substantially all of the Company’s revenues are derived from its single basin operations, the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. The following table disaggregates the Company’s revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company's single basin operations, for the periods indicated (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 (1) 2018 2017 (1) Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 53,918 $ 88,256 $ 145,743 $ 319,472 Natural gas 1,407 2,886 5,286 15,051 Natural gas liquids 5,920 5,448 14,623 16,779 Total oil, natural gas and natural gas liquids sales 61,245 96,590 165,652 351,302 Other 350 363 613 1,386 Total operating revenues $ 61,595 $ 96,953 $ 166,265 $ 352,688 (1) As noted above, prior period amounts have not been adjusted under the modified retrospective method of adoption. Oil Sales The Company generally markets its crude oil production directly to the customer using two methods. Under the first method, crude oil is sold at the wellhead at an index price adjusted for pricing differentials and other deductions. Revenue is recognized at the wellhead, where control of the crude oil transfers to the customer, at the net price received. Under the second method, crude oil is delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, net of transportation costs and other market-related adjustments. Revenue is recognized when control of the crude oil transfers at the delivery point at the net price received. Settlement statements for the Company's crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded. Payment under the Company's crude oil contracts is typically due on or before the 20 th of the month following the delivery month. Natural Gas and Natural Gas Liquids Sales The Company evaluates its natural gas gathering and processing arrangements in place with midstream companies to determine when control of the natural gas is transferred. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are treated as a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity's processing plant, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers, and therefore any fees incurred to gather or process the natural gas are presented separately as " Gathering and other ." Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity's processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as " Gathering and other ." Settlement statements for the Company's natural gas and natural gas liquids production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. Historically, differences between the Company's estimates and the actual revenue received have not been material. Payment under the Company's natural gas gathering and processing contracts is typically due on or before the fifth day of the second month following the delivery month. Concentrations of Credit Risk The purchasers of the Company's oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. For the nine months ended September 30, 2018, two individual purchasers of the Company's production, Sunoco, Inc. and Western Refining, Inc., each accounted for more than 10% of total sales, collectively representing 81% of the Company's total sales for the period. In 2017, two individual purchasers of the Company's production, Crestwood Midstream Partners, formerly Arrow Field Services, LLC, and Suncor Energy Marketing, Inc., each accounted for more than 10% of total sales, collectively representing 58% of the Company's total sales for the year. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company's joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company's joint interest partners to reimburse the Company could be adversely affected. Practical Expedients The Company does not disclose the transaction price of unsatisfied performance obligations for i) contracts with an original expected duration of one year or less and ii) contracts where variable consideration is allocated entirely to a wholly unsatisfied performance obligation (each unit of product typically represents a separate performance obligation, and therefore, future volumes under the Company’s long-term contracts are wholly unsatisfied).

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	9 Months Ended
	Sep. 30, 2018
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES	3. ACQUISITIONS AND DIVESTITURES Acquisitions West Quito Draw Properties On February 6, 2018, a wholly owned subsidiary of the Company entered into a Purchase and Sale Agreement (the Shell PSA) with SWEPI LP (Shell), an affiliate of Shell Oil Company, pursuant to which the Company purchased acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) for a total adjusted purchase price of $198.5 million. The effective date of the acquisition was February 1, 2018, and the Company closed the transaction on April 4, 2018. The Company funded the cash consideration for the acquisition of the West Quito Draw Properties with the net proceeds from the issuance of the Additional 2025 Notes and common stock, which are discussed in Note 5, " Long-term Debt ," and Note 10, " Stockholders' Equity ," respectively. Monument Draw Assets (Ward and Winkler Counties, Texas) On December 9, 2016, the Company entered into an agreement with a private company, pursuant to which the Company acquired the rights to purchase acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations for an initial purchase price of $11,000 per acre. The Ward County Assets are divided into two tracts (the Southern Tract and the Northern Tract) with separate options for each tract. The agreement was subsequently amended on June 14, 2017 to increase the purchase price of the Southern Tract and the Northern Tract acreage, from $11,000 per acre to $13,000 per acre, for rights to additional depths in the acreage under option. Pursuant to the terms of the agreement, on June 15, 2017, the Company purchased the Southern Tract acreage for approximately $87.4 million and on January 9, 2018, the Company purchased the Northern Tract acreage for approximately $108.2 million. Acquisition of Additional Properties in Monument Draw (Ward and Winkler Counties, Texas) On December 13, 2017, the Company acquired undeveloped acreage and related assets in the Delaware Basin, in an area contiguous to the western and southern areas of the Company’s existing Monument Draw properties in Ward County, Texas from a private company, for a total adjusted cash purchase price of $101.8 million. The effective date of the acquisition was September 1, 2017. Hackberry Draw Assets (Pecos and Reeves Counties, Texas) On January 18, 2017, Halcón Energy Properties, Inc., a wholly owned subsidiary of the Company, entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which it acquired acreage and related assets in the Hackberry Draw area of the Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total adjusted purchase price of $699.2 million (the Pecos County Acquisition). The Pecos County Acquisition closed on February 28, 2017. The transaction had an effective date of November 1, 2016. The Company funded the Pecos County Acquisition with the net proceeds from the private placement of new 8% automatically convertible preferred stock and borrowings under its Senior Credit Agreement. Refer to Note 10, “Stockholders’ Equity,” for further discussion of the Company’s issuance of the preferred stock. Pro Forma Impact of Acquisition (Unaudited) As disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, the acquisition of the Pecos County Assets was accounted for as a business combination in accordance with ASC No. 805, Business Combinations (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Certain assets and liabilities may be adjusted as additional information is obtained, but no later than one year from the respective acquisition dates. During the nine months ended September 30, 2018, there were no adjustments to the purchase price of the Pecos County Assets. The purchase price allocation for the Pecos County Assets is complete. The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2017 as though the Pecos County Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2016. The pro forma combined results of operations for the nine months ended September 30, 2017 have been prepared by adjusting the historical results of the Company to include the historical results of the Pecos County Assets. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the period presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Pecos County Acquisition, or any estimated costs that will be incurred to integrate the Pecos County Assets. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors. The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Pecos County Acquisition and that were factually supportable. Adjustments and assumptions made for this pro forma calculation are consistent with those used in the Company’s annual pro forma information, as more fully described in Item 8. Consolidated Financial Statements and Supplementary Data— Note 5, “ Acquisitions and Divestitures ,” to the Company’s Annual Report on Form 10-K for the year ended December 31, 2017. Amounts included in the table below are rounded to thousands, except per share amounts. Nine Months Ended September 30, 2017 (Unaudited) Revenue $ 360,590 Net income (loss) 635,854 Net income (loss) available to common stockholders 587,847 Pro forma net income (loss) per share of common stock: Basic $ 4.61 Diluted $ 4.58 Divestitures Williston Basin Non-Operated Assets On September 19, 2017, certain wholly owned subsidiaries of the Company entered into an agreement with a privately-owned company pursuant to which the Company sold its non-operated properties and related assets located in the Williston Basin in North Dakota and Montana (the Non-Operated Williston Assets) for a total adjusted sales price of $103.4 million. The effective date of the transaction was April 1, 2017 and the transaction closed on November 9, 2017. Proceeds from the sale were recorded as a reduction to the carrying value of the Company’s full cost pool with no gain or loss recorded. Williston Basin Operated Assets On July 10, 2017, the Company and certain of its subsidiaries entered into an agreement with Bruin Williston Holdings, LLC for the sale of all of the Company’s operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of its subsidiaries (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion (the Williston Divestiture). The effective date of the sale was June 1, 2017 and the transaction closed on September 7, 2017. The Company used the net proceeds from the sale to repay borrowings outstanding under its Senior Credit Agreement, repurchase approximately $425.0 million principal amount of the then outstanding $850.0 million principal amount of its 6.75% senior notes, redeem all of its outstanding 12% senior secured second lien notes and for general corporate purposes. The net proceeds from the sale were allocated between the Company’s oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $1.39 billion was allocated to the Company’s oil and natural gas properties and approximately $10.9 million was allocated to other operating property and equipment. As discussed further in Note 4, “ Oil and Natural Gas Properties ,” the Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017. This gain was reduced by $7.2 million during the nine months ended September 30, 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. East Texas Eagle Ford Assets On January 24, 2017, certain of the Company’s subsidiaries entered into an agreement with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of its oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total adjusted sales price of $491.1 million (the El Halcón Divestiture). The effective date of the sale was January 1, 2017 and the transaction closed on March 9, 2017. The Company used the net proceeds from the sale to repay borrowings outstanding under its Senior Credit Agreement and for general corporate purposes. The net proceeds from the sale were allocated between the Company’s oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $484.1 million was allocated to the Company’s oil and natural gas properties and $10.2 million was allocated to other operating property and equipment. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the El Halcón Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of $235.7 million during the year ended December 31, 2017. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in “Gain (loss) on sale of oil and natural gas properties,” on the Company’s unaudited condensed consolidated statements of operations.

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	9 Months Ended
	Sep. 30, 2018
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES	4. 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 September 30, 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 September 30, 2018 of the West Texas Intermediate (WTI) crude oil spot price of $63.43 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 September 30, 2018 of the Henry Hub natural gas price of $2.91 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 September 30, 2018 did not exceed the ceiling amount. At September 30, 2017, 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 September 30, 2017 of the WTI crude oil spot price of $49.81 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 September 30, 2017 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 September 30, 2017 did not exceed the ceiling amount. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending, and other factors will determine the Company’s ceiling test calculations and impairment analyses in future periods.

