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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2018	Feb. 26, 2019	Jun. 30, 2018
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, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 3,305,546,848
Entity Common Stock, Shares Outstanding		116,388,317

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash	$ 64,545	$ 96,505
Restricted cash	19,439	5,977
Accounts receivable
Oil and natural gas revenues	68,161	65,962
Joint interest billings	61,831	67,225
Other	16,159	8,031
Derivative instruments	49,929	1,190
Lease and well equipment inventory	17,564	5,993
Prepaid expenses and other assets	8,057	6,287
Total current assets	305,685	257,170
Oil and natural gas properties, full-cost method
Evaluated	3,780,236	3,004,770
Unproved and unevaluated	1,199,511	637,396
Midstream and other property and equipment	450,066	281,096
Less accumulated depletion, depreciation and amortization	(2,306,949)	(2,041,806)
Net property and equipment	3,122,864	1,881,456
Other assets
Deferred income taxes	20,457	0
Other assets	6,512	7,064
Total other assets	26,969	7,064
Total assets	3,455,518	2,145,690
Current liabilities
Accounts payable	66,970	11,757
Accrued liabilities	170,855	174,348
Royalties payable	64,776	61,358
Amounts due to affiliates	13,052	10,302
Derivative instruments	0	16,429
Advances from joint interest owners	10,968	2,789
Amounts due to joint ventures	2,373	4,873
Other current liabilities	1,028	750
Total current liabilities	330,022	282,606
Long-term liabilities
Borrowings under Credit Agreement	40,000	0
Long-term Line of Credit	220,000
Borrowings under San Mateo Credit Facility		0
Senior unsecured notes payable	1,037,837	574,073
Asset retirement obligations	29,736	25,080
Derivative instruments	83	0
Deferred income taxes	13,221	0
Other long-term liabilities	4,962	6,385
Total long-term liabilities	1,345,839	605,538
Commitments and contingencies (Note 13)
Shareholders' equity
Common stock — $0.01 par value, 160,000,000 shares authorized; 116,374,503 and 108,513,597 shares issued; and 116,353,590 and 108,510,160 shares outstanding, respectively	1,164	1,085
Additional paid-in capital	1,924,408	1,666,024
Accumulated deficit	(236,277)	(510,484)
Treasury stock, at cost, 20,913 and 3,437 shares, respectively	(415)	(69)
Total shareholders' equity	1,688,880	1,156,556
Non-controlling interest in subsidiaries	90,777	100,990
Total shareholders’ equity	1,779,657	1,257,546
Total liabilities and shareholders’ equity	$ 3,455,518	$ 2,145,690

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	160,000,000	160,000,000
Common stock, shares issued (in shares)	116,374,503	108,513,597
Common stock, shares outstanding (in shares)	116,353,590	108,510,160
Treasury stock (in shares)	20,913	3,437

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues
Revenues	$ 829,691
Lease bonus - mineral acreage	2,489	$ 0	$ 0
Realized gain (loss) on derivatives	2,334	(4,321)	9,286
Unrealized gain (loss) on derivatives	65,085	9,715	(41,238)
Total revenues	899,599	544,276	264,422
Expenses
Production taxes, transportation and processing	76,138	58,275	43,046
Lease operating	92,966	67,313	56,202
Plant and other midstream services operating	24,609	13,039	5,389
Purchased natural gas	6,635	0	0
Depletion, depreciation and amortization	265,142	177,502	122,048
Accretion of asset retirement obligations	1,530	1,290	1,182
Full-cost ceiling impairment	0	0	158,633
General and administrative	69,308	66,016	55,089
Total expenses	536,328	383,435	441,589
Operating income (loss)	363,271	160,841	(177,167)
Other income (expense)
Net (loss) gain on asset sales and inventory impairment	(196)	23	107,277
Interest expense	(41,327)	(34,565)	(28,199)
Prepayment premium on extinguishment of debt	(31,226)	0	0
Other income (expense)	1,551	3,551	(4)
Total other (expense) income	(71,198)	(30,991)	79,074
Income (loss) before income taxes	292,073	129,850	(98,093)
Income tax (benefit) provision
Current	(455)	(8,157)	(1,036)
Deferred	(7,236)	0	0
Total income tax benefit	(7,691)	(8,157)	(1,036)
Net income (loss)	274,207	125,867	(97,421)
Net income attributable to non-controlling interest in subsidiaries	(25,557)	(12,140)	(364)
Net income (loss) attributable to Matador Resources Company shareholders	$ 299,764	$ 138,007	$ (97,057)
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic (usd per share)	$ 2.41	$ 1.23	$ (1.07)
Diluted (usd per share)	$ 2.41	$ 1.23	$ (1.07)
Weighted average common shares outstanding
Basic (in shares)	113,580	102,029	91,273
Diluted (in shares)	113,691	102,543	91,273
Oil and natural gas revenues
Revenues
Revenues	$ 800,700	$ 528,684	$ 291,156
Third-party midstream services revenues
Revenues
Revenues	21,920	10,198	5,218
Sales of purchased natural gas
Revenues
Revenues	$ 7,071	$ 0	$ 0

Consolidated Statements of Changes in Shareholders' Equity - USD ($)	Total	Common stock	Additional paid-in capital	Accumulated deficit	Treasury stock	Parent	Noncontrolling Interest
Beginning Balance at Dec. 31, 2015	$ 488,959,000	$ 856,000	$ 1,026,077,000	$ (538,930,000)	$ 0	$ 488,003,000	$ 956,000
Beginning Balance, shares (in shares) at Dec. 31, 2015		85,567,000			2,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock, shares		13,500,000
Issuance of Class A common stock	288,510,000	$ 135,000	288,375,000			288,510,000
Issuance of common stock pursuant to employee stock compensation plan, shares		471,000
Issuance of common stock pursuant to employee stock compensation plan	0	$ 4,000	(4,000)			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	0	$ 1,000	(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, net of options forfeited in net share settlements	10,000		10,000			10,000
Cost to issue equity	(1,190,000)		(1,190,000)			(1,190,000)
Liability-based stock option awards settled, shares		10,000
Liability-based stock option awards settled	255,000		255,000			255,000
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
Net (loss) income	(97,057,000)			(97,421,000)		(97,421,000)	364,000
Ending Balance, shares (in shares) at Dec. 31, 2016		99,519,000			6,000
Ending Balance at Dec. 31, 2016	691,445,000	$ 995,000	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, shares		8,000,000
Issuance of Class A common stock	208,720,000	$ 80,000	208,640,000			208,720,000
Issuance of common stock pursuant to employee stock compensation plan, shares		530,000
Issuance of common stock pursuant to employee stock compensation plan	0	$ 5,000	(5,000)			0
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	0	$ 1,000	(1,000)			0
Stock options expense related to equity based awards	19,594,000		19,594,000			19,594,000
Stock options exercised, shares		514,000
Stock options exercised, net of options forfeited in net share settlements	(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
Net (loss) income	$ 138,007,000			125,867,000		125,867,000	12,140,000
Ending Balance, shares (in shares) at Dec. 31, 2017	108,510,160	108,514,000			3,000
Ending Balance at Dec. 31, 2017	$ 1,257,546,000	$ 1,085,000	1,666,024,000	(510,484,000)	$ (69,000)	1,156,556,000	100,990,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock, shares		7,000,000
Issuance of Class A common stock	226,612,000	$ 70,000	226,542,000			226,612,000
Issuance of common stock pursuant to employee stock compensation plan, shares		759,000
Issuance of common stock pursuant to employee stock compensation plan	0	$ 8,000	(8,000)			0
Issuance of Class A common stock to Board member and advisors, shares		81,000
Issuance of Class A common stock to Board member and advisors	0	$ 1,000	(1,000)			0
Stock options expense related to equity based awards	$ 22,660,000		22,660,000			22,660,000
Stock options exercised, shares	383,000	179,000
Stock options exercised, net of options forfeited in net share settlements	$ (1,267,000)	$ 2,000	(1,269,000)			(1,267,000)
Cost to issue equity	(204,000)		(204,000)			(204,000)
Restricted stock forfeited, shares					176,000
Restricted stock forfeited	(4,384,000)				$ (4,384,000)	(4,384,000)
Contributions related to formation of Joint Venture (see Note 5)	14,700,000		14,700,000			14,700,000	0
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	85,750,000						85,750,000
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries	(121,520,000)						(121,520,000)
Cancellation of treasury stock, shares		158,000			158,000
Cancellation of treasury stock	0	$ (2,000)	(4,036,000)		$ 4,038,000	0
Net (loss) income	$ 299,764,000			274,207,000		274,207,000	25,557,000
Ending Balance, shares (in shares) at Dec. 31, 2018	116,353,590	116,375,000			21,000
Ending Balance at Dec. 31, 2018	$ 1,779,657,000	$ 1,164,000	$ 1,924,408,000	$ (236,277,000)	$ (415,000)	$ 1,688,880,000	$ 90,777,000

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities
Net income (loss)	$ 299,764	$ 138,007	$ (97,057)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives	(65,085)	(9,715)	41,238
Depletion, depreciation and amortization	265,142	177,502	122,048
Accretion of asset retirement obligations	1,530	1,290	1,182
Full-cost ceiling impairment	0	0	158,633
Stock-based compensation expense	17,200	16,654	12,362
Prepayment premium on extinguishment of debt	31,226	0	0
Deferred income tax benefit	(7,236)	0	0
Amortization of debt issuance cost	1,357	468	1,148
Net loss (gain) on asset sales and inventory impairment	196	(23)	(107,277)
Changes in operating assets and liabilities
Accounts receivable	(4,934)	(82,549)	(14,259)
Lease and well equipment inventory	(12,176)	(3,623)	(700)
Prepaid expenses	(1,770)	(2,960)	(124)
Other assets	3,418	(6,425)	490
Accounts payable, accrued liabilities and other current liabilities	68,647	33,559	6,611
Royalties payable	3,418	37,370	7,495
Advances from joint interest owners	8,179	1,089	1,000
Income taxes payable	0	0	(2,848)
Other long-term liabilities	(353)	(1,519)	4,144
Net cash provided by operating activities	608,523	299,125	134,086
Investing activities
Oil and natural gas properties capital expenditures	(1,357,802)	(699,445)	(379,067)
Expenditures for other property and equipment	(165,784)	(120,816)	(74,845)
Proceeds from sale of assets	8,333	977	5,173
Net cash used in investing activities	(1,515,253)	(819,284)	(448,739)
Financing activities
Repayments of borrowings	(370,000)	0	(120,000)
Borrowings under Credit Agreement	410,000	0	120,000
Borrowings under San Mateo Credit Facility	220,000	0	0
Cost to enter into or amend credit facilities	(3,077)	0	0
Proceeds from issuance of senior unsecured notes	1,051,500	0	184,625
Cost to issue senior unsecured notes	(14,098)	0	(2,734)
Purchase of senior unsecured notes	(605,780)	0	0
Proceeds from issuance of common stock	226,612	208,720	288,510
Cost to issue equity	(204)	(280)	(847)
Proceeds from stock options exercised	815	2,920	100
Contributions related to formation of Joint Venture	14,700	171,500	0
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	85,750	44,100	0
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(121,520)	(10,045)	0
Taxes paid related to net share settlement of stock-based compensation	(6,466)	(5,763)	(1,948)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	0	(2,653)	0
Net cash provided by financing activities	888,232	408,499	467,706
(Decrease) increase in cash and restricted cash	(18,498)	(111,660)	153,053
Cash and restricted cash at beginning of year	102,482	214,142	61,089
Cash and restricted cash at end of year	$ 83,984	$ 102,482	$ 214,142

Nature of Operations	12 Months Ended
Nature of Operations	Dec. 31, 2018
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, 2018

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador 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.

Change in Accounting Principles — Revenue Recognition

During the first quarter of 2018, the Company adopted Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 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. The Company adopted the new guidance using the modified retrospective approach. The adoption did not require an adjustment to opening accumulated deficit for any cumulative effect adjustment and did not have a material impact on the Company’s consolidated balance sheets, statements of operations, statement of shareholders’ equity or statements of cash flows.

Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

The Company enters into contracts with customers to sell its oil and natural gas production. With the adoption of ASC 606, revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production.

The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer.

The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, natural gas liquids (“NGL”) are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations.

The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract.

The Company periodically enters into natural gas purchase transactions with third parties whereby the Company processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold.

From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations.

The Company determined the impact on its consolidated financial statements as a result of adoption of ASC 606 was a $10.6 million decrease in oil and natural gas revenues and a $10.6 million decrease in production taxes, transportation and processing expenses for the year ended December 31, 2018, respectively, which was not material. As a result of adoption of this standard, the Company is now required to disclose the following information regarding total revenues and revenues from contracts with customers on a disaggregated basis for the year ended December 31, 2018 (in thousands).



	Year Ended December 31, 2018
Revenues from contracts with customers	$	829,691
Lease bonus - mineral acreage	2,489
Realized gain on derivatives	2,334
Unrealized gain on derivatives	65,085
Total revenues	$	899,599



	Year Ended December 31, 2018
Oil revenues	$	635,554
Natural gas revenues	165,146
Third-party midstream services revenues	21,920
Sales of purchased natural gas	7,071
Total revenues from contracts with customers	$	829,691

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Change in Accounting Principles — Cash Flows

During the first quarter of 2018, the Company adopted Accounting Standards Update (“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. The Company adopted ASU 2016-18 effective January 1, 2018 and determined that the adoption of this ASU changed the presentation of its beginning and ending cash balances and eliminated the presentation of changes in restricted cash balances from investing activities in its consolidated statements of cash flows. The Company adopted the new guidance using the retrospective transition method; as a result, approximately $6.0 million, $1.3 million and $44.4 million of restricted cash was added to the beginning cash balance for the years ended December 31, 2018, 2017 and 2016, respectively.

Change in Accounting Principles — Business Combinations

During the first quarter of 2018, the Company adopted 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. The Company adopted ASU 2017-01 prospectively, which did not have a material impact on its consolidated financial statements.

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 NGL production to various purchasers (See “—Change in Accounting Principles—Revenue Recognition” above.) 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 NGLs 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.

For the year ended December 31, 2018, four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (19%), BP America Production Company (15%), Occidental Energy Marketing, Inc. (14%) and Western Refining Crude Oil (12%). For the year ended December 31, 2017, four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL 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 NGL revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc. (13%). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2018, 2017 and 2016, approximately 34%, 43% and 38%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

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 $29.9 million, $23.1 million and $15.7 million of its general and administrative costs in 2018, 2017 and 2016, respectively. The Company capitalized $8.8 million, $7.3 million and $3.7 million of its interest expense for the years ended December 31, 2018, 2017 and 2016, 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) any 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 Company’s derivative instruments are not considered in the ceiling test computations 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 2018, these average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. 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. 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 years ended December 31, 2018 and 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 years ended December 31, 2018 and 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.

