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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2017	Feb. 21, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	Matador Resources Co
Entity Central Index Key	0001520006
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,910,451,565
Entity Common Stock, Shares Outstanding		109,248,747

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash	$ 96,505	$ 212,884
Restricted cash	5,977	1,258
Accounts receivable
Oil and natural gas revenues	65,962	34,154
Joint interest billings	67,225	19,347
Other	8,031	5,167
Derivative instruments	1,190	0
Lease and well equipment inventory	5,993	3,045
Prepaid expenses and other assets	6,287	3,327
Total current assets	257,170	279,182
Oil and natural gas properties, full-cost method
Evaluated	3,004,770	2,408,305
Unproved and unevaluated	637,396	479,736
Midstream and other property and equipment	281,096	160,795
Less accumulated depletion, depreciation and amortization	(2,041,806)	(1,864,311)
Net property and equipment	1,881,456	1,184,525
Other assets
Other assets	7,064	958
Total assets	2,145,690	1,464,665
Current liabilities
Accounts payable	11,757	4,674
Accrued liabilities	174,348	101,460
Royalties payable	61,358	23,988
Amounts due to affiliates	10,302	8,651
Derivative instruments	16,429	24,203
Advances from joint interest owners	2,789	1,700
Amounts due to joint ventures	4,873	4,251
Other current liabilities	750	578
Total current liabilities	282,606	169,505
Long-term liabilities
Senior unsecured notes payable	574,073	573,924
Asset retirement obligations	25,080	19,725
Derivative instruments	0	751
Amounts due to joint ventures	0	1,771
Other long-term liabilities	6,385	7,544
Total long-term liabilities	605,538	603,715
Commitments and contingencies (Note 13)
Shareholders' equity
Common stock — $0.01 par value, 160,000,000 and 120,000,000 shares authorized; 108,513,597 and 99,518,764 shares issued; and 108,510,160 and 99,511,931 shares outstanding, respectively	1,085	995
Additional paid-in capital	1,666,024	1,325,481
Accumulated deficit	(510,484)	(636,351)
Treasury stock, at cost, 3,437 and 6,833 shares, respectively	(69)	0
Total shareholders' equity	1,156,556	690,125
Non-controlling interest in subsidiaries	100,990	1,320
Total shareholders’ equity	1,257,546	691,445
Total liabilities and shareholders’ equity	$ 2,145,690	$ 1,464,665

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Treasury stock (in shares)	3,437	6,833
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	160,000,000	120,000,000
Common stock, shares issued (in shares)	108,513,597	99,518,764
Common stock, shares outstanding (in shares)	108,510,160	99,511,931

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Oil and natural gas revenues	$ 528,684	$ 291,156	$ 278,340
Third-party midstream services revenues	10,198	5,218	1,864
Realized (loss) gain on derivatives	(4,321)	9,286	77,094
Unrealized gain (loss) on derivatives	9,715	(41,238)	(39,265)
Total revenues	544,276	264,422	318,033
Expenses
Production taxes, transportation and processing	58,275	43,046	35,650
Lease operating	67,313	56,202	54,704
Plant and other midstream services operating	13,039	5,389	3,489
Depletion, depreciation and amortization	177,502	122,048	178,847
Accretion of asset retirement obligations	1,290	1,182	734
Full-cost ceiling impairment	0	158,633	801,166
General and administrative	66,016	55,089	50,105
Total expenses	383,435	441,589	1,124,695
Operating income (loss)	160,841	(177,167)	(806,662)
Other income (expense)
Net gain on asset sales and inventory impairment	23	107,277	908
Interest expense	(34,565)	(28,199)	(21,754)
Other income (expense)	3,551	(4)	616
Total other (expense) income	(30,991)	79,074	(20,230)
Income (loss) before income taxes	129,850	(98,093)	(826,892)
Income tax (benefit) provision
Current	(8,157)	(1,036)	2,959
Deferred	0	0	(150,327)
Total income tax benefit	(8,157)	(1,036)	(147,368)
Net income (loss)	138,007	(97,057)	(679,524)
Net income attributable to non-controlling interest in subsidiaries	(12,140)	(364)	(261)
Net income (loss) attributable to Matador Resources Company shareholders	$ 125,867	$ (97,421)	$ (679,785)
Earnings (loss) per common share
Basic (usd per share)	$ 1.23	$ (1.07)	$ (8.34)
Diluted (usd per share)	$ 1.23	$ (1.07)	$ (8.34)
Weighted average common shares outstanding
Basic (in shares)	102,029	91,273	81,537
Diluted (in shares)	102,543	91,273	81,537

Consolidated Statements of Changes in Shareholders' Equity - USD ($)	Total	Common stock	Preferred Stock	Additional paid-in capital	Retained earnings (deficit)	Treasury stock	Parent	Noncontrolling Interest	Convertible Preferred Stock [Member]	Convertible Preferred Stock [Member] Common stock	Convertible Preferred Stock [Member] Preferred Stock	Convertible Preferred Stock [Member] Additional paid-in capital	Convertible Preferred Stock [Member] Parent
Beginning Balance at Dec. 31, 2014	$ 866,541,000	$ 734,000	$ 0	$ 724,819,000	$ 140,855,000	$ 0	$ 866,408,000	$ 133,000
Beginning Balance, shares (in shares) at Dec. 31, 2014		73,374,000	0			31,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock	260,252,000	$ 104,000		260,148,000			260,252,000		$ 32,490,000		$ 1,000	$ 32,489,000	$ 32,490,000
Issuance of Class A common stock, shares		10,329,000									150,000
Conversion of Class B common stock to Class A common stock, shares		(1,500,000)	150,000
Stock Issued During Period, Value, Conversion of Convertible Securities	0	$ (15,000)	$ 1,000	14,000			0
Stock options expense related to equity based awards	9,333,000			9,333,000			9,333,000
Stock options exercised, shares		25,000
Stock options exercised	10,000			10,000			10,000
Liability-based stock option awards settled, shares		25,000
Liability-based stock option awards settled	446,000			446,000			446,000
Restricted stock issued	0	$ (4,000)		(4,000)			0
Restricted stock issued, shares		429,000
Cost to issue equity	(1,151,000)	$ 0		(1,151,000)			(1,151,000)
Restricted stock forfeited, Shares						138,000
Restricted stock forfeited	0			0			0
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	562,000							562,000
Vesting of restricted stock units		52,000
Restricted stock and restricted stock units expense	0	$ 1,000		(1,000)			0
Cancellation of treasury stock (shares)		(167,000)				(167,000)
Cancellation of treasury stock	0	$ (2,000)		2,000		$ 0	0
Current period net income	(679,785,000)
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	0
Class B dividends declared					0
Net (loss) income	(679,524,000)				(679,785,000)		(679,785,000)	261,000
Ending Balance, shares (in shares) at Dec. 31, 2015		85,567,000	0			2,000
Ending Balance at Dec. 31, 2015	488,959,000	$ 856,000	$ 0	1,026,077,000	(538,930,000)	$ 0	488,003,000	956,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock	288,510,000	$ 135,000		288,375,000			288,510,000		0	$ 4,000	$ 0	(4,000)	0
Issuance of Class A common stock, shares		13,500,000								471,000	0
Issuance of Class A common stock to Board member and advisors, shares		51,000
Issuance of Class A common stock to Board member and advisors		$ 1,000							0			(1,000)	0
Stock options expense related to equity based awards	11,958,000			11,958,000			11,958,000
Stock options exercised, shares		36,000
Stock options exercised	10,000			10,000			10,000
Liability-based stock option awards settled, shares		10,000
Liability-based stock option awards settled	255,000			255,000			255,000
Cost to issue equity	(1,190,000)			(1,190,000)			(1,190,000)
Restricted stock forfeited, Shares						120,000
Restricted stock forfeited	0			0			0
Cancellation of treasury stock (shares)		(116,000)				(116,000)
Cancellation of treasury stock	0	$ (1,000)		1,000		$ 0	0
Current period net income	(97,421,000)
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	0
Net (loss) income	$ (97,057,000)				(97,421,000)		(97,421,000)	364,000
Ending Balance, shares (in shares) at Dec. 31, 2016	99,511,931	99,519,000	0			6,000
Ending Balance at Dec. 31, 2016	$ 691,445,000	$ 995,000	$ 0	1,325,481,000	(636,351,000)	$ 0	690,125,000	1,320,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock	208,720,000	$ 80,000		208,640,000			208,720,000		0	$ 5,000		(5,000)	0
Issuance of Class A common stock, shares		8,000,000								530,000
Issuance of Class A common stock to Board member and advisors, shares		77,000
Issuance of Class A common stock to Board member and advisors		$ 1,000							$ 0			$ (1,000)	$ 0
Stock options expense related to equity based awards	$ 19,594,000			19,594,000			19,594,000
Stock options exercised, shares	833,000	514,000
Stock options exercised	$ (1,184,000)	$ 5,000		(1,189,000)			(1,184,000)
Cost to issue equity	(280,000)			(280,000)			(280,000)
Restricted stock forfeited, Shares						123,000
Restricted stock forfeited	(1,658,000)					$ (1,658,000)	(1,658,000)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	(2,653,000)			(1,250,000)			(1,250,000)	(1,403,000)
Contributions related to formation of Joint Venture (see Note 5)	171,500,000			116,622,000			116,622,000	54,878,000
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	44,100,000							44,100,000
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries	(10,045,000)							(10,045,000)
Cancellation of treasury stock (shares)		(126,000)				(126,000)
Cancellation of treasury stock	0	$ (1,000)		(1,588,000)		$ (1,589,000)	0
Current period net income	125,867,000
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	44,100,000
Net (loss) income	$ 138,007,000						125,867,000	12,140,000
Ending Balance, shares (in shares) at Dec. 31, 2017	108,510,160	108,514,000	0			3,000
Ending Balance at Dec. 31, 2017	$ 1,257,546,000	$ 1,085,000	$ 0	$ 1,666,024,000	$ (510,484,000)	$ (69,000)	$ 1,156,556,000	$ 100,990,000

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net (loss) income	$ 138,007	$ (97,057)	$ (679,524)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives	(9,715)	41,238	39,265
Depletion, depreciation and amortization	177,502	122,048	178,847
Accretion of asset retirement obligations	1,290	1,182	734
Full-cost ceiling impairment	0	158,633	801,166
Stock-based compensation expense	16,654	12,362	9,450
Deferred income tax benefit	0	0	(150,327)
Amortization of debt issuance cost	468	1,148	852
Net gain on asset sales and inventory impairment	(23)	(107,277)	(908)
Changes in operating assets and liabilities
Accounts receivable	(82,549)	(14,259)	3,633
Lease and well equipment inventory	(3,623)	(700)	(180)
Prepaid expenses	(2,960)	(124)	(544)
Other assets	(6,425)	490	(552)
Accounts payable, accrued liabilities and other current liabilities	33,559	6,611	1,375
Royalties payable	37,370	7,495	1,654
Advances from joint interest owners	1,089	1,000	700
Income taxes payable	0	(2,848)	2,405
Other long-term liabilities	(1,519)	4,144	489
Net cash provided by operating activities	299,125	134,086	208,535
Investing activities
Oil and natural gas properties capital expenditures	(699,445)	(379,067)	(432,715)
Expenditures for other property and equipment	(120,816)	(74,845)	(64,499)
Proceeds from sale of assets	977	5,173	139,836
Business combination, net of cash acquired	0	0	(24,028)
Restricted cash	0	43,098	(43,098)
Restricted cash in less-than-wholly-owned subsidiaries	(4,719)	1	(650)
Net cash used in investing activities	(824,003)	(405,640)	(425,154)
Financing activities
Repayments of borrowings	0	(120,000)	(476,982)
Borrowings under Credit Agreement	0	120,000	125,000
Proceeds from issuance of common stock	208,720	288,510	188,720
Proceeds from issuance of senior unsecured notes	0	184,625	400,000
Cost to issue equity	(280)	(847)	(1,158)
Cost to issue senior unsecured notes	0	(2,734)	(9,598)
Proceeds from stock options exercised	2,920	100	10
Capital commitments from non-controlling interest owners of less-than-wholly-owned subsidiaries	0	0	562
Contributions related to formation of Joint Venture	171,500	0	0
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	44,100	0	0
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	10,045	0	0
Taxes paid related to net share settlement of stock-based compensation	5,763	1,948	1,610
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	(2,653)	0	0
Net cash provided by financing activities	408,499	467,706	224,944
(Decrease) increase in cash	(116,379)	196,152	8,325
Cash at beginning of year	212,884	16,732	8,407
Cash at end of year	$ 96,505	$ 212,884	$ 16,732

Nature of Operations	12 Months Ended
Nature of Operations	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS	Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Restricted Cash

Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $23.1 million, $15.7 million and $6.9 million of its general and administrative costs in 2017, 2016 and 2015, respectively. The Company capitalized $7.3 million, $3.7 million and $3.9 million of its interest expense for the years ended December 31, 2017, 2016 and 2015, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2017, these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the year ended December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2017.

During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes periodically exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million, exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.

Midstream and Other Property and Equipment

Midstream and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream and other property and equipment.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments.

Revenue Recognition

The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services have been rendered and the price is fixed and determinable. See below for a discussion of the impact of the adoption of Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) on the Company’s 2018 consolidated financial statements.

For the year ended December 31, 2017, four significant purchasers accounted for 60% of the Company’s total oil, natural gas and natural gas liquids revenues: Occidental Energy Marketing, Inc. (23%), Plains Marketing, L.P. (14%), Shell Trading (US) Company (12%) and Western Refining Crude Oil (11%). For the year ended December 31, 2016, three significant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc. (13%). For the year ended December 31, 2015, three significant purchasers accounted for approximately 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (33%), Enterprise Crude Oil LLC (14%) and Sequent Energy Management, L.P. (12%). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2017, 2016 and 2015, approximately 43%, 38% and 39%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

Stock-Based Compensation

The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units.

The Company’s consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015 include a stock-based compensation (non-cash) expense of $16.7 million, $12.4 million and $9.5 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $3.0 million (including a one-time expense of $1.5 million resulting from a change in the vesting schedule applicable to equity awards granted to independent members of the Company’s Board of Directors), $1.0 million and $0.9 million in 2017, 2016 and 2015, respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2017, 2016 and 2015, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2017, 2016 and 2015.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The legislation significantly changes U.S. tax law by, among other things, lowering corporate income tax rates, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The Tax Cuts and Jobs Act permanently reduces the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21% effective January 1, 2018. For the year ended December 31, 2017, the Company re-valued its deferred tax assets and liabilities at the enacted rate (see Note 7).