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2018
LONG-TERM DEBT
LONG-TERM DEBT	5. LONG-TERM DEBT Long-term debt as of September 30, 2018 and December 31, 2017 consisted of the following (in thousands): September 30, December 31, 2018 2017 Senior revolving credit facility $ 55,000 $ — 6.75% senior notes due 2025 (1) 612,726 409,168 $ 667,726 $ 409,168 (1) On February 15, 2018, the Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at 103.0% of par. Amount includes a $7.4 million and $8.1 million unamortized discount at September 30, 2018 and December 31, 2017, respectively, associated with the 2025 Notes. Amount includes a $5.6 million unamortized premium at September 30, 2018, associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.4 million and $7.7 million unamortized debt issuance costs at September 30, 2018 and December 31, 2017, respectively. Refer to “6.75% Senior Notes” below for further details. Senior Revolving Credit Facility On September 7, 2017, the Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Senior Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the Senior Credit Agreement, the lenders party thereto have agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a current borrowing base of $200.0 million. The maturity date of the Senior Credit Agreement is September 7, 2022. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.25% to 2.25% for ABR-based loans or at specified margins over LIBOR of 2.25% to 3.25% for Eurodollar-based loans. These margins fluctuate based on the Company’s utilization of the facility. The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Amounts outstanding under the Senior Credit Agreement are guaranteed by certain of the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries. The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement), which was recently revised by the Consent and Fifth 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. The Senior Credit Agreement also 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. At September 30, 2018, under the then effective borrowing base of $200.0 million, the Company had $55.0 million of indebtedness outstanding, approximately $1.6 million letters of credit outstanding and approximately $143.4 million of borrowing capacity available under the Senior Credit Agreement. On November 7, 2018, the Company entered into the Fifth Amendment (the Fifth Amendment) to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of (a) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (b) 4.25 to 1.0 for the fiscal quarter ending December 31, 2018 and (c) 4.0 to 1.0 for the fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter. On November 6, 2018, the lenders party to the Senior Credit Agreement issued a consent (the Consent) to the Company whereby H2S Expenses (as defined in the Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019. On July 12, 2018, the Company entered into the Fourth Amendment (the Fourth Amendment) to the Senior Credit Agreement which provided for an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA (as defined in the Senior Credit Agreement) of (i) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (ii) 5.0 to 1.0 for the fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019, (iii) 4.25 to 1.0 for the fiscal quarter ending September 30, 2019 and (iv) 4.0 to 1.0 for the fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter; provided, however, that if the Company consummates a sale of all or a material portion of its midstream assets, then the ratio of Consolidated Total Net Debt to EBITDA shall be reduced to 4.0 to 1.0 for each fiscal quarter ending after the fiscal quarter in which such sale is consummated. On May 1, 2018, the Company entered into the Third Amendment (the Third Amendment) to the Senior Credit Agreement which provided for an assignment and reallocation of the Maximum Credit Amounts (as defined in the Senior Credit Agreement) among certain of the lender financial institutions. The Third Amendment did not adjust the aggregate Maximum Credit Amounts, which remain at $1.0 billion. On February 2, 2018, the Company entered into the Second Amendment (the Second Amendment) to the Senior Credit Agreement by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. The Second Amendment among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending June 30, 2018, September 30, 2018 and December 31, 2018, (ii) an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of 4.50 to 1.00 for the fiscal quarter ending June 30, 2018, and a ratio of 4.00 to 1.00 for any fiscal quarter thereafter, (iii) a waiver of compliance with the covenant relating to the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2018, and (iv) a waiver of the automatic reduction to the borrowing base that would otherwise result due to the issuance of the Additional 2025 Notes (defined below). After giving effect to the Consent and the Fifth Amendment, at September 30, 2018, the Company was in compliance with the financial covenants under the Senior Credit Agreement. 6.75% Senior Notes On February 16, 2017, the Company issued $850.0 million aggregate principal amount of new 6.75% senior unsecured 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 then outstanding 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes) and for general corporate purposes. Upon repurchase and redemption of the 2020 Second Lien Notes during the three months ended March 31, 2017, the Company recorded a loss on extinguishment of debt of approximately $56.9 million, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes. The 2025 Notes are governed by an Indenture, dated as of February 16, 2017 (the February 2017 Indenture) by and among the Company, the Guarantors and U.S. Bank National Association, as Trustee, which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The February 2017 Indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company’s existing wholly-owned subsidiaries. Halcón, the issuer of the 2025 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries. In connection with the sale of the 2025 Notes, on February 16, 2017, the Company, the Guarantors and J.P. Morgan Securities LLC, on behalf of itself and as representative of the initial purchasers, entered into a Registration Rights Agreement (the 2017 Registration Rights Agreement) pursuant to which the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 365 days after closing. The Company filed the registration statement on November 1, 2017 and it was declared effective by the SEC on December 21, 2017. In addition, 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 amends provisions in order to exempt, among other things, the Williston Divestiture from certain provisions therein 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 Additional 2025 Notes were issued in a private placement exempt from registration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act and applicable state securities laws. The net proceeds from the sale of the Additional 2025 Notes were approximately $202.4 million after initial purchasers’ premiums and deducting commissions and offering expenses and were used to fund the cash consideration for the acquisition of the West Quito Draw Properties, discussed further in Note 3, "Acquisitions and Divestitures,” and for general corporate purposes, including to fund the Company’s 2018 drilling program. These notes were issued under the February 2017 Indenture. The Additional 2025 Notes are treated as a single class with, and have the same terms as, the 2025 Notes, except that the Additional 2025 Notes will initially be subject to transfer restrictions and have the benefit of certain registration rights and provisions for the payment of additional interest in the event of a breach with respect to such registration rights pursuant to the terms of a Registration Rights Agreement, entered into on February 15, 2018 (the 2018 Registration Rights Agreement). Pursuant to the 2018 Registration Rights Agreement the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 180 days after closing. The Company filed the registration statement on March 20, 2018 and it was declared effective by the SEC on April 9, 2018. In addition, the Company completed the exchange offer for the Additional 2025 Notes on May 17, 2018. The remaining unamortized discount on the 2025 Notes was $7.4 million at September 30, 2018. The unamortized premium on the Additional 2025 Notes was $5.6 million at September 30, 2018. Debt Issuance Costs The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. During the nine months ended September 30, 2018, the Company capitalized approximately $3.9 million of debt issuance costs related to the Senior Credit Agreement and the Additional 2025 Notes. At September 30, 2018 and December 31, 2017, the Company had approximately $11.2 million and $8.3 million, respectively, of unamortized debt issuance costs. The debt issuance costs for the Company’s Senior Credit Agreement are presented in “Funds in escrow and other” and the debt issuance costs for the Company’s senior unsecured debt are presented in “ Long-term debt, net ” on the unaudited condensed consolidated balance sheets.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2018
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	6. 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 September 30, 2018 and December 31, 2017 (in thousands): September 30, 2018 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 19,347 $ — $ 19,347 Liabilities Liabilities from derivative contracts $ — $ 123,635 $ — $ 123,635 December 31, 2017 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 677 $ — $ 677 Liabilities Liabilities from derivative contracts $ — $ 26,999 $ — $ 26,999 Derivative contracts listed above as Level 2 include collars, puts, calls, 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 7, “Derivative and Hedging Activities,” for additional discussion of derivatives. The Company’s derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments . The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts 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 debt instruments as of September 30, 2018 and December 31, 2017 (excluding discounts, premiums and debt issuance costs) (in thousands): September 30, 2018 December 31, 2017 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes $ 625,005 $ 600,005 $ 425,005 $ 443,790 The fair value of the Company’s fixed interest rate debt instruments was calculated using Level 1 criteria. The fair value of the Company’s senior notes is based on quoted market prices from trades of such debt. The Company follows the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; consequently, the Company has designated these liabilities as Level 3. See Note 8, “ 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	9 Months Ended
	Sep. 30, 2018
DERIVATIVE AND HEDGING ACTIVITIES
DERIVATIVE AND HEDGING ACTIVITIES	7. 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 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 institutions determined by management as competent and competitive market makers. 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 generally consist of swaps, basis swaps and costless put/call “collars.” 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) and the relevant price index at which the oil production is sold (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 not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations. At September 30, 2018, the Company had 85 open commodity derivative contracts summarized in the following tables: eight natural gas collar arrangements, seven natural gas basis swaps, eight natural gas liquids swaps, 25 crude oil basis swaps, 31 crude oil collar arrangements two crude oil puts, three crude oil calls, and one crude oil WTI NYMEX roll. At December 31, 2017, the Company had 34 open commodity derivative contracts summarized in the following tables: three natural gas collar arrangements, 12 crude oil basis swaps and 19 crude oil collar arrangements. All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivatives and Hedging (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 (in thousands): Asset derivative contracts Liability derivative contracts September 30, December 31, September 30, December 31, Derivatives not designated as hedging contracts under ASC 815 Balance sheet location 2018 (1) 2017 Balance sheet location 2018 (2) 2017 Commodity contracts Current assets - receivables from derivative contracts $ 16,553 $ 677 Current liabilities - liabilities from derivative contracts $ (86,176) $ (19,248) Commodity contracts Other noncurrent assets -receivables from derivative contracts 2,794 — Other noncurrent liabilities - liabilities from derivative contracts (37,459) (7,751) Total derivatives not designated as hedging contracts under ASC 815 $ 19,347 $ 677 $ (123,635) $ (26,999) (1) Amount includes a $0.7 million deferred premium asset classified all as current as of September 30, 2018. (2) Amount includes a $4.7 million deferred premium obligation of which $0.3 million was classified as current as of September 30, 2018. 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 Amount of gain or (loss) or (loss) recognized in recognized in income on income on derivative derivative contracts for the contracts for the Three Months Nine Months Ended Ended Location of gain or (loss) recognized in September 30, September 30, Derivatives not designated as hedging contracts under ASC 815 income on derivative contracts 2018 2017 2018 2017 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts $ (50,763) $ (31,209) $ (77,524) $ 11,010 Realized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts (9,643) 8,794 10,921 17,129 Total net gain (loss) on derivative contracts $ (60,406) $ (22,415) $ (66,603) $ 28,139 At September 30, 2018 and December 31, 2017, the Company had the following open crude oil, natural gas and natural gas liquids derivative contracts: September 30, 2018 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu’s/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl’s Price Range Price Price Range Price Price Range Price October 2018 - December 2018 Basis Swap Crude Oil 1,012,000 $ — — $ — $ — — $ — $ (6.90) - $ (12.50) $ (10.64) October 2018 - December 2018 Basis Swap Natural Gas 1,380,000 (1.05) - (1.19) (1.10) October 2018 - December 2018 Collars Crude Oil 1,196,000 45.00 - 55.80 50.08 50.00 - 63.00 56.87 October 2018 - December 2018 Collars Natural Gas 690,000 3.00 - 3.03 3.01 3.22 - 3.38 3.30 October 2018 - December 2018 Calls Crude Oil 1,196,000 59.00 - 63.00 59.92 October 2018 - December 2018 Calls Crude Oil (1,196,000) 50.00 - 63.00 56.87 October 2018 - December 2018 Swap Natural Gas Liquids 92,000 32.50 32.50 October 2018 - December 2018 WTI NYMEX Roll Crude Oil 460,000 0.35 0.35 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - June 2019 Basis Swap Crude Oil 543,000 (1.15) - (1.33) (1.22) January 2019 - September 2019 Basis Swap Crude Oil 546,000 (6.20) - (7.60) (6.90) January 2019 - December 2019 Basis Swap Crude Oil 2,365,000 (0.98) - (6.50) (3.73) January 2019 - December 2019 Basis Swap Natural Gas 9,307,500 (1.05) - (1.40) (1.18) January 2019 - December 2019 Collars Crude Oil 5,110,000 50.00 - 58.00 53.12 55.00 - 63.00 58.98 January 2019 - December 2019 Collars Natural Gas 8,395,000 2.52 - 2.65 2.60 3.00 - 3.03 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 - December 2019 Collars Crude Oil 275,000 55.00 55.00 62.85 62.85 July 2019 - December 2019 Collars Crude Oil 184,000 55.00 55.00 69.00 69.00 October 2019 - December 2019 Basis Swap Crude Oil 368,000 3.45 - 3.75 3.65 October 2019 - December 2019 Swap Natural Gas Liquids 92,000 32.50 32.50 January 2020 - December 2020 Basis Swap Crude Oil 2,928,000 2.00 - 3.75 2.82 January 2020 - December 2020 Collars Crude Oil 549,000 50.00 50.00 70.00 70.00 January 2020 - December 2020 Calls Crude Oil 1,464,000 70.00 70.00 January 2020 - December 2020 Puts Crude Oil 915,000 55.00 55.00 January 2020 - December 2020 Swap Natural Gas Liquids 732,000 31.00 31.00 December 31, 2017 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu’s/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl’s Price Range Price Price Range Price Price Range Price January 2018 - December 2018 Basis Swap Crude Oil 2,555,000 $ $ — $ — $ — $ — $ — $ (1.05) - $ (1.50) $ (1.29) January 2018 - December 2018 Collars Crude Oil 2,920,000 45.00 - 53.00 49.29 50.00 - 60.00 56.82 January 2018 - December 2018 Collars Natural Gas 2,737,500 3.00 - 3.03 3.01 3.22 - 3.38 3.30 April 2018 - December 2018 Basis Swap Crude Oil 275,000 (1.15) (1.15) April 2018 - December 2018 Collars Crude Oil 275,000 46.75 46.75 51.75 51.75 July 2018 - December 2018 Basis Swap Crude Oil 1,012,000 (0.98) - (1.18) (1.12) July 2018 - December 2018 Collars Crude Oil 184,000 48.50 48.50 53.50 53.50 October 2018 - December 2018 Collars Crude Oil 92,000 50.65 50.65 55.65 55.65 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - December 2019 Basis Swap Crude Oil 4,380,000 (0.50) - (1.33) (1.02) January 2019 - December 2019 Collars Crude Oil 1,825,000 50.00 - 51.00 50.24 55.00 - 57.30 55.70 The Company presents the fair value of its derivative contracts at the gross amounts in the 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 (in thousands): Derivative Assets Derivative Liabilities Offsetting of Derivative Assets and Liabilities September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Gross Amounts Presented in the Consolidated Balance Sheet $ 19,347 $ 677 $ (123,635) $ (26,999) Amounts Not Offset in the Consolidated Balance Sheet (18,040) (231) 18,040 231 Net Amount $ 1,307 $ 446 $ (105,595) $ (26,768) The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	9 Months Ended
	Sep. 30, 2018
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS	8. 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 (in thousands, inclusive of the current portion): Liability for asset retirement obligations as of December 31, 2017 $ 4,368 Liabilities settled and divested (110) Additions 796 Acquisitions (1) 2,465 Accretion expense 225 Revisions in estimated cash flows (632) Liability for asset retirement obligations as of September 30, 2018 $ 7,112 (1) See Note 3, "Acquisitions and Divestitures," for additional information on the Company's acquisition and divestiture activities.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2018
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	9. COMMITMENTS AND CONTINGENCIES Commitments The Company leases corporate office space in Houston, Texas and Denver, Colorado. Rent expense was approximately $2.8 million and $3.0 million for the nine months ended September 30, 2018 and 2017, respectively. Future obligations associated with the Company’s operating leases are presented in the table below (in thousands): Remaining period in 2018 $ 846 2019 2,990 2020 1,811 2021 1,497 2022 835 Thereafter 1,345 Total $ 9,324 As of September 30, 2018, the Company has the following active drilling rig commitments (in thousands): Remaining period in 2018 $ 4,419 2019 4,726 2020 — 2021 — 2022 — Thereafter — Total $ 9,145 As of September 30, 2018, termination of the Company’s active drilling rig commitments would require early termination penalties of $8.2 million, which would be in lieu of paying the remaining active commitments of $9.1 million. In past years, with the sustained decline in crude oil prices, the Company stacked certain drilling rigs and amended previously entered into drilling rig contracts. In connection with the early termination of a drilling contract from 2015, if certain requirements are not met by January 12, 2020, the Company may incur an additional $3.0 million. Rig stacking fees are expensed as incurred within “Gathering and other” on the unaudited condensed consolidated statements of operations and are not included in the table above. In September 2018, the Company entered into a purchase agreement for certain natural gas treating equipment totaling approximately $13.3 million. As of September 30, 2018, the Company's remaining commitment is approximately $9.8 million and is expected to be incurred by March 31, 2019. The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of September 30, 2018, the Company had in place three long‑term crude oil contracts and eleven long‑term natural gas contracts in this area and the sales price 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	9 Months Ended
	Sep. 30, 2018
STOCKHOLDERS' EQUITY
STOCKHOLDERS' EQUITY	10. STOCKHOLDERS’ EQUITY Preferred Stock and Non-Cash Preferred Stock Dividend On January 24, 2017 (the Commitment Date), the Company entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which was convertible into 10,000 shares of common stock. Also on January 24, 2017, the Company received an executed written consent in lieu of a stockholders’ meeting authorizing and approving the conversion of the Preferred Stock into common stock. On February 27, 2017, the Company filed with the Delaware Secretary of State a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation), which created the series of preferred stock issued by the Company on that same date. The Company issued the Preferred Stock at $72,500 per share. Gross proceeds were approximately $400.1 million, or $7.25 per share of common stock. The Company incurred approximately $11.9 million in expenses associated with this offering, including placement agent fees. On March 16, 2017, the Company mailed a definitive information statement to its common stockholders notifying them that a majority of its stockholders had consented to the issuance of common stock, par value $0.0001 per share, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 55.2 million shares of common stock on April 6, 2017 in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since, pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to June 1, 2017. The Company agreed to file a registration statement to register the resale of shares of common stock issuable upon conversion of the Preferred Stock and to pay penalties in the event such registration was not effective by June 27, 2017. The Company filed such registration statement on March 3, 2017 and it was declared effective by the SEC on April 7, 2017. In accordance with ASC Topic 470, Debt (ASC 470), the Company determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature. The fair value of the Company’s common stock of $8.12 per share on the Commitment Date was greater than the conversion price of $7.25 per share of common stock, representing a beneficial conversion feature of $0.87 per share of common stock, or approximately $48.0 million in aggregate. Under ASC 470, $48.0 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to “Additional paid-in capital,” creating a discount on the Preferred Stock (the Discount). The Discount was required to be amortized on a non-cash basis over the approximate 65-month period between the issuance date and the required redemption date of July 28, 2022, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. As a result, approximately $0.8 million of the Discount was amortized and a non-cash preferred dividend was recorded in the three months ended March 31, 2017 and due to the conversion date occurring on April 6, 2017, the remaining $47.2 million of the amortization of the Discount was accelerated to the conversion date and fully amortized in the three months ended June 30, 2017. The Discount amortization is reflected in “Non-cash preferred dividend” in the unaudited condensed consolidated statements of operations. The preferred dividend was charged against additional paid-in capital since no retained earnings were available. 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 September 30, 2018 and December 31, 2017, a maximum of 4.9 million and 7.7 million shares, respectively, of the Company’s common stock remained reserved for issuance under the Plan. The Company accounts for stock-based payment accruals under authoritative guidance on stock compensation. The guidance requires all stock-based payments to employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values. The Company has elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. For the three and nine months ended September 30, 2018, the Company recognized $4.4 million and $12.2 million, respectively, of stock-based compensation expense. For the three and nine months ended September 30, 2017, the Company recognized $12.3 million and $33.5 million, respectively, of stock-based compensation expense. Stock-based compensation expense is recorded as a component of “ General and administrative ” on the unaudited condensed consolidated statements of operations. Stock Options From time to time, the Company grants stock options under the Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. During the nine months ended September 30, 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. During the nine months ended September 30, 2018, the Company received $0.3 million from the exercise of stock options. At September 30, 2018, the Company had $7.1 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.1 years. During the nine months ended September 30, 2017, the Company granted stock options under the Plan covering 1.8 million shares of common stock to employees of the Company. These stock options have exercise prices ranging from $6.55 to $7.75 per share with a weighted average exercise price of $7.72 per share. At September 30, 2017, the Company had $17.3 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.5 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. Certain shares granted under the Plan specifically related to the Company's emergence from chapter 11 bankruptcy, vested on or before September 30, 2017. During the nine months ended September 30, 2018, the Company granted 2.3 million shares of restricted stock under the Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $3.75 to $5.65 with a weighted average price of $5.47. At September 30, 2018, the Company had $8.6 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.2 years. During the nine months ended September 30, 2017, the Company granted 2.0 million shares of restricted stock under the Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $6.08 to $7.75 per share with a weighted average price of $7.07 per share. At September 30, 2017, the Company had $5.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	9 Months Ended
	Sep. 30, 2018
EARNINGS PER COMMON SHARE
EARNINGS PER COMMON SHARE	11. EARNINGS PER COMMON SHARE The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts): Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Basic: Net income (loss) available to common stockholders $ (81,837) $ 419,287 $ (100,709) $ 580,809 Weighted average basic number of common shares outstanding 158,011 146,944 156,628 127,458 Basic net income (loss) per share of common stock $ (0.52) $ 2.85 $ (0.64) $ 4.56 Diluted: Net income (loss) available to common stockholders $ (81,837) $ 419,287 $ (100,709) $ 580,809 Weighted average basic number of common shares outstanding 158,011 146,944 156,628 127,458 Common stock equivalent shares representing shares issuable upon: Exercise of stock options Anti-dilutive Anti-dilutive Anti-dilutive Anti-dilutive Exercise of warrants Anti-dilutive Anti-dilutive Anti-dilutive Anti-dilutive Vesting of restricted shares Anti-dilutive 1,546 Anti-dilutive 952 Conversion of preferred stock — — — Anti-dilutive Weighted average diluted number of common shares outstanding 158,011 148,490 156,628 128,410 Diluted net income (loss) per share of common stock $ (0.52) $ 2.82 $ (0.64) $ 4.52 Common stock equivalents, including stock options, restricted shares, and warrants totaling 14.9 million and 14.3 million shares for the three and nine months ended September 30, 2018, respectively, 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 losses. Common stock equivalents, including stock options, restricted shares, warrants, and preferred stock totaling 11.7 million and 19.0 million shares for the three and nine months ended September 30, 2017, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