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 NGL 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.

Stock-Based Compensation

The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based 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 consolidated statements of operations on a straight-line basis over the awards’ vesting periods. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are generally recognized as a component of general and administrative expenses in the consolidated statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the Company’s 2003 Stock and Incentive Plan (the “2003 Plan”) 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. As the stock options accounted for as liability-based awards are fully vested, changes in the fair value of the awards are generally recognized as a component of general and administrative expenses in the consolidated statements of operations until the awards are settled.

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, 2018, 2017 and 2016 include a stock-based compensation (non-cash) expense of $17.2 million, $16.7 million and $12.4 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.6 million, $3.0 million and $1.0 million in 2018, 2017 and 2016, 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, 2018, 2017 and 2016, 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, 2018, 2017 and 2016.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The legislation significantly changed 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 reduced the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21% effective January 1, 2018.

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, 2018, 2017 and 2016 (in thousands, except per share data).



	Year Ended December 31,
	2018		2017		2016
Net income (loss) attributable to Matador Resources Company shareholders — numerator	$	274,207	$	125,867	$	(97,421	)

Weighted average common shares outstanding — denominator
Basic	113,580		102,029		91,273
Dilutive effect of options and restricted stock units	111		514		—
Diluted weighted average common shares outstanding	113,691		102,543		91,273
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	2.41	$	1.23	$	(1.07	)
Diluted	$	2.41	$	1.23	$	(1.07	)

Options to purchase a total of 1.6 million and 1.0 million shares of the Company’s common stock were excluded from the calculations above for the years ended December 31, 2018 and 2017, respectively, because their effects were anti-dilutive.

Options to purchase a total of 2.9 million 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.

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 NGL 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, 2018 were with The Bank of Nova Scotia 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

Leases. In February 2016, the Financial Accounting Standards Board (“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. 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. The Company plans to use this practical expedient, and as a result, the Company will evaluate new or modified land easements under this ASU beginning at the date of adoption. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), which is a targeted improvement for comparative reporting requirements for initial adoption of ASU 2016-02. The Company plans to use the optional transition method to adopt ASU 2016-02, and the amendments provided for in ASU 2018-11 will allow the Company to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of accumulated deficit in the period of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The Company has evaluated the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases as defined under the new lease standards, and estimates that adoption of these standards will result in assets and liabilities related to leases of approximately $55 million to $65 million to be reflected on the Company’s consolidated balance sheet. The Company adopted these ASUs as of January 1, 2019.

Stock Compensation. In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting. This ASU extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Currently, the Company accounts for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards is recalculated each reporting period. Upon adoption, all such awards will be measured at fair value on the grant date and the resulting expense will be recognized on a straight-line basis over the awards’ vesting period. The transitional guidance requires entities to remeasure all unvested awards that are being accounted for under ASC 505-50 as liability instruments as of the beginning of the year in which this ASU is adopted. The Company adopted this ASU as of January 1, 2019. Adoption of this ASU will not have a material impact on the Company’s consolidated financial statements.

Property and Equipment

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 (in thousands).



	December 31,
	2018			2017
Oil and natural gas properties
Evaluated (subject to amortization)	$	3,780,236		$	3,004,770
Unproved and unevaluated (not subject to amortization)	1,199,511			637,396
Total oil and natural gas properties	4,979,747			3,642,166
Accumulated depletion	(2,273,010		)	(2,021,169		)
Net oil and natural gas properties	2,706,737			1,620,997
Midstream and other property and equipment
Midstream equipment and facilities	424,480			258,725
Furniture, fixtures and other equipment	7,184			6,109
Software	8,039			7,942
Land	4,192			2,892
Leasehold improvements	6,171			5,428
Total midstream and other property and equipment	450,066			281,096
Accumulated depreciation	(33,939		)	(20,637		)
Net midstream and other property and equipment	416,127			260,459
Net property and equipment	$	3,122,864		$	1,881,456

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2018 and the year in which these costs were incurred (in thousands).



Description	2018		2017		2016		2015 and prior		Total
Costs incurred for
Property acquisition	$	602,117	$	212,846	$	116,389	$	223,656	$	1,155,008
Exploration wells	12,361		1,235		712		204		14,512
Development wells	29,399		391		159		42		29,991
Total	$	643,877	$	214,472	$	117,260	$	223,902	$	1,199,511

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, 2018 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.

On September 12, 2018, the Company announced the successful acquisition of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”). The BLM Acquisition was responsible for a significant portion of the Company’s property acquisition costs in 2018.

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 $44.5 million at December 31, 2018. Of this total, $14.5 million was associated with exploration wells and $30.0 million was associated with development wells. The Company anticipates that most of the $44.5 million associated with these wells in progress at December 31, 2018 will be transferred to the amortization base during 2019.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 (in thousands).



	Year Ended December 31,
	2018			2017
Beginning asset retirement obligations	$	26,256		$	20,640
Liabilities incurred during period	3,566			2,920
Liabilities settled during period	(708		)	(430		)
Revisions in estimated cash flows	442			1,836
Accretion expense	1,530			1,290
Ending asset retirement obligations	31,086			26,256
Less: current asset retirement obligations ⁽¹⁾	(1,350		)	(1,176		)
Long-term asset retirement obligations	$	29,736		$	25,080

__________________


(1)	Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2018 and 2017.

Business Combinations and Divestitures	12 Months Ended
Business Combinations and Divestitures	Dec. 31, 2018
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 Energy LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) 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. The Company earned $14.7 million in performance incentives effective January 31, 2018, which was paid by Five Point in the first quarter of 2018. Through January 31, 2019, the Company had earned an additional $14.7 million in performance incentives expected to be paid by Five Point in the first quarter of 2019 and may earn an additional $44.1 million in performance incentives over the next three years. These performance incentives are recorded as additional contributions related to the formation of the Joint Venture as they are received. 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). 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, 2018

Debt Disclosure [Abstract]

DEBT

Credit Agreements

MRC Energy Company

On September 28, 2012, the Company amended and restated its revolving credit agreement with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company, a subsidiary of Matador that 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 certain of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries are not guarantors of the Credit Agreement. 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. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. During the first quarter of 2018, the lenders completed their review of our proved oil and natural gas reserves at December 31, 2017. As a result, in March 2018, the lenders increased the borrowing base from $525.0 million to $725.0 million. In October 2018, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2018. In connection with that review, the Company amended the Credit Agreement to, among other items, increase the borrowing base from $725.0 million to $850.0 million, increase the maximum facility amount to $1.5 billion, increase the elected borrowing commitment to $500.0 million, extend the maturity to October 31, 2023, reduce the borrowing rates by 0.25% per annum and set the maximum leverage ratio at 4.00 to 1.00. This October 2018 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment.

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 $2.0 million at December 31, 2018, 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 such 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, 2018, the Company had $40.0 million in borrowings outstanding under the Credit Agreement and approximately $3.0 million in outstanding letters of credit issued pursuant to the Credit Agreement. At February 26, 2019, the Company had $80.0 million in borrowings outstanding under the Credit Agreement and approximately $13.7 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 greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount ranging from 0.25% to 1.25% per annum 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 (x) the reserve adjusted LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.25% to 2.25% per annum 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. If the Company has outstanding borrowings under the Credit Agreement and interest rates increase, so will the Company’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition.

A commitment fee of 0.375% to 0.50% per annum, depending on the level of borrowings 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 debt outstanding (net of up to $50 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less.

Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s and its restricted subsidiaries’ 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, 2018.

San Mateo Midstream, LLC

On December 19, 2018, San Mateo entered into a $250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent (the “San Mateo Credit Facility”), and including all lenders party to the Credit Agreement. The San Mateo Credit Facility, which matures December 19, 2023, includes an accordion feature, which could expand lender commitments to up to $400.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property.

Total deferred loan costs were $1.9 million at December 31, 2018, and these costs are being amortized over the term of the San Mateo Credit Facility, which approximates amortization of these costs using the effective interest method. At December 31, 2018 and February 26, 2019, San Mateo had $220.0 million in borrowings outstanding under the San Mateo Credit Facility and zero and $16.2 million, respectively, in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.

Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus, in each case, an amount ranging from 0.50% to 1.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 1.50% to 2.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition.

A commitment fee of 0.30% to 0.50% per annum, depending on the unused availability under the San Mateo Credit Facility, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more.

Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following:


•	incur indebtedness or grant liens on any of San Mateo’s assets;


•	enter into 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 San Mateo’s assets; and


•	issue equity interests in San Mateo or its subsidiaries.

If an event of default exists under the San Mateo Credit Facility, 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 San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods;


•	bankruptcy or insolvency events involving San Mateo or its subsidiaries; and


•	a change of control, as defined in the San Mateo Credit Facility.

The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2018.

Senior Unsecured Notes

On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original 2023 Notes”) in a private placement at par value. The Original 2023 Notes were later exchanged for a like principal amount of 6.875% senior notes due 2023 (the “2023 Exchange Notes”) that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), at par value. On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional 2023 Notes”) in a private placement, 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 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 2023 Notes. The Additional 2023 Notes were later exchanged for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (together with the 2023 Exchange Notes, the “2023 Notes”).

On August 21, 2018, the Company issued $750.0 million of 5.875% senior notes due 2026 (the “Original 2026 Notes”) in a private placement at par value (the “2026 Notes Offering”). The Company received net proceeds of approximately $740.0 million, after deducting the initial purchasers’ discounts and offering expenses. In conjunction with the 2026 Notes Offering, in August and September 2018, respectively, the Company completed a tender offer to purchase for cash and subsequent redemption of all of the 2023 Notes (the “2023 Notes Tender Offer and Redemption”). The Company used a portion of the net proceeds from the 2026 Notes Offering to fund the 2023 Notes Tender Offer and Redemption. In connection with the 2023 Notes Tender Offer and Redemption, the Company incurred a loss of $31.2 million, including total payments of $30.4 million to holders of the 2023 Notes as a result of the tender premium and the required 105.156% redemption price payable pursuant to the 2023 Notes indenture.

On October 4, 2018, the Company issued an additional $300.0 million of 5.875% senior notes due 2026 (the “Additional 2026 Notes”). The Additional 2026 Notes were issued pursuant to, and are governed by, the same indenture governing the Original 2026 Notes (the “Indenture”). The Additional 2026 Notes were issued at 100.5% of par, plus accrued interest from August 21, 2018. The Company received net proceeds from this offering of approximately $297.3 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest from August 21, 2018 paid by the initial purchasers of the Additional 2026 Notes. The proceeds from this offering were used to repay a portion of the outstanding borrowings under the Credit Agreement, which were incurred in connection with the BLM Acquisition.

In December 2018, the Company exchanged substantially all of the Original 2026 Notes and Additional 2026 Notes for a like principal amount of 5.875% senior notes due 2026 that have been registered under the Securities Act (the “Notes”). The terms of the Notes are substantially the same as the terms of the Original 2026 Notes and Additional 2026 Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original 2026 Notes and Additional 2026 Notes do not apply to the Notes. The Notes will mature September 15, 2026, and interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted Subsidiaries under the Indenture or Guarantors of the Notes (see Note 16).

On or after September 15, 2021, the Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below:



Year		Redemption Price
2021		104.406%
2022		102.938%
2023		101.469%
2024 and thereafter		100.000%

At any time prior to September 15, 2021, the Company 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 105.875% of the principal amount thereof, 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 the Company 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 September 15, 2021, the Company 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 September 15, 2021 plus (2) any required interest payments due on such Notes through September 15, 2021, 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 additional indebtedness;


•	sell assets;


•	pay dividends or make certain investments;


•	create liens that secure indebtedness;


•	enter into transactions with affiliates; and


•	merge or consolidate with another company.

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) 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 the Company to comply with its obligations to offer to purchase or purchase notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers;


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


•	failure by the Company 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 the Company and its Restricted Subsidiaries in the aggregate principal amount of $50.0 million or more;


•	failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $50.0 million within 60 days;


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


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

The outstanding borrowings of $40.0 million at December 31, 2018 under the Credit Agreement mature on October 31, 2023. The outstanding borrowings of $220.0 million at December 31, 2018 under the San Mateo Credit Facility mature on December 19, 2023. The $1.05 billion of outstanding Notes at December 31, 2018 mature on September 15, 2026.

Income Taxes

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 is as follows (in thousands).



	December 31,
	2018			2017
Deferred tax assets
Unrealized loss on derivatives	$	—		$	3,200
Net operating loss carryforwards	116,374			118,134
Percentage depletion carryover	1,624			1,582
Basis increase related to the San Mateo transaction	—			18,382
Other	9,115			—
Total deferred tax assets	127,113			141,298
Valuation allowance on deferred tax assets	(6,519		)	(89,482		)
Total deferred tax assets, net of valuation allowance	120,594			51,816
Deferred tax liabilities
Unrealized gain on derivatives	(10,468		)	—
Property and equipment	(100,634		)	(40,568		)
Other	(2,256		)	(11,248		)
Total deferred tax liabilities	(113,358		)	(51,816		)
Net deferred tax assets	$	7,236		$	—

At December 31, 2018, the Company had net operating loss carryforwards of $511.3 million for federal income tax purposes and $156.4 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.

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 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 due to uncertainties regarding the future utilization of its deferred tax assets. Due to a variety of factors, including the Company’s significant net income in 2017 and 2018, the Company’s federal valuation allowance and a portion of the Company’s state valuation allowance were reversed at December 31, 2018 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized.

The current income tax (benefit) provision and the deferred income tax (benefit) provision for the years ended December 31, 2018, 2017 and 2016 were comprised of the following (in thousands).



	Year Ended December 31,
	2018			2017			2016
Current income tax (benefit) provision
Federal income tax	$	(455	)	$	(8,178	)	$	(1,144	)
State income tax	—			21			108
Net current income tax benefit	$	(455	)	$	(8,157	)	$	(1,036	)
Deferred income tax (benefit) provision
Federal income tax	$	(20,457	)	$	—		$	—
State income tax	13,221			—			—
Net deferred income tax benefit	$	(7,236	)	$	—		$	—

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, 2018, 2017 and 2016 is as follows (in thousands).