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Earnings (Loss) Per Common Share

The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share data).



	Year Ended December 31,
	2017		2016			2015
Net income (loss) attributable to Matador Resources Company shareholders — numerator	$	125,867	$	(97,421	)	$	(679,785	)

Weighted average common shares outstanding — denominator
Basic	102,029		91,273			81,537
Dilutive effect of options and restricted stock units	514		—			—
Diluted weighted average common shares outstanding	102,543		91,273			81,537
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	1.23	$	(1.07	)	$	(8.34	)
Diluted	$	1.23	$	(1.07	)	$	(8.34	)

A total of 1.0 million options to purchase shares of the Company’s common stock were excluded from the calculations above for the year ended December 31, 2017 because their effects were anti-dilutive.

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company.

A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company.

Credit Risk

The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2017 were with Royal Bank of Canada (“RBC”), The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.

Recent Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company adopted the new guidance effective January 1, 2018 using the modified approach. The Company identified all revenue streams and reviewed all contracts and procedures currently in place. The Company determined there is no material impact on its consolidated financial statements as a result of adoption, including no material impact to the timing or amount of revenue recognized, although the Company will be required to include certain additional disclosures regarding revenue from contracts with customers as a result of adoption of ASU 2014-09.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is a land easement practical expedient. If the Company elects to use this practical expedient, the Company should evaluate new or modified land easements under this ASU beginning at the date of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The quantitative impact of the new lease standard will depend on the leases in force at the time of adoption. The Company is currently evaluating the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases, as defined under the new lease standard, determining which practical expedients the Company will use and quantifying the impact of the new lease standard on existing leases. The Company expects to adopt this lease standard on January 1, 2019.

Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230), which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The update should be applied using a retrospective transition method to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 and believes that the adoption of this ASU will change the presentation of its beginning and ending cash balances and eliminate the presentation of changes in restricted cash balances from investing activities in its consolidated statement of cash flows.

Clarifying the Definition of a Business. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017. Entities are required to apply guidance prospectively upon adoption. Effective January 1, 2018, the Company adopted ASU 2017-01, which did not have a material impact on its consolidated financial statements.

Property and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2017 and 2016 (in thousands).



	December 31,
	2017			2016
Oil and natural gas properties
Evaluated (subject to amortization)	$	3,004,770		$	2,408,305
Unproved and unevaluated (not subject to amortization)	637,396			479,736
Total oil and natural gas properties	3,642,166			2,888,041
Accumulated depletion	(2,021,169		)	(1,850,882		)
Net oil and natural gas properties	1,620,997			1,037,159
Midstream and other property and equipment
Midstream equipment and facilities	258,725			145,662
Furniture, fixtures and other equipment	6,109			5,487
Software	7,942			3,206
Land	2,892			1,437
Leasehold improvements	5,428			5,003
Total midstream and other property and equipment	281,096			160,795
Accumulated depreciation	(20,637		)	(13,429		)
Net midstream and other property and equipment	260,459			147,366
Net property and equipment	$	1,881,456		$	1,184,525

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2017 and the year in which these costs were incurred (in thousands).



Description	2017		2016		2015		2014 and prior		Total
Costs incurred for
Property acquisition	$	213,076	$	125,689	$	222,912	$	45,809	$	607,486
Exploration wells	16,688		988		547		—		18,223
Development wells	11,396		272		19		—		11,687
Total	$	241,160	$	126,949	$	223,478	$	45,809	$	637,396

Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2017 are related almost entirely to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past five years. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base.

Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $29.9 million at December 31, 2017. Of this total, $18.2 million was associated with exploration wells and $11.7 million was associated with development wells. The Company anticipates that most of the $29.9 million associated with these wells in progress at December 31, 2017 will be transferred to the amortization base during 2018.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability.

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016 (in thousands).



	Year Ended December 31,
	2017			2016
Beginning asset retirement obligations	$	20,640		$	15,420
Liabilities incurred during period	2,920			1,791
Liabilities settled during period	(430		)	(375		)
Revisions in estimated cash flows	1,836			2,622
Accretion expense	1,290			1,182
Ending asset retirement obligations	26,256			20,640
Less: current asset retirement obligations ⁽¹⁾	(1,176		)	(915		)
Long-term asset retirement obligations	$	25,080		$	19,725

__________________


(1)	Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2017 and 2016.

Business Combinations and Divestitures (Notes)	12 Months Ended
Business Combinations and Divestitures (Notes)	Dec. 31, 2017
Business Combinations [Abstract]
BUSINESS COMBINATIONS AND DIVESTITURES	Joint Venture On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo, a joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets and San Mateo’s other assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest Louisiana, which are not part of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. Five Point provided initial cash consideration of $176.4 million to San Mateo in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by San Mateo to the Company as a special distribution. Through January 31, 2018, the Company had earned an additional $14.7 million in performance incentives to be paid by Five Point in the first quarter of 2018 and may earn an additional $58.8 million in performance incentives over the next four years. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to San Mateo in exchange for its 51% interest. San Mateo is consolidated in the Company’s financial statements with Five Point’s interest in San Mateo being accounted for as a non-controlling interest. The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas to San Mateo pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement (see Note 13). Business Combinations On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross (18,200 net) acres strategically located between the Company’s existing acreage in its Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction. As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). Divestitures On October 1, 2015, the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Wolf Processing Plant. Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million, and the Company received net proceeds of approximately $139.8 million after deducting customary purchase price adjustments of approximately $3.6 million. In conjunction with the sale of the Loving County Processing System, the Company dedicated a significant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15-year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement. Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the gathering and processing agreement. During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing agreement, EnLink began processing the Company’s natural gas produced in this area at the new plant. As such, the gathering and processing agreement the Company entered into with EnLink was no longer considered a lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016. The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. On February 17, 2017, these assets were contributed to San Mateo.

Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

DEBT

Credit Agreement

On September 28, 2012, the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million. MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. Early in the fourth quarter of 2017, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2017, and as a result, on October 25, 2017, the borrowing base was increased to $525.0 million and the maximum facility amount remained at $500.0 million. This October 2017 redetermination constituted the regularly scheduled November 1 redetermination. The Company elected to keep the borrowing commitment at $400.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment. The Credit Agreement matures on October 16, 2020.

In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. Total deferred loan costs were $1.0 million at December 31, 2017, and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.

At December 31, 2017 and February 21, 2018, the Company had no borrowings outstanding under the Credit Agreement and approximately $2.1 million in outstanding letters of credit issued pursuant to the Credit Agreement.

Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company.

A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less.

Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:


•	incur indebtedness or grant liens on any of the Company’s assets;


•	enter into commodity hedging agreements;


•	declare or pay dividends, distributions or redemptions;


•	merge or consolidate;


•	make any loans or investments;


•	engage in transactions with affiliates;


•	engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and


•	take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:


•	failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;


•	failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;


•	bankruptcy or insolvency events involving the Company or its subsidiaries; and


•	a change of control, as defined in the Credit Agreement.

The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2017.

Senior Unsecured Notes

On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes were issued at par value, and the net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger.

On October 21, 2015, and pursuant to a registered exchange offer, Matador exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Registered Notes.

On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes”) in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to and are governed by the same indenture governing the Original Notes (the “Indenture”). The Additional Notes were issued at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5%. The Company received net proceeds from the Notes Offering of approximately $181.5 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes.

On May 24, 2017, pursuant to a registered exchange offer, Matador exchanged all of the privately placed Additional Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Additional Registered Notes,” and, collectively with the Registered Notes, the “Notes”). The terms of the Additional Registered Notes are substantially the same as the terms of the Additional Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Additional Notes do not apply to the Additional Registered Notes.

The Notes are Matador’s senior unsecured obligations and are redeemable as described below. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

On or after April 15, 2018, Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15 of the years indicated.



Year		Redemption Price
2018		105.156%
2019		103.438%
2020		101.719%
2021 and thereafter		100.000%

At any time prior to April 15, 2018, Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering.

In addition, at any time prior to April 15, 2018, Matador may redeem all or part of the Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date.

Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:


•	incur or guarantee additional debt or issue certain types of preferred stock;


•	pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness;


•	transfer or sell assets;


•	make certain investments;


•	create certain liens;


•	enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company;


•	consolidate, merge or transfer all or substantially all of its assets;


•	engage in transactions with affiliates; and


•	create unrestricted subsidiaries.

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events:


•	default for 30 days in the payment when due of interest on the Notes;


•	default in the payment when due of the principal of, or premium, if any, on the Notes;


•	failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets;


•	failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture;


•	failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture;


•	payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more;


•	failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days;


•	any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in a judicial proceeding or being denied or disaffirmed by its maker; and


•	certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

On February 17, 2017, in connection with the formation of San Mateo (see Note 5), Matador entered into a Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”), which supplements the indenture governing the Notes. Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes and (ii) DLK Black River Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released as parties to, and as guarantors of, the Notes. The guarantors of the Notes, following the effectiveness of the Fourth Supplemental Indenture, are referred to herein as the “Guarantor Subsidiaries.” San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes, although they remain restricted subsidiaries under the Indenture.

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2017 and 2016 is as follows (in thousands).



	December 31,
	2017			2016
Deferred tax assets
Unrealized loss on derivatives	$	3,200		$	8,734
Net operating loss carryforwards	118,134			137,757
Alternative minimum tax carryforward	—			8,633
Percentage depletion carryover	1,582			2,595
Property and equipment	—			44,391
Basis increase related to the San Mateo transaction	18,382			—
Total deferred tax assets	141,298			202,110
Valuation allowance on deferred tax assets	(89,482		)	(190,255		)
Total deferred tax assets, net of valuation allowance	51,816			11,855
Deferred tax liabilities
Property and equipment	(40,568		)	—
Other	(11,248		)	(11,855		)
Total deferred tax liabilities	(51,816		)	(11,855		)
Net deferred tax liabilities	$	—		$	—

At December 31, 2017, the Company had net operating loss carryforwards of $498.4 million for federal income tax purposes and $17.0 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.

As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015, the Company recorded impairment charges of $158.6 million and $801.2 million, respectively, exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. At December 31, 2017 and 2016, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges recorded in 2016 and 2015. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at December 31, 2017 and 2016 due to uncertainties regarding the future utilization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized.

The current income tax (benefit) provision for the years ended December 31, 2017, 2016 and 2015 was comprised of the following (in thousands).



	Year Ended December 31,
	2017			2016			2015
Current income tax provision
State income tax	$	21		$	108		$	371
Federal alternative minimum tax	(8,178		)	(1,144		)	2,588
Net current income tax (benefit) provision	$	(8,157	)	$	(1,036	)	$	2,959

Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax benefit for the years ended December 31, 2017, 2016 and 2015 is as follows (in thousands).



	Year Ended December 31,
	2017			2016			2015
Federal tax expense (benefit) at statutory rate ⁽¹⁾	$	45,447		$	(34,333	)	$	(289,412	)
State income tax	368			539			(13,215		)
Permanent differences ⁽²⁾	(4,740		)	(499		)	698
Federal alternative minimum tax	—			1,144			(2,588		)
AMT credit refundable (net of sequestration)	8,178			—			—
Tax Cuts and Jobs Act rate change	51,525			—			—
Change in federal valuation allowance	(101,917		)	33,688			145,777
Change in state valuation allowance	1,139			(539		)	8,413
Net deferred income tax benefit	—			—			(150,327		)
Net current income tax (benefit) provision	(8,157		)	(1,036		)	2,959
Total income tax benefit	$	(8,157	)	$	(1,036	)	$	(147,368	)

__________________


(1)	The statutory federal tax rate was 35% for the years ended December 31, 2017, 2016 and 2015.


(2)	Amount is primarily attributable to stock-based compensation.

The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the State of New Mexico and the State of Louisiana tax returns is 2015. The earliest tax years open for examination for the federal and the State of Texas tax returns are 2013 and 2014, respectively.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2017, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a result of the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act, the Company revalued its deferred tax assets and liabilities at December 31, 2017, which resulted in a $51.5 million tax provision. As the Company maintained a valuation allowance against its federal and state deferred tax assets at December 31, 2017, a corresponding reduction in the valuation allowance was recorded against this tax provision; therefore, there was no net impact to the Company’s consolidated statement of operations for the year ended December 31, 2017 as a result of this corporate income tax rate change.

Corporate alternative minimum taxes were also repealed under the Tax Cuts and Jobs Act; therefore, corporate alternative minimum tax carryforwards will be refunded. As a result, the Company recorded $8.2 million as a current income tax benefit in its consolidated statement of operations for the year ended December 31, 2017.

On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Cuts and Jobs Act. The Company has recognized the tax impacts related to the revaluation of deferred tax assets and liabilities and the repeal of the corporate alternative minimum tax and included these amounts in its consolidated financial statements for the year ended December 31, 2017. The ultimate tax impacts may differ from these provisional amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions the Company has made, additional regulatory guidance that may be issued, and actions the Company may take as a result of the Tax Cuts and Jobs Act.

Stock-Based Compensation

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK-BASED COMPENSATION

Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards

In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company.

In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2017, the 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled.

The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period.

Stock Options

Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five, six or ten years.

The fair value of the 75,000, 77,500 and 87,500 stock option awards outstanding under the 2003 Plan at December 31, 2017, 2016 and 2015, respectively, was estimated using the following weighted average assumptions.



	2017	2016	2015
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	2.14 years	3.14 years	0.39 years
Risk-free interest rate	1.98%	1.70%	0.64%
Volatility	43.60%	47.07%	91.98%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	—%	—%	—%

The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2017, 2016 and 2015.



	2017	2016	2015
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	4.00 years	3.96 years	4.00 years
Risk-free interest rate	1.77%	1.08%	1.15%
Volatility	47.00%	45.68%	56.89%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	3.66%	1.16%	3.21%
Weighted average fair value of stock option awards granted during the year	$10.49	$5.65	$9.90

The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award.

Summarized information about stock options outstanding at December 31, 2017 under the 2003 Plan and the 2012 Incentive Plan is as follows.