ADDITIONAL FINANCIAL STATEMENT

ADDITIONAL FINANCIAL STATEMENT INFORMATION	9 Months Ended
	Sep. 30, 2018
ADDITIONAL FINANCIAL STATEMENT INFORMATION
ADDITIONAL FINANCIAL STATEMENT INFORMATION	12. ADDITIONAL FINANCIAL STATEMENT INFORMATION Certain balance sheet amounts are comprised of the following (in thousands): September 30, December 31, 2018 2017 Accounts receivable: Oil, natural gas and natural gas liquids revenues $ 37,085 $ 24,110 Joint interest accounts 8,736 2,249 Other 943 10,057 $ 46,764 $ 36,416 Prepaids and other: Prepaids $ 4,684 $ 4,324 Income tax receivable 6,250 6,250 Other 35 54 $ 10,969 $ 10,628 Funds in escrow and other: Funds in escrow $ 568 $ 563 Other 1,347 1,128 $ 1,915 $ 1,691 Accounts payable and accrued liabilities: Trade payables $ 51,192 $ 35,688 Accrued oil and natural gas capital costs 53,692 50,743 Revenues and royalties payable 20,587 20,256 Accrued interest expense 5,858 10,985 Accrued employee compensation 5,086 9,805 Accrued lease operating expenses 4,667 2,024 Other 295 1,586 $ 141,377 $ 131,087