	Year Ended December 31,
	2018			2017			2016
Federal tax expense (benefit) at statutory rate ⁽¹⁾	$	61,543		$	45,447		$	(34,333	)
State income tax	16,181			368			539
Permanent differences	(2,488		)	(4,740		)	(499		)
Federal alternative minimum tax	—			—			1,144
AMT credit refundable	455			8,178			—
Tax Cuts and Jobs Act rate change	—			51,525			—
Change in federal valuation allowance	(80,003		)	(101,917		)	33,688
Change in state valuation allowance	(2,924		)	1,139			(539		)
Net deferred income tax benefit	(7,236		)	—			—
Net current income tax benefit	(455		)	(8,157		)	(1,036		)
Total income tax benefit	$	(7,691	)	$	(8,157	)	$	(1,036	)

__________________


(1)	The statutory federal tax rate was 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016.

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 federal, the State of New Mexico and the State of Louisiana tax returns is 2015. The earliest tax year open for examination for the State of Texas tax return is 2014.

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, 2018, 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 the 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 are expected to be refunded. As a result, the Company recorded $0.5 million and $8.2 million, respectively, as a current income tax benefit in its consolidated statements of operations for the years ended December 31, 2018 and 2017.

Stock-Based Compensation

12 Months Ended

Dec. 31, 2018

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 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, 2018, 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, directors, contractors or 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. At December 31, 2018, all stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and substantially all 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 67,500, 75,000 and 77,500 stock option awards outstanding under the 2003 Plan at December 31, 2018, 2017 and 2016, respectively, was estimated using the following weighted average assumptions.



	2018	2017	2016
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	1.14 years	2.14 years	3.14 years
Risk-free interest rate	2.48%	1.98%	1.70%
Volatility	37.94%	43.60%	47.07%
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, 2018, 2017 and 2016.



	2018	2017	2016
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	4.00 years	4.00 years	3.96 years
Risk-free interest rate	2.51%	1.77%	1.08%
Volatility	45.17%	47.00%	45.68%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	2.24%	3.66%	1.16%
Weighted average fair value of stock option awards granted during the year	$12.64	$10.49	$5.65

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, 2018 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, 2017	3,064		$	21.14
Options granted	563		$	29.68
Options exercised	(383	)	$	13.84
Options forfeited	(18	)	$	26.33
Options expired	(1	)	$	26.86
Options outstanding at December 31, 2018	3,225		$	23.48



	Options outstanding at December 31, 2018				Options exercisable at December 31, 2018
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
$9.00	68	1.14	$	9.00	68	$	9.00
$13.22 - $15.00	615	2.13	$	14.98	3	$	13.22
$19.71 - $22.70	727	1.10	$	21.92	706	$	21.93
$23.40 - $29.68	1,815	3.91	$	26.79	556	$	24.65

At December 31, 2018, the aggregate intrinsic value was $0.8 million for outstanding options and $0.4 million for exercisable options, based on the Company’s quoted closing market price of $15.53 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2018 was 2.88 years.

The total intrinsic value of options exercised during the years ended December 31, 2018, 2017 and 2016 was $7.0 million, $13.2 million and $1.6 million, respectively. The tax related benefit realized from the exercise of stock options totaled $5.7 million, $5.0 million and $0.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.

At December 31, 2018, the total remaining unrecognized compensation expense related to unvested stock options was approximately $9.3 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.65 years.

The fair value of options vested during 2018, 2017 and 2016 was $11.8 million, $2.1 million and $3.0 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 2018, 2017 and 2016 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, 2018 were granted under the 2012 Incentive Plan.

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2018 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, 2017	1,104		$	22.59	65		$	23.36
Granted	759		$	29.45	64		$	27.69
Vested	(475	)	$	23.87	(71	)	$	23.90
Forfeited	(32	)	$	27.20	—		—
Non-vested at December 31, 2018	1,356		$	25.87	58		$	27.48

At December 31, 2018, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $22.0 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 $15.53 per share on that date.

At December 31, 2018, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $22.0 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 0.90 years.

The fair value of restricted stock and restricted stock units vested during 2018, 2017 and 2016 was $13.0 million, $9.9 million and $4.6 million, respectively.

Summary

During the years ended December 31, 2018, 2017 and 2016, the total expense attributable to stock options was $6.3 million, $7.1 million and $5.9 million, respectively. At December 31, 2018, 2017 and 2016, the Company recorded a decrease of $1.1 million and increases of $0.4 million and $1.4 million to long-term 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, 2018, 2017 and 2016, respectively.

During the years ended December 31, 2018, 2017 and 2016, the total expense attributable to restricted stock and restricted stock units was $15.3 million, $12.9 million and $6.6 million, respectively. During the year ended December 31, 2018, the Company capitalized $4.4 million related to stock-based compensation and expensed the remaining $17.2 million.

The total tax benefit recognized for all stock-based compensation was $4.8 million, $6.8 million and $4.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

In February 2019, the Company granted awards to certain of its employees of 428,005 service-based restricted stock units to be settled in cash, which are liability instruments, and 428,005 performance-based stock units, which are equity instruments. The performance-based stock units vest in an amount between zero and 200% based on the Company’s relative total shareholder return over the three-year period ending December 31, 2021, as compared to a designated peer group. The service-based restricted stock units vest ratably over three years, and the performance-based stock units vest after completion of the three-year performance period.

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2018
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 $1.1 million, $0.9 million and $0.7 million in 2018, 2017 and 2016, 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 $1.4 million, $1.1 million and $0.9 million in 2018, 2017 and 2016, respectively. The Company made no additional contributions in any reporting period presented.

Equity	12 Months Ended
Equity	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
EQUITY	Stock On May 17, 2018, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.2 million, the Company received net proceeds of approximately $226.4 million. The proceeds from this offering were used to acquire additional leasehold and mineral acres in the Delaware Basin, to fund certain midstream initiatives in the Delaware Basin and for general corporate purposes, including to fund a portion of the Company’s capital expenditures. Pending such uses, the Company used a portion of the proceeds from the offering to repay the $45.0 million in borrowings then outstanding under the Credit Agreement. 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. 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. Treasury Stock On October 25, 2018, November 1, 2017, and October 27, 2016, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2018, 2017 and 2016, 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, 2018, 2017 and 2016 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. Preferred Stock The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series.

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2018

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 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, 2018, 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 2019 and 2020.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2018.



		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	01/01/2019 - 12/31/2019	3,720,000	$	53.55	$	72.22	$	31,531
Natural Gas	01/01/2019 - 12/31/2019	2,400,000	$	2.50	$	3.80	164
Total open costless collar contracts							$	31,695

The following is a summary of the Company’s open three-way costless collar contracts for oil at December 31, 2018. Open three-way costless collars consist of a long put (the floor), a short call (the ceiling) and a long call that limits losses on the upside.



Commodity	Calculation Period		Notional Quantity (Bbl)	Weighted Average Price Floor ($/Bbl)		Weighted Average Price, Short Call ($/Bbl)		Weighted Average Price, Long Call ($/Bbl)			Fair Value of Asset (Liability) (thousands)
Oil	01/01/2019 - 12/31/2019		1,320,000	$	60.00	$	75.00	$	78.85		$	18,114
Natural Gas	01/01/2019 - 12/31/2019	2.50	4,800,000	$	2.50	$	3.00	3.24		120	120
Total open three-way costless collar contracts											$	18,234

The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2018.



Commodity	Calculation Period	Notional Quantity (Bbl or Gal)	Fixed Price ($/Bbl or $/Gal)			Fair Value of Asset (Liability) (thousands)
Oil Basis Swaps	01/01/2020 - 12/31/2020	1,200,000	$	(0.15	)	$	(83	)
Total open swap contracts						$	(83	)

At December 31, 2018, the Company had an aggregate asset value for open derivative financial instruments of $49.8 million.

The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement 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, 2018 and December 31, 2017 (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, 2018
Current assets	$	53,136		$	(3,207	)	$	49,929
Long-term liabilities	(83		)	—			(83		)
Total	$	53,053		$	(3,207	)	$	49,846
December 31, 2017
Current assets	$	131,092		$	(129,902	)	$	1,190
Current liabilities	(146,331		)	129,902			(16,429		)
Total	$	(15,239	)	$	—		$	(15,239	)

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	2018			2017			2016
Derivative Instrument
Oil	Revenues: Realized gain (loss) on derivatives	$	3,741		$	(3,657	)	$	5,851
Natural Gas	Revenues: Realized (loss) gain on derivatives	(1,407		)	(608		)	3,435
NGLs	Revenues: Realized loss on derivatives	—			(56		)	—
Realized gain (loss) on derivatives		2,334			(4,321		)	9,286
Oil	Revenues: Unrealized gain (loss) on derivatives	65,991			2,638			(18,969		)
Natural Gas	Revenues: Unrealized (loss) gain on derivatives	(906		)	7,077			(22,269		)
Unrealized gain (loss) on derivatives		65,085			9,715			(41,238		)
Total		$	67,419		$	5,394		$	(31,952	)

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

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.

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, 2018 and 2017 (in thousands).



	Fair Value Measurements at December 31, 2018 using
Description	Fair Value Measurements at December 31, 2018 using
Description	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	49,562	$	—	$	49,562
Natural gas derivatives	—		284		—		284
Total	$	—	$	49,846	$	—	$	49,846



	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)
Oil derivatives and basis swaps	$	—	$	(16,429	)	$	—	$	(16,429	)
Natural gas derivatives	—		1,190			—		1,190
Total	$	—	$	(15,239	)	$	—	$	(15,239	)

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 at Level 2 in the fair value hierarchy.

Other Fair Value Measurements

At December 31, 2018 and 2017, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other assets, 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, 2018, the carrying values of the borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy.

At December 31, 2018 and 2017, the fair value of the Notes and the 2023 Notes was $968.9 million and $614.1 million, respectively, based on quoted market prices, which represents Level 1 inputs 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 2018 and 2017.

- 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, 2018

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, 2018 (in thousands).



Year Ending December 31,	Amount
2019	$	3,091
2020	3,914
2021	3,877
2022	4,009
2023	4,141
Thereafter	9,921
Total	$	28,953

Rent expense, including fees for operating expenses and consumption of electricity, was $2.7 million, $2.6 million and $2.9 million for 2018, 2017 and 2016, 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, 2018, the total deficiency fee required to be paid would be approximately $7.6 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 that year’s natural gas deficiency. The Company paid approximately $15.4 million and $14.4 million in processing and gathering fees under this agreement during the years ended December 31, 2018 and 2017, 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 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, the Company will owe the fees to transport the committed volume whether or not the committed volume is utilized. The minimum contractual obligation at December 31, 2018 was approximately $20.1 million. The Company paid approximately $3.3 million and $0.2 million in transportation fees, which included no deficiency fees, under this agreement during the years ended December 31, 2018 and 2017, respectively.

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 volume 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 in 2020. 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 volume 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. Should the pipeline extension and fractionation facility be completed on or prior to February 28, 2021, the minimum obligation during the seven-year period would be approximately $132.3 million.

In April 2018, the Company entered into a short-term natural gas transportation agreement whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Under this short-term agreement, the Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation under this short-term contract at December 31, 2018 was approximately $2.7 million. This short-term agreement ends on September 30, 2019. The Company paid approximately $1.9 million in transportation fees under this agreement during the year ended December 31, 2018.

In April 2018, the Company also entered into a 16-year, fixed-fee natural gas transportation agreement that begins on October 1, 2019, whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation at December 31, 2018 was approximately $56.8 million.

In May 2018, the Company also entered into a 10-year, fixed-fee natural gas sales agreement whereby the Company committed to deliver residue gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date of such pipeline, which is expected to be operational in late 2019. If the Company does not meet the volume commitment specified in the natural gas sales agreement, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. The minimum contractual obligation at December 31, 2018 was approximately $200.6 million.

Delaware Basin — San Mateo

In February 2017, 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 with subsidiaries of San Mateo. 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, 2018 was approximately $221.1 million.

During the first quarter of 2018, a subsidiary of San Mateo entered into agreements for additional field compression and an amine gas treatment unit to maximize the operation of the Black River Processing Plant. Since inception, San Mateo’s commitments under these agreements totaled $24.9 million. The subsidiary of San Mateo paid approximately $21.3 million under these agreements during the year ended December 31, 2018. As of December 31, 2018, the remaining obligations under these agreements were $3.6 million, which are expected to be paid during 2019.

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 $28.4 million at December 31, 2018.

At December 31, 2018, 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 $24.3 million at December 31, 2018. 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, 2018

Supplemental Disclosures [Abstract]

SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2018 and 2017 (in thousands).



	December 31,
	2018		2017
Accrued evaluated and unproved and unevaluated property costs	$	86,318	$	105,347
Accrued midstream properties costs	16,808		14,823
Accrued lease operating expenses	12,705		12,611
Accrued interest on debt	22,448		8,345
Accrued asset retirement obligations	1,350		1,176
Accrued partners’ share of joint interest charges	17,037		27,628
Other	14,189		4,418
Total accrued liabilities	$	170,855	$	174,348

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2018, 2017 and 2016 (in thousands).



	Year Ended December 31,
	2018			2017			2016
Cash paid for income taxes	$	—		$	—		$	2,895
Cash paid for interest expense, net of amounts capitalized	$	29,474		$	32,760		$	27,464
Increase in asset retirement obligations related to mineral properties	$	2,614		$	4,385		$	3,817
Increase (decrease) in asset retirement obligations related to midstream properties	$	686		$	(60	)	$	222
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures	$	(16,802	)	$	48,929		$	1,775
Increase (decrease) in liabilities for midstream properties capital expenditures	$	2,499		$	(955	)	$	(588	)
Issuance of restricted stock units for director and advisor services	$	—		$	—		$	992
Stock-based compensation (benefit) expense recognized as liability	$	(1,069	)	$	362		$	569
(Decrease) increase in liabilities for accrued cost to issue equity	$	—		$	(343	)	$	343
Increase in liabilities for accrued cost to issue debt	$	232		$	—		$	—
Transfer of inventory from (to) oil and natural gas properties	$	409		$	(374	)	$	395
Transfer of inventory to midstream and other property and equipment	$	—		$	(317	)	$	—

The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands).



	Year Ended December 31,
	2018		2017		2016
Cash	$	64,545	$	96,505	$	212,884
Restricted cash	19,439		5,977		1,258
Total cash and restricted cash	$	83,984	$	102,482	$	214,142

Segment Reporting

12 Months Ended

Dec. 31, 2018

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, oil, natural gas 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 business 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, 2018
Oil and natural gas revenues	$	794,261	$	6,439	$	—		$	—		$	800,700
Midstream services revenues	—		86,737		—			(64,817		)	21,920
Sales of purchased natural gas	902		6,169		—			—			7,071
Lease bonus - mineral acreage	2,489		—		—			—			2,489
Realized gain on derivatives	2,334		—		—			—			2,334
Unrealized gain on derivatives	65,085		—		—			—			65,085
Expenses ⁽¹⁾	487,539		44,098		69,508			(64,817		)	536,328
Operating income (loss) ⁽²⁾	$	377,532	$	55,247	$	(69,508	)	$	—		$	363,271
Total assets	$	2,910,326	$	439,953	$	105,239		$	—		$	3,455,518
Capital expenditures ⁽³⁾	$	1,335,690	$	166,407	$	2,562		$	—		$	1,504,659

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $252.3 million and $10.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.4 million.