	Number of options (in thousands)		Weighted average exercise price
Options outstanding at December 31, 2016	2,887		$	15.59
Options granted	1,034		$	27.09
Options exercised	(833	)	$	9.20
Options forfeited	(24	)	$	23.81
Options expired	—		$	—
Options outstanding at December 31, 2017	3,064		$	21.14



	Options outstanding at December 31, 2017				Options exercisable at December 31, 2017
Range of exercise prices	Shares outstanding (in thousands)	Weighted average remaining contractual life	Weighted average exercise price		Shares exercisable (in thousands)	Weighted average exercise price
$8.18 - $9.55	294	0.69	$	8.46	294	$	8.46
$13.22 - $17.80	625	3.10	$	15.01	11	$	16.45
$19.71 - $22.70	839	2.05	$	21.87	73	$	21.50
$23.40 - $27.33	1,306	4.33	$	26.47	141	$	24.21

At December 31, 2017, the aggregate intrinsic value was $30.6 million for outstanding options and $8.5 million for exercisable options, based on the Company’s quoted closing market price of $31.13 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2017 was 1.07 years.

The total intrinsic value of options exercised during the years ended December 31, 2017, 2016 and 2015 was $13.2 million, $1.6 million and $1.3 million, respectively. The tax related benefit realized from the exercise of stock options totaled $5.0 million, $0.5 million and $0.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.

At December 31, 2017, the total remaining unrecognized compensation expense related to unvested stock options was approximately $9.8 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 0.78 years.

The fair value of options vested during 2017, 2016 and 2015 was $2.1 million, $3.0 million and $1.3 million, respectively.

Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Restricted stock and restricted stock units granted in 2017, 2016 and 2015 were service based awards and vest over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2017 were granted under the 2012 Incentive Plan.

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2017 is presented below (in thousands, except fair value).



	Restricted Stock				Restricted Stock Units
Non-vested restricted stock and restricted stock units	Shares		Weighted average fair value		Shares		Weighted average fair value
Non-vested at December 31, 2016	1,039		$	18.23	82		$	21.32
Granted	531		$	26.25	113		$	23.77
Vested	(429	)	$	16.54	(124	)	$	22.38
Forfeited	(37	)	$	22.94	(6	)	23.45
Non-vested at December 31, 2017	1,104		$	22.59	65		$	23.36

At December 31, 2017, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $36.4 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the Company’s quoted closing market price of $31.13 per share on that date.

At December 31, 2017, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $14.4 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 0.95 years.

The fair value of restricted stock and restricted stock units vested during 2017, 2016 and 2015 was $9.9 million, $4.6 million and $0.8 million, respectively.

The total tax benefit recognized for all stock-based compensation was $6.8 million, $4.3 million and $3.4 million for the years ended December 31, 2017, 2016 and 2015, respectively.

During the years ended December 31, 2017, 2016 and 2015, the total expense attributable to stock options was $7.1 million, $5.9 million and $4.7 million, respectively. At December 31, 2017, 2016 and 2015, the Company had recorded $0.4 million, $1.4 million and zero of long-term liabilities and zero, zero and $1.0 million of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2017, 2016 and 2015, respectively.

During the years ended December 31, 2017, 2016 and 2015, the total expense attributable to restricted stock and restricted stock units was $12.9 million, $6.6 million and $4.7 million, respectively. During the year ended December 31, 2017, the Company capitalized $3.3 million related to stock-based compensation and expensed the remaining $16.7 million.

In mid-February 2018, the Company granted awards of 667,488 shares of restricted stock and options to purchase 563,408 shares of the Company’s common stock at an exercise price of $29.68 per share to certain of its employees. The fair value of these awards was approximately $26.9 million. All of these awards vest ratably over three years.

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2017
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	401(k) Plan All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $0.9 million, $0.7 million and $0.6 million in 2017, 2016 and 2015, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $1.1 million, $0.9 million and $0.8 million in 2017, 2016 and 2015, respectively. The Company made no additional contributions in any reporting period presented.

Equity	12 Months Ended
Equity	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
EQUITY	Stock Offerings, Retirement and Issuances On October 10, 2017, the Company completed a public offering of 8,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.3 million, the Company received net proceeds of approximately $208.4 million. A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to be used for other midstream development, acreage acquisitions and general corporate purposes, including to fund a portion of the Company’s current and future capital expenditures. On June 1, 2017, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 120,000,000 to 160,000,000 shares. On December 9, 2016, the Company completed a public offering of 6,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.4 million, the Company received net proceeds of approximately $145.8 million. On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting offering costs totaling approximately $0.8 million, the Company received net proceeds of approximately $141.5 million. On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $1.2 million, the Company received net proceeds of approximately $187.6 million. As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock. On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2017 to satisfy certain conditions under the merger agreement. Treasury Stock On November 1, 2017, October 27, 2016 and October 30, 2015, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2017, 2016 and 2015, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. The shares of treasury stock outstanding at December 31, 2017, 2016 and 2015 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees.

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids (“NGL”) prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments.

At December 31, 2017, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling and fixed price for the swaps. Each contract is set to expire at varying times during 2018.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2017.



		Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Asset (Liability) (thousands)

Commodity	Calculation Period
Oil - WTI ⁽¹⁾	01/01/2018 - 12/31/2018	2,880,000	$	44.27	$	60.29	(8,414		)
Oil - LLS ⁽²⁾	01/01/2018 - 12/31/2018	720,000	$	45.00	$	63.05	(2,451		)
Natural Gas	01/01/2018 - 12/31/2018	16,800,000	$	2.58	$	3.67	1,190
Total open costless collar contracts							$	(9,675	)

_____________________


(1)	NYMEX West Texas Intermediate crude oil.


(2)	Argus Louisiana Light Sweet crude oil.

The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2017.



Commodity	Calculation Period	Notional Quantity (Bbl or Gal)	Fixed Price ($/Bbl or $/Gal)			Fair Value of Asset (Liability) (thousands)
Oil Basis Swaps	01/01/2018 - 12/31/2018	5,220,000	$	(1.02	)	$	(5,564	)
Total open swap contracts						$	(5,564	)
Total open derivative financial instruments						$	(15,239	)

From time-to-time, we enter into derivative financial instruments with certain counterparties. These derivative financial instruments are subject to master netting arrangements, and all but one counterparty allow for cross-commodity master netting provided the settlements dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2017 and December 31, 2016 (in thousands).



Derivative Instruments	Gross amounts recognized			Gross amounts netted in the consolidated balance sheets			Net amounts presented in the consolidated balance sheets
December 31, 2017
Current assets	$	131,092		$	(129,902	)	$	1,190
Current liabilities	(146,331		)	129,902			(16,429		)
Total	$	(15,239	)	$	—		$	(15,239	)
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.



		Year Ended December 31,
Type of Instrument	Location in Statement of Operations	2017			2016			2015
Derivative Instrument
Oil	Revenues: Realized (loss) gain on derivatives	$	(3,657	)	$	5,851		$	62,259
Natural Gas	Revenues: Realized (loss) gain on derivatives	(608		)	3,435			12,653
Natural Gas Liquids (NGL)	Revenues: Realized (loss) gain on derivatives	(56		)	—			2,182
Realized (loss) gain on derivatives		(4,321		)	9,286			77,094
Oil	Revenues: Unrealized gain (loss) on derivatives	2,638			(18,969		)	(31,897		)
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	7,077			(22,269		)	(5,440		)
Natural Gas Liquids (NGL)	Revenues: Unrealized loss on derivatives	—			—			(1,928		)
Unrealized gain (loss) on derivatives		9,715			(41,238		)	(39,265		)
Total		$	5,394		$	(31,952	)	$	37,829

Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is 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). Fair value measurements are classified and disclosed in one of the following categories.


Level 1	Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2

Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.


Level 3	Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

At December 31, 2017 and 2016, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximate their fair values due to their short-term maturities.

At December 31, 2017 and 2016, the fair value of the Company’s Notes was $614.1 million and $605.2 million, respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy.

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2017 and 2016 (in thousands).



	Fair Value Measurements at December 31, 2017 using
Description	Fair Value Measurements at December 31, 2017 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Natural gas derivatives	$	—	$	1,190		$	—	$	1,190
Oil derivatives and basis swaps	—		(16,429		)	—		(16,429		)
Total	$	—	$	(15,239	)	$	—	$	(15,239	)



	Fair Value Measurements at December 31, 2016 using
Description	Fair Value Measurements at December 31, 2016 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Oil and natural gas derivatives	$	—	$	(24,954	)	$	—	$	(24,954	)
Total	$	—	$	(24,954	)	$	—	$	(24,954	)

Additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified as Level 2 in the fair value hierarchy.

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2017 and 2016. The Company determined the value of the lease and well equipment inventory using Level 3 inputs and assumptions.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

Office Lease

The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The lease for the Company’s corporate headquarters expires during 2026. The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease.

From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties.

The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2017 (in thousands).



Year Ending December 31,	Amount
2018	$	2,495
2019	2,528
2020	2,602
2021	2,660
2022	2,774
Thereafter	9,561
Total	$	22,620

Rent expense, including fees for operating expenses and consumption of electricity, was $2.6 million, $2.9 million and $1.7 million for 2017, 2016 and 2015, respectively.

Processing, Transportation and Salt Water Disposal Commitments

Delaware Basin — Loving County, Texas Natural Gas Processing

In late 2015, the Company entered into a 15-year, fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2017, the total deficiency fee required to be paid would be approximately $8.4 million. In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $14.4 million and $9.8 million in processing and gathering fees under this agreement during the years ended December 31, 2017 and 2016, respectively. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants.

Delaware Basin — Eddy County, New Mexico Natural Gas Transportation

In late 2017, the Company entered into an 18-year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue natural gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Under this agreement, if the Company does not meet the volume commitment for transportation in a contract year, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. The minimum contractual obligation at December 31, 2017 was approximately $59.4 million. The Company paid approximately $0.2 million in transportation fees, which included no deficiency fees, under this agreement during the year ended December 31, 2017.

In late 2017, the Company also entered into a fixed-fee NGL transportation and fractionation agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant. The Company is committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed late in 2019. The Company has no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the Company does not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven-year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. The Company’s minimum contractual obligation over the seven-year period containing minimum NGL commitments would be approximately $132.5 million.

Delaware Basin — San Mateo

The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at December 31, 2017 was approximately $232.6 million. The Company paid approximately $39.4 million in fees under the Operational Agreements during the year ended December 31, 2017.

Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed into service in 2018. San Mateo’s total commitments under these agreements are $55.3 million. The subsidiary of San Mateo paid approximately $49.7 million under these agreements during the year ended December 31, 2017. As of December 31, 2017, the remaining obligations under these agreements were $5.6 million, which are expected to be incurred within the next year.

On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains All American Pipeline, L.P. (“Plains”) (see Note 18).

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $36.5 million at December 31, 2017.

At December 31, 2017, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $24.8 million at December 31, 2017. The Company expects these costs to be incurred within the next year.

Legal Proceedings

The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

Supplemental Disclosures

12 Months Ended

Dec. 31, 2017

Supplemental Disclosures [Abstract]

SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2017 and 2016 (in thousands).



	December 31,
	2017		2016
Accrued evaluated and unproved and unevaluated property costs	$	105,347	$	54,273
Accrued support equipment and facilities costs	14,823		15,139
Accrued lease operating expenses	12,611		16,009
Accrued interest on debt	8,345		6,541
Accrued asset retirement obligations	1,176		915
Accrued partners’ share of joint interest charges	27,628		5,572
Other	4,418		3,011
Total accrued liabilities	$	174,348	$	101,460

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2017, 2016 and 2015 (in thousands).



	Year Ended December 31,
	2017			2016			2015
Cash paid for income taxes	$	—		$	2,895		$	506
Cash paid for interest expense, net of amounts capitalized	$	32,760		$	27,464		$	16,154
Increase in asset retirement obligations related to mineral properties	$	4,385		$	3,817		$	2,510
(Decrease) increase in asset retirement obligations related to support equipment and facilities	$	(60	)	$	222		$	383
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	$	48,929		$	1,775		$	(30,683	)
(Decrease) increase in liabilities for support equipment and facilities	$	(955	)	$	(588	)	$	12,076
Issuance of restricted stock units for director and advisor services	$	—		$	992		$	584
Stock-based compensation expense recognized as liability	$	362		$	569		$	79
(Decrease) increase in liabilities for accrued cost to issue equity	$	(343	)	$	343		$	—
Transfer of inventory (to) from oil and natural gas properties	$	(374	)	$	395		$	615
Transfer of inventory to midstream and other property and equipment	$	(317	)	$	—		$	—

Subsidiary Guarantors (Notes)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

SUBSIDIARY GUARANTORS

On April 14, 2015, Matador issued the Original Notes and on December 9, 2016, Matador issued the Additional Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). Matador filed a registration statement on Form S-3 with the SEC on August 11, 2017, which became effective upon filing, registering, among other securities, senior and subordinated debt securities and guarantees of debt securities by the Guarantor Subsidiaries. At December 31, 2017, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries are not guarantors of the Notes.

The following presents condensed consolidating financial information of the issuer (Matador), the Non-Guarantor Subsidiaries, the Guarantor Subsidiaries and all entities on a consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.