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2018
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	13. SUBSEQUENT EVENTS Sale of Water Infrastructure Assets On October 31, 2018, certain wholly owned subsidiaries of the Company entered into an Asset Purchase Agreement (the Agreement) with an affiliate of WaterBridge Resources LLC (the Purchaser) pursuant to which the Company agreed to sell its water infrastructure assets located in the Delaware Basin (the Water Assets) to Purchaser for a total purchase price of up to $325.0 million, consisting of $200.0 million payable in cash upon closing and additional incentive payments of up to $25.0 million per year for the next five years 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 ability of the Company 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. The purchase price is subject to adjustment for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date and (ii) environmental defects, if any. The effective date of the transaction is October 1, 2018 and the transaction is expected to close in late-December 2018, subject to satisfaction of customary closing conditions set forth in the Agreement. The Agreement also contains customary representations, warranties and covenants by the Company and Purchaser and contemplates a transition services period whereby the Company would operate the Water Assets for approximately two months following the closing and also operate the Water Assets in Monument Draw for approximately six months in order to install additional water service and treating infrastructure. In addition, the parties have agreed to negotiate in good faith prior to closing, a definitive agreement relating to certain water supply assets. While the parties have a non-binding agreement relating to the material business terms of such agreement, if they are unable to agree on a definitive agreement prior to closing, certain water supply assets will remain with the Company and $30.0 million of the cash purchase price will not be paid to the Company until such time as such definitive agreement is executed. At closing, the Company will dedicate all of the produced water from its oil and natural gas wells within the Company’s Monument Draw, Hackberry Draw and West Quito Draw operating areas to Purchaser. Purchaser will be entitled to receive a current market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and assuming a definitive agreement related to the water supply assets is executed, Purchaser will be entitled to receive a market price for the supply of freshwater and recycled produced water to the Company Borrowing Base Redetermination The Company recently completed the fall 2018 borrowing base redetermination for its Senior Credit Agreement. The Company received commitments to increase its borrowing base from $200.0 million to $275.0 million upon the closing of its water infrastructure assets sale in December 2018.

FINANCIAL STATEMENT PRESENTAT_2

FINANCIAL STATEMENT PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2018
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 1, 2018. Please refer to the notes in the 2017 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 the Company’s management, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of the fair values of assets acquired and liabilities assumed in connection with the Pecos County Acquisition and the fair value of assets sold in connection with the Williston Divestiture and the El Halcón Divestiture (see Note 3, “Acquisitions and Divestitures, ” for information on the Pecos County Acquisition, the Williston Divestiture and the El Halcón Divestiture), including the gains on sales recorded and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s 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.
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 September 30, 2018 and December 31, 2017, allowances for doubtful accounts were approximately $0.1 million and $0.7 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 and water gathering systems, thirty years; water disposal and recycling facilities, gas treating systems and buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, the lesser of the 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.
Income Taxes	Income Taxes On December 22, 2017, Staff Accounting Bulletin No. 118 (SAB 118) was issued to address the application of accounting principles generally accepted in the United States in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Cuts Job Act of 2017. In accordance with SAB 118, the Company has determined that the $280.9 million income tax provision and corresponding decrease in the Company's valuation allowance was a provisional amount and a reasonable estimate for the year ended December 31, 2017. Any subsequent adjustments to these amounts will be recorded to current tax benefit (provision) in the fourth quarter of 2018, when the analysis is complete.
Related Party Transactions	Related Party Transactions 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 natural gas 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 and nine months ended September 30, 2018, the Company received zero and $0.4 million from Salt Creek under the gas purchase and processing agreement. Certain funds under the control of Ares Management LLC (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 common 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, also serves on the board of directors of Salt Creek’s parent company. Crude Oil Gathering Agreement On July 27, 2018, a subsidiary of the Company entered into a crude oil gathering agreement with SCM Crude, LLC (SCM) pursuant to which the Company agreed to dedicate, for a term of 15 years, production of crude oil from its currently owned, or later acquired acreage in designated areas in Ward and Winkler Counties, Texas (excluding certain specific wells) for the receipt, gathering and transportation on a gathering system to be designed, engineered and constructed by SCM. The gathering system is expected to be operational by December 31, 2018. The agreement with SCM was the culmination of a lengthy process during which the Company analyzed the most effective method of gathering and transportation of its future oil production in these areas. During the course of its investigation, the Company considered a variety of alternatives and solicited and received numerous third party proposals. The Company received and evaluated proposals from eleven companies covering some or all of its oil production in the region and determined that among the proposals it received, SCM’s was superior for economic and strategic reasons. Because certain funds under the control of Ares are the majority owners and controlling parties of SCM, the Audit Committee of the board of directors of the Company and the disinterested members of the Company’s board of directors evaluated and approved (in a vote that excluded the Company director who is employed by Ares) the process by which the Company determined the SCM proposal to be superior to other alternatives, as well as the principal terms of the agreement, in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company’s website at www.halconresources.com ) and the Company’s procedures for the review and approval of transactions with related parties. Ares also controls other funds which own in excess of ten percent (10%) of the common stock of the Company. No Ares fund that is a stockholder of the Company has an interest in SCM but one of the Company’s directors, who is employed by Ares, also serves on the board of directors of SCM’s parent company. Charter of Aircraft In the ordinary course of its business, the Company occasionally charters a private aircraft for business use. Floyd C. Wilson, Halcón's Chairman, Chief Executive Officer and President, owns an aircraft which the Company has chartered from time to time. For a portion of 2017, Mr. Wilson's aircraft was managed by an independent air charter company unaffiliated with both Mr. Wilson and Halcón. The aircraft in the air charter company's fleet are available to the public for charter based upon a standard fee schedule established by the air charter company, with the fees dependent primarily upon the type and size of the aircraft utilized and the duration of the flight. Because the air charter company established fees for the use of the aircraft in its fleet, Mr. Wilson did not receive any greater benefit from Halcón's charter of the aircraft indirectly owned by him than he would have if any third party were to charter the aircraft. During the course of 2017, Mr. Wilson terminated the independent air charter company and removed his aircraft from the charter company's fleet, pending his search for a new charter company to manage his aircraft. During the search period for a new charter company, fees for the use of Mr. Wilson's aircraft by the Company were based upon comparable costs that the Company would have incurred in chartering the same type and size of aircraft from an independent third party utilizing data from several independent third party aircraft leasing companies. The terms for this use were evaluated and approved by the Audit Committee of the Company, and subsequently by the disinterested members of the Company's board of directors upon the recommendation of the Audit Committee, in accordance with the Company's procedures for the review and approval of transactions with related parties. During the three and nine months ended September 30, 2018, the Company paid approximately $0.2 million and $0.8 million, respectively, to Mr. Wilson for the Company use of the aircraft. As of September 30, 2018, the Company recorded a $0.1 million payable to Mr. Wilson. The payable is recorded in "Accounts payable and accrued liabilities , " on the Company's unaudited condensed consolidated balance sheet.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). For public business entities, ASU 2017-01 is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2017. The amendments in this ASU should be applied prospectively on or after the effective date. The ASU was issued to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The Company applied the provisions of ASU 2017-01 to the acquisition of the West Quito Draw Properties, which is discussed further in Note 3, “Acquisitions and Divestitures . ” In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) (ASU 2016-15). For public business entities, ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and early adoption is permitted. The areas for simplification in this ASU involve addressing eight specific classification issues in the statement of cash flows. An entity should apply the amendments in this ASU using a retrospective transition method. The adoption of ASU 2016-15 did not have an impact on the Company’s unaudited condensed consolidated statement of cash flows. In February 2016, the FASB issued 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 and early adoption is permitted. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In January 2018, ASU 2016-02 was updated with ASU No. 2018-01, Lease (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842 (ASU 2018-01), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases . An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. An entity that does not elect this practical expedient should evaluate all existing or expired land easements in connection with the adoption of the new lease requirements in Topic 842 to assess whether they meet the definition of a lease. In July 2018, ASU 2016-02 was updated with ASU No. 2018-11, Targeted Improvements to ASC 842 , which provides entities with relief from the costs of implementing certain aspects of the new leasing standard. Specifically, under the amendments in ASU 2018-11, (1) entities may elect not to recast the comparative periods presented when transitioning to ASC 842 and (2) lessors may elect not to separate lease and nonlease components when certain conditions are met. Before ASU 2018-11 was issued, transition to the new lease standard required application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. As of September 30, 2018, the Company had approximately $18.5 million of contractual obligations related to its non-cancelable leases and drilling contracts, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under the new leasing standard. In addition, the Company is implementing an accounting software solution to facilitate compliance with the new lease accounting requirements, as well as continuing to analyze its processes and internal controls surrounding its leases. At this time, the Company cannot reasonably estimate the financial statement impact of the adoption of ASU 2016-02; however, the unaudited condensed consolidated balance sheets will be impacted due to the recognition of right-of-use assets and lease liabilities that are not recognized under the current lease accounting guidance. The Company will adopt ASU 2016-02 on January 1, 2019. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08, and collectively with ASU 2014-09, ASC 606), which provides further clarification on the principal versus agent evaluation. The Company adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. See Note 2, “ Operating Revenues ,” for further details.

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	9 Months Ended
	Sep. 30, 2018
OPERATING REVENUES
Schedule of disaggregation of revenues by major product	The following table disaggregates the Company’s revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company's single basin operations, for the periods indicated (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 (1) 2018 2017 (1) Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 53,918 $ 88,256 $ 145,743 $ 319,472 Natural gas 1,407 2,886 5,286 15,051 Natural gas liquids 5,920 5,448 14,623 16,779 Total oil, natural gas and natural gas liquids sales 61,245 96,590 165,652 351,302 Other 350 363 613 1,386 Total operating revenues $ 61,595 $ 96,953 $ 166,265 $ 352,688 (1) As noted above, prior period amounts have not been adjusted under the modified retrospective method of adoption.

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	9 Months Ended
	Sep. 30, 2018
ACQUISITIONS AND DIVESTITURES
Schedule of pro forma financial information	Amounts included in the table below are rounded to thousands, except per share amounts. Nine Months Ended September 30, 2017 (Unaudited) Revenue $ 360,590 Net income (loss) 635,854 Net income (loss) available to common stockholders 587,847 Pro forma net income (loss) per share of common stock: Basic $ 4.61 Diluted $ 4.58

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	9 Months Ended
	Sep. 30, 2018
LONG-TERM DEBT
Schedule of long-term debt	Long-term debt as of September 30, 2018 and December 31, 2017 consisted of the following (in thousands): September 30, December 31, 2018 2017 Senior revolving credit facility $ 55,000 $ — 6.75% senior notes due 2025 (1) 612,726 409,168 $ 667,726 $ 409,168 (1) On February 15, 2018, the Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at 103.0% of par. Amount includes a $7.4 million and $8.1 million unamortized discount at September 30, 2018 and December 31, 2017, respectively, associated with the 2025 Notes. Amount includes a $5.6 million unamortized premium at September 30, 2018, associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.4 million and $7.7 million unamortized debt issuance costs at September 30, 2018 and December 31, 2017, respectively. Refer to “6.75% Senior Notes” below for further details.