(2)	Includes $25.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $656.9 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $80.2 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, 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.

Subsidiary Guarantors

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

SUBSIDIARY GUARANTORS

The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2018, 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 (the “Non-Guarantor 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, 2018
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	1,244,405	$	29,816	$	—	$	(1,274,221	)	$	—
Current assets	4,109		34,027		267,549		—			305,685
Net property and equipment	—		379,052		2,743,812		—			3,122,864
Investment in subsidiaries	1,490,401		—		95,346		(1,585,747		)	—
Long-term assets	23,897		1,479		11,095		(9,502		)	26,969
Total assets	$	2,762,812	$	444,374	$	3,117,802	$	(2,869,470	)	$	3,455,518
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	1,274,221	$	(1,274,221	)	$	—
Current liabilities	22,874		27,988		279,884		(724		)	330,022
Senior unsecured notes payable	1,037,837		—		—					1,037,837
Other long-term liabilities	13,221		230,263		73,296		(8,778		)	308,002
Total equity attributable to Matador Resources Company	1,688,880		95,346		1,490,401		(1,585,747		)	1,688,880
Non-controlling interest in subsidiaries	—		90,777		—		—			90,777
Total liabilities and equity	$	2,762,812	$	444,374	$	3,117,802	$	(2,869,470	)	$	3,455,518



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 Statement of Operations For the Year Ended December 31, 2018
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	98,665		$	865,725		$	(64,791	)	$	899,599
Total expenses	4,935			46,236			549,948			(64,791		)	536,328
Operating (loss) income	(4,935		)	52,429			315,777			—			363,271
Net loss on asset sales and inventory impairment	—			—			(196		)	—			(196		)
Interest expense	(40,994		)	(333		)	—			—			(41,327		)
Prepayment penalty on extinguishment of debt	(31,226		)	—			—			—			(31,226		)
Other income	565			62			924			—			1,551
Earnings in subsidiaries	343,106			—			26,601			(369,707		)	—
Income before income taxes	266,516			52,158			343,106			(369,707		)	292,073
Total income tax benefit	(7,691		)	—			—			—			(7,691		)
Net income attributable to non-controlling interest in subsidiaries	—			(25,557		)	—			—			(25,557		)
Net income attributable to Matador Resources Company shareholders	$	274,207		$	26,601		$	343,106		$	(369,707	)	$	274,207



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 Cash Flows For the Year Ended December 31, 2018
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(657,860	)	$	35,119		$	1,231,264		$	—		$	608,523
Net cash used in investing activities	—			(162,147		)	(1,310,776		)	(42,330		)	(1,515,253		)
Net cash provided by financing activities	658,030			140,205			47,667			42,330			888,232
Increase (decrease) in cash and restricted cash	170			13,177			(31,845		)	—			(18,498		)
Cash and restricted cash at beginning of year	286			5,663			96,533			—			102,482
Cash and restricted cash at end of year	$	456		$	18,840		$	64,688		$	—		$	83,984



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			(114,852		)	(597,870		)	(106,595		)	(819,284		)
Net cash provided by (used in) financing activities	208,440			96,307			(2,843		)	106,595			408,499
Decrease in cash and restricted cash	(99,509		)	2,763			(14,914		)	—			(111,660		)
Cash and restricted cash at beginning of year	99,795			2,900			111,447			—			214,142
Cash and restricted cash at end of year	$	286		$	5,663		$	96,533		$	—		$	102,482



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		)	(64,999		)	(443,817		)	384,801			(448,739		)
Net cash provided by financing activities	469,654			60,110			322,743			(384,801		)	467,706
Increase in cash and restricted cash	99,715			1,805			51,533			—			153,053
Cash and restricted cash at beginning of year	80			1,095			59,914			—			61,089
Cash and restricted cash at end of year	$	99,795		$	2,900		$	111,447		$	—		$	214,142

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	On February 25, 2019, the Company announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with a subsidiary of Five Point designed to expand the Company’s midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by the Company and 49% by Five Point. In addition, Five Point has committed to pay $125 million of the first $150 million of capital expenditures incurred by San Mateo II to develop facilities in the Stebbins area and the Stateline asset area. The Company has the ability to earn up to $150 million in deferred performance incentives over the next five years, plus additional performance incentives for securing volumes from third-party customers. In connection with the formation of San Mateo II, the Company dedicated to San Mateo II acreage in the Stebbins area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal (collectively, the “San Mateo II Operational Agreements”). San Mateo II will provide the Company with firm service under each of the San Mateo II Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the San Mateo II Operational Agreements at inception was approximately $363.8 million and begins in 2020.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated financial statements include the accounts of Matador 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.
Revenue Recognition	The Company enters into contracts with customers to sell its oil and natural gas production. With the adoption of ASC 606, revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, natural gas liquids (“NGL”) are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. The Company periodically enters into natural gas purchase transactions with third parties whereby the Company processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations.
Recent Accounting Pronouncements	Change in Accounting Principles — Cash Flows During the first quarter of 2018, the Company adopted Accounting Standards Update (“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. The Company adopted ASU 2016-18 effective January 1, 2018 and determined that the adoption of this ASU changed the presentation of its beginning and ending cash balances and eliminated the presentation of changes in restricted cash balances from investing activities in its consolidated statements of cash flows. The Company adopted the new guidance using the retrospective transition method; as a result, approximately $6.0 million, $1.3 million and $44.4 million of restricted cash was added to the beginning cash balance for the years ended December 31, 2018, 2017 and 2016, respectively. Change in Accounting Principles — Business Combinations During the first quarter of 2018, the Company adopted 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. The Company adopted ASU 2017-01 prospectively, which did not have a material impact on its consolidated financial statements Recent Accounting Pronouncements Leases. In February 2016, the Financial Accounting Standards Board (“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. 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. The Company plans to use this practical expedient, and as a result, the Company will evaluate new or modified land easements under this ASU beginning at the date of adoption. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), which is a targeted improvement for comparative reporting requirements for initial adoption of ASU 2016-02. The Company plans to use the optional transition method to adopt ASU 2016-02, and the amendments provided for in ASU 2018-11 will allow the Company to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of accumulated deficit in the period of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The Company has evaluated the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases as defined under the new lease standards, and estimates that adoption of these standards will result in assets and liabilities related to leases of approximately $55 million to $65 million to be reflected on the Company’s consolidated balance sheet. The Company adopted these ASUs as of January 1, 2019. Stock Compensation. In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting. This ASU extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Currently, the Company accounts for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards is recalculated each reporting period. Upon adoption, all such awards will be measured at fair value on the grant date and the resulting expense will be recognized on a straight-line basis over the awards’ vesting period. The transitional guidance requires entities to remeasure all unvested awards that are being accounted for under ASC 505-50 as liability instruments as of the beginning of the year in which this ASU is adopted. The Company adopted this ASU as of January 1, 2019. Adoption of this ASU will not have a material impact on the Company’s consolidated financial statements. During the first quarter of 2018, the Company adopted Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 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. The Company adopted the new guidance using the modified retrospective approach. The adoption did not require an adjustment to opening accumulated deficit for any cumulative effect adjustment and did not have a material impact on the Company’s consolidated balance sheets, statements of operations, statement of shareholders’ equity or statements of cash flows.
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 NGL production to various purchasers (See “—Change in Accounting Principles—Revenue Recognition” above.) 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 NGLs 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. For the year ended December 31, 2018, four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (19%), BP America Production Company (15%), Occidental Energy Marketing, Inc. (14%) and Western Refining Crude Oil (12%). For the year ended December 31, 2017, four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL 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 NGL revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc. (13%). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2018, 2017 and 2016, approximately 34%, 43% and 38%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.
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 $29.9 million, $23.1 million and $15.7 million of its general and administrative costs in 2018, 2017 and 2016, respectively. The Company capitalized $8.8 million, $7.3 million and $3.7 million of its interest expense for the years ended December 31, 2018, 2017 and 2016, 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) any 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 Company’s derivative instruments are not considered in the ceiling test computations 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 2018, these average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. 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. 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 years ended December 31, 2018 and 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 years ended December 31, 2018 and 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. 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 NGL 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.
Stock-Based Compensation	Stock-Based Compensation The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based 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 consolidated statements of operations on a straight-line basis over the awards’ vesting periods. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are generally recognized as a component of general and administrative expenses in the consolidated statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the Company’s 2003 Stock and Incentive Plan (the “2003 Plan”) 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. As the stock options accounted for as liability-based awards are fully vested, changes in the fair value of the awards are generally recognized as a component of general and administrative expenses in the consolidated statements of operations until the awards are settled. 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, 2018, 2017 and 2016, 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 NGL 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, 2018 were with The Bank of Nova Scotia 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.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Disaggregation of Revenue

As a result of adoption of this standard, the Company is now required to disclose the following information regarding total revenues and revenues from contracts with customers on a disaggregated basis for the year ended December 31, 2018 (in thousands).



	Year Ended December 31, 2018
Revenues from contracts with customers	$	829,691
Lease bonus - mineral acreage	2,489
Realized gain on derivatives	2,334
Unrealized gain on derivatives	65,085
Total revenues	$	899,599



	Year Ended December 31, 2018
Oil revenues	$	635,554
Natural gas revenues	165,146
Third-party midstream services revenues	21,920
Sales of purchased natural gas	7,071
Total revenues from contracts with customers	$	829,691

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



	Year Ended December 31,
	2018		2017		2016
Net income (loss) attributable to Matador Resources Company shareholders — numerator	$	274,207	$	125,867	$	(97,421	)

Weighted average common shares outstanding — denominator
Basic	113,580		102,029		91,273
Dilutive effect of options and restricted stock units	111		514		—
Diluted weighted average common shares outstanding	113,691		102,543		91,273
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	2.41	$	1.23	$	(1.07	)
Diluted	$	2.41	$	1.23	$	(1.07	)

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 (in thousands).



	December 31,
	2018			2017
Oil and natural gas properties
Evaluated (subject to amortization)	$	3,780,236		$	3,004,770
Unproved and unevaluated (not subject to amortization)	1,199,511			637,396
Total oil and natural gas properties	4,979,747			3,642,166
Accumulated depletion	(2,273,010		)	(2,021,169		)
Net oil and natural gas properties	2,706,737			1,620,997
Midstream and other property and equipment
Midstream equipment and facilities	424,480			258,725
Furniture, fixtures and other equipment	7,184			6,109
Software	8,039			7,942
Land	4,192			2,892
Leasehold improvements	6,171			5,428
Total midstream and other property and equipment	450,066			281,096
Accumulated depreciation	(33,939		)	(20,637		)
Net midstream and other property and equipment	416,127			260,459
Net property and equipment	$	3,122,864		$	1,881,456

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



Description	2018		2017		2016		2015 and prior		Total
Costs incurred for
Property acquisition	$	602,117	$	212,846	$	116,389	$	223,656	$	1,155,008
Exploration wells	12,361		1,235		712		204		14,512
Development wells	29,399		391		159		42		29,991
Total	$	643,877	$	214,472	$	117,260	$	223,902	$	1,199,511

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 (in thousands).



	Year Ended December 31,
	2018			2017
Beginning asset retirement obligations	$	26,256		$	20,640
Liabilities incurred during period	3,566			2,920
Liabilities settled during period	(708		)	(430		)
Revisions in estimated cash flows	442			1,836
Accretion expense	1,530			1,290
Ending asset retirement obligations	31,086			26,256
Less: current asset retirement obligations ⁽¹⁾	(1,350		)	(1,176		)
Long-term asset retirement obligations	$	29,736		$	25,080

__________________


(1)	Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2018 and 2017.

Debt (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt Instrument Redemption



Year		Redemption Price
2021		104.406%
2022		102.938%
2023		101.469%
2024 and thereafter		100.000%

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Summary of net deferred tax position

The Company’s net deferred tax position as of December 31, 2018 and 2017 is as follows (in thousands).



	December 31,
	2018			2017
Deferred tax assets
Unrealized loss on derivatives	$	—		$	3,200
Net operating loss carryforwards	116,374			118,134
Percentage depletion carryover	1,624			1,582
Basis increase related to the San Mateo transaction	—			18,382
Other	9,115			—
Total deferred tax assets	127,113			141,298
Valuation allowance on deferred tax assets	(6,519		)	(89,482		)
Total deferred tax assets, net of valuation allowance	120,594			51,816
Deferred tax liabilities
Unrealized gain on derivatives	(10,468		)	—
Property and equipment	(100,634		)	(40,568		)
Other	(2,256		)	(11,248		)
Total deferred tax liabilities	(113,358		)	(51,816		)
Net deferred tax assets	$	7,236		$	—

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

The current income tax (benefit) provision and the deferred income tax (benefit) provision for the years ended December 31, 2018, 2017 and 2016 were comprised of the following (in thousands).



	Year Ended December 31,
	2018			2017			2016
Current income tax (benefit) provision
Federal income tax	$	(455	)	$	(8,178	)	$	(1,144	)
State income tax	—			21			108
Net current income tax benefit	$	(455	)	$	(8,157	)	$	(1,036	)
Deferred income tax (benefit) provision
Federal income tax	$	(20,457	)	$	—		$	—
State income tax	13,221			—			—
Net deferred income tax benefit	$	(7,236	)	$	—		$	—



	Year Ended December 31,
	2018			2017			2016
Federal tax expense (benefit) at statutory rate ⁽¹⁾	$	61,543		$	45,447		$	(34,333	)
State income tax	16,181			368			539
Permanent differences	(2,488		)	(4,740		)	(499		)
Federal alternative minimum tax	—			—			1,144
AMT credit refundable	455			8,178			—
Tax Cuts and Jobs Act rate change	—			51,525			—
Change in federal valuation allowance	(80,003		)	(101,917		)	33,688
Change in state valuation allowance	(2,924		)	1,139			(539		)
Net deferred income tax benefit	(7,236		)	—			—
Net current income tax benefit	(455		)	(8,157		)	(1,036		)
Total income tax benefit	$	(7,691	)	$	(8,157	)	$	(1,036	)

__________________


(1)	The statutory federal tax rate was 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016.