Condensed Consolidating Balance Sheet December 31, 2017
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	585,109	$	2,912	$	—	$	(588,021	)	$	—
Third-party current assets	2,240		9,334		245,596		—			257,170
Net property and equipment	—		223,178		1,658,278		—			1,881,456
Investment in subsidiaries	1,147,295		—		111,077		(1,258,372		)	—
Third-party long-term assets	6,425		—		3,642		(3,003		)	7,064
Total assets	$	1,741,069	$	235,424	$	2,018,593	$	(1,849,396	)	$	2,145,690
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	588,021	$	(588,021	)	$	—
Third-party current liabilities	8,847		19,891		254,142		(274		)	282,606
Senior unsecured notes payable	574,073		—		—		—			574,073
Other third-party long-term liabilities	1,593		3,466		29,135		(2,729		)	31,465
Total equity attributable to Matador Resources Company	1,156,556		111,077		1,147,295		(1,258,372		)	1,156,556
Non-controlling interest in subsidiaries	—		100,990		—		—			100,990
Total liabilities and equity	$	1,741,069	$	235,424	$	2,018,593	$	(1,849,396	)	$	2,145,690



Condensed Consolidating Balance Sheet December 31, 2016
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	316,791	$	3,571	$	12,091	$	(332,453	)	$	—
Third-party current assets	101,102		4,242		173,838		—			279,182
Net property and equipment	33		113,107		1,071,385		—			1,184,525
Investment in subsidiaries	856,762		—		90,275		(947,037		)	—
Third-party long-term assets	—		—		958		—			958
Total assets	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	12,091	$	320,362	$	(332,453	)	$	—
Third-party current liabilities	9,265		16,632		143,608		—			169,505
Senior unsecured notes payable	573,924		—		—		—			573,924
Other third-party long-term liabilities	1,374		602		27,815		—			29,791
Total equity attributable to Matador Resources Company	690,125		90,275		856,762		(947,037		)	690,125
Non-controlling interest in subsidiaries	—		1,320		—		—			1,320
Total liabilities and equity	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665



Condensed Consolidating Statement of Operations For the Year Ended December 31, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	47,883		$	531,508	$	(35,115	)	$	544,276
Total expenses	5,610			21,260			391,680		(35,115		)	383,435
Operating (loss) income	(5,610		)	26,623			139,828		—			160,841
Net gain on asset sales and inventory impairment	—			—			23		—			23
Interest expense	(34,565		)	—			—		—			(34,565		)
Other income	27			37			3,487		—			3,551
Earnings in subsidiaries	157,589			—			14,251		(171,840		)	—
Income before income taxes	117,441			26,660			157,589		(171,840		)	129,850
Total income tax (benefit) provision	(8,426		)	269			—		—			(8,157		)
Net income attributable to non-controlling interest in subsidiaries	—			(12,140		)	—		—			(12,140		)
Net income attributable to Matador Resources Company shareholders	$	125,867		$	14,251		$	157,589	$	(171,840	)	$	125,867



Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	17,302		$	257,828		$	(10,708	)	$	264,422
Total expenses	5,319			7,031			439,947			(10,708		)	441,589
Operating (loss) income	(5,319		)	10,271			(182,119		)	—			(177,167		)
Net gain on asset sales and inventory impairment	—			—			107,277			—			107,277
Interest expense	(28,199		)	—			—			—			(28,199		)
Other expense	—			—			(4		)	—			(4		)
(Loss) earnings in subsidiaries	(64,349		)	—			9,810			54,539			—
(Loss) income before income taxes	(97,867		)	10,271			(65,036		)	54,539			(98,093		)
Total income tax (benefit) provision	(446		)	97			(687		)	—			(1,036		)
Net income attributable to non-controlling interest in subsidiaries	—			(364		)	—			—			(364		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(97,421	)	$	9,810		$	(64,349	)	$	54,539		$	(97,421	)



Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	6,310		$	316,067		$	(4,344	)	$	318,033
Total expenses	5,739			2,944			1,120,356			(4,344		)	1,124,695
Operating (loss) income	(5,739		)	3,366			(804,289		)	—			(806,662		)
Net gain on asset sales and inventory impairment	—			—			908			—			908
Interest expense	(20,511		)	—			(1,243		)	—			(21,754		)
Other income	—			—			616			—			616
(Loss) earnings in subsidiaries	(658,698		)	—			2,458			656,240			—
(Loss) income before income taxes	(684,948		)	3,366			(801,550		)	656,240			(826,892		)
Total income tax (benefit) provision	(5,163		)	647			(142,852		)	—			(147,368		)
Net income attributable to non-controlling interest in subsidiaries	—			(261		)	—			—			(261		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(679,785	)	$	2,458		$	(658,698	)	$	656,240		$	(679,785	)



Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(307,982	)	$	21,308		$	585,799		$	—		$	299,125
Net cash provided by (used in) investing activities	33			(119,922		)	(597,519		)	(106,595		)	(824,003		)
Net cash provided by (used in) financing activities	208,440			96,307			(2,843		)	106,595			408,499
Decrease in cash	(99,509		)	(2,307		)	(14,563		)	—			(116,379		)
Cash at beginning of year	99,795			2,307			110,782			—			212,884
Cash at end of year	$	286		$	—		$	96,219		$	—		$	96,505



Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(45,215	)	$	6,694		$	172,607		$	—		$	134,086
Net cash used in investing activities	(324,724		)	(64,683		)	(401,034		)	384,801			(405,640		)
Net cash provided by financing activities	469,654			60,110			322,743			(384,801		)	467,706
Increase in cash	99,715			2,121			94,316			—			196,152
Cash at beginning of year	80			186			16,466			—			16,732
Cash at end of year	$	99,795		$	2,307		$	110,782		$	—		$	212,884



Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(31,271	)	$	13,916		$	225,890		$	—		$	208,535
Net cash used in investing activities	(546,715		)	(31,101		)	(410,843		)	563,505			(425,154		)
Net cash provided by financing activities	577,973			17,353			193,123			(563,505		)	224,944
(Decrease) increase in cash	(13		)	168			8,170			—			8,325
Cash at beginning of year	93			18			8,296			—			8,407
Cash at end of year	$	80		$	186		$	16,466		$	—		$	16,732

Related Party Transactions (Notes)	12 Months Ended
Related Party Transactions (Notes)	Dec. 31, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2017, the Company had contributed an aggregate of approximately $4.4 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities.

Segment Reporting (Notes)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Reporting

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, natural gas, oil and salt water gathering services and salt water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo (see Note 5).

The following tables present selected financial information for the periods presented regarding the Company’s operating segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.”



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Year Ended December 31, 2017
Oil and natural gas revenues	$	525,862		$	2,822	$	—		$	—		$	528,684
Midstream services revenues	—			47,037		—			(36,839		)	10,198
Realized loss on derivatives	(4,321		)	—		—			—			(4,321		)
Unrealized gain on derivatives	9,715			—		—			—			9,715
Expenses ⁽¹⁾	333,923			23,420		62,931			(36,839		)	383,435
Operating income (loss) ⁽²⁾	$	197,333		$	26,439	$	(62,931	)	$	—		$	160,841
Total assets	$	1,768,393		$	257,871	$	119,426		$	—		$	2,145,690
Capital expenditures ⁽³⁾	$	753,157		$	114,113	$	5,688		$	—		$	872,958

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $170.5 million and $5.2 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.7 million.


(2)	Includes $12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Year Ended December 31, 2016
Oil and natural gas revenues	$	289,512		$	1,644	$	—		$	—		$	291,156
Midstream services revenues	—			18,982		—			(13,764		)	5,218
Realized gain on derivatives	9,286			—		—			—			9,286
Unrealized loss on derivatives	(41,238		)	—		—			—			(41,238		)
Expenses ⁽¹⁾	391,098			8,254		56,001			(13,764		)	441,589
Operating (loss) income ⁽²⁾	$	(133,538	)	$	12,372	$	(56,001	)	$	—		$	(177,167	)
Total assets	$	1,098,525		$	140,459	$	225,681		$	—		$	1,464,665
Capital expenditures	$	379,881		$	67,566	$	6,913		$	—		$	454,360

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $118.4 million and $2.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.9 million and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment.


(2)	Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Year Ended December 31, 2015
Oil and natural gas revenues	$	277,844		$	496	$	—		$	—		$	278,340
Midstream services revenues	—			11,485		—			(9,621		)	1,864
Realized gain on derivatives	77,094			—		—			—			77,094
Unrealized loss on derivatives	(39,265		)	—		—			—			(39,265		)
Expenses ⁽¹⁾	1,078,534			5,178		50,604			(9,621		)	1,124,695
Operating (loss) income ⁽²⁾	$	(762,861	)	$	6,803	$	(50,604	)	$	—		$	(806,662	)
Total assets	$	1,000,075		$	75,980	$	64,806		$	—		$	1,140,861
Capital expenditures ⁽³⁾	$	622,642		$	75,009	$	786		$	—		$	698,437

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $176.7 million and $1.6 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.5 million and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment.


(2)	Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	In October 2015, the Company sold the Loving County Processing System to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains to gather and transport crude oil for the Company and third-party customers in and around the Rustler Breaks asset area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase Matador’s oil production in the Rustler Breaks asset area and in the Wolf asset area in Loving County, Texas.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Restricted Cash	Restricted Cash Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.
Accounts Receivable	Accounts Receivable The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.
Lease and Well Equipment Inventory	Lease and Well Equipment Inventory Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations.
Property and Equipment	The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $23.1 million, $15.7 million and $6.9 million of its general and administrative costs in 2017, 2016 and 2015, respectively. The Company capitalized $7.3 million, $3.7 million and $3.9 million of its interest expense for the years ended December 31, 2017, 2016 and 2015, respectively. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2017, these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. During the year ended December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2017. During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes periodically exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million, exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. Midstream and Other Property and Equipment Midstream and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream and other property and equipment
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations.
Derivative Financial Instruments	Derivative Financial Instruments From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations.
Revenue Recognition	Revenue Recognition The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received.
Stock-Based Compensation	Stock-Based Compensation The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock. The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units.
Income Taxes	Income Taxes The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2017, 2016 and 2015, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations.
Earnings Per Common Share	Earnings (Loss) Per Common Share The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.
Credit Risk	Credit Risk The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2017 were with Royal Bank of Canada (“RBC”), The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company adopted the new guidance effective January 1, 2018 using the modified approach. The Company identified all revenue streams and reviewed all contracts and procedures currently in place. The Company determined there is no material impact on its consolidated financial statements as a result of adoption, including no material impact to the timing or amount of revenue recognized, although the Company will be required to include certain additional disclosures regarding revenue from contracts with customers as a result of adoption of ASU 2014-09. Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is a land easement practical expedient. If the Company elects to use this practical expedient, the Company should evaluate new or modified land easements under this ASU beginning at the date of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The quantitative impact of the new lease standard will depend on the leases in force at the time of adoption. The Company is currently evaluating the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases, as defined under the new lease standard, determining which practical expedients the Company will use and quantifying the impact of the new lease standard on existing leases. The Company expects to adopt this lease standard on January 1, 2019. Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230), which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The update should be applied using a retrospective transition method to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 and believes that the adoption of this ASU will change the presentation of its beginning and ending cash balances and eliminate the presentation of changes in restricted cash balances from investing activities in its consolidated statement of cash flows. Clarifying the Definition of a Business. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017. Entities are required to apply guidance prospectively upon adoption. Effective January 1, 2018, the Company adopted ASU 2017-01, which did not have a material impact on its consolidated financial statements.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Reconciliations of basic and diluted distributed and undistributed earnings (loss) per common share



	Year Ended December 31,
	2017		2016			2015
Net income (loss) attributable to Matador Resources Company shareholders — numerator	$	125,867	$	(97,421	)	$	(679,785	)

Weighted average common shares outstanding — denominator
Basic	102,029		91,273			81,537
Dilutive effect of options and restricted stock units	514		—			—
Diluted weighted average common shares outstanding	102,543		91,273			81,537
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	1.23	$	(1.07	)	$	(8.34	)
Diluted	$	1.23	$	(1.07	)	$	(8.34	)

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Summary of the Company's property and equipment

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2017 and 2016 (in thousands).



	December 31,
	2017			2016
Oil and natural gas properties
Evaluated (subject to amortization)	$	3,004,770		$	2,408,305
Unproved and unevaluated (not subject to amortization)	637,396			479,736
Total oil and natural gas properties	3,642,166			2,888,041
Accumulated depletion	(2,021,169		)	(1,850,882		)
Net oil and natural gas properties	1,620,997			1,037,159
Midstream and other property and equipment
Midstream equipment and facilities	258,725			145,662
Furniture, fixtures and other equipment	6,109			5,487
Software	7,942			3,206
Land	2,892			1,437
Leasehold improvements	5,428			5,003
Total midstream and other property and equipment	281,096			160,795
Accumulated depreciation	(20,637		)	(13,429		)
Net midstream and other property and equipment	260,459			147,366
Net property and equipment	$	1,881,456		$	1,184,525

Breakdown of the Company's unproved and unevaluated property costs not subject to amortization



Description	2017		2016		2015		2014 and prior		Total
Costs incurred for
Property acquisition	$	213,076	$	125,689	$	222,912	$	45,809	$	607,486
Exploration wells	16,688		988		547		—		18,223
Development wells	11,396		272		19		—		11,687
Total	$	241,160	$	126,949	$	223,478	$	45,809	$	637,396

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of changes in Company's asset retirement obligations

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016 (in thousands).



	Year Ended December 31,
	2017			2016
Beginning asset retirement obligations	$	20,640		$	15,420
Liabilities incurred during period	2,920			1,791
Liabilities settled during period	(430		)	(375		)
Revisions in estimated cash flows	1,836			2,622
Accretion expense	1,290			1,182
Ending asset retirement obligations	26,256			20,640
Less: current asset retirement obligations ⁽¹⁾	(1,176		)	(915		)
Long-term asset retirement obligations	$	25,080		$	19,725

__________________


(1)	Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2017 and 2016.

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Summary of net deferred tax position

The Company’s net deferred tax position as of December 31, 2017 and 2016 is as follows (in thousands).



	December 31,
	2017			2016
Deferred tax assets
Unrealized loss on derivatives	$	3,200		$	8,734
Net operating loss carryforwards	118,134			137,757
Alternative minimum tax carryforward	—			8,633
Percentage depletion carryover	1,582			2,595
Property and equipment	—			44,391
Basis increase related to the San Mateo transaction	18,382			—
Total deferred tax assets	141,298			202,110
Valuation allowance on deferred tax assets	(89,482		)	(190,255		)
Total deferred tax assets, net of valuation allowance	51,816			11,855
Deferred tax liabilities
Property and equipment	(40,568		)	—
Other	(11,248		)	(11,855		)
Total deferred tax liabilities	(51,816		)	(11,855		)
Net deferred tax liabilities	$	—		$	—

Income tax expense reconciled to the tax computed at the statutory federal rate

The current income tax (benefit) provision for the years ended December 31, 2017, 2016 and 2015 was comprised of the following (in thousands).