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
FAIR VALUE MEASUREMENTS
Schedule of fair value of the Company's financial assets and liabilities	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2018 and December 31, 2017 (in thousands): September 30, 2018 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 19,347 $ — $ 19,347 Liabilities Liabilities from derivative contracts $ — $ 123,635 $ — $ 123,635 December 31, 2017 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 677 $ — $ 677 Liabilities Liabilities from derivative contracts $ — $ 26,999 $ — $ 26,999
Schedule of the estimated fair values of the Company's fixed interest rate debt instruments	The following table presents the estimated fair values of the Company’s fixed interest rate debt instruments as of September 30, 2018 and December 31, 2017 (excluding discounts, premiums and debt issuance costs) (in thousands): September 30, 2018 December 31, 2017 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes $ 625,005 $ 600,005 $ 425,005 $ 443,790

DERIVATIVE AND HEDGING ACTIVI_2

DERIVATIVE AND HEDGING ACTIVITIES (Tables)	9 Months Ended
	Sep. 30, 2018
DERIVATIVE AND HEDGING ACTIVITIES
Summary of location and fair value of derivative contracts	The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets (in thousands): Asset derivative contracts Liability derivative contracts September 30, December 31, September 30, December 31, Derivatives not designated as hedging contracts under ASC 815 Balance sheet location 2018 (1) 2017 Balance sheet location 2018 (2) 2017 Commodity contracts Current assets - receivables from derivative contracts $ 16,553 $ 677 Current liabilities - liabilities from derivative contracts $ (86,176) $ (19,248) Commodity contracts Other noncurrent assets -receivables from derivative contracts 2,794 — Other noncurrent liabilities - liabilities from derivative contracts (37,459) (7,751) Total derivatives not designated as hedging contracts under ASC 815 $ 19,347 $ 677 $ (123,635) $ (26,999) (1) Amount includes a $0.7 million deferred premium asset classified all as current as of September 30, 2018. (2) Amount includes a $4.7 million deferred premium obligation of which $0.3 million was classified as current as of September 30, 2018.
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 Amount of gain or (loss) or (loss) recognized in recognized in income on income on derivative derivative contracts for the contracts for the Three Months Nine Months Ended Ended Location of gain or (loss) recognized in September 30, September 30, Derivatives not designated as hedging contracts under ASC 815 income on derivative contracts 2018 2017 2018 2017 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts $ (50,763) $ (31,209) $ (77,524) $ 11,010 Realized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts (9,643) 8,794 10,921 17,129 Total net gain (loss) on derivative contracts $ (60,406) $ (22,415) $ (66,603) $ 28,139
Schedule of open derivative contracts	September 30, 2018 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu’s/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl’s Price Range Price Price Range Price Price Range Price October 2018 - December 2018 Basis Swap Crude Oil 1,012,000 $ — — $ — $ — — $ — $ (6.90) - $ (12.50) $ (10.64) October 2018 - December 2018 Basis Swap Natural Gas 1,380,000 (1.05) - (1.19) (1.10) October 2018 - December 2018 Collars Crude Oil 1,196,000 45.00 - 55.80 50.08 50.00 - 63.00 56.87 October 2018 - December 2018 Collars Natural Gas 690,000 3.00 - 3.03 3.01 3.22 - 3.38 3.30 October 2018 - December 2018 Calls Crude Oil 1,196,000 59.00 - 63.00 59.92 October 2018 - December 2018 Calls Crude Oil (1,196,000) 50.00 - 63.00 56.87 October 2018 - December 2018 Swap Natural Gas Liquids 92,000 32.50 32.50 October 2018 - December 2018 WTI NYMEX Roll Crude Oil 460,000 0.35 0.35 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - June 2019 Basis Swap Crude Oil 543,000 (1.15) - (1.33) (1.22) January 2019 - September 2019 Basis Swap Crude Oil 546,000 (6.20) - (7.60) (6.90) January 2019 - December 2019 Basis Swap Crude Oil 2,365,000 (0.98) - (6.50) (3.73) January 2019 - December 2019 Basis Swap Natural Gas 9,307,500 (1.05) - (1.40) (1.18) January 2019 - December 2019 Collars Crude Oil 5,110,000 50.00 - 58.00 53.12 55.00 - 63.00 58.98 January 2019 - December 2019 Collars Natural Gas 8,395,000 2.52 - 2.65 2.60 3.00 - 3.03 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 - December 2019 Collars Crude Oil 275,000 55.00 55.00 62.85 62.85 July 2019 - December 2019 Collars Crude Oil 184,000 55.00 55.00 69.00 69.00 October 2019 - December 2019 Basis Swap Crude Oil 368,000 3.45 - 3.75 3.65 October 2019 - December 2019 Swap Natural Gas Liquids 92,000 32.50 32.50 January 2020 - December 2020 Basis Swap Crude Oil 2,928,000 2.00 - 3.75 2.82 January 2020 - December 2020 Collars Crude Oil 549,000 50.00 50.00 70.00 70.00 January 2020 - December 2020 Calls Crude Oil 1,464,000 70.00 70.00 January 2020 - December 2020 Puts Crude Oil 915,000 55.00 55.00 January 2020 - December 2020 Swap Natural Gas Liquids 732,000 31.00 31.00 December 31, 2017 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu’s/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl’s Price Range Price Price Range Price Price Range Price January 2018 - December 2018 Basis Swap Crude Oil 2,555,000 $ $ — $ — $ — $ — $ — $ (1.05) - $ (1.50) $ (1.29) January 2018 - December 2018 Collars Crude Oil 2,920,000 45.00 - 53.00 49.29 50.00 - 60.00 56.82 January 2018 - December 2018 Collars Natural Gas 2,737,500 3.00 - 3.03 3.01 3.22 - 3.38 3.30 April 2018 - December 2018 Basis Swap Crude Oil 275,000 (1.15) (1.15) April 2018 - December 2018 Collars Crude Oil 275,000 46.75 46.75 51.75 51.75 July 2018 - December 2018 Basis Swap Crude Oil 1,012,000 (0.98) - (1.18) (1.12) July 2018 - December 2018 Collars Crude Oil 184,000 48.50 48.50 53.50 53.50 October 2018 - December 2018 Collars Crude Oil 92,000 50.65 50.65 55.65 55.65 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - December 2019 Basis Swap Crude Oil 4,380,000 (0.50) - (1.33) (1.02) January 2019 - December 2019 Collars Crude Oil 1,825,000 50.00 - 51.00 50.24 55.00 - 57.30 55.70
Schedule of potential effects of master netting arrangements on the fair value of derivative contracts	The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands): Derivative Assets Derivative Liabilities Offsetting of Derivative Assets and Liabilities September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Gross Amounts Presented in the Consolidated Balance Sheet $ 19,347 $ 677 $ (123,635) $ (26,999) Amounts Not Offset in the Consolidated Balance Sheet (18,040) (231) 18,040 231 Net Amount $ 1,307 $ 446 $ (105,595) $ (26,768)

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	9 Months Ended
	Sep. 30, 2018
ASSET RETIREMENT OBLIGATIONS
Schedule of activity related to ARO liability	The Company recorded the following activity related to its ARO liability (in thousands, inclusive of the current portion): Liability for asset retirement obligations as of December 31, 2017 $ 4,368 Liabilities settled and divested (110) Additions 796 Acquisitions (1) 2,465 Accretion expense 225 Revisions in estimated cash flows (632) Liability for asset retirement obligations as of September 30, 2018 $ 7,112 (1) See Note 3, "Acquisitions and Divestitures," for additional information on the Company's acquisition and divestiture activities.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	9 Months Ended
	Sep. 30, 2018
COMMITMENTS AND CONTINGENCIES
Schedule of approximate future minimum lease payments for subsequent annual periods for all non-cancelable operating leases	Future obligations associated with the Company’s operating leases are presented in the table below (in thousands): Remaining period in 2018 $ 846 2019 2,990 2020 1,811 2021 1,497 2022 835 Thereafter 1,345 Total $ 9,324
Schedule of commitments	As of September 30, 2018, the Company has the following active drilling rig commitments (in thousands): Remaining period in 2018 $ 4,419 2019 4,726 2020 — 2021 — 2022 — Thereafter — Total $ 9,145

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	9 Months Ended
	Sep. 30, 2018
EARNINGS PER COMMON SHARE
Schedule of calculation of earnings (loss) per share	The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts): Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Basic: Net income (loss) available to common stockholders $ (81,837) $ 419,287 $ (100,709) $ 580,809 Weighted average basic number of common shares outstanding 158,011 146,944 156,628 127,458 Basic net income (loss) per share of common stock $ (0.52) $ 2.85 $ (0.64) $ 4.56 Diluted: Net income (loss) available to common stockholders $ (81,837) $ 419,287 $ (100,709) $ 580,809 Weighted average basic number of common shares outstanding 158,011 146,944 156,628 127,458 Common stock equivalent shares representing shares issuable upon: Exercise of stock options Anti-dilutive Anti-dilutive Anti-dilutive Anti-dilutive Exercise of warrants Anti-dilutive Anti-dilutive Anti-dilutive Anti-dilutive Vesting of restricted shares Anti-dilutive 1,546 Anti-dilutive 952 Conversion of preferred stock — — — Anti-dilutive Weighted average diluted number of common shares outstanding 158,011 148,490 156,628 128,410 Diluted net income (loss) per share of common stock $ (0.52) $ 2.82 $ (0.64) $ 4.52

ADDITIONAL FINANCIAL STATEMEN_2

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2018
ADDITIONAL FINANCIAL STATEMENT INFORMATION
Schedule of additional financial statement information, balance sheet	Certain balance sheet amounts are comprised of the following (in thousands): September 30, December 31, 2018 2017 Accounts receivable: Oil, natural gas and natural gas liquids revenues $ 37,085 $ 24,110 Joint interest accounts 8,736 2,249 Other 943 10,057 $ 46,764 $ 36,416 Prepaids and other: Prepaids $ 4,684 $ 4,324 Income tax receivable 6,250 6,250 Other 35 54 $ 10,969 $ 10,628 Funds in escrow and other: Funds in escrow $ 568 $ 563 Other 1,347 1,128 $ 1,915 $ 1,691 Accounts payable and accrued liabilities: Trade payables $ 51,192 $ 35,688 Accrued oil and natural gas capital costs 53,692 50,743 Revenues and royalties payable 20,587 20,256 Accrued interest expense 5,858 10,985 Accrued employee compensation 5,086 9,805 Accrued lease operating expenses 4,667 2,024 Other 295 1,586 $ 141,377 $ 131,087

FINANCIAL STATEMENT PRESENTAT_3

FINANCIAL STATEMENT PRESENTATION (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)segment	Sep. 30, 2017USD ($)
Basis of Presentation and Principles of Consolidation
Number of operating segments | segment	1
Allowance for doubtful accounts | $	$ 0.1	$ 0.7

FINANCIAL STATEMENT PRESENTAT_4

FINANCIAL STATEMENT PRESENTATION - Other Operating Property and Equipment (Details)	9 Months Ended
	Sep. 30, 2018
Gas and water gathering systems
Other operating property and equipment
Estimated useful lives	30 years
Water disposal and recycling facilities
Other operating property and equipment
Estimated useful lives	20 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_5