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 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, 2017	3,064		$	21.14
Options granted	563		$	29.68
Options exercised	(383	)	$	13.84
Options forfeited	(18	)	$	26.33
Options expired	(1	)	$	26.86
Options outstanding at December 31, 2018	3,225		$	23.48

Summarized information about outstanding and exercisable stock option



	Options outstanding at December 31, 2018				Options exercisable at December 31, 2018
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
$9.00	68	1.14	$	9.00	68	$	9.00
$13.22 - $15.00	615	2.13	$	14.98	3	$	13.22
$19.71 - $22.70	727	1.10	$	21.92	706	$	21.93
$23.40 - $29.68	1,815	3.91	$	26.79	556	$	24.65

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, 2018 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, 2017	1,104		$	22.59	65		$	23.36
Granted	759		$	29.45	64		$	27.69
Vested	(475	)	$	23.87	(71	)	$	23.90
Forfeited	(32	)	$	27.20	—		—
Non-vested at December 31, 2018	1,356		$	25.87	58		$	27.48

2003 Stock and Incentive Plan

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



	2018	2017	2016
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	1.14 years	2.14 years	3.14 years
Risk-free interest rate	2.48%	1.98%	1.70%
Volatility	37.94%	43.60%	47.07%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	—%	—%	—%

2012 Incentive Plan

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



	2018	2017	2016
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	4.00 years	4.00 years	3.96 years
Risk-free interest rate	2.51%	1.77%	1.08%
Volatility	45.17%	47.00%	45.68%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	2.24%	3.66%	1.16%
Weighted average fair value of stock option awards granted during the year	$12.64	$10.49	$5.65

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018.



		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	01/01/2019 - 12/31/2019	3,720,000	$	53.55	$	72.22	$	31,531
Natural Gas	01/01/2019 - 12/31/2019	2,400,000	$	2.50	$	3.80	164
Total open costless collar contracts							$	31,695



Commodity	Calculation Period		Notional Quantity (Bbl)	Weighted Average Price Floor ($/Bbl)		Weighted Average Price, Short Call ($/Bbl)		Weighted Average Price, Long Call ($/Bbl)			Fair Value of Asset (Liability) (thousands)
Oil	01/01/2019 - 12/31/2019		1,320,000	$	60.00	$	75.00	$	78.85		$	18,114
Natural Gas	01/01/2019 - 12/31/2019	2.50	4,800,000	$	2.50	$	3.00	3.24		120	120
Total open three-way costless collar contracts											$	18,234

The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2018.



Commodity	Calculation Period	Notional Quantity (Bbl or Gal)	Fixed Price ($/Bbl or $/Gal)			Fair Value of Asset (Liability) (thousands)
Oil Basis Swaps	01/01/2020 - 12/31/2020	1,200,000	$	(0.15	)	$	(83	)
Total open swap contracts						$	(83	)

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, 2018
Current assets	$	53,136		$	(3,207	)	$	49,929
Long-term liabilities	(83		)	—			(83		)
Total	$	53,053		$	(3,207	)	$	49,846
December 31, 2017
Current assets	$	131,092		$	(129,902	)	$	1,190
Current liabilities	(146,331		)	129,902			(16,429		)
Total	$	(15,239	)	$	—		$	(15,239	)

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, 2018
Current assets	$	53,136		$	(3,207	)	$	49,929
Long-term liabilities	(83		)	—			(83		)
Total	$	53,053		$	(3,207	)	$	49,846
December 31, 2017
Current assets	$	131,092		$	(129,902	)	$	1,190
Current liabilities	(146,331		)	129,902			(16,429		)
Total	$	(15,239	)	$	—		$	(15,239	)

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	2018			2017			2016
Derivative Instrument
Oil	Revenues: Realized gain (loss) on derivatives	$	3,741		$	(3,657	)	$	5,851
Natural Gas	Revenues: Realized (loss) gain on derivatives	(1,407		)	(608		)	3,435
NGLs	Revenues: Realized loss on derivatives	—			(56		)	—
Realized gain (loss) on derivatives		2,334			(4,321		)	9,286
Oil	Revenues: Unrealized gain (loss) on derivatives	65,991			2,638			(18,969		)
Natural Gas	Revenues: Unrealized (loss) gain on derivatives	(906		)	7,077			(22,269		)
Unrealized gain (loss) on derivatives		65,085			9,715			(41,238		)
Total		$	67,419		$	5,394		$	(31,952	)

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 using
Description	Fair Value Measurements at December 31, 2018 using
Description	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	49,562	$	—	$	49,562
Natural gas derivatives	—		284		—		284
Total	$	—	$	49,846	$	—	$	49,846



	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)
Oil derivatives and basis swaps	$	—	$	(16,429	)	$	—	$	(16,429	)
Natural gas derivatives	—		1,190			—		1,190
Total	$	—	$	(15,239	)	$	—	$	(15,239	)

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 (in thousands).



Year Ending December 31,	Amount
2019	$	3,091
2020	3,914
2021	3,877
2022	4,009
2023	4,141
Thereafter	9,921
Total	$	28,953

Supplemental Disclosures (Tables)

12 Months Ended

Dec. 31, 2018

Supplemental Disclosures [Abstract]

Summary of current accrued liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2018 and 2017 (in thousands).



	December 31,
	2018		2017
Accrued evaluated and unproved and unevaluated property costs	$	86,318	$	105,347
Accrued midstream properties costs	16,808		14,823
Accrued lease operating expenses	12,705		12,611
Accrued interest on debt	22,448		8,345
Accrued asset retirement obligations	1,350		1,176
Accrued partners’ share of joint interest charges	17,037		27,628
Other	14,189		4,418
Total accrued liabilities	$	170,855	$	174,348

Supplemental disclosures of cash flow information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2018, 2017 and 2016 (in thousands).



	Year Ended December 31,
	2018			2017			2016
Cash paid for income taxes	$	—		$	—		$	2,895
Cash paid for interest expense, net of amounts capitalized	$	29,474		$	32,760		$	27,464
Increase in asset retirement obligations related to mineral properties	$	2,614		$	4,385		$	3,817
Increase (decrease) in asset retirement obligations related to midstream properties	$	686		$	(60	)	$	222
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures	$	(16,802	)	$	48,929		$	1,775
Increase (decrease) in liabilities for midstream properties capital expenditures	$	2,499		$	(955	)	$	(588	)
Issuance of restricted stock units for director and advisor services	$	—		$	—		$	992
Stock-based compensation (benefit) expense recognized as liability	$	(1,069	)	$	362		$	569
(Decrease) increase in liabilities for accrued cost to issue equity	$	—		$	(343	)	$	343
Increase in liabilities for accrued cost to issue debt	$	232		$	—		$	—
Transfer of inventory from (to) oil and natural gas properties	$	409		$	(374	)	$	395
Transfer of inventory to midstream and other property and equipment	$	—		$	(317	)	$	—



	Year Ended December 31,
	2018		2017		2016
Cash	$	64,545	$	96,505	$	212,884
Restricted cash	19,439		5,977		1,258
Total cash and restricted cash	$	83,984	$	102,482	$	214,142

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018
Oil and natural gas revenues	$	794,261	$	6,439	$	—		$	—		$	800,700
Midstream services revenues	—		86,737		—			(64,817		)	21,920
Sales of purchased natural gas	902		6,169		—			—			7,071
Lease bonus - mineral acreage	2,489		—		—			—			2,489
Realized gain on derivatives	2,334		—		—			—			2,334
Unrealized gain on derivatives	65,085		—		—			—			65,085
Expenses ⁽¹⁾	487,539		44,098		69,508			(64,817		)	536,328
Operating income (loss) ⁽²⁾	$	377,532	$	55,247	$	(69,508	)	$	—		$	363,271
Total assets	$	2,910,326	$	439,953	$	105,239		$	—		$	3,455,518
Capital expenditures ⁽³⁾	$	1,335,690	$	166,407	$	2,562		$	—		$	1,504,659

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $252.3 million and $10.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.4 million.


(2)	Includes $25.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $656.9 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $80.2 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, 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.

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2018 USD ($) Purchasers	Dec. 31, 2018 USD ($) $ / bbl	Dec. 31, 2018 USD ($) $ / MMBTU	Dec. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	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 USD ($) Purchasers	Dec. 31, 2016 USD ($) $ / bbl	Dec. 31, 2016 USD ($) $ / MMBTU	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Jan. 01, 2019 USD ($)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Stock-based compensation (non-cash) expense						$ 17,200,000					$ 16,654,000					$ 12,362,000
Capitalized general and administrative costs						29,900,000					23,100,000					15,700,000
Restricted cash	$ 19,439,000	$ 19,439,000	$ 19,439,000	$ 19,439,000	$ 19,439,000	19,439,000	$ 5,977,000	$ 5,977,000	$ 5,977,000	$ 5,977,000	5,977,000	$ 1,258,000	$ 1,258,000	$ 1,258,000	$ 1,258,000	1,258,000
Revenue from contract with customer						829,691,000
Billing date	30 days
Outstanding days of account receivable	60 days
Allowance for doubtful accounts	$ 0	$ 0	$ 0	$ 0	$ 0	0
Number of purchasers \| Purchasers		4					4					3
Capitalized interest expense						8,800,000					7,300,000					3,700,000
Present value discounted percent of future net revenues of proved oil and natural gas reserves					10.00%
Average oil and natural gas prices			62.04	3.10				47.79	2.98				39.25	2.48
Impairment charge of net capitalized costs						0					0					158,633,000
Common stock and restricted stock unit expense						1,600,000					3,000,000					1,000,000
Accounting Standards Update 2014-09 \| Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contract with customer						10,600,000
Cost of revenue						(10,600,000)
Accounting Standards Update 2016-18
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Restricted cash	$ 6,000,000	$ 6,000,000	$ 6,000,000	$ 6,000,000	$ 6,000,000	$ 6,000,000	$ 1,300,000	$ 1,300,000	$ 1,300,000	$ 1,300,000	$ 1,300,000	$ 44,400,000	$ 44,400,000	$ 44,400,000	$ 44,400,000	$ 44,400,000
Minimum
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract term after production	1 month
Accounts receivable due period	30 days
Useful life	5 years
Maximum
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract term after production	2 months
Accounts receivable due period	60 days
Useful life	30 years
Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage					60.00%					60.00%					48.00%
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage					34.00%					43.00%					38.00%
Plains Marketing, L.P. \| Customer Concentration Risk \| Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage					19.00%					14.00%					18.00%
Shell Trading (US) Company \| Customer Concentration Risk \| Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage										12.00%					17.00%
BP America Production Company \| Customer Concentration Risk \| Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage					15.00%
Occidental Energy Marketing, Inc. \| Customer Concentration Risk \| Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage					14.00%					23.00%					13.00%
Western Refining Oil \| Customer Concentration Risk \| Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage					12.00%					11.00%
Machinery and Equipment
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Useful life using the straight-line	30 years
Accumulated Deficit \| Subsequent Event \| Minimum \| Accounting Standards Update 2016-02
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
RIght-of-use asset																	$ 55,000,000
Lease liability																	55,000,000
Accumulated Deficit \| Subsequent Event \| Maximum \| Accounting Standards Update 2016-02
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
RIght-of-use asset																	65,000,000
Lease liability																	$ 60,000,000

Summary of Significant Accounting Policies - Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) attributable to Matador Resources Company shareholders — numerator	$ 274,207	$ 125,867	$ (97,421)
Weighted average common shares outstanding — denominator
Basic (in shares)	113,580,000	102,029,000	91,273,000
Dilutive effect of options and restricted stock units (in shares)	111,000	514,000	0
Diluted weighted average common shares outstanding (in shares)	113,691,000	102,543,000	91,273,000
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic (usd per share)	$ 2.41	$ 1.23	$ (1.07)
Diluted (usd per share)	$ 2.41	$ 1.23	$ (1.07)
Stock options
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Total (usd per share)	1,600,000	972,337	2,886,821
Restricted Stock Units (RSUs)
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Total (usd per share)			90,552
Restricted Stock
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Total (usd per share)			1,039,292

Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Disaggregated Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 829,691
Lease bonus - mineral acreage	2,489	$ 0	$ 0
Realized gain on derivatives	2,334	(4,321)	9,286
Unrealized gain on derivatives	65,085	9,715	(41,238)
Total revenues	899,599	544,276	264,422
Oil
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	635,554
Natural gas revenues
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	165,146
Third-party midstream services revenues
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	21,920	10,198	5,218
Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 7,071	$ 0	$ 0

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Oil and natural gas properties
Evaluated (subject to amortization)	$ 3,780,236	$ 3,004,770
Total unproved and unevaluated	1,199,511	637,396
Total oil and natural gas properties	4,979,747	3,642,166
Accumulated depletion	(2,273,010)	(2,021,169)
Net oil and natural gas properties	2,706,737	1,620,997
Other property and equipment
Midstream and other property and equipment	450,066	281,096
Accumulated depreciation	(33,939)	(20,637)
Net other property and equipment	416,127	260,459
Net property and equipment	3,122,864	1,881,456
Midstream equipment and facilities
Other property and equipment
Midstream and other property and equipment	424,480	258,725
Furniture, fixtures and other equipment
Other property and equipment
Midstream and other property and equipment	7,184	6,109
Software
Other property and equipment
Midstream and other property and equipment	8,039	7,942
Land
Other property and equipment
Midstream and other property and equipment	4,192	2,892
Leasehold improvements
Other property and equipment
Midstream and other property and equipment	$ 6,171	$ 5,428

Property and Equipment (Details 1) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs incurred for
Total unproved and unevaluated	$ 1,199,511	$ 637,396
2018
Costs incurred for
Property acquisition	602,117
Exploration wells	12,361
Development wells	29,399
Total unproved and unevaluated	643,877
2017
Costs incurred for
Property acquisition		212,846
Exploration wells		1,235
Development wells		391
Total unproved and unevaluated		$ 214,472
2016
Costs incurred for
Property acquisition			$ 116,389
Exploration wells			712
Development wells			159
Total unproved and unevaluated			$ 117,260
2015 and prior
Costs incurred for
Property acquisition				$ 223,656
Exploration wells				204
Development wells				42
Total unproved and unevaluated				$ 223,902
Total
Costs incurred for
Property acquisition	1,155,008
Exploration wells	14,512
Development wells	29,991
Total unproved and unevaluated	$ 1,199,511

Property and Equipment (Details Textual) $ in Millions		12 Months Ended
Property and Equipment (Details Textual) $ in Millions	Sep. 12, 2018 USD ($) a	Dec. 31, 2018 USD ($)
Property, Plant and Equipment [Line Items]
Amortization costs		$ 44.5
Anticipated amount for wells		$ 44.5
BLM Acquisition
Property, Plant and Equipment [Line Items]
Acres of land, gross \| a	8,400
Acres of land, net \| a	8,400
Consideration transferred	$ 387.0