	Year Ended December 31,
	2017			2016			2015
Current income tax provision
State income tax	$	21		$	108		$	371
Federal alternative minimum tax	(8,178		)	(1,144		)	2,588
Net current income tax (benefit) provision	$	(8,157	)	$	(1,036	)	$	2,959



	Year Ended December 31,
	2017			2016			2015
Federal tax expense (benefit) at statutory rate ⁽¹⁾	$	45,447		$	(34,333	)	$	(289,412	)
State income tax	368			539			(13,215		)
Permanent differences ⁽²⁾	(4,740		)	(499		)	698
Federal alternative minimum tax	—			1,144			(2,588		)
AMT credit refundable (net of sequestration)	8,178			—			—
Tax Cuts and Jobs Act rate change	51,525			—			—
Change in federal valuation allowance	(101,917		)	33,688			145,777
Change in state valuation allowance	1,139			(539		)	8,413
Net deferred income tax benefit	—			—			(150,327		)
Net current income tax (benefit) provision	(8,157		)	(1,036		)	2,959
Total income tax benefit	$	(8,157	)	$	(1,036	)	$	(147,368	)

__________________


(1)	The statutory federal tax rate was 35% for the years ended December 31, 2017, 2016 and 2015.


(2)	Amount is primarily attributable to stock-based compensation.

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Summarized information about stock options outstanding

Summarized information about stock options outstanding at December 31, 2017 under the 2003 Plan and the 2012 Incentive Plan is as follows.



	Number of options (in thousands)		Weighted average exercise price
Options outstanding at December 31, 2016	2,887		$	15.59
Options granted	1,034		$	27.09
Options exercised	(833	)	$	9.20
Options forfeited	(24	)	$	23.81
Options expired	—		$	—
Options outstanding at December 31, 2017	3,064		$	21.14

Summarized information about outstanding and exercisable stock option



	Options outstanding at December 31, 2017				Options exercisable at December 31, 2017
Range of exercise prices	Shares outstanding (in thousands)	Weighted average remaining contractual life	Weighted average exercise price		Shares exercisable (in thousands)	Weighted average exercise price
$8.18 - $9.55	294	0.69	$	8.46	294	$	8.46
$13.22 - $17.80	625	3.10	$	15.01	11	$	16.45
$19.71 - $22.70	839	2.05	$	21.87	73	$	21.50
$23.40 - $27.33	1,306	4.33	$	26.47	141	$	24.21

Summary of the non-vested restricted stock and restricted stock units

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2017 is presented below (in thousands, except fair value).



	Restricted Stock				Restricted Stock Units
Non-vested restricted stock and restricted stock units	Shares		Weighted average fair value		Shares		Weighted average fair value
Non-vested at December 31, 2016	1,039		$	18.23	82		$	21.32
Granted	531		$	26.25	113		$	23.77
Vested	(429	)	$	16.54	(124	)	$	22.38
Forfeited	(37	)	$	22.94	(6	)	23.45
Non-vested at December 31, 2017	1,104		$	22.59	65		$	23.36

2003 Stock and Incentive Plan [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan



	2017	2016	2015
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	2.14 years	3.14 years	0.39 years
Risk-free interest rate	1.98%	1.70%	0.64%
Volatility	43.60%	47.07%	91.98%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	—%	—%	—%

2012 Incentive Plan [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan



	2017	2016	2015
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	4.00 years	3.96 years	4.00 years
Risk-free interest rate	1.77%	1.08%	1.15%
Volatility	47.00%	45.68%	56.89%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	3.66%	1.16%	3.21%
Weighted average fair value of stock option awards granted during the year	$10.49	$5.65	$9.90

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of contracts for oil and natural gas

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2017.



		Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Asset (Liability) (thousands)

Commodity	Calculation Period
Oil - WTI ⁽¹⁾	01/01/2018 - 12/31/2018	2,880,000	$	44.27	$	60.29	(8,414		)
Oil - LLS ⁽²⁾	01/01/2018 - 12/31/2018	720,000	$	45.00	$	63.05	(2,451		)
Natural Gas	01/01/2018 - 12/31/2018	16,800,000	$	2.58	$	3.67	1,190
Total open costless collar contracts							$	(9,675	)

_____________________


(1)	NYMEX West Texas Intermediate crude oil.


(2)	Argus Louisiana Light Sweet crude oil.

The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2017.



Commodity	Calculation Period	Notional Quantity (Bbl or Gal)	Fixed Price ($/Bbl or $/Gal)			Fair Value of Asset (Liability) (thousands)
Oil Basis Swaps	01/01/2018 - 12/31/2018	5,220,000	$	(1.02	)	$	(5,564	)
Total open swap contracts						$	(5,564	)
Total open derivative financial instruments						$	(15,239	)

Summary of offsetting assets



Derivative Instruments	Gross amounts recognized			Gross amounts netted in the consolidated balance sheets			Net amounts presented in the consolidated balance sheets
December 31, 2017
Current assets	$	131,092		$	(129,902	)	$	1,190
Current liabilities	(146,331		)	129,902			(16,429		)
Total	$	(15,239	)	$	—		$	(15,239	)
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)

Summary of offsetting liabilities



Derivative Instruments	Gross amounts recognized			Gross amounts netted in the consolidated balance sheets			Net amounts presented in the consolidated balance sheets
December 31, 2017
Current assets	$	131,092		$	(129,902	)	$	1,190
Current liabilities	(146,331		)	129,902			(16,429		)
Total	$	(15,239	)	$	—		$	(15,239	)
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)

Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations



		Year Ended December 31,
Type of Instrument	Location in Statement of Operations	2017			2016			2015
Derivative Instrument
Oil	Revenues: Realized (loss) gain on derivatives	$	(3,657	)	$	5,851		$	62,259
Natural Gas	Revenues: Realized (loss) gain on derivatives	(608		)	3,435			12,653
Natural Gas Liquids (NGL)	Revenues: Realized (loss) gain on derivatives	(56		)	—			2,182
Realized (loss) gain on derivatives		(4,321		)	9,286			77,094
Oil	Revenues: Unrealized gain (loss) on derivatives	2,638			(18,969		)	(31,897		)
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	7,077			(22,269		)	(5,440		)
Natural Gas Liquids (NGL)	Revenues: Unrealized loss on derivatives	—			—			(1,928		)
Unrealized gain (loss) on derivatives		9,715			(41,238		)	(39,265		)
Total		$	5,394		$	(31,952	)	$	37,829

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Summary of the valuation of the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis



	Fair Value Measurements at December 31, 2017 using
Description	Fair Value Measurements at December 31, 2017 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Natural gas derivatives	$	—	$	1,190		$	—	$	1,190
Oil derivatives and basis swaps	—		(16,429		)	—		(16,429		)
Total	$	—	$	(15,239	)	$	—	$	(15,239	)



	Fair Value Measurements at December 31, 2016 using
Description	Fair Value Measurements at December 31, 2016 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Oil and natural gas derivatives	$	—	$	(24,954	)	$	—	$	(24,954	)
Total	$	—	$	(24,954	)	$	—	$	(24,954	)

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum lease payments required under the office lease agreement

The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2017 (in thousands).



Year Ending December 31,	Amount
2018	$	2,495
2019	2,528
2020	2,602
2021	2,660
2022	2,774
Thereafter	9,561
Total	$	22,620

Supplemental Disclosures (Tables)

12 Months Ended

Dec. 31, 2017

Supplemental Disclosures [Abstract]

Summary of current accrued liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2017 and 2016 (in thousands).



	December 31,
	2017		2016
Accrued evaluated and unproved and unevaluated property costs	$	105,347	$	54,273
Accrued support equipment and facilities costs	14,823		15,139
Accrued lease operating expenses	12,611		16,009
Accrued interest on debt	8,345		6,541
Accrued asset retirement obligations	1,176		915
Accrued partners’ share of joint interest charges	27,628		5,572
Other	4,418		3,011
Total accrued liabilities	$	174,348	$	101,460

Supplemental disclosures of cash flow information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2017, 2016 and 2015 (in thousands).



	Year Ended December 31,
	2017			2016			2015
Cash paid for income taxes	$	—		$	2,895		$	506
Cash paid for interest expense, net of amounts capitalized	$	32,760		$	27,464		$	16,154
Increase in asset retirement obligations related to mineral properties	$	4,385		$	3,817		$	2,510
(Decrease) increase in asset retirement obligations related to support equipment and facilities	$	(60	)	$	222		$	383
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	$	48,929		$	1,775		$	(30,683	)
(Decrease) increase in liabilities for support equipment and facilities	$	(955	)	$	(588	)	$	12,076
Issuance of restricted stock units for director and advisor services	$	—		$	992		$	584
Stock-based compensation expense recognized as liability	$	362		$	569		$	79
(Decrease) increase in liabilities for accrued cost to issue equity	$	(343	)	$	343		$	—
Transfer of inventory (to) from oil and natural gas properties	$	(374	)	$	395		$	615
Transfer of inventory to midstream and other property and equipment	$	(317	)	$	—		$	—

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Year Ended December 31, 2017
Oil and natural gas revenues	$	525,862		$	2,822	$	—		$	—		$	528,684
Midstream services revenues	—			47,037		—			(36,839		)	10,198
Realized loss on derivatives	(4,321		)	—		—			—			(4,321		)
Unrealized gain on derivatives	9,715			—		—			—			9,715
Expenses ⁽¹⁾	333,923			23,420		62,931			(36,839		)	383,435
Operating income (loss) ⁽²⁾	$	197,333		$	26,439	$	(62,931	)	$	—		$	160,841
Total assets	$	1,768,393		$	257,871	$	119,426		$	—		$	2,145,690
Capital expenditures ⁽³⁾	$	753,157		$	114,113	$	5,688		$	—		$	872,958

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $170.5 million and $5.2 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.7 million.


(2)	Includes $12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Year Ended December 31, 2016
Oil and natural gas revenues	$	289,512		$	1,644	$	—		$	—		$	291,156
Midstream services revenues	—			18,982		—			(13,764		)	5,218
Realized gain on derivatives	9,286			—		—			—			9,286
Unrealized loss on derivatives	(41,238		)	—		—			—			(41,238		)
Expenses ⁽¹⁾	391,098			8,254		56,001			(13,764		)	441,589
Operating (loss) income ⁽²⁾	$	(133,538	)	$	12,372	$	(56,001	)	$	—		$	(177,167	)
Total assets	$	1,098,525		$	140,459	$	225,681		$	—		$	1,464,665
Capital expenditures	$	379,881		$	67,566	$	6,913		$	—		$	454,360

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $118.4 million and $2.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.9 million and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment.


(2)	Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Year Ended December 31, 2015
Oil and natural gas revenues	$	277,844		$	496	$	—		$	—		$	278,340
Midstream services revenues	—			11,485		—			(9,621		)	1,864
Realized gain on derivatives	77,094			—		—			—			77,094
Unrealized loss on derivatives	(39,265		)	—		—			—			(39,265		)
Expenses ⁽¹⁾	1,078,534			5,178		50,604			(9,621		)	1,124,695
Operating (loss) income ⁽²⁾	$	(762,861	)	$	6,803	$	(50,604	)	$	—		$	(806,662	)
Total assets	$	1,000,075		$	75,980	$	64,806		$	—		$	1,140,861
Capital expenditures ⁽³⁾	$	622,642		$	75,009	$	786		$	—		$	698,437

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $176.7 million and $1.6 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.5 million and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment.


(2)	Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	In October 2015, the Company sold the Loving County Processing System to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets.

Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2017 USD ($) shares	Dec. 31, 2017 USD ($) Purchasers	Dec. 31, 2017 USD ($) $ / bbl	Dec. 31, 2017 USD ($) $ / MMBTU	Dec. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 shares	Dec. 31, 2016 Purchasers	Dec. 31, 2016 $ / bbl	Dec. 31, 2016 $ / MMBTU	Dec. 31, 2016	Dec. 31, 2016 USD ($)	Dec. 31, 2015 shares	Dec. 31, 2015 Purchasers	Dec. 31, 2015 $ / bbl	Dec. 31, 2015 $ / MMBTU	Dec. 31, 2015	Dec. 31, 2015 USD ($)
Summary of Significant Accounting Policies [Line Items]
Billing date	30 days
Outstanding days of account receivable	60 days
Allowance for doubtful accounts	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Capitalized general and administrative costs							23,100,000						$ 15,700,000						$ 6,900,000
Capitalized interest expense							7,300,000						3,700,000						3,900,000
Present value discounted percent of future net revenues of proved oil and natural gas reserves						10.00%
Average oil and natural gas prices				47.79	2.98					39.25	2.48					46.79	2.59
Impairment charge of net capitalized costs							0						158,633,000						801,166,000
Number of purchasers \| Purchasers			4						3						3
Stock-based compensation (non-cash) expense							16,654,000						12,362,000						9,450,000
Common stock and restricted stock unit expense							3,000,000						1,000,000						900,000
Accelerated compensation cost							1,500,000
Percentage being realized up on ultimate settlement						50.00%
Machinery and Equipment [Member]
Summary of Significant Accounting Policies [Line Items]
Useful life using the straight-line	30 years
Maximum [Member]
Summary of Significant Accounting Policies [Line Items]
Accounts receivable due period	60 days
Useful life	30 years
Minimum [Member]
Summary of Significant Accounting Policies [Line Items]
Accounts receivable due period	30 days
Useful life	5 years
Accounts Receivable [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						43.00%						38.00%						39.00%
Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						60.00%						48.00%						59.00%
Stock options [Member]
Summary of Significant Accounting Policies [Line Items]
Stock-based compensation (non-cash) expense							$ 7,100,000						$ 5,900,000						$ 4,700,000
Restricted Stock Units (RSUs) [Member]
Summary of Significant Accounting Policies [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount \| shares								90,552						73,923
Restricted stock [Member]
Summary of Significant Accounting Policies [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount \| shares								1,039,292						854,238
Stock options [Member]
Summary of Significant Accounting Policies [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount \| shares		1,000,000						2,886,821						2,362,861
Plains Marketing [Member] \| Customer Concentration Risk [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						14.00%						18.00%
Shell Trading (US) Company [Member] \| Customer Concentration Risk [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						12.00%						17.00%						33.00%
Western Refining Oil [Member] \| Customer Concentration Risk [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						11.00%
Occidental Energy Marketing [Member] \| Customer Concentration Risk [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						23.00%						13.00%
Enterprise Crude Oil LLC [Member] \| Customer Concentration Risk [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage																		14.00%
Sequent Energy Management [Member] \| Customer Concentration Risk [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage																		12.00%

Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Current period net income	$ 125,867	$ (97,421)	$ (679,785)
Weighted average common shares outstanding — denominator
Weighted average common shares outstanding for basic earnings (loss) per share (in shares)	102,029,000	91,273,000	81,537,000
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	514,000	0	0
Diluted weighted average common shares outstanding (in shares)	102,543,000	91,273,000	81,537,000
Earnings (loss) per common share
Basic (usd per share)	$ 1.23	$ (1.07)	$ (8.34)
Diluted (usd per share)	$ 1.23	$ (1.07)	$ (8.34)
Stock options [Member]
Earnings (loss) per common share
Total (usd per share)	1,000,000	2,886,821	2,362,861
Restricted Stock Units (RSUs) [Member]
Earnings (loss) per common share
Total (usd per share)		90,552	73,923
Restricted stock [Member]
Earnings (loss) per common share
Total (usd per share)		1,039,292	854,238

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and natural gas properties
Evaluated (subject to amortization)	$ 3,004,770	$ 2,408,305
Total unproved and unevaluated	637,396	479,736
Total oil and natural gas properties	3,642,166	2,888,041
Accumulated depletion	(2,021,169)	(1,850,882)
Net oil and natural gas properties	1,620,997	1,037,159
Other property and equipment
Midstream and other property and equipment	281,096	160,795
Accumulated depreciation	(20,637)	(13,429)
Net other property and equipment	260,459	147,366
Net property and equipment	1,881,456	1,184,525
Midstream equipment and facilities
Other property and equipment
Midstream and other property and equipment	258,725	145,662
Furniture, fixtures and other equipment
Other property and equipment
Midstream and other property and equipment	6,109	5,487
Software
Other property and equipment
Midstream and other property and equipment	7,942	3,206
Land
Other property and equipment
Midstream and other property and equipment	2,892	1,437
Leasehold improvements
Other property and equipment
Midstream and other property and equipment	$ 5,428	$ 5,003

Property and Equipment (Details 1) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2011
Costs incurred for
Total unproved and unevaluated	$ 637,396	$ 479,736
2017
Costs incurred for
Property acquisition	213,076
Exploration wells	16,688
Development wells	11,396
Total unproved and unevaluated	241,160
2016
Costs incurred for
Property acquisition		125,689
Exploration wells		988
Development wells		272
Total unproved and unevaluated		$ 126,949
2015
Costs incurred for
Property acquisition			$ 222,912
Exploration wells			547
Development wells			19
Total unproved and unevaluated			$ 223,478
2014 and prior
Costs incurred for
Property acquisition				$ 45,809
Exploration wells				0
Development wells				0
Total unproved and unevaluated				$ 45,809
Total
Costs incurred for
Property acquisition	607,486
Exploration wells	18,223
Development wells	11,687
Total unproved and unevaluated	$ 637,396

Property and Equipment (Details Textual) $ in Millions	12 Months Ended
Property and Equipment (Details Textual) $ in Millions	Dec. 31, 2017 USD ($)
Property, Plant and Equipment [Abstract]
Amortization costs	$ 29.9
Anticipated amount for wells	$ 29.9

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Changes in the Company's asset retirement obligations
Beginning asset retirement obligations	$ 20,640	$ 15,420
Liabilities incurred during period	2,920	1,791
Liabilities settled during period	(430)	(375)
Revisions in estimated cash flows	1,836	2,622
Accretion expense	1,290	1,182
Ending asset retirement obligations	$ 20,640	$ 15,420	$ 26,256	$ 20,640
Less: current asset retirement obligations			(1,176)	(915)
Long-term asset retirement obligations			$ 25,080	$ 19,725

Business Combinations and Divestitures (Details) $ in Millions				11 Months Ended	12 Months Ended
	Feb. 17, 2017 USD ($) well	Oct. 01, 2015 USD ($)	Feb. 27, 2015 USD ($) a shares	Jan. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017	Oct. 31, 2015 USD ($)
Business Acquisition [Line Items]
Subsidiary ownership percentage					100.00%
Carrying value of net assets sold							$ 31.0
Sale leaseback transaction, transaction costs					$ 0.4
Sale leaseback transaction, current period gain recognized					107.3
Harvey E Yates Company [Member]
Business Acquisition [Line Items]
Number of gross acres in acreage acquired \| a			58,600
Number of net acres in acreage acquired \| a			18,200
Business combination, consideration transferred, liabilities incurred			$ 33.6
Shares issued upon conversion \| shares			10
Harvey E Yates Company [Member] \| Common Stock [Member]
Business Acquisition [Line Items]
Shares issued for acquisition \| shares			3,300,000
Harvey E Yates Company [Member] \| Convertible Preferred Stock [Member]
Business Acquisition [Line Items]
Shares issued for acquisition \| shares			150,000
EnLink [Member]
Business Acquisition [Line Items]
Proceeds from sale of oil and gas property and equipment		$ 143.4
Proceeds from sale of oil and gas property and equipment net of purchase price adjustments		139.8
Purchase price adjustments for production, revenues and operating and capital expenditures		$ 3.6
Gas gathering and processing agreement, term		15 years
Sale leaseback transaction, deferred gain					$ 108.4
Corporate Joint Venture [Member] \| San Mateo Midstream [Member]
Business Acquisition [Line Items]
Subsidiary ownership percentage	51.00%					51.00%
Deferred performance incentives	$ 58.8
Deferred performance incentives, term	4 years
Contributions to joint venture, operating capital	$ 5.1
Corporate Joint Venture [Member] \| San Mateo Midstream [Member] \| Subsequent Event [Member]
Business Acquisition [Line Items]
Deferred performance incentives				$ 14.7
Five Point [Member] \| Corporate Joint Venture [Member] \| San Mateo Midstream [Member]
Business Acquisition [Line Items]
Subsidiary ownership percentage	49.00%
Payments to acquire interest in joint venture	$ 176.4
Proceeds from divestiture of interest in joint venture	$ 171.5
Rustler Breaks and Wolf Asset Area [Member] \| Corporate Joint Venture [Member] \| San Mateo Midstream [Member]
Business Acquisition [Line Items]
Contractual obligation, term	15 years
Rustler Breaks Asset Area [Member] \| Corporate Joint Venture [Member] \| San Mateo Midstream [Member]
Business Acquisition [Line Items]
Number of wells contributed to joint venture \| well	1
Contractual obligation, term	15 years
Wolf Asset Area [Member] \| Corporate Joint Venture [Member] \| San Mateo Midstream [Member]
Business Acquisition [Line Items]
Number of wells contributed to joint venture \| well	3

Revolving Credit Agreement (Details Textual) - USD ($)			1 Months Ended	12 Months Ended
Revolving Credit Agreement (Details Textual) - USD ($)	Dec. 09, 2016	Apr. 14, 2015	Sep. 30, 2012	Dec. 31, 2017	Feb. 21, 2018	Sep. 30, 2017	Feb. 17, 2017	Dec. 31, 2016	Oct. 31, 2016	Oct. 21, 2015	Sep. 28, 2012
Revolving Credit Agreement (Textual) [Abstract]
Deferred loan costs				$ 1,000,000
Repay deficit in agreement Period				6 months
Borrowings under Credit Agreement				$ 0
Outstanding letters of credit				2,100,000
Borrowings interest rate		50.00%
Senior unsecured notes payable				$ 574,073,000				$ 573,924,000
Proceeds from Issuance or Sale of Equity	$ 181,500,000
Subsidiary ownership percentage				100.00%
Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Company amended and restated its senior secured revolving credit agreement			September 28, 2012
Senior secured revolving credit maximum facility									$ 525,000,000		$ 400,000,000
Maximum borrowing capacity, amended				$ 500,000,000
Percentage of reserves required to maintain				100.00%
Debt to EBITDA ratio covenant				4.25
Subsequent Event [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings under Credit Agreement					$ 0
Outstanding letters of credit					$ 2,100,000
LIBOR rate [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings interest rate				1.00%
Maximum [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Commitment fee percentage				0.50%
Minimum [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Commitment fee percentage				0.375%
Minimum [Member] \| Base rate loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate				0.50%
Eurodollar [Member] \| Maximum [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate				2.50%
Eurodollar [Member] \| Minimum [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate				1.50%
Unsecured Debt [Member] \| Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Senior unsecured notes payable	$ 175,000,000	$ 400,000,000
Stated interest rate		6.875%								6.875%
Effective interest rate				5.50%
Percentage of principal amount redeemed		35.00%
Percentage of aggregate principal amount of notes outstanding after redemption		65.00%
Percentage of principal amount outstanding		25.00%
Period of default when due of interest		30 days
Period after notice to comply with reporting obligations		180 days
Period after notice to comply with agreements in indenture		60 days
Aggregate principal amount related to payment defaults or accelerations		$ 25,000,000.0
Amount of failure to pay final judgments		$ 25,000,000.0
Period for failure to pay final judgments		60 days
Federal Funds Effective Rate [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings interest rate				0.50%
Base rate loan [Member] \| Maximum [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate				1.50%
Debt Redemption, 2018 [Member] \| Unsecured Debt [Member] \| Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price		105.156%
Percentage of principal amount redeemed	105.50%	106.875%
Debt Redemption, 2019 [Member] \| Unsecured Debt [Member] \| Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price		103.438%
Debt Redemption, 2020 [Member] \| Unsecured Debt [Member] \| Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price		101.719%
Debt Redemption, 2021 and thereafter [Member] \| Unsecured Debt [Member] \| Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price		100.00%
Revolving Credit Facility [Member]
Revolving Credit Agreement (Textual) [Abstract]
Senior secured revolving credit maximum facility				$ 400,000,000
Corporate Joint Venture [Member] \| San Mateo Midstream [Member]
Revolving Credit Agreement (Textual) [Abstract]
Subsidiary ownership percentage						51.00%	51.00%

Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets
Unrealized loss on derivatives	$ 3,200	$ 8,734
Net operating loss carryforwards	118,134	137,757
Alternative minimum tax carryforward	0	8,633
Percentage depletion carryover	1,582	2,595
Property and equipment	0	44,391
Basis increase related to the San Mateo transaction	18,382	0
Total deferred tax assets	141,298	202,110
Valuation allowance on deferred tax assets	(89,482)	(190,255)
Total deferred tax assets, net of valuation allowance	51,816	11,855
Deferred tax liabilities
Property and equipment	40,568	0
Other	(11,248)	(11,855)
Total deferred tax liabilities	(51,816)	(11,855)
Net deferred tax liabilities	$ 0	$ 0

Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Details Textual) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Full-cost ceiling impairment	$ 0	$ 158,633	$ 801,166
Increase in valuation allowance	101,917	(33,688)	(145,777)
Provisional income tax	51,500
Net current income tax (benefit) provision	8,157	$ 1,036	$ (2,959)
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	498,400
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 17,000

Income Taxes (Details 1) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Details 1) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current income tax provision
State income tax	$ 21	$ 108	$ 371
Federal alternative minimum tax	(8,178)	(1,144)	2,588
Net current income tax (benefit) provision	(8,157)	(1,036)	2,959
Deferred income tax provision (benefit)
Federal tax (benefit) expense at statutory rate	45,447	(34,333)	(289,412)
State income tax	368	539	(13,215)
Permanent differences	(4,740)	(499)	698
AMT credit refundable (net of sequestration)	0	1,144	(2,588)
AMT credit refundable (net of sequestration)	8,178	0	0
Tax Cuts and Jobs Act rate change	51,525	0	0
Change in federal valuation allowance	(101,917)	33,688	145,777
Change in state valuation allowance	1,139	(539)	8,413
Net deferred income tax benefit	0	0	(150,327)
Total income tax benefit	$ (8,157)	$ (1,036)	$ (147,368)
Federal statutory rate	35.00%	35.00%	35.00%

Stock-Based Compensation (Details) - $ / shares	12 Months Ended
Stock-Based Compensation (Details) - $ / shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Weighted average fair value of stock option awards granted during the year	$ 10.49	$ 5.65	$ 9.90
Stock Based Compensation Two Thousand Twelve Incentive Plan [Member]
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Stock option pricing model		Black Scholes Merton	Black Scholes Merton
Expected option life	4 years	3 years 11 months 16 days	4 years
Risk-free interest rate	1.77%	1.08%	1.15%
Volatility	47.00%	45.68%	56.89%
Dividend yield	0.00%	0.00%	0.00%
Estimated forfeiture rate	3.66%	1.16%	3.21%
2003 Stock and Incentive Plan [Member]
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	2 years 1 month 20 days	3 years 1 month 21 days	4 months 21 days
Risk-free interest rate	1.98%	1.70%	0.64%
Volatility	43.60%	47.07%	91.98%
Dividend yield	0.00%	0.00%	0.00%
Estimated forfeiture rate	0.00%	0.00%	0.00%

Stock-Based Compensation (Details 1) shares in Thousands	12 Months Ended
Stock-Based Compensation (Details 1) shares in Thousands	Dec. 31, 2017 $ / shares shares
Number of options (in thousands)
Options outstanding at beginning of period (in shares) \| shares	2,887
Options granted (in shares) \| shares	1,034
Options exercised (in shares) \| shares	(833)
Options forfeited (in shares) \| shares	(24)
Options expired (in shares) \| shares	0
Options outstanding at end of period (in shares) \| shares	3,064
Weighted average exercise price
Weighted average exercise price, Options outstanding Beginning Balance (usd per share) \| $ / shares	$ 15.59
Weighted average exercise price, Options granted (usd per share) \| $ / shares	27.09
Weighted average exercise price, Options exercised (usd per share) \| $ / shares	9.20
Weighted average exercise price, Options forfeited (usd per share) \| $ / shares	23.81
Weighted average exercise price, Options expired (usd per share) \| $ / shares	0.00
Weighted average exercise price, Options outstanding Ending Balance (usd per share) \| $ / shares	$ 21.14