FINANCIAL STATEMENT PRESENTATION - Income Taxes (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
FINANCIAL STATEMENT PRESENTATION
Income tax provision	$ 280.9

FINANCIAL STATEMENT PRESENTAT_6

FINANCIAL STATEMENT PRESENTATION - Related Party Transaction (Details) - USD ($) $ in Millions	Jul. 27, 2018	Nov. 16, 2017	Sep. 30, 2018	Sep. 30, 2018
Chairman, Chief Executive Officer and President
Related Party Transaction
Amount paid for charter of aircraft			$ 0.2	$ 0.8
Chairman, Chief Executive Officer and President | Accounts payable and accrued liabilities
Related Party Transaction
Amount payable			0.1	0.1
Salt Creek Midstream, LLC
Related Party Transaction
Term		15 years
Amount received			$ 0	$ 0.4
Minimum percentage of funds controlled by related party		10.00%
SCM Crude, LLC
Related Party Transaction
Term	15 years
Minimum percentage of funds controlled by related party	10.00%

FINANCIAL STATEMENT PRESENTAT_7

FINANCIAL STATEMENT PRESENTATION - Recently Issued Accounting Pronouncements (Details) $ in Thousands	Sep. 30, 2018USD ($)
Recently Issued Accounting Pronouncements
Contractual obligations related to non-cancelable leases and drilling contracts	$ 9,145
Non-cancelable leases and drilling contracts
Recently Issued Accounting Pronouncements
Contractual obligations related to non-cancelable leases and drilling contracts	$ 18,500

OPERATING REVENUES - Adoption o

OPERATING REVENUES - Adoption of ASC 606, Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating revenues
Gathering and other expense	$ (18,404)	$ (10,886)	$ (30,782)	$ (34,640)
Adjustments due to ASU 201409 | ASU 201409
Operating revenues
Cumulative effect of applying ASC 606			0
Oil, natural gas and natural gas liquids sales	200		600
Gathering and other expense	$ 200		$ 600

OPERATING REVENUES - Revenue Re

OPERATING REVENUES - Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	$ 61,245		$ 165,652
Other	350	$ 363	613	$ 1,386
Total operating revenues	61,595	96,953	166,265	352,688
Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		96,590		351,302
Other		363		1,386
Total operating revenues		96,953		352,688
Oil
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	53,918		145,743
Total operating revenues	53,918	88,256	145,743	319,472
Oil | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		88,256		319,472
Natural gas
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	1,407		5,286
Total operating revenues	1,407	2,886	5,286	15,051
Natural gas | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		2,886		15,051
Natural gas liquids
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	5,920		14,623
Total operating revenues	5,920	5,448	14,623	16,779
Natural gas liquids | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		$ 5,448		$ 16,779
Accounts receivable
Disaggregation of operating revenue
Due from contracts with customers	$ 37,100		$ 37,100		$ 24,100

OPERATING REVENUES - Revenue _2

OPERATING REVENUES - Revenue Recognition - Concentrations of Credit Risk (Details) - Revenue - Concentrations of Credit Risk - customer	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Concentrations of Credit Risk
Number of customers	2	2
Percentage of concentration risk	81.00%	58.00%
Sunoco
Concentrations of Credit Risk
Percentage of concentration risk	10.00%
Western refining
Concentrations of Credit Risk
Percentage of concentration risk	10.00%
Crestwood
Concentrations of Credit Risk
Percentage of concentration risk		10.00%
Suncor
Concentrations of Credit Risk
Percentage of concentration risk		10.00%

OPERATING REVENUES - Revenue _3

OPERATING REVENUES - Revenue Recognition - Practical Expedients (Details)	9 Months Ended
	Sep. 30, 2018
OPERATING REVENUES
Practical Expedients	true

ACQUISITIONS AND DIVESTITURES -

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

ACQUISITIONS AND DIVESTITURES-M

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

ACQUISITIONS AND DIVESTITURES-P

ACQUISITIONS AND DIVESTITURES-Pecos County Acquisition (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 28, 2017	Jan. 24, 2017	Jan. 18, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pro forma financial information
Net income (loss) available to common stockholders				$ (81,837)	$ 419,287	$ (100,709)	$ 580,809
8% Convertible Preferred Stock
ACQUISITIONS AND DIVESTITURES
Dividend rate (as a percent)		8.00%	8.00%
Pecos County Assets
ACQUISITIONS AND DIVESTITURES
Purchase price	$ 699,200
Pro forma financial information
Revenue							360,590
Net income (loss)							635,854
Net income (loss) available to common stockholders							$ 587,847
Pro forma net income (loss) per share of common stock:
Basic (in dollars per share)							$ 4.61
Diluted (in dollars per share)							$ 4.58

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES - Divestitures (Details) $ in Thousands	Sep. 19, 2017USD ($)	Jul. 10, 2017USD ($)subsidiary	Jan. 24, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Oct. 10, 2017USD ($)	Sep. 07, 2017USD ($)	Feb. 16, 2017USD ($)
Divestitures
Proceeds received from sale of oil and natural gas properties						$ 1,647	$ 1,901,578
Aggregate principal amount				$ 625,005		625,005		$ 425,005
Proceeds received from sale of other operating property and equipment						2,236	21,291
Gain (loss) from sale of other operating property and equipment				$ (1,331)	$ 491,830	$ (7,235)	$ 727,520
12.0% senior secured second lien notes due 2022
Divestitures
Interest rate (as a percent)		12.00%
6.75% senior notes due 2025
Divestitures
Principal amount repurchased									$ 425,000
Aggregate principal amount										$ 850,000	$ 850,000
Interest rate (as a percent)				6.75%		6.75%		6.75%		6.75%	6.75%
Gain on sale of oil and natural gas assets
Divestitures
Gain (loss) from sale of other operating property and equipment		$ 0	$ 0
Williston Basin Assets
Divestitures
Gain (loss) from sale of other operating property and equipment		0				$ (7,200)		$ 485,900
Williston Basin Assets | Other operating property and equipment
Divestitures
Proceeds received from sale of oil and natural gas properties		1,390,000
Proceeds received from sale of other operating property and equipment		$ 10,900
Williston Basin Assets | 6.75% senior notes due 2025
Divestitures
Principal amount repurchased										$ 425,000
Williston Basin Assets | Disposal Group Disposed of by Sale
Divestitures
Ownership percentage in subsidiaries		100.00%
Number of subsidiaries | subsidiary		2
Proceeds received from sale of oil and natural gas properties		$ 1,400,000
El Halcon Assets
Divestitures
Gain (loss) from sale of other operating property and equipment			0
El Halcon Assets | Other operating property and equipment
Divestitures
Proceeds received from sale of oil and natural gas properties			484,100
Proceeds received from sale of other operating property and equipment			10,200
El Halcon Assets | Gain on sale of oil and natural gas assets
Divestitures
Gain (loss) from sale of other operating property and equipment								$ 235,700
El Halcon Assets | Disposal Group Disposed of by Sale
Divestitures
Proceeds from sales of interests			$ 491,100
Non-operating owner | Williston Basin Assets
Divestitures
Proceeds from sales of interests	$ 103,400
Gain (loss) on sale	$ 0

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Details)	9 Months Ended
	Sep. 30, 2018$ / MMBTU$ / bbl	Sep. 30, 2017$ / MMBTU$ / bbl
Ceiling Limitation Disclosures
First day average of the (WTI) crude oil spot price (in dollars per barrel) | $ / bbl	63.43	49.81
First day average of the Henry Hub natural gas price (in dollars per Mmbtu) | $ / MMBTU	2.91	3

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Feb. 15, 2018	Oct. 10, 2017	Sep. 30, 2018	Dec. 31, 2017	Sep. 07, 2017	Feb. 16, 2017
Current and long-term debt
Principal amount outstanding, net			$ 667,726	$ 409,168
Principal amount			625,005	425,005
Unamortized debt issuance costs			11,200	8,300
6.75% senior notes due 2025
Current and long-term debt
Principal amount outstanding, net			$ 612,726	$ 409,168
Interest rate (as a percent)			6.75%	6.75%	6.75%	6.75%
Principal amount					$ 850,000	$ 850,000
Redemption price (as a percent)		103.00%
Unamortized discount			$ 7,400	$ 8,100
Unamortized debt issuance costs			10,400	$ 7,700
Additional 2025 Notes
Current and long-term debt
Principal amount	$ 200,000
Issue price as a percentage of par value	103.00%
Unamortized premium related to debt issued			5,600
Senior revolving credit facility
Current and long-term debt
Principal amount outstanding, net			$ 55,000

LONG-TERM DEBT - Senior Facilit

LONG-TERM DEBT - Senior Facility (Details) $ in Millions	Jul. 12, 2018	Sep. 07, 2017USD ($)item	Nov. 07, 2018	Sep. 30, 2018USD ($)	May 01, 2018USD ($)	Feb. 02, 2018
Senior revolving credit facility
Current and long-term debt
Maximum borrowing capacity		$ 1,000
Current borrowing capacity				$ 200
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				55
Letters of credit outstanding				1.6
Borrowing capacity available				$ 143.4
Senior revolving credit facility | Minimum
Current and long-term debt
Current Ratio		1
Senior revolving credit facility | ABR - based | Minimum
Current and long-term debt
Applicable margin (as a percent)		1.25%
Senior revolving credit facility | ABR - based | Maximum
Current and long-term debt
Applicable margin (as a percent)		2.25%
Senior revolving credit facility | LIBOR | Minimum
Current and long-term debt
Applicable margin (as a percent)		2.25%
Senior revolving credit facility | LIBOR | Maximum
Current and long-term debt
Applicable margin (as a percent)		3.25%
Fifth Amendment to Senior Credit Agreement | Fiscal quarter ending September 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio			4.75
Fifth Amendment to Senior Credit Agreement | Fiscal quarter ending December 31, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio			4.25
Fifth Amendment to Senior Credit Agreement | Fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter
Current and long-term debt
Total Net Debt to EBITDA ratio			4
Fourth Amendment to the Senior Credit Agreement
Current and long-term debt
Total Net Debt to EBITDA when major portion of assets sold	4
Fourth Amendment to the Senior Credit Agreement | Fiscal quarter ending September 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio	4.75
Fourth Amendment to the Senior Credit Agreement | Fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio	5
Fourth Amendment to the Senior Credit Agreement | Fiscal quarter ending September 30, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio	4.25
Fourth Amendment to the Senior Credit Agreement | Fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter
Current and long-term debt
Total Net Debt to EBITDA ratio	4
Third Amendment to the Senior Credit Agreement
Current and long-term debt
Maximum borrowing capacity					$ 1,000
Second Amendment to Senior Credit Agreement | Fiscal quarter ending June 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio						4.50
Second Amendment to Senior Credit Agreement | Fiscal quarter after June 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio						4