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Changes in the Company's asset retirement obligations
Beginning asset retirement obligations	$ 26,256	$ 20,640
Liabilities incurred during period	3,566	2,920
Liabilities settled during period	(708)	(430)
Revisions in estimated cash flows	442	1,836
Accretion expense	1,530	1,290
Ending asset retirement obligations	$ 26,256	$ 20,640	$ 31,086	$ 26,256
Less: current asset retirement obligations			(1,350)	(1,176)
Long-term asset retirement obligations			$ 29,736	$ 25,080

Business Combinations and Divestitures (Details) $ in Millions					9 Months Ended	11 Months Ended		12 Months Ended
	Feb. 25, 2019 USD ($)	Feb. 16, 2018	Feb. 17, 2017 USD ($) well	Oct. 01, 2015 USD ($) MMcf	Sep. 30, 2018	Jan. 31, 2019 USD ($)	Jan. 31, 2018 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2018
Business Acquisition [Line Items]
Subsidiary ownership percentage										100.00%
EnLink
Business Acquisition [Line Items]
Natural gas capacity, MMcf per day \| MMcf				35
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
Carrying value of net assets sold									$ 31.0
Sale leaseback transaction, deferred gain									108.4
Sale leaseback transaction, transaction costs									$ 0.4
Sale leaseback transaction, current period gain recognized								$ 107.3
Corporate Joint Venture \| San Mateo Midstream
Business Acquisition [Line Items]
Subsidiary ownership percentage			51.00%
Deferred performance incentives			$ 44.1				$ 14.7
Deferred performance incentives, term		3 years			5 years
Contributions to joint venture, operating capital			$ 5.1
Corporate Joint Venture \| San Mateo Midstream \| Subsequent Event
Business Acquisition [Line Items]
Deferred performance incentives	$ 150.0					$ 14.7
Five Point \| Corporate Joint Venture \| San Mateo Midstream
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 \| Corporate Joint Venture \| San Mateo Midstream
Business Acquisition [Line Items]
Contractual obligation, term			15 years
Rustler Breaks Asset Area \| Corporate Joint Venture \| San Mateo Midstream
Business Acquisition [Line Items]
Number of wells contributed to joint venture \| well			1
Contractual obligation, term			15 years
Wolf Asset Area \| Corporate Joint Venture \| San Mateo Midstream
Business Acquisition [Line Items]
Number of wells contributed to joint venture \| well			3

Debt Credit Agreements (Details Textual) (Details) $ in Thousands		1 Months Ended	12 Months Ended
	Dec. 19, 2018 USD ($)	Oct. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Feb. 26, 2019 USD ($)	Mar. 31, 2018 USD ($)	Mar. 30, 2018 USD ($)	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
Secured debt, percentage of mortgages used as security			80.00%
Deferred loan costs			$ 2,000
Repay deficit in agreement, period			6 months
Borrowings under Credit Agreement			$ 40,000				$ 0
Outstanding letters of credit			3,000
Long-term line of credit			220,000
Third Amended Credit Agreement
Debt Instrument [Line Items]
Senior secured revolving credit maximum facility		$ 850,000
Maximum borrowing capacity, amended		1,500,000
EBITDA ratio, debt outstanding, cash and cash equivalents limit			$ 50,000
Debt to EBITDA ratio covenant			4.00
Third Amended Credit Agreement \| Minimum
Debt Instrument [Line Items]
Commitment fee percentage			0.375%
Third Amended Credit Agreement \| Maximum
Debt Instrument [Line Items]
Commitment fee percentage			0.50%
Eurodollar \| Third Amended Credit Agreement \| Minimum
Debt Instrument [Line Items]
Additional interest rate			1.25%
Eurodollar \| Third Amended Credit Agreement \| Maximum
Debt Instrument [Line Items]
Additional interest rate			2.25%
Federal Funds Effective Rate \| Third Amended Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			0.50%
Base Rate Loan \| Third Amended Credit Agreement \| Maximum
Debt Instrument [Line Items]
Additional interest rate			1.25%
Revolving Credit Facility
Debt Instrument [Line Items]
Senior secured revolving credit maximum facility		$ 500,000
Decrease in borrowing rate		0.25%
Revolving Credit Facility \| Minimum
Debt Instrument [Line Items]
Leverage ratio		4.00
Revolving Credit Facility \| Maximum
Debt Instrument [Line Items]
Leverage ratio		1.00
Revolving Credit Facility \| Credit Agreement
Debt Instrument [Line Items]
Senior secured revolving credit maximum facility					$ 725,000	$ 525,000
Line of Credit \| San Mateo Credit Facility
Debt Instrument [Line Items]
Senior secured revolving credit maximum facility	$ 250,000
Outstanding letters of credit			$ 0
Accordian feature, increase limit	$ 400,000
Deferred loan costs			1,900
Long-term line of credit			$ 220,000
Line of Credit \| San Mateo Credit Facility \| Minimum
Debt Instrument [Line Items]
Commitment fee percentage	0.30%
Line of Credit \| San Mateo Credit Facility \| Maximum
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Libor Rate \| Third Amended Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			1.00%
Base Rate Loan \| Minimum
Debt Instrument [Line Items]
Additional interest rate			0.25%
Subsequent Event
Debt Instrument [Line Items]
Borrowings under Credit Agreement				$ 80,000
Outstanding letters of credit				13,700
Subsequent Event \| Line of Credit \| San Mateo Credit Facility
Debt Instrument [Line Items]
Outstanding letters of credit				16,200
Debt outstanding				$ 220,000
Federal Funds Effective Rate \| Line of Credit \| San Mateo Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
Adjusted LIBO Rate \| Line of Credit \| San Mateo Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Adjusted LIBO Rate \| Line of Credit \| San Mateo Credit Facility \| Minimum
Debt Instrument [Line Items]
Additional interest rate	0.50%
Adjusted LIBO Rate \| Line of Credit \| San Mateo Credit Facility \| Maximum
Debt Instrument [Line Items]
Additional interest rate	1.50%
Statutory Reserve Rate \| Line of Credit \| San Mateo Credit Facility \| Minimum
Debt Instrument [Line Items]
Additional interest rate	1.50%
Statutory Reserve Rate \| Line of Credit \| San Mateo Credit Facility \| Maximum
Debt Instrument [Line Items]
Additional interest rate	2.50%
The Bank Of Nova Scotia \| San Mateo Credit Facility
Debt Instrument [Line Items]
Debt to EBITDA ratio covenant	5.00
Interest coverage ratio	2.50

Debt Senior Unsecured Notes (Details Textual) (Details) - USD ($)				12 Months Ended
	Oct. 04, 2018	Aug. 21, 2018	Dec. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 14, 2015
Debt Instrument [Line Items]
Senior unsecured notes payable				$ 1,037,837,000	$ 574,073,000
Proceeds from issuance of debt			$ 181,500,000
Loss on extinguishment of debt		$ (31,200,000)		31,226,000	$ 0	$ 0
Long-term line of credit				220,000,000
Unsecured Debt \| Senior Notes [Member]
Debt Instrument [Line Items]
Long-term debt				$ 1,050,000,000
Unsecured Debt \| Senior Notes Due 2023
Debt Instrument [Line Items]
Senior unsecured notes payable			$ 175,000,000				$ 400,000,000
Stated interest rate							6.875%
Effective interest rate				5.50%
Repayments of debt		$ 30,400,000
Unsecured Debt \| Senior Notes Due 2023 \| Debt Instrument, Redemption, Period One
Debt Instrument [Line Items]
Percentage of principal amount redeemed		105.156%	105.50%
Unsecured Debt \| 2026 Notes Offering
Debt Instrument [Line Items]
Senior unsecured notes payable		$ 750,000,000
Stated interest rate		5.875%
Proceeds from issuance of unsecured debt		$ 740,000,000
Unsecured Debt \| Additional 2026 Notes
Debt Instrument [Line Items]
Senior unsecured notes payable	$ 300,000,000
Stated interest rate	5.875%
Percentage of principal amount redeemed	100.50%
Proceeds from issuance of unsecured debt	$ 297,300,000
Unsecured Debt \| Additional 2026 Notes \| Debt Instrument, Redemption, Period One
Debt Instrument [Line Items]
Basis spread on variable rate	5.00%
Threshold percentage of principle	25.00%
Default period	30 days
Period after notice to comply	180 days
Period after notice to comply with other agreements	60 days
Maximum aggregate payment defaults and accelerations	$ 50,000,000
Maximum outstanding judgments	$ 50,000,000.0
Maximum outstanding judgements, payment period	60 days
Unsecured Debt \| Senior Notes Due 2026 \| Debt Instrument, Redemption, Period One
Debt Instrument [Line Items]
Percentage of principal amount redeemed	35.00%
Debt redemption price, percentage	105.875%
Threshold percentage of outstanding principal remaining	65.00%
Unsecured Debt \| Senior Notes Due 2026 \| Debt Instrument, Redemption, Period Two
Debt Instrument [Line Items]
Debt redemption price, percentage	104.406%
Redemption period	180 days

Debt Debt Redemption (Details) - Unsecured Debt - Senior Notes Due 2026	Oct. 04, 2018
2021
Debt Instrument [Line Items]
Redemption Price	104.406%
2022
Debt Instrument [Line Items]
Redemption Price	102.938%
2023
Debt Instrument [Line Items]
Redemption Price	101.469%
2024 and thereafter
Debt Instrument [Line Items]
Redemption Price	100.00%

Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets
Unrealized loss on derivatives	$ 0	$ 3,200
Net operating loss carryforwards	116,374	118,134
Percentage depletion carryover	1,624	1,582
Basis increase related to the San Mateo transaction	0	18,382
Other	9,115	0
Total deferred tax assets	127,113	141,298
Valuation allowance on deferred tax assets	(6,519)	(89,482)
Total deferred tax assets, net of valuation allowance	120,594	51,816
Deferred tax liabilities
Unrealized gain on derivatives	10,468	0
Property and equipment	(100,634)	(40,568)
Other	(2,256)	(11,248)
Total deferred tax liabilities	(113,358)	(51,816)
Net deferred tax assets	$ 7,236	$ 0

Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Details Textual) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Full-cost ceiling impairment	$ 0	$ 0	$ 158,633
Provisional income tax		51,500
Net current income tax (benefit) provision	455	$ 8,157	$ 1,036
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	511,300
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 156,400

Income Taxes (Details 1) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Details 1) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current income tax (benefit) provision
Federal income tax	$ (455)	$ (8,178)	$ (1,144)
State income tax	0	21	108
Net current income tax benefit	(455)	(8,157)	(1,036)
Deferred income tax (benefit) provision
Federal income tax	(20,457)	0	0
State income tax	13,221	0	0
Net deferred income tax benefit	(7,236)	0	0
Deferred income tax provision (benefit)
Federal tax (benefit) expense at statutory rate	61,543	45,447	(34,333)
State income tax	16,181	368	539
Permanent differences	(2,488)	(4,740)	(499)
AMT credit refundable	0	0	1,144
AMT credit refundable	455	8,178	0
Tax Cuts and Jobs Act rate change	0	51,525	0
Change in federal valuation allowance	(80,003)	(101,917)	33,688
Change in state valuation allowance	(2,924)	1,139	(539)
Net deferred income tax benefit	(7,236)	0	0
Net current income tax benefit	(455)	(8,157)	(1,036)
Total income tax benefit	$ (7,691)	$ (8,157)	$ (1,036)

Stock-Based Compensation (Details) - $ / shares	12 Months Ended
Stock-Based Compensation (Details) - $ / shares	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ 12.64	$ 10.49	$ 5.65
2012 Incentive Plan
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	4 years	3 years 11 months 16 days
Risk-free interest rate	2.51%	1.77%	1.08%
Volatility	45.17%	47.00%	45.68%
Dividend yield	0.00%	0.00%	0.00%
Estimated forfeiture rate	2.24%	3.66%	1.16%
2003 Stock and Incentive Plan
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	1 year 1 month 20 days	2 years 1 month 20 days	3 years 1 month 21 days
Risk-free interest rate	2.48%	1.98%	1.70%
Volatility	37.94%	43.60%	47.07%
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, 2018 $ / shares shares
Number of options (in thousands)
Options outstanding at beginning of period (in shares) \| shares	3,064
Options granted (in shares) \| shares	563
Options exercised (in shares) \| shares	(383)
Options forfeited (in shares) \| shares	(18)
Options expired (in shares) \| shares	(1)
Options outstanding at end of period (in shares) \| shares	3,225
Weighted average exercise price
Weighted average exercise price, Options outstanding Beginning Balance (usd per share) \| $ / shares	$ 21.14
Weighted average exercise price, Options granted (usd per share) \| $ / shares	29.68
Weighted average exercise price, Options exercised (usd per share) \| $ / shares	13.84
Weighted average exercise price, Options forfeited (usd per share) \| $ / shares	26.33
Weighted average exercise price, Options expired (usd per share) \| $ / shares	26.86
Weighted average exercise price, Options outstanding Ending Balance (usd per share) \| $ / shares	$ 23.48

Stock-Based Compensation (Details 2) shares in Thousands	12 Months Ended
Stock-Based Compensation (Details 2) shares in Thousands	Dec. 31, 2018 $ / shares shares
$9.00
Summarized information about outstanding and exercisable stock option
Shares outstanding (in shares) \| shares	68
Weighted average remaining contractual price	1 year 1 month 20 days
Weighted average exercise price (usd per share)	$ 9.00
Shares exercisable \| shares	68
Weighted average exercise price (usd per share)	$ 9.00
$13.22 - $15.00
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	13.22
Range of exercise prices, Upper limit	$ 15.00
Shares outstanding (in shares) \| shares	615
Weighted average remaining contractual price	2 years 1 month 17 days
Weighted average exercise price (usd per share)	$ 14.98
Shares exercisable \| shares	3
Weighted average exercise price (usd per share)	$ 13.22
$19.71 - $22.70
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) \| shares	727
Weighted average remaining contractual price	1 year 1 month 5 days
Weighted average exercise price (usd per share)	$ 21.92
Shares exercisable \| shares	706
Weighted average exercise price (usd per share)	$ 21.93
$23.40 - $29.68
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	23.4
Range of exercise prices, Upper limit	$ 29.68
Shares outstanding (in shares) \| shares	1,815
Weighted average remaining contractual price	3 years 10 months 28 days
Weighted average exercise price (usd per share)	$ 26.79
Shares exercisable \| shares	556
Weighted average exercise price (usd per share)	$ 24.65