Stock-Based Compensation (Details 2) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Deferred Compensation Liability, Current	$ 0.0	$ 0.0	$ 1.0
$8.18 - $9.55 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	$ 8.18
Range of exercise prices, Upper limit	$ 9.55
Shares outstanding (in shares)	294
Weighted average remaining contractual price	8 months 10 days
Weighted average exercise price (usd per share)	$ 8.46
Shares exercisable	294
Weighted average exercise price (usd per share)	$ 8.46
$13.22 - $17.80 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	13.22
Range of exercise prices, Upper limit	$ 17.80
Shares outstanding (in shares)	625
Weighted average remaining contractual price	3 years 1 month 6 days
Weighted average exercise price (usd per share)	$ 15.01
Shares exercisable	11
Weighted average exercise price (usd per share)	$ 16.45
$19.71 - $22.70 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	19.71
Range of exercise prices, Upper limit	$ 22.70
Shares outstanding (in shares)	839
Weighted average remaining contractual price	2 years 17 days
Weighted average exercise price (usd per share)	$ 21.87
Shares exercisable	73
Weighted average exercise price (usd per share)	$ 21.50
$23.40-27.33 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	23.4
Range of exercise prices, Upper limit	$ 27.33
Shares outstanding (in shares)	1,306
Weighted average remaining contractual price	4 years 3 months 29 days
Weighted average exercise price (usd per share)	$ 26.47
Shares exercisable	141
Weighted average exercise price (usd per share)	$ 24.21

Stock-Based Compensation (Details 3) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 16,654	$ 12,362	$ 9,450
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 7,100	$ 5,900	$ 4,700
Restricted Stock Service Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance (in shares)	1,039
Shares Granted (in shares)	531
Shares Vested (in shares)	(429)
Shares Forfeited (in shares)	(37)
Non-vested Shares, Ending Balance (in shares)	1,104	1,039
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted average fair value, Beginning Balance (usd per share)	$ 18.23
Weighted average fair value, Granted (usd per share)	26.25
Weighted average fair value, Vested (usd per share)	16.54
Weighted average fair value, Forfeited (usd per share)	22.94
Weighted average fair value, Ending Balance (usd per share)	$ 22.59	$ 18.23
Restricted Stock Units Service Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance (in shares)	82
Shares Granted (in shares)	113
Shares Vested (in shares)	(124)
Shares Forfeited (in shares)	(6)
Non-vested Shares, Ending Balance (in shares)	65	82
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted average fair value, Beginning Balance (usd per share)	$ 21.32
Weighted average fair value, Granted (usd per share)	23.77
Weighted average fair value, Vested (usd per share)	22.38
Weighted average fair value, Forfeited (usd per share)	23.45
Weighted average fair value, Ending Balance (usd per share)	$ 23.36	$ 21.32

Stock Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	Feb. 16, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 10, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares of common stock provided (in shares)					8,700,000
Fair value of stock option awards outstanding (in shares)		3,064,000	2,887,000
Aggregate intrinsic value		$ 30,600
Aggregate intrinsic value exercisable		$ 8,500
Quoted closing market price		$ 31.13
Weighted average contractual term		1 year 25 days
Total intrinsic value of options exercised		$ 13,200	$ 1,600	$ 1,300
Tax related benefits realized from the exercise of stock options		5,000	500	300
Unrecognized compensation expense related to unvested stock options		$ 9,800
Weighted average remaining requisite service period of unvested stock awards		9 months 12 days
Fair value of option shares vested		$ 2,100	3,000	1,300
Stock-based compensation expense		16,654	12,362	9,450
Stock based long term liability		400	1,400	0
Stock based current liability		$ 0	0	1,000
Restricted stock or unit expenses				0
Options granted (in shares)		1,034,000
Aggregate intrinsic value for the restricted stock and restricted stock units outstanding		$ 36,400
Tax benefits recognized for stock based compensation		6,800	4,300	3,400
Capitalized stock-based compensation		3,300
Expensed stock-based compensation		$ 16,700
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares		3 years
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares		4 years
Class A [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares that may be issued pursuant to options or restricted stock grants (in shares)		3,481,569
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining requisite service period of unvested stock awards		11 months 12 days
Unrecognized compensation expense related to unvested restricted stock and restricted stock units		$ 14,400
Fair value of restricted stock and restricted stock units vested		9,900	4,600	800
Restricted stock or unit expenses		$ 12,900	6,600	4,700
Stock options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum vesting period		5 years
Maximum vesting period 2		6 years
Maximum vesting period 3		10 years
Stock-based compensation expense		$ 7,100	$ 5,900	$ 4,700
Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	563,408
Fair value of grants	$ 26,900
Subsequent Event [Member] \| Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock grants (in shares)	667,488
Subsequent Event [Member] \| Stock options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares	3 years
Weighted average fair value, Granted	$ 29.68
2003 Stock and Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of stock option awards outstanding (in shares)		75,000	77,500	87,500

Employee Benefit Plans (Details) - USD ($)	12 Months Ended
Employee Benefit Plans (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee Benefit Plan (Textual) [Abstract]
Employees annual compensation	3.00%
Safe Harbor match	$ 900,000	$ 700,000	$ 600,000
Discretionary matching contributions	1,100,000	900,000	800,000
No additional discretionary contributions	$ 0	$ 0	$ 0

Equity (Details) $ in Thousands							12 Months Ended
Equity (Details) $ in Thousands	Oct. 10, 2017 USD ($) a shares	Dec. 09, 2016 USD ($) shares	Mar. 11, 2016 USD ($) shares	Apr. 21, 2015 USD ($) shares	Apr. 06, 2015 shares	Feb. 27, 2015 shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($)	Jun. 01, 2017 shares	May 31, 2017 shares	Apr. 02, 2015 shares	Apr. 01, 2015 shares
Subsidiary, Sale of Stock [Line Items]
Payments of Stock Issuance Costs \| $	$ 300						$ 280	$ 847	$ 1,158
Sale of Stock, Consideration Received on Transaction \| $		$ 145,800	$ 141,500
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs \| $		$ 400	$ 800				$ 280	$ 1,190	1,151
Common stock, shares authorized (in shares)							160,000,000	120,000,000
Issuance of Class A common stock, shares				7,000,000
Offering costs \| $				$ 1,200
Proceeds from issuance of common stock \| $				$ 187,600			$ 208,720	$ 288,510	188,720
Repayments of long-term debt \| $							$ 0	$ 120,000	$ 476,982
Net Acres \| a	6,600
Acquisition Costs, Period Cost \| $	$ 38,000
Common Stock [Member]
Subsidiary, Sale of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		6,000,000	7,500,000
Common stock, shares authorized (in shares)										160,000,000	120,000,000	120,000,000	80,000,000
Shares converted					1,500,000
Shares held in escrow					166,667
Harvey E Yates Company [Member]
Subsidiary, Sale of Stock [Line Items]
Shares issued upon conversion						10
Harvey E Yates Company [Member] \| Convertible Preferred Stock [Member]
Subsidiary, Sale of Stock [Line Items]
Shares issued for acquisition						150,000
Shares issued as consideration in business combination						150,000
Harvey E Yates Company [Member] \| Common Stock [Member]
Subsidiary, Sale of Stock [Line Items]
Shares issued for acquisition						3,300,000
Public Stock Offering [Member]
Subsidiary, Sale of Stock [Line Items]
Sale of Stock, Consideration Received on Transaction \| $	$ 208,400
Public Stock Offering [Member] \| Common Stock [Member]
Subsidiary, Sale of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	8,000,000

Derivative Financial Instruments (Details) $ in Thousands	Dec. 31, 2017 USD ($) MMBTU bbl $ / bbl $ / MMBTU	Sep. 30, 2017 USD ($)
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ (15,239)
Open costless collar contracts [Member]
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)		$ (9,675)
Open costless collar contracts [Member] \| Oil - WTI [Member]
Summary of contracts for oil and natural gas
Derivative, Nonmonetary Notional Amount \| bbl	2,880,000
Price Floor \| $ / bbl	44.27
Price Ceiling \| $ / bbl	60.29
Fair Value of Asset (Liability)	$ (8,414)
Open costless collar contracts [Member] \| Oil - LLS [Member]
Summary of contracts for oil and natural gas
Derivative, Nonmonetary Notional Amount \| bbl	720,000
Price Floor \| $ / bbl	45.00
Price Ceiling \| $ / bbl	63.05
Fair Value of Asset (Liability)	$ (2,451)
Open costless collar contracts [Member] \| Natural Gas, Calculation Period One [Member]
Summary of contracts for oil and natural gas
Derivative, Nonmonetary Notional Amount \| MMBTU	16,800,000
Price Floor \| $ / MMBTU	2.58
Price Ceiling \| $ / MMBTU	3.67
Fair Value of Asset (Liability)	$ 1,190
Open Swap Contracts [Member]
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ (5,564)
Open Swap Contracts [Member] \| Oil, Calculation Period Two [Member]
Summary of contracts for oil and natural gas
Derivative, Nonmonetary Notional Amount \| bbl	5,220,000
Fair Value of Asset (Liability)	$ (5,564)
Fixed price \| $ / bbl	(1.02)

Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Offsetting Derivative Assets [Abstract]
Derivative Liability	$ (15,239)	$ (24,954)
Offsetting Derivative Liabilities [Abstract]
Derivative Asset	0	0
Other Current Assets [Member]
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets	131,092
Gross amounts netted in the consolidated balance sheets	(129,902)
Derivative Asset	1,190
Current liabilities [Member]
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities	(146,331)	(24,203)
Gross amounts netted in the consolidated balance sheet	(129,902)	0
Derivative Liability	$ (16,429)	(24,203)
Other liabilities [Member]
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities		751
Gross amounts netted in the consolidated balance sheet		0
Derivative Liability		$ 751

Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized (loss) gain on derivatives	$ (4,321)	$ 9,286	$ 77,094
Unrealized gain (loss) on derivatives	9,715	(41,238)	(39,265)
Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized (loss) gain on derivatives	(4,321)	9,286	77,094
Unrealized gain (loss) on derivatives	9,715	(41,238)	(39,265)
Total	5,394	(31,952)	37,829
Oil [Member] \| Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized (loss) gain on derivatives	(3,657)	5,851	62,259
Unrealized gain (loss) on derivatives	2,638	(18,969)	(31,897)
Natural Gas [Member] \| Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized (loss) gain on derivatives	(608)	3,435	12,653
Unrealized gain (loss) on derivatives	7,077	(22,269)	(5,440)
NGL's [Member] \| Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized (loss) gain on derivatives	(56)	0	2,182
Unrealized gain (loss) on derivatives	$ 0	$ 0	$ (1,928)

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets (Liabilities)
Derivative Liability	$ 15,239	$ 24,954
Derivative, Fair Value, Net	(15,239)
Fair value on a recurring basis [Member]
Assets (Liabilities)
Derivative Liability	1,190	(24,954)
Derivative Assets (Liabilities), at Fair Value, Net	(15,239)
Fair value on a recurring basis [Member] \| Oil [Member]
Assets (Liabilities)
Derivative Assets (Liabilities), at Fair Value, Net	(16,429)	(24,954)
Fair value on a recurring basis [Member] \| Level 1 [Member]
Assets (Liabilities)
Derivative Liability	0	0
Fair value on a recurring basis [Member] \| Level 1 [Member] \| Oil [Member]
Assets (Liabilities)
Derivative Assets (Liabilities), at Fair Value, Net	0
Fair value on a recurring basis [Member] \| Level 2 [Member]
Assets (Liabilities)
Derivative Liability	1,190	(24,954)
Derivative, Fair Value, Net	(15,239)	(24,954)
Fair value on a recurring basis [Member] \| Level 2 [Member] \| Oil [Member]
Assets (Liabilities)
Derivative Assets (Liabilities), at Fair Value, Net	(16,429)
Fair value on a recurring basis [Member] \| Level 3 [Member]
Assets (Liabilities)
Derivative Liability	0	$ 0
Fair value on a recurring basis [Member] \| Level 3 [Member] \| Oil [Member]
Assets (Liabilities)
Derivative Assets (Liabilities), at Fair Value, Net	$ 0

Fair Value Measurements (Details Textual) - USD ($)	12 Months Ended
Fair Value Measurements (Details Textual) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of notes payable	$ 614,100,000	$ 605,200,000
Pipe and other equipment [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Impairment charge for equipments held in inventory	$ 0	$ 0

Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Schedule of future minimum lease payments required under the office lease agreement
2018	$ 2,495
2019	2,528
2020	2,602
2021	2,660
2022	2,774
Thereafter	9,561
Total	$ 22,620

Commitments and Contingencies (Details Textual) - USD ($)		12 Months Ended
	Feb. 17, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Long-term Purchase Commitment [Line Items]
Term of leases		5 years
Rent expense, including fees for operating expenses and consumption of electricity		$ 2,600,000	$ 2,900,000	$ 1,700,000
Deficiency fees		0
Minimum outstanding commitments		24,800,000
Capital Addition Purchase Commitments [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment		55,300,000
Payment for long-term purchase commitment		49,700,000
Remaining minimum amount committed		5,600,000
Drilling Rig Commitments [Member]
Long-term Purchase Commitment [Line Items]
Maximum termination outstanding obligations of contracts		36,500,000
Loving County System Agreement [Member]
Long-term Purchase Commitment [Line Items]
Supply agreement, term				15 years
Total deficiency fee estimate		8,400,000
Transportation and processing fees under the agreement		14,400,000	$ 9,800,000
Eddy County [Member]
Long-term Purchase Commitment [Line Items]
Transportation and processing fees under the agreement		200,000
Corporate Joint Venture [Member] \| San Mateo Midstream [Member]
Long-term Purchase Commitment [Line Items]
Contractual obligation		232,600,000
Payment for long-term purchase commitment		$ 39,400,000
Corporate Joint Venture [Member] \| San Mateo Midstream [Member] \| Rustler Breaks and Wolf Asset Area [Member]
Long-term Purchase Commitment [Line Items]
Contractual obligation, term	15 years
Corporate Joint Venture [Member] \| San Mateo Midstream [Member] \| Rustler Breaks Asset Area [Member]
Long-term Purchase Commitment [Line Items]
Contractual obligation, term	15 years
Natural Gas Transportation Agreement [Member] \| Eddy County [Member]
Long-term Purchase Commitment [Line Items]
Supply agreement, term		18 years
Contractual obligation		$ 59,400,000
Natural Gas Transportation and Fractionation Agreement [Member] \| Eddy County [Member]
Long-term Purchase Commitment [Line Items]
Supply agreement, term		7 years
Contractual obligation		$ 132,500,000