LONG-TERM DEBT - 6.75% Senior N

LONG-TERM DEBT - 6.75% Senior Notes (Details) - USD ($) $ in Thousands	Feb. 15, 2018	Oct. 10, 2017	Sep. 07, 2017	Jul. 25, 2017	Feb. 16, 2017	Sep. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Current and long-term debt
Principal amount								$ 625,005		$ 425,005
Accrued and unpaid interest		$ 4,100
Gains (Losses) on Extinguishment of Debt						$ (29,167)			$ (86,065)
6.75% senior notes due 2025
Current and long-term debt
Principal amount			$ 850,000		$ 850,000
Interest rate (as a percent)			6.75%		6.75%			6.75%		6.75%
Net proceeds from issuance					$ 834,100
Redemption price of debt instrument (as a percent)		103.00%
Gains (Losses) on Extinguishment of Debt							$ 56,900
Loss on the repurchase for the tender premium paid							30,900
Loss on the write-off of the discount on notes							$ 26,000
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
Period within which to complete exchange offer after closing								180 days
Unamortized discount								$ 7,400		$ 8,100
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								$ 5,600
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

LONG-TERM DEBT - Debt Issuance

LONG-TERM DEBT - Debt Issuance Costs (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Debt Issuance Costs
Costs associated with the issuance of debt capitalized	$ 4,013	$ 17,220
Unamortized debt issuance costs	11,200		$ 8,300
Senior Revolving Credit Facility , 2025 notes and additional 2025 notes
Debt Issuance Costs
Costs associated with the issuance of debt capitalized	$ 3,900

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Assets
Asset transfers between levels	$ 0	$ 0
Liabilities
Liability transfers between levels	0	0
Recurring | Total
Assets
Receivables from derivative contracts	19,347	677
Liabilities
Liabilities from derivative contracts	123,635	26,999
Recurring | Level 2
Assets
Receivables from derivative contracts	19,347	677
Liabilities
Liabilities from derivative contracts	$ 123,635	$ 26,999

FAIR VALUE MEASUREMENTS - Estim

FAIR VALUE MEASUREMENTS - Estimated FV (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Sep. 07, 2017	Feb. 16, 2017
Fair value measurements
Principal amount	$ 625,005	$ 425,005
6.75% senior notes due 2025
Fair value measurements
Interest rate (as a percent)	6.75%	6.75%	6.75%	6.75%
Principal amount			$ 850,000	$ 850,000
Total
Fair value measurements
Estimated fair value of debt	$ 600,005	$ 443,790

DERIVATIVE AND HEDGING ACTIVI_3

DERIVATIVE AND HEDGING ACTIVITIES - Number of Contracts (Details) - Derivatives not designated as hedging contracts - Commodity contracts - item	Sep. 30, 2018	Dec. 31, 2017
Derivative and hedging activities
Number of open commodity derivative contracts	85	34
Collars | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts	8	3
Collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	31	19
Basis Swap | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts	7
Basis Swap | Natural gas liquids
Derivative and hedging activities
Number of open commodity derivative contracts	8
Basis Swap | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	25	12
Put options | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	2
Call option | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	3
WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	1

DERIVATIVE AND HEDGING ACTIVI_4

DERIVATIVE AND HEDGING ACTIVITIES - Location in Balance Sheets (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivative and hedging activities
Asset derivative contracts	$ 19,347	$ 677
Liability derivative contracts	(123,635)	(26,999)
Derivatives not designated as hedging contracts
Derivative and hedging activities
Asset derivative contracts	19,347	677
Liability derivative contracts	(123,635)	(26,999)
Derivatives not designated as hedging contracts | Commodity contracts
Derivative and hedging activities
Deferred premium obligation	4,700
Derivatives not designated as hedging contracts | Commodity contracts | Current assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	16,553	677
Deferred premium asset	700
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	2,794
Derivatives not designated as hedging contracts | Commodity contracts | Current liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts	(86,176)	(19,248)
Deferred premium obligation	300
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts	$ (37,459)	$ (7,751)

DERIVATIVE AND HEDGING ACTIVI_5

DERIVATIVE AND HEDGING ACTIVITIES - Realized Unrealized (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative and hedging activities
Total net gain (loss) on derivative contracts	$ (60,406)	$ (22,415)	$ (66,603)	$ 28,139
Derivatives not designated as hedging contracts | Commodity contracts | Other Income Expense
Derivative and hedging activities
Unrealized gain (loss) on commodity contracts	(50,763)	(31,209,000)	(77,524,000)	11,010
Realized gain (loss) on commodity contracts	(9,643)	8,794,000	10,921,000	17,129
Total net gain (loss) on derivative contracts	$ (60,406)	$ (22,415,000)	$ (66,603,000)	$ 28,139

DERIVATIVE AND HEDGING ACTIVI_6

DERIVATIVE AND HEDGING ACTIVITIES - Open Contracts (Details) - Commodity contracts	Sep. 30, 2018MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2017MMBTU$ / MMBTU$ / bblbbl
January 2018 - December 2018 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		2,555,000
January 2018 - December 2018 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		(1.05)
January 2018 - December 2018 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		(1.50)
January 2018 - December 2018 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(1.29)
January 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		2,920,000
January 2018 - December 2018 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		45
Ceilings (in dollars per Mmbtu's/Bbl's)		50
January 2018 - December 2018 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		53
Ceilings (in dollars per Mmbtu's/Bbl's)		60
January 2018 - December 2018 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		49.29
Ceilings (in dollars per Mmbtu's/Bbl's)		56.82
January 2018 - December 2018 | Collars | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU		2,737,500
January 2018 - December 2018 | Collars | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.22
January 2018 - December 2018 | Collars | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.03
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.38
January 2018 - December 2018 | Collars | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.01
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.30
April 2018 - December 2018 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		275,000
Basis Differential		(1.15)
April 2018 - December 2018 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(1.15)
April 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		275,000
Floors (in dollars per Mmbtu's/Bbl's)		46.75
Ceilings (in dollars per Mmbtu's/Bbl's)		51.75
April 2018 - December 2018 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		46.75
Ceilings (in dollars per Mmbtu's/Bbl's)		51.75
July 2018 - December 2018 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,012,000
July 2018 - December 2018 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		(0.98)
July 2018 - December 2018 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		(1.18)
July 2018 - December 2018 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(1.12)
July 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		184,000
Floors (in dollars per Mmbtu's/Bbl's)		48.50
Ceilings (in dollars per Mmbtu's/Bbl's)		53.50
July 2018 - December 2018 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		48.50
Ceilings (in dollars per Mmbtu's/Bbl's)		53.50
October 2018 - December 2018 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	1,012,000
October 2018 - December 2018 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(6.90)
October 2018 - December 2018 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(12.50)
October 2018 - December 2018 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(10.64)
October 2018 - December 2018 | Basis Swap | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU	1,380,000
October 2018 - December 2018 | Basis Swap | Natural gas | Minimum
Derivative and hedging activities
Basis Differential | $ / MMBTU	(1.05)
October 2018 - December 2018 | Basis Swap | Natural gas | Maximum
Derivative and hedging activities
Basis Differential | $ / MMBTU	(1.19)
October 2018 - December 2018 | Basis Swap | Natural gas | Weighted Average
Derivative and hedging activities
Basis Differential | $ / MMBTU	(1.10)
October 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	1,196,000	92,000
Floors (in dollars per Mmbtu's/Bbl's)		50.65
Ceilings (in dollars per Mmbtu's/Bbl's)		55.65
October 2018 - December 2018 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	45
Ceilings (in dollars per Mmbtu's/Bbl's)	50
October 2018 - December 2018 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55.80
Ceilings (in dollars per Mmbtu's/Bbl's)	63
October 2018 - December 2018 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50.08	50.65
Ceilings (in dollars per Mmbtu's/Bbl's)	56.87	55.65
October 2018 - December 2018 | Collars | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU	690,000
October 2018 - December 2018 | Collars | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3.22
October 2018 - December 2018 | Collars | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3.03
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3.38
October 2018 - December 2018 | Collars | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3.01
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3.30
October 2018 - December 2018 | Swaps | Natural gas liquids
Derivative and hedging activities
Volume in Bbl's | bbl	92,000
October 2018 - December 2018 | Swaps | Natural gas liquids | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	32.50
October 2018 - December 2018 | Swaps | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	32.50
October 2018 - December 2018 | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	460,000
Basis Differential	0.35
October 2018 - December 2018 | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	0.35
October 2018 - December 2018 with weighted average price of $59.92 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	1,196,000
October 2018 - December 2018 with weighted average price of $59.92 | Call option | Crude oil | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	59
October 2018 - December 2018 with weighted average price of $59.92 | Call option | Crude oil | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	63
October 2018 - December 2018 with weighted average price of $59.92 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	59.92
October 2018 - December 2018 with weighted average price of $56.87 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	(1,196,000)
October 2018 - December 2018 with weighted average price of $56.87 | Call option | Crude oil | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	50
October 2018 - December 2018 with weighted average price of $56.87 | Call option | Crude oil | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	63
October 2018 - December 2018 with weighted average price of $56.87 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	56.87
January 2019 - March 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	90,000	90,000
Floors (in dollars per Mmbtu's/Bbl's)	46.75	46.75
Ceilings (in dollars per Mmbtu's/Bbl's)	51.75	51.75
January 2019 - March 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	46.75	46.75
Ceilings (in dollars per Mmbtu's/Bbl's)	51.75	51.75
January 2019 - June 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	543,000
January 2019 - June 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(1.15)
January 2019 - June 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(1.33)
January 2019 - June 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(1.22)
January 2019 - September 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	546,000
January 2019 - September 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(6.20)
January 2019 - September 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(7.60)
January 2019 - September 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(6.90)
January 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,365,000	4,380,000
January 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(0.98)	(0.50)
January 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(6.50)	(1.33)
January 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(3.73)	(1.02)
January 2019 - December 2019 | Basis Swap | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU	9,307,500
January 2019 - December 2019 | Basis Swap | Natural gas | Minimum
Derivative and hedging activities
Basis Differential | $ / MMBTU	(1.05)
January 2019 - December 2019 | Basis Swap | Natural gas | Maximum
Derivative and hedging activities
Basis Differential | $ / MMBTU	(1.40)
January 2019 - December 2019 | Basis Swap | Natural gas | Weighted Average
Derivative and hedging activities
Basis Differential | $ / MMBTU	(1.18)
January 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	5,110,000	1,825,000
January 2019 - December 2019 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50	50
Ceilings (in dollars per Mmbtu's/Bbl's)	55	55
January 2019 - December 2019 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	58	51
Ceilings (in dollars per Mmbtu's/Bbl's)	63	57.30
January 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	53.12	50.24
Ceilings (in dollars per Mmbtu's/Bbl's)	58.98	55.70
January 2019 - December 2019 | Collars | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU	8,395,000
January 2019 - December 2019 | Collars | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	2.52
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3
January 2019 - December 2019 | Collars | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	2.65
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3.03
January 2019 - December 2019 | Collars | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	2.60
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	3.01
January 2019 - December 2019 | Swaps | Natural gas liquids
Derivative and hedging activities
Volume in Bbl's | bbl	1,460,000
January 2019 - December 2019 | Swaps | Natural gas liquids | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	29.08
January 2019 - December 2019 | Swaps | Natural gas liquids | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	30.15
January 2019 - December 2019 | Swaps | 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 Bbl's | bbl	1,825,000
Basis Differential	0.35
January 2019 - December 2019 | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	0.35
April 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	275,000
Floors (in dollars per Mmbtu's/Bbl's)	55
Ceilings (in dollars per Mmbtu's/Bbl's)	62.85
April 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55
Ceilings (in dollars per Mmbtu's/Bbl's)	62.85
July 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	184,000
Floors (in dollars per Mmbtu's/Bbl's)	55
Ceilings (in dollars per Mmbtu's/Bbl's)	69
July 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55
Ceilings (in dollars per Mmbtu's/Bbl's)	69
October 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	368,000
October 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	3.45
October 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	3.75
October 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	3.65
October 2019 - December 2019 | Swaps | Natural gas liquids
Derivative and hedging activities
Volume in Bbl's | bbl	92,000
October 2019 - December 2019 | Swaps | Natural gas liquids | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	32.50
October 2019 - December 2019 | Swaps | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	32.50
January 2020 - December 2020 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,928,000
January 2020 - December 2020 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	2
January 2020 - December 2020 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	3.75
January 2020 - December 2020 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	2.82
January 2020 - December 2020 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	549,000
Floors (in dollars per Mmbtu's/Bbl's)	50
Ceilings (in dollars per Mmbtu's/Bbl's)	70
January 2020 - December 2020 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50
Ceilings (in dollars per Mmbtu's/Bbl's)	70
January 2020 - December 2020 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	1,464,000
Ceilings (in dollars per Mmbtu's/Bbl's)	70
January 2020 - December 2020 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	70
January 2020 - December 2020 | Swaps | Natural gas liquids
Derivative and hedging activities
Volume in Bbl's | bbl	732,000
Floors (in dollars per Mmbtu's/Bbl's)	31
January 2020 - December 2020 | Swaps | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	31
January 2020 - December 2020 | Put options | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	915,000
January 2020 - December 2020 | Put options | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55
January 2020 - December 2020 | Put options | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55