Stock-Based Compensation (Details 3) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 17,200	$ 16,654	$ 12,362
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 6,300	$ 7,100	$ 5,900
Restricted Stock Service Based
Summary of non-vested stock options
Non-vested Shares, Beginning Balance (in shares)	1,104
Shares Granted (in shares)	759
Shares Vested (in shares)	(475)
Shares Forfeited (in shares)	(32)
Non-vested Shares, Ending Balance (in shares)	1,356	1,104
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)	$ 22.59
Weighted average fair value, Granted (usd per share)	29.45
Weighted average fair value, Vested (usd per share)	23.87
Weighted average fair value, Forfeited (usd per share)	27.20
Weighted average fair value, Ending Balance (usd per share)	$ 25.87	$ 22.59
Restricted Stock Units Service Based
Summary of non-vested stock options
Non-vested Shares, Beginning Balance (in shares)	65
Shares Granted (in shares)	64
Shares Vested (in shares)	(71)
Shares Forfeited (in shares)	0
Non-vested Shares, Ending Balance (in shares)	58	65
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)	$ 23.36
Weighted average fair value, Granted (usd per share)	27.69
Weighted average fair value, Vested (usd per share)	23.90
Weighted average fair value, Forfeited (usd per share)	0.00
Weighted average fair value, Ending Balance (usd per share)	$ 27.48	$ 23.36

Stock Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	Feb. 28, 2019	Feb. 26, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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)			3,225,000	3,064,000
Aggregate intrinsic value			$ 800
Aggregate intrinsic value exercisable			$ 400
Quoted closing market price			$ 15.53
Weighted average contractual term			2 years 10 months 16 days
Total intrinsic value of options exercised			$ 7,000	$ 13,200	$ 1,600
Tax related benefits realized from the exercise of stock options			5,700	5,000	500
Unrecognized compensation expense related to unvested stock options			$ 9,300
Weighted average remaining requisite service period of unvested stock awards			1 year 7 months 25 days
Fair value of option shares vested			$ 11,800	2,100	3,000
Stock-based compensation expense			17,200	16,654	12,362
Stock based long term liability			$ (1,100)	400	1,400
Options granted (in shares)			563,000
Aggregate intrinsic value for the restricted stock and restricted stock units outstanding			$ 22,000
Tax benefits recognized for stock based compensation			4,800	6,800	4,300
Capitalized stock-based compensation			4,400
Expensed stock-based compensation			$ 17,200
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares			3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares			4 years
Class A
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
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining requisite service period of unvested stock awards			10 months 25 days
Unrecognized compensation expense related to unvested restricted stock and restricted stock units			$ 22,000
Fair value of restricted stock and restricted stock units vested			13,000	9,900	4,600
Restricted stock or unit expenses			$ 15,300	12,900	6,600
Restricted Stock \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares			1 year
Restricted Stock \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares			4 years
Stock options
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			$ 6,300	$ 7,100	$ 5,900
Subsequent Event \| Service-Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares		3 years
Subsequent Event \| Service-Based Restricted Stock Units \| Common stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	428,005
Subsequent Event \| Performance-Based Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares		3 years
Subsequent Event \| Performance-Based Stock Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%
Subsequent Event \| Performance-Based Stock Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%
Subsequent Event \| Performance-Based Stock Units \| Common stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	428,005
2003 Stock and Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of stock option awards outstanding (in shares)			67,500	75,000	77,500

Employee Benefit Plans (Details) - USD ($)	12 Months Ended
Employee Benefit Plans (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Benefit Plan (Textual) [Abstract]
Employees annual compensation	3.00%
Safe Harbor match	$ 1,100,000	$ 900,000	$ 700,000
Discretionary matching contributions	1,400,000	1,100,000	900,000
No additional discretionary contributions	$ 0	$ 0	$ 0

Equity (Details) - USD ($) $ in Thousands					12 Months Ended
Equity (Details) - USD ($) $ in Thousands	May 17, 2018	Oct. 10, 2017	Dec. 09, 2016	Mar. 11, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 01, 2017	May 31, 2017
Subsidiary, Sale of Stock [Line Items]
Offering costs	$ 200	$ 300			$ 204	$ 280	$ 847
Repayment of debt					$ 45,000
Consideration received on sale of stock			$ 145,800	$ 141,500
Common stock, shares authorized (in shares)					160,000,000	160,000,000
Issuance cost of equity			$ 400	$ 800	$ 204	$ 280	$ 1,190
Preferred shares authorized (in shares)					2,000,000
Common Stock
Subsidiary, Sale of Stock [Line Items]
Shares issued (in shares)			6,000,000	7,500,000
Common stock, shares authorized (in shares)								160,000,000	120,000,000
Public Stock Offering
Subsidiary, Sale of Stock [Line Items]
Consideration received on sale of stock	$ 226,400	$ 208,400
Public Stock Offering \| Common Stock
Subsidiary, Sale of Stock [Line Items]
Shares issued (in shares)	7,000,000	8,000,000

Derivative Financial Instruments (Details) $ in Thousands	Dec. 31, 2018 USD ($) bbl MMBTU $ / bbl $ / MMBTU	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)
Derivative [Line Items]
Derivative Asset (Liability), Net	$ 49,846
Summary of contracts for oil and natural gas
Derivative liability		$ 15,239
Open costless collar contracts
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)			$ 31,695
Open costless collar contracts \| Oil - WTI
Summary of contracts for oil and natural gas
Notional Quantity (Bbl) \| bbl	3,720,000
Weighted Average Price Floor (usd per Bbl) \| $ / bbl	53.55
Weighted Average Price Ceiling (usd per Bbl) \| $ / bbl	72.22
Fair Value of Asset (Liability)	$ 31,531
Open costless collar contracts \| Natural Gas
Summary of contracts for oil and natural gas
Notional Quantity (Bbl) \| MMBTU	2,400,000
Weighted Average Price Floor (usd per Bbl) \| $ / MMBTU	2.50
Weighted Average Price Ceiling (usd per Bbl) \| $ / MMBTU	3.80
Fair Value of Asset (Liability)	$ 164
Open Swap Contracts
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ (83)
Open Swap Contracts \| Oil, Calculation Period Two
Summary of contracts for oil and natural gas
Notional Quantity (Bbl) \| bbl	1,200,000
Fair Value of Asset (Liability)	$ (83)
Fixed price (usd per Bbl) \| $ / bbl	(0.15)
Derivative Contract, Calculation Period One \| Open Three-way Costless Collar Contracts
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ 18,234
Derivative Contract, Calculation Period One \| Open Three-way Costless Collar Contracts \| Oil - WTI
Summary of contracts for oil and natural gas
Notional Quantity (Bbl) \| bbl	1,320,000
Weighted Average Price Floor (usd per Bbl) \| $ / bbl	60.00
Fair Value of Asset (Liability)	$ 18,114
Derivative Contract, Calculation Period One \| Open Three-way Costless Collar Contracts \| Natural Gas
Summary of contracts for oil and natural gas
Notional Quantity (Bbl) \| bbl	4,800,000
Weighted Average Price Floor (usd per Bbl) \| $ / bbl	2.50
Fair Value of Asset (Liability)	$ 120
Short \| Derivative Contract, Calculation Period One \| Open Three-way Costless Collar Contracts \| Oil - WTI
Summary of contracts for oil and natural gas
Weighted Average Price Ceiling (usd per Bbl) \| $ / bbl	75.00
Short \| Derivative Contract, Calculation Period One \| Open Three-way Costless Collar Contracts \| Natural Gas
Summary of contracts for oil and natural gas
Weighted Average Price Ceiling (usd per Bbl) \| $ / bbl	3.00
Long \| Derivative Contract, Calculation Period One \| Open Three-way Costless Collar Contracts \| Oil - WTI
Summary of contracts for oil and natural gas
Weighted Average Price Ceiling (usd per Bbl) \| $ / bbl	78.85
Long \| Derivative Contract, Calculation Period One \| Open Three-way Costless Collar Contracts \| Natural Gas
Summary of contracts for oil and natural gas
Weighted Average Price Ceiling (usd per Bbl) \| $ / bbl	3.24

Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Offsetting Derivative Assets [Abstract]
Derivative liability		$ (15,239)
Total	$ 53,053
Derivative Asset (Liability) Subject to Master Netting Arrangement	(3,207)
Derivative Asset (Liability), Net	49,846
Offsetting Derivative Liabilities [Abstract]
Derivative Asset		0
Current assets
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities		131,092
Gross amounts netted in the consolidated balance sheet		129,902
Derivative liability		1,190
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets	53,136
Gross amounts netted in the consolidated balance sheets	(3,207)
Derivative Asset	49,929
Long-term liabilities
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities	(83)
Gross amounts netted in the consolidated balance sheet	0
Derivative liability	$ (83)
Current liabilities
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities		(146,331)
Gross amounts netted in the consolidated balance sheet		(129,902)
Derivative liability		$ (16,429)

Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	$ 2,334	$ (4,321)	$ 9,286
Unrealized gain (loss) on derivatives	65,085	9,715	(41,238)
Revenues
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	2,334	(4,321)	9,286
Unrealized gain (loss) on derivatives	65,085	9,715	(41,238)
Total	67,419	5,394	(31,952)
Oil \| Revenues
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	3,741	(3,657)	5,851
Unrealized gain (loss) on derivatives	65,991	2,638	(18,969)
Natural Gas \| Revenues
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	(1,407)	(608)	3,435
Unrealized gain (loss) on derivatives	(906)	7,077	(22,269)
NGLs \| Revenues
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	$ 0	$ (56)	$ 0

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets (Liabilities)
Oil derivatives and basis swaps		$ 0
Natural gas derivatives		(15,239)
Total	$ 53,053
Fair value on a recurring basis
Assets (Liabilities)
Oil derivatives and basis swaps	49,562	(16,429)
Natural gas derivatives	284	1,190
Total	49,846	(15,239)
Fair value on a recurring basis \| Level 1
Assets (Liabilities)
Oil derivatives and basis swaps		0
Natural gas derivatives	0	0
Fair value on a recurring basis \| Level 2
Assets (Liabilities)
Oil derivatives and basis swaps	49,562	(16,429)
Natural gas derivatives	284	1,190
Total	49,846	(15,239)
Fair value on a recurring basis \| Level 3
Assets (Liabilities)
Oil derivatives and basis swaps		0
Natural gas derivatives	$ 0	$ 0

Fair Value Measurements (Details Textual) - USD ($)	12 Months Ended
Fair Value Measurements (Details Textual) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of notes payable	$ 968,900,000	$ 614,100,000
Pipe and other equipment
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, 2018 USD ($)
Schedule of future minimum lease payments required under the office lease agreement
2019	$ 3,091
2020	3,914
2021	3,877
2022	4,009
2023	4,141
Thereafter	9,921
Total	$ 28,953

Supplemental Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Summary of current accrued liabilities
Total accrued liabilities	$ 170,855	$ 174,348
Other	14,189	4,418
Accrued evaluated and unproved and unevaluated property costs
Summary of current accrued liabilities
Total accrued liabilities	86,318	105,347
Accrued midstream properties costs
Summary of current accrued liabilities
Total accrued liabilities	16,808	14,823
Accrued lease operating expenses
Summary of current accrued liabilities
Total accrued liabilities	12,705	12,611
Accrued interest on debt
Summary of current accrued liabilities
Total accrued liabilities	22,448	8,345
Accrued asset retirement obligations
Summary of current accrued liabilities
Total accrued liabilities	1,350	1,176
Accrued partners’ share of joint interest charges
Summary of current accrued liabilities
Total accrued liabilities	$ 17,037	$ 27,628

Commitments and Contingencies (Details Textual) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
	Feb. 17, 2017	May 31, 2018	Apr. 30, 2018	Dec. 31, 2018	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				$ 2.7	$ 2.6	$ 2.9
Minimum outstanding commitments				24.3
Field Compression and Amine Gas Treatment
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				24.9
Payment for long-term purchase commitment				21.3
Long-term purchase commitment, remaining obligation				3.6
Drilling Rig Commitments
Long-term Purchase Commitment [Line Items]
Maximum termination outstanding obligations of contracts				28.4
Loving County System Agreement
Long-term Purchase Commitment [Line Items]
Supply agreement, term							15 years
Total deficiency fee estimate				7.6
Corporate Joint Venture \| San Mateo Midstream
Long-term Purchase Commitment [Line Items]
Contractual obligation				221.1
Corporate Joint Venture \| San Mateo Midstream \| Rustler Breaks and Wolf Asset Area
Long-term Purchase Commitment [Line Items]
Contractual obligation, term	15 years
Corporate Joint Venture \| San Mateo Midstream \| Rustler Breaks Asset Area
Long-term Purchase Commitment [Line Items]
Contractual obligation, term	15 years
Natural Gas Transportation Agreement \| Eddy County
Long-term Purchase Commitment [Line Items]
Supply agreement, term					18 years
Contractual obligation				$ 20.1
Natural Gas Transportation and Fractionation Agreement \| Eddy County
Long-term Purchase Commitment [Line Items]
Supply agreement, term				7 years
Contractual obligation				$ 132.3
16-Year Fixed Fee Natural Gas Transportation Agreement \| Eddy County
Long-term Purchase Commitment [Line Items]
Supply agreement, term			16 years
Contractual obligation				56.8
10-Year Fixed Fee Natural Gas Transportation Agreement \| Eddy County
Long-term Purchase Commitment [Line Items]
Supply agreement, term		10 years
Contractual obligation				200.6
Natural Gas, Gathering, Transportation, Marketing and Processing \| Loving County System Agreement
Long-term Purchase Commitment [Line Items]
Processing and gathering fees				15.4	$ 14.4
Natural Gas, Gathering, Transportation, Marketing and Processing \| Eddy County
Long-term Purchase Commitment [Line Items]
Processing and gathering fees				3.3	$ 0.2
Natural Gas Transportation Agreement \| Eddy County
Long-term Purchase Commitment [Line Items]
Contractual obligation				2.7
Natural Gas Transportation Agreement \| Transportation Fees \| Eddy County
Long-term Purchase Commitment [Line Items]
Processing and gathering fees				$ 1.9

Supplemental Disclosures (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental disclosures of cash flow information
Cash paid for income taxes	$ 0	$ 0	$ 2,895
Cash paid for interest expense, net of amounts capitalized	29,474	32,760	27,464
Increase in asset retirement obligations related to mineral properties	2,614	4,385	3,817
Increase (decrease) in asset retirement obligations related to midstream properties	686	(60)	222
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures	(16,802)	48,929	1,775
Increase (decrease) in liabilities for midstream properties capital expenditures	2,499	(955)	(588)
Issuance of restricted stock units for director and advisor services	0	0	992
Stock-based compensation (benefit) expense recognized as liability	(1,069)	362	569
(Decrease) increase in liabilities for accrued cost to issue equity	0	(343)	343
Increase in liabilities for accrued cost to issue debt	232	0	0
Transfer of inventory from (to) oil and natural gas properties	409	(374)	395
Transfer of inventory to midstream and other property and equipment	$ 0	$ (317)	$ 0