Supplemental Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Summary of current accrued liabilities
Total accrued liabilities	$ 174,348	$ 101,460
Other	4,418	3,011
Accrued evaluated and unproved and unevaluated property costs [Member]
Summary of current accrued liabilities
Total accrued liabilities	105,347	54,273
Accrued support equipment and facilities costs [Member]
Summary of current accrued liabilities
Total accrued liabilities	14,823	15,139
Accrued lease operating expenses [Member]
Summary of current accrued liabilities
Total accrued liabilities	12,611	16,009
Accrued interest on debt [Member]
Summary of current accrued liabilities
Total accrued liabilities	8,345	6,541
Accrued asset retirement obligations [Member]
Summary of current accrued liabilities
Total accrued liabilities	1,176	915
Accrued partners' share of joint interest charges [Member]
Summary of current accrued liabilities
Total accrued liabilities	$ 27,628	$ 5,572

Supplemental Disclosures (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental disclosures of cash flow information
Cash paid for income taxes	$ 0	$ 2,895	$ 506
Cash paid for interest expense, net of amounts capitalized	32,760	27,464	16,154
Increase in asset retirement obligations related to mineral properties	4,385	3,817	2,510
(Decrease) increase in asset retirement obligations related to support equipment and facilities	(60)	222	383
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	48,929	1,775	(30,683)
(Decrease) increase in liabilities for support equipment and facilities	(955)	(588)	12,076
Issuance of restricted stock units for director and advisor services	0	992	584
Stock-based compensation expense recognized as liability	362	569	79
(Decrease) increase in liabilities for accrued cost to issue equity	(343)	343	0
Transfer of inventory (to) from oil and natural gas properties	(374)	395	615
Transfer of inventory to other property and equipment	$ (317)	$ 0	$ 0

Subsidiary Guarantors Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Balance Sheet Statements, Captions [Line Items]
Receivables, Intercompany	$ 0	$ 0
Other Assets, Current	257,170	279,182
Property, Plant and Equipment, Net	1,881,456	1,184,525
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	0	0
Other Assets	7,064	958
Assets	2,145,690	1,464,665	$ 1,140,861
Payables, Intercompany	0	0
Other Sundry Liabilities, Current	282,606	169,505
Unsecured Long-term Debt, Noncurrent	574,073	573,924
Other Sundry Liabilities, Noncurrent	31,465	29,791
Stockholders' Equity Attributable to Parent	1,156,556	690,125
Non-controlling interest in subsidiaries	100,990	1,320
Liabilities and Equity	$ 2,145,690	1,464,665
Subsidiary ownership percentage	100.00%
Consolidation, Eliminations [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Receivables, Intercompany	$ (588,021)	(332,453)
Other Assets, Current	0	0
Property, Plant and Equipment, Net	0	0
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	(1,258,372)	(947,037)
Other Assets	(3,003)	0
Assets	(1,849,396)	(1,279,490)
Payables, Intercompany	(588,021)	(332,453)
Other Sundry Liabilities, Current	(274)	0
Unsecured Long-term Debt, Noncurrent	0	0
Other Sundry Liabilities, Noncurrent	(2,729)	0
Stockholders' Equity Attributable to Parent	(1,258,372)	(947,037)
Non-controlling interest in subsidiaries	0	0
Liabilities and Equity	(1,849,396)	(1,279,490)
Parent Company [Member] \| Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Receivables, Intercompany	585,109	316,791
Other Assets, Current	2,240	101,102
Property, Plant and Equipment, Net	0	33
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	1,147,295	856,762
Other Assets	6,425	0
Assets	1,741,069	1,274,688
Payables, Intercompany	0	0
Other Sundry Liabilities, Current	8,847	9,265
Unsecured Long-term Debt, Noncurrent	574,073	573,924
Other Sundry Liabilities, Noncurrent	1,593	1,374
Stockholders' Equity Attributable to Parent	1,156,556	690,125
Non-controlling interest in subsidiaries	0	0
Liabilities and Equity	1,741,069	1,274,688
Non-Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Receivables, Intercompany	2,912	3,571
Other Assets, Current	9,334	4,242
Property, Plant and Equipment, Net	223,178	113,107
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	0	0
Other Assets	0	0
Assets	235,424	120,920
Payables, Intercompany	0	12,091
Other Sundry Liabilities, Current	19,891	16,632
Unsecured Long-term Debt, Noncurrent	0	0
Other Sundry Liabilities, Noncurrent	3,466	602
Stockholders' Equity Attributable to Parent	111,077	90,275
Non-controlling interest in subsidiaries	100,990	1,320
Liabilities and Equity	235,424	120,920
Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Receivables, Intercompany	0	12,091
Other Assets, Current	245,596	173,838
Property, Plant and Equipment, Net	1,658,278	1,071,385
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	111,077	90,275
Other Assets	3,642	958
Assets	2,018,593	1,348,547
Payables, Intercompany	588,021	320,362
Other Sundry Liabilities, Current	254,142	143,608
Unsecured Long-term Debt, Noncurrent	0	0
Other Sundry Liabilities, Noncurrent	29,135	27,815
Stockholders' Equity Attributable to Parent	1,147,295	856,762
Non-controlling interest in subsidiaries	0	0
Liabilities and Equity	$ 2,018,593	$ 1,348,547

Subsidiary Guarantors Consolidated Income Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Income Statements, Captions [Line Items]
Total revenues	$ 544,276	$ 264,422	$ 318,033
Total expenses	383,435	441,589	1,124,695
Operating (loss) income	160,841	(177,167)	(806,662)
Net gain on asset sales and inventory impairment	23	107,277	908
Interest expense	(34,565)	(28,199)	(21,754)
Other income	3,551	(4)	616
Earnings in subsidiaries	0	0	0
Income (loss) before income taxes	129,850	(98,093)	(826,892)
Total income tax (benefit) provision	(8,157)	(1,036)	(147,368)
Net income attributable to non-controlling interest in subsidiaries	(12,140)	(364)	(261)
Net income (loss) attributable to Matador Resources Company shareholders	125,867	(97,421)	(679,785)
Consolidation, Eliminations [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	(35,115)	(10,708)	(4,344)
Total expenses	(35,115)	(10,708)	(4,344)
Operating (loss) income	0	0
Net gain on asset sales and inventory impairment	0	0	0
Interest expense	0	0	0
Other income			0
Earnings in subsidiaries	(171,840)	54,539	656,240
Income (loss) before income taxes	(171,840)	54,539	656,240
Total income tax (benefit) provision	0	0	0
Net income attributable to non-controlling interest in subsidiaries	0	0	0
Net income (loss) attributable to Matador Resources Company shareholders	(171,840)	54,539	656,240
Parent Company [Member] \| Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	0
Total expenses	5,610	5,319	5,739
Operating (loss) income	(5,610)	(5,319)	(5,739)
Net gain on asset sales and inventory impairment	0	0	0
Interest expense	(34,565)	(28,199)	(20,511)
Other income	27		0
Earnings in subsidiaries	157,589	(64,349)	(658,698)
Income (loss) before income taxes	117,441	(97,867)	(684,948)
Total income tax (benefit) provision	(8,426)	(446)	(5,163)
Net income attributable to non-controlling interest in subsidiaries	0	0	0
Net income (loss) attributable to Matador Resources Company shareholders	125,867	(97,421)	(679,785)
Non-Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	47,883	17,302	6,310
Total expenses	21,260	7,031	2,944
Operating (loss) income	26,623	10,271	3,366
Net gain on asset sales and inventory impairment	0	0	0
Interest expense	0		0
Other income	37	0	0
Earnings in subsidiaries	0	0	0
Income (loss) before income taxes	26,660	10,271	3,366
Total income tax (benefit) provision	269	97	647
Net income attributable to non-controlling interest in subsidiaries	(12,140)	(364)	(261)
Net income (loss) attributable to Matador Resources Company shareholders	14,251	9,810	2,458
Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	531,508	257,828	316,067
Total expenses	391,680	439,947	1,120,356
Operating (loss) income	139,828	(182,119)	(804,289)
Net gain on asset sales and inventory impairment	23	107,277	908
Interest expense		0	(1,243)
Other income	3,487	(4)	616
Earnings in subsidiaries	14,251	9,810	2,458
Income (loss) before income taxes	157,589	(65,036)	(801,550)
Total income tax (benefit) provision	0	(687)	(142,852)
Net income attributable to non-controlling interest in subsidiaries	0	0	0
Net income (loss) attributable to Matador Resources Company shareholders	$ 157,589	$ (64,349)	$ (658,698)

Subsidiary Guarantors Consolidated Cash Flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 299,125	$ 134,086	$ 208,535
Net cash provided by (used in) investing activities	(824,003)	(405,640)	(425,154)
Net cash provided by (used in) financing activities	408,499	467,706	224,944
Decrease in cash	(116,379)	196,152	8,325
Cash at beginning of year	212,884	16,732	8,407
Cash at end of year	96,505	212,884	16,732
Consolidation, Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	0	0	0
Net cash provided by (used in) investing activities	(106,595)	384,801	563,505
Net cash provided by (used in) financing activities	106,595	(384,801)	(563,505)
Decrease in cash	0	0	0
Cash at beginning of year	0	0	0
Cash at end of year	0	0	0
Parent Company [Member] \| Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(307,982)	(45,215)	(31,271)
Net cash provided by (used in) investing activities	33	(324,724)	(546,715)
Net cash provided by (used in) financing activities	208,440	469,654	577,973
Decrease in cash	(99,509)	99,715	(13)
Cash at beginning of year	99,795	80	93
Cash at end of year	286	99,795	80
Non-Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	21,308	6,694	13,916
Net cash provided by (used in) investing activities	(119,922)	(64,683)	(31,101)
Net cash provided by (used in) financing activities	96,307	60,110	17,353
Decrease in cash	(2,307)	2,121	168
Cash at beginning of year	2,307	186	18
Cash at end of year	0	2,307	186
Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	585,799	172,607	225,890
Net cash provided by (used in) investing activities	(597,519)	(401,034)	(410,843)
Net cash provided by (used in) financing activities	(2,843)	322,743	193,123
Decrease in cash	(14,563)	94,316	8,170
Cash at beginning of year	110,782	16,466	8,296
Cash at end of year	$ 96,219	$ 110,782	$ 16,466

Related Party Transactions (Details) $ in Thousands	1 Months Ended	12 Months Ended
Related Party Transactions (Details) $ in Thousands	Jun. 30, 2015 USD ($) a joint_venture	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Related Party Transaction [Line Items]
Capital contributed to joint ventures		$ 171,500	$ 0	$ 0
Corporate Joint Venture [Member]
Related Party Transaction [Line Items]
Number of joint ventures \| joint_venture	2
Acreage contributed by joint venture partner \| a	1,900
Percentage of joint ventures owned by partners		50.00%
Capital commitment to joint ventures	$ 14,000
Capital contributed to joint ventures		$ 4,400

Segment Reporting (Details)	12 Months Ended
Segment Reporting (Details)	Dec. 31, 2017 USD ($) segment	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Oct. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of business segments \| segment	2
Oil and natural gas revenues	$ 528,684,000	$ 291,156,000	$ 278,340,000
Third-party midstream services revenues	10,198,000	5,218,000	1,864,000
Realized gain on derivatives	(4,321,000)	9,286,000	77,094,000
Unrealized gain on derivatives	9,715,000	(41,238,000)	(39,265,000)
Total expenses	383,435,000	441,589,000	1,124,695,000
Operating income (loss)	160,841,000	(177,167,000)	(806,662,000)
Assets	2,145,690,000	1,464,665,000	1,140,861,000
Capital expenditures	872,958,000	454,360,000	698,437,000
Income (loss) attributable to noncontrolling interest	12,140,000	364,000	261,000
Depletion, depreciation and amortization	177,502,000	122,048,000	178,847,000
Impairment charge of net capitalized costs	0	158,633,000	801,166,000
Carrying value of net assets sold				$ 31,000,000
Operating Segments [Member] \| Exploration and Production Segment [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	525,862,000	289,512,000	277,844,000
Third-party midstream services revenues	0	0	0
Realized gain on derivatives	(4,321,000)	9,286,000	77,094,000
Unrealized gain on derivatives	9,715,000	(41,238,000)	(39,265,000)
Total expenses	333,923,000	391,098,000	1,078,534,000
Operating income (loss)	197,333,000	(133,538,000)	(762,861,000)
Assets	1,768,393,000	1,098,525,000	1,000,075,000
Capital expenditures	753,157,000	379,881,000	622,642,000
Depletion, depreciation and amortization	170,500,000	118,400,000	176,700,000
Impairment charge of net capitalized costs		158,600,000	801,200,000
Operating Segments [Member] \| Midstream Segment [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	2,822,000	1,644,000	496,000
Third-party midstream services revenues	47,037,000	18,982,000	11,485,000
Realized gain on derivatives	0	0
Unrealized gain on derivatives	0	0
Total expenses	23,420,000	8,254,000	5,178,000
Operating income (loss)	26,439,000	12,372,000	6,803,000
Assets	257,871,000	140,459,000	75,980,000
Capital expenditures	114,113,000	67,566,000	75,009,000
Income (loss) attributable to noncontrolling interest	12,100,000		300,000
Depletion, depreciation and amortization	5,200,000	2,700,000	1,600,000
Payments to acquire productive assets	54,900,000	400,000
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	0	0
Third-party midstream services revenues	0	0	0
Realized gain on derivatives	0	0
Unrealized gain on derivatives	0	0
Total expenses	62,931,000	56,001,000	50,604,000
Operating income (loss)	(62,931,000)	(56,001,000)	(50,604,000)
Assets	119,426,000	225,681,000	64,806,000
Capital expenditures	5,688,000	6,913,000	786,000
Depletion, depreciation and amortization	1,700,000	900,000	500,000
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	0	0
Third-party midstream services revenues	(36,839,000)	(13,764,000)	(9,621,000)
Realized gain on derivatives	0	0
Unrealized gain on derivatives	0	0
Total expenses	(36,839,000)	(13,764,000)	(9,621,000)
Assets	0	0	0
Capital expenditures	$ 0	$ 0	$ 0

Subsequent Events (Narrative) (Details)	Jan. 22, 2018 a
Subsequent Event [Member]
Subsequent Event [Line Items]
Joint development area (acres)	400,000