DERIVATIVE AND HEDGING ACTIVI_7

DERIVATIVE AND HEDGING ACTIVITIES - Netting Arrangements (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivative Assets
Gross Amounts Presented in the Consolidated Balance Sheet	$ 19,347	$ 677
Amounts Not Offset in the Consolidated Balance Sheet	(18,040)	(231)
Net Amount	1,307	446
Derivative Liabilities
Gross Amounts Presented in the Consolidated Balance Sheet	(123,635)	(26,999)
Amounts Not Offset in the Consolidated Balance Sheet	18,040	231
Net Amount	$ (105,595)	$ (26,768)

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)
Activity related to ARO liability
Liability for asset retirement obligations at the beginning of the period	$ 4,368
Liabilities settled and divested	(110)
Additions	796
Acquisitions	2,465
Accretion expense	225
Revisions in estimated cash flows	(632)
Liability for asset retirement obligations at the end of the period	$ 7,112

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	1 Months Ended	9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)item	Sep. 30, 2017USD ($)
Commitments and contingencies
Rent expense		$ 2,800	$ 3,000
Approximate future minimum lease payments for all non-cancelable operating leases
Remaining period in 2018	$ 846	846
2,019	2,990	2,990
2,020	1,811	1,811
2,021	1,497	1,497
2,022	835	835
Thereafter	1,345	1,345
Total	9,324	9,324
Obligation under contractual commitments
Remaining period in 2018	4,419	4,419
2,019	4,726	4,726
Total	9,145	9,145
Other contractual commitments for, among other things, stacking charges on certain drilling rig commitments
Additional Fees may incur if certain requirements are not met by January 12, 2020	3,000	3,000
Drilling rig commitments
Obligation under contractual commitments
Non-cancelable termination penalties	8,200	8,200
Drilling rig commitments	9,100	$ 9,100
Gathering, transportation and sales | West Texas
Other contractual commitments for, among other things, stacking charges on certain drilling rig commitments
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		11
Gathering, transportation and sales | West Texas | Minimum
Other contractual commitments for, among other things, stacking charges on certain drilling rig commitments
Period of commitment for production from the date of first production		1 year
Gathering, transportation and sales | West Texas | Maximum
Other contractual commitments for, among other things, stacking charges on certain drilling rig commitments
Period of commitment for production from the date of first production		20 years
Purchase agreement for natural gas treating equipment
Other contractual commitments for, among other things, stacking charges on certain drilling rig commitments
Purchase agreement amount	13,300
Remaining commitment	$ 9,800	$ 9,800

STOCKHOLDERS' EQUITY - Preferre

STOCKHOLDERS' EQUITY - Preferred Stock and Non-Cash Preferred Stock Dividend (Details) - USD ($) $ / shares in Units, $ in Thousands

Feb. 09, 2018

Apr. 06, 2017

Feb. 27, 2017

Jan. 24, 2017

Jan. 18, 2017

Mar. 31, 2018

Jun. 30, 2017

Mar. 31, 2017

May 31, 2017

Sep. 30, 2018

Dec. 31, 2017

Mar. 16, 2017

Stockholders' equity

Shares issued

9,200,000

Share price (in dollars per share)

$ 6.90

Offering costs including placement agent fees

$ 3,044

$ 90

$ 11,829

Par value of common stock (in dollars per share)

$ 0.0001

$ 0.0001

$ 0.0001

8% Convertible Preferred Stock

Stockholders' equity

Shares issued

5,518

Dividend rate (as a percent)

8.00%

8.00%

Preferred stock, par value (in dollars per share)

$ 0.0001

Number of shares of common stock to be issued upon conversion

10,000

Proceeds from issuance of convertible preferred stock per share

$ 72,500

Gross proceeds from preferred stock offering

$ 400,100

Share price (in dollars per share)

$ 7.25

$ 8.12

Offering costs including placement agent fees

$ 11,900

Par value of common stock (in dollars per share)

$ 0.0001

Preferred dividend

$ 0

Conversion price (in dollars per share)

$ 0.87

Beneficial conversion proceeds

$ 48,000

Discount amortization period

65 months

Amortization of beneficial conversion discount

$ 47,200

$ 800

Common Stock

Stockholders' equity

Shares issued

55,200,000

STOCKHOLDERS' EQUITY-Common sto

STOCKHOLDERS' EQUITY-Common stock and warrants (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Feb. 09, 2018	Sep. 30, 2018	Dec. 31, 2017	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
Number of warrants issued				4.7
Warrants Issued to Former Holders of Unsecured and Convertible Notes
Stockholders' equity
Number of warrants issued				4.7
Exercise price (in dollars per share)				$ 14.04

STOCKHOLDERS' EQUITY - Incentiv

STOCKHOLDERS' EQUITY - Incentive Plans (Details) - USD ($) shares in Millions, $ in Millions	Apr. 06, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Sep. 09, 2016
General and administrative
Stock-based compensation
Compensation expense recorded		$ 4.4	$ 12.3	$ 12.2	$ 33.5
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		4.9		4.9		7.7

STOCKHOLDERS' EQUITY - Stock Op

STOCKHOLDERS' EQUITY - Stock Options (Details) - Stock options $ / shares in Units, shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / sharesshares
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
2016 Incentive Plan
Stock-based compensation
Exercise of stock options | $	$ 0.3
Unrecognized compensation expense stock option | $	$ 7.1	$ 17.3
Weighted average remaining vesting period	1 year 1 month 6 days	1 year 6 months
2016 Incentive Plan | Employee
Stock-based compensation
Granted (in shares) | shares	1.2	1.8
Granted (in dollars per share)	$ 5.65	$ 7.72
2016 Incentive Plan | Employee | Minimum
Stock-based compensation
Granted (in dollars per share)		6.55
2016 Incentive Plan | Employee | Maximum
Stock-based compensation
Granted (in dollars per share)		$ 7.75

STOCKHOLDERS' EQUITY - Restrict

STOCKHOLDERS' EQUITY - Restricted Stock (Details) - 2016 Incentive Plan - Restricted Stock - USD ($) $ / shares in Units, shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Stock-based compensation
Weighted average grant date price (in dollars per share)	$ 5.47	$ 7.07
Unrecognized compensation expense other than options	$ 8.6	$ 5.7
Weighted average remaining vesting period	1 year 2 months 12 days	1 year 3 months 18 days
Minimum
Stock-based compensation
Grant date price (in dollars per share)	$ 3.75	$ 6.08
Maximum
Stock-based compensation
Grant date price (in dollars per share)	$ 5.65	$ 7.75
Employees and non-employee directors
Stock-based compensation
Number of shares granted	2.3	2
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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Basic:
Net income (loss) available to common stockholders	$ (81,837)	$ 419,287	$ (100,709)	$ 580,809
Weighted average basic number of common shares outstanding	158,011	146,944	156,628	127,458
Basic net income (loss) per share of common share (in dollars per share)	$ (0.52)	$ 2.85	$ (0.64)	$ 4.56
Diluted:
Net income (loss) available to common stockholders	$ (81,837)	$ 419,287	$ (100,709)	$ 580,809
Weighted average basic number of common shares outstanding	158,011	146,944	156,628	127,458
Common stock equivalent shares representing shares included upon Vesting of restricted shares		1,546		952
Weighted average diluted number of common shares outstanding	158,011	148,490	156,628	128,410
Diluted net income (loss) per share of common stock (in dollars per share)	$ (0.52)	$ 2.82	$ (0.64)	$ 4.52
Common stock equivalents of stock options, restricted shares and warrants not included in the computations of diluted earnings per share of common stock as their effect would have been anti-dilutive due to the net losses (in shares)	14,900	11,700	14,300	19,000

ADDITIONAL FINANCIAL STATEMEN_3

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$ 37,085	$ 24,110
Joint interest accounts	8,736	2,249
Other	943	10,057
Total	46,764	36,416
Prepaids and other:
Prepaids	4,684	4,324
Income tax receivable	6,250	6,250
Other	35	54
Total	10,969	10,628
Funds in escrow and other:
Funds in escrow	568	563
Other	1,347	1,128
Total	1,915	1,691
Accounts payable and accrued liabilities:
Trade payables	51,192	35,688
Accrued oil and natural gas capital costs	53,692	50,743
Revenues and royalties payable	20,587	20,256
Accrued interest expense	5,858	10,985
Accrued employee compensation	5,086	9,805
Accrued lease operating expenses	4,667	2,024
Other	295	1,586
Total	$ 141,377	$ 131,087

SUBSEQUENT EVENTS - (Details)

SUBSEQUENT EVENTS - (Details) - USD ($) $ in Millions	Oct. 31, 2018	Nov. 07, 2018	Sep. 30, 2018
Senior revolving credit facility
SUBSEQUENT EVENTS
Borrowing capacity			$ 200
Subsequent events | Senior revolving credit facility
SUBSEQUENT EVENTS
Borrowing capacity		$ 275
Purchase and Sale Agreement | Subsequent events | Water Infrastructure Assets
SUBSEQUENT EVENTS
Maximum sale price	$ 325
Cash price payable at closing	200
Incentives payable per year if certain thresholds are met	$ 25
Deferred period of sale price based on certain thresholds	5 years
Transition services period	2 months
Transition services period to install additional water service and treating infrastructure	6 months
Amount that will not be paid until definitive agreement is executive	$ 30