Supplemental Disclosures Supplemental Disclosures (Details 2) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Disclosures [Abstract]
Cash	$ 64,545	$ 96,505	$ 212,884
Restricted cash	19,439	5,977	1,258
Total cash and restricted cash	$ 83,984	$ 102,482	$ 214,142	$ 61,089

Segment Reporting (Details)	12 Months Ended
Segment Reporting (Details)	Dec. 31, 2018 USD ($) segment	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Segment Reporting Information [Line Items]
Number of business segments \| segment	2
Revenues	$ 829,691,000
Lease bonus - mineral acreage	2,489,000	$ 0	$ 0
Realized gain on derivatives	2,334,000	(4,321,000)	9,286,000
Unrealized gain on derivatives	65,085,000	9,715,000	(41,238,000)
Expenses	536,328,000	383,435,000	441,589,000
Operating income (loss)	363,271,000	160,841,000	(177,167,000)
Assets	3,455,518,000	2,145,690,000	1,464,665,000
Capital expenditures	1,504,659,000	872,958,000	454,360,000
Depletion, depreciation and amortization	265,142,000	177,502,000	122,048,000
Income (loss) attributable to noncontrolling interest	25,557,000	12,140,000	364,000
Impairment charge of net capitalized costs	0	0	158,633,000
Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	2,489,000
Realized gain on derivatives	2,334,000	(4,321,000)	9,286,000
Unrealized gain on derivatives	65,085,000	9,715,000	(41,238,000)
Expenses	487,539,000	333,923,000	391,098,000
Operating income (loss)	377,532,000	197,333,000	(133,538,000)
Assets	2,910,326,000	1,768,393,000	1,098,525,000
Capital expenditures	1,335,690,000	753,157,000	379,881,000
Depletion, depreciation and amortization	252,300,000	170,500,000	118,400,000
Impairment charge of net capitalized costs			158,600,000
Operating Segments \| Midstream
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	0
Realized gain on derivatives	0	0
Unrealized gain on derivatives	0	0
Expenses	44,098,000	23,420,000	8,254,000
Operating income (loss)	55,247,000	26,439,000	12,372,000
Assets	439,953,000	257,871,000	140,459,000
Capital expenditures	166,407,000	114,113,000	67,566,000
Depletion, depreciation and amortization	10,500,000	5,200,000	2,700,000
Income (loss) attributable to noncontrolling interest	25,600,000	12,100,000	400,000
Land and seismic acquisition expenditures	656,900,000
Payments to acquire productive assets	80,200,000	54,900,000
Corporate
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	0
Realized gain on derivatives	0	0
Unrealized gain on derivatives	0	0
Expenses	69,508,000	62,931,000	56,001,000
Operating income (loss)	(69,508,000)	(62,931,000)	(56,001,000)
Assets	105,239,000	119,426,000	225,681,000
Capital expenditures	2,562,000	5,688,000	6,913,000
Depletion, depreciation and amortization	2,400,000	1,700,000	900,000
Consolidations and Eliminations
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	0
Realized gain on derivatives	0	0
Unrealized gain on derivatives	0	0
Expenses	(64,817,000)	(36,839,000)	(13,764,000)
Assets	0	0	0
Capital expenditures	0	0	0
Oil and natural gas revenues
Segment Reporting Information [Line Items]
Revenues	800,700,000	528,684,000	291,156,000
Oil and natural gas revenues \| Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Revenues	794,261,000	525,862,000	289,512,000
Oil and natural gas revenues \| Operating Segments \| Midstream
Segment Reporting Information [Line Items]
Revenues	6,439,000	2,822,000	1,644,000
Third-party midstream services revenues
Segment Reporting Information [Line Items]
Revenues	21,920,000	10,198,000	5,218,000
Third-party midstream services revenues \| Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Revenues	0	0	0
Third-party midstream services revenues \| Operating Segments \| Midstream
Segment Reporting Information [Line Items]
Revenues	86,737,000	47,037,000	18,982,000
Third-party midstream services revenues \| Corporate
Segment Reporting Information [Line Items]
Revenues	0	0	0
Third-party midstream services revenues \| Consolidations and Eliminations
Segment Reporting Information [Line Items]
Revenues	(64,817,000)	(36,839,000)	(13,764,000)
Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenues	7,071,000	$ 0	$ 0
Sales of purchased natural gas \| Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Revenues	902,000
Sales of purchased natural gas \| Operating Segments \| Midstream
Segment Reporting Information [Line Items]
Revenues	6,169,000
Sales of purchased natural gas \| Corporate
Segment Reporting Information [Line Items]
Revenues	0
Sales of purchased natural gas \| Consolidations and Eliminations
Segment Reporting Information [Line Items]
Revenues	$ 0

Subsidiary Guarantors Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	$ 0	$ 0
Current assets	305,685	257,170
Net property and equipment	3,122,864	1,881,456
Investment in subsidiaries	0	0
Long-term assets	26,969	7,064
Total assets	3,455,518	2,145,690	$ 1,464,665
Intercompany payable	0	0
Current liabilities	330,022	282,606
Senior unsecured notes payable	1,037,837	574,073
Other long-term liabilities	308,002	31,465
Total shareholders' equity	1,688,880	1,156,556
Non-controlling interest in subsidiaries	90,777	100,990
Total liabilities and shareholders’ equity	$ 3,455,518	2,145,690
Subsidiary ownership percentage	100.00%
Eliminating Entries
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	$ (1,274,221)	(588,021)
Current assets	0	0
Net property and equipment	0	0
Investment in subsidiaries	(1,585,747)	(1,258,372)
Long-term assets	(9,502)	(3,003)
Total assets	(2,869,470)	(1,849,396)
Intercompany payable	(1,274,221)	(588,021)
Current liabilities	(724)	(274)
Senior unsecured notes payable		0
Other long-term liabilities	(8,778)	(2,729)
Total shareholders' equity	(1,585,747)	(1,258,372)
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	(2,869,470)	(1,849,396)
Matador \| Reportable Legal Entities
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	1,244,405	585,109
Current assets	4,109	2,240
Net property and equipment	0	0
Investment in subsidiaries	1,490,401	1,147,295
Long-term assets	23,897	6,425
Total assets	2,762,812	1,741,069
Intercompany payable	0	0
Current liabilities	22,874	8,847
Senior unsecured notes payable	1,037,837	574,073
Other long-term liabilities	13,221	1,593
Total shareholders' equity	1,688,880	1,156,556
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	2,762,812	1,741,069
Non-Guarantor Subsidiaries \| Reportable Legal Entities
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	29,816	2,912
Current assets	34,027	9,334
Net property and equipment	379,052	223,178
Investment in subsidiaries	0	0
Long-term assets	1,479	0
Total assets	444,374	235,424
Intercompany payable	0	0
Current liabilities	27,988	19,891
Senior unsecured notes payable	0	0
Other long-term liabilities	230,263	3,466
Total shareholders' equity	95,346	111,077
Non-controlling interest in subsidiaries	90,777	100,990
Total liabilities and shareholders’ equity	444,374	235,424
Guarantor Subsidiaries \| Reportable Legal Entities
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	0	0
Current assets	267,549	245,596
Net property and equipment	2,743,812	1,658,278
Investment in subsidiaries	95,346	111,077
Long-term assets	11,095	3,642
Total assets	3,117,802	2,018,593
Intercompany payable	1,274,221	588,021
Current liabilities	279,884	254,142
Senior unsecured notes payable	0	0
Other long-term liabilities	73,296	29,135
Total shareholders' equity	1,490,401	1,147,295
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	$ 3,117,802	$ 2,018,593

Subsidiary Guarantors Consolidated Income Statement (Details) - USD ($) $ in Thousands		12 Months Ended
	Aug. 21, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Income Statements, Captions [Line Items]
Total revenues		$ 899,599	$ 544,276	$ 264,422
Total expenses		536,328	383,435	441,589
Operating income (loss)		363,271	160,841	(177,167)
Net loss on asset sales and inventory impairment		(196)	23	107,277
Interest expense		(41,327)	(34,565)	(28,199)
Prepayment penalty on extinguishment of debt	$ 31,200	(31,226)	0	0
Other income		1,551	3,551	(4)
Earnings in subsidiaries		0	0	0
Income (loss) before income taxes		292,073	129,850	(98,093)
Total income tax benefit		(7,691)	(8,157)	(1,036)
Net income attributable to non-controlling interest in subsidiaries		(25,557)	(12,140)	(364)
Net income (loss)		274,207	125,867	(97,421)
Eliminating Entries
Condensed Income Statements, Captions [Line Items]
Total revenues		(64,791)	(35,115)	(10,708)
Total expenses		(64,791)	(35,115)	(10,708)
Operating income (loss)		0	0	0
Net loss on asset sales and inventory impairment		0	0	0
Interest expense		0	0	0
Prepayment penalty on extinguishment of debt		0
Other income				0
Earnings in subsidiaries		(369,707)	(171,840)	54,539
Income (loss) before income taxes		(369,707)	(171,840)	54,539
Total income tax benefit		0	0	0
Net income attributable to non-controlling interest in subsidiaries		0	0	0
Net income (loss)		(369,707)	(171,840)	54,539
Matador \| Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total revenues		0		0
Total expenses		4,935	5,610	5,319
Operating income (loss)		(4,935)	(5,610)	(5,319)
Net loss on asset sales and inventory impairment		0	0	0
Interest expense		(40,994)	(34,565)	(28,199)
Prepayment penalty on extinguishment of debt		(31,226)
Other income		565	27	0
Earnings in subsidiaries		343,106	157,589	(64,349)
Income (loss) before income taxes		266,516	117,441	(97,867)
Total income tax benefit		(7,691)	(8,426)	(446)
Net income attributable to non-controlling interest in subsidiaries		0	0	0
Net income (loss)		274,207	125,867	(97,421)
Non-Guarantor Subsidiaries \| Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total revenues		98,665	47,883	17,302
Total expenses		46,236	21,260	7,031
Operating income (loss)		52,429	26,623	10,271
Net loss on asset sales and inventory impairment		0	0	0
Interest expense		(333)		0
Prepayment penalty on extinguishment of debt		0
Other income		62	37	0
Earnings in subsidiaries		0	0	0
Income (loss) before income taxes		52,158	26,660	10,271
Total income tax benefit		0	269	97
Net income attributable to non-controlling interest in subsidiaries		(25,557)	(12,140)	(364)
Net income (loss)		26,601	14,251	9,810
Guarantor Subsidiaries \| Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total revenues		865,725	531,508	257,828
Total expenses		549,948	391,680	439,947
Operating income (loss)		315,777	139,828	(182,119)
Net loss on asset sales and inventory impairment		(196)	23	107,277
Interest expense			0	0
Prepayment penalty on extinguishment of debt		0
Other income		924	3,487	(4)
Earnings in subsidiaries		26,601	14,251	9,810
Income (loss) before income taxes		343,106	157,589	(65,036)
Total income tax benefit		0	0	(687)
Net income attributable to non-controlling interest in subsidiaries		0	0	0
Net income (loss)		$ 343,106	$ 157,589	$ (64,349)

Subsidiary Guarantors Consolidated Cash Flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 608,523	$ 299,125	$ 134,086
Net cash used in investing activities	(1,515,253)	(819,284)	(448,739)
Net cash provided by financing activities	888,232	408,499	467,706
(Decrease) increase in cash and restricted cash	(18,498)	(111,660)	153,053
Cash and restricted cash at beginning of year	102,482	214,142	61,089
Cash and restricted cash at end of year	83,984	102,482	214,142
Eliminating Entries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	0	0	0
Net cash used in investing activities	(42,330)	(106,595)	384,801
Net cash provided by financing activities	42,330	106,595	(384,801)
(Decrease) increase in cash and restricted cash	0	0	0
Cash and restricted cash at beginning of year	0	0	0
Cash and restricted cash at end of year	0	0	0
Matador \| Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(657,860)	(307,982)	(45,215)
Net cash used in investing activities	0	33	(324,724)
Net cash provided by financing activities	658,030	208,440	469,654
(Decrease) increase in cash and restricted cash	170	(99,509)	99,715
Cash and restricted cash at beginning of year	286	99,795	80
Cash and restricted cash at end of year	456	286	99,795
Non-Guarantor Subsidiaries \| Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	35,119	21,308	6,694
Net cash used in investing activities	(162,147)	(114,852)	(64,999)
Net cash provided by financing activities	140,205	96,307	60,110
(Decrease) increase in cash and restricted cash	13,177	2,763	1,805
Cash and restricted cash at beginning of year	5,663	2,900	1,095
Cash and restricted cash at end of year	18,840	5,663	2,900
Guarantor Subsidiaries \| Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	1,231,264	585,799	172,607
Net cash used in investing activities	(1,310,776)	(597,870)	(443,817)
Net cash provided by financing activities	47,667	(2,843)	322,743
(Decrease) increase in cash and restricted cash	(31,845)	(14,914)	51,533
Cash and restricted cash at beginning of year	96,533	111,447	59,914
Cash and restricted cash at end of year	$ 64,688	$ 96,533	$ 111,447

Subsequent Events (Details) - USD ($) $ in Millions				9 Months Ended	11 Months Ended
Subsequent Events (Details) - USD ($) $ in Millions	Feb. 25, 2019	Feb. 16, 2018	Feb. 17, 2017	Sep. 30, 2018	Jan. 31, 2019	Jan. 31, 2018	Dec. 31, 2018
Subsequent Event [Line Items]
Ownership percentage							100.00%
Corporate Joint Venture \| Matador Resources Company \| San Mateo Midstream \| Subsequent Event
Subsequent Event [Line Items]
Ownership percentage	51.00%
Corporate Joint Venture \| Five Point \| San Mateo Midstream \| Subsequent Event
Subsequent Event [Line Items]
Ownership percentage	49.00%
San Mateo Midstream \| Corporate Joint Venture
Subsequent Event [Line Items]
Ownership percentage			51.00%
Deferred performance incentives			$ 44.1			$ 14.7
Deferred performance incentives, term		3 years		5 years
Minimum contractual obligation							$ 221.1
San Mateo Midstream \| Corporate Joint Venture \| Subsequent Event
Subsequent Event [Line Items]
Commitment to pay, amount	$ 125.0
Capital expenditures incurred	150.0
Deferred performance incentives	$ 150.0				$ 14.7
Contract agreement term	15 years
San Mateo Midstream \| Corporate Joint Venture \| Five Point
Subsequent Event [Line Items]
Ownership percentage			49.00%
Operational Agreements \| San Mateo Midstream \| Subsequent Event
Subsequent Event [Line Items]
Minimum contractual obligation	$ 363.8