Matador Resources (MTDR) 10-K 2 Mar 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 28, 2020	Jun. 30, 2019
Document and Entity Information [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-35410
Entity Registrant Name	Matador Resources Company
Entity Incorporation, State or Country Code	TX
Entity Address, Address Line Two	Suite 1500
Entity Tax Identification Number	27-4662601
Entity Address, Address Line One	5400 LBJ Freeway,
Entity Address, City or Town	Dallas,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75240
City Area Code	972
Local Phone Number	371-5200
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	MTDR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 2,187,634,344
Entity Common Stock, Shares Outstanding		116,569,389
Entity Central Index Key	0001520006
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Documents Incorporated by Reference	The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2020 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash	$ 40,024	$ 64,545
Restricted cash	25,104	19,439
Accounts receivable
Oil and natural gas revenues	95,228	68,161
Joint interest billings	67,546	61,831
Other	26,639	16,159
Derivative instruments	0	49,929
Lease and well equipment inventory	10,744	17,564
Prepaid expenses and other current assets	13,207	8,057
Total current assets	278,492	305,685
Oil and natural gas properties, full-cost method
Evaluated	4,557,265	3,780,236
Unproved and unevaluated	1,126,992	1,199,511
Midstream properties	643,903	428,025
Midstream properties	27,021	22,041
Less accumulated depletion, depreciation and amortization	(2,655,586)	(2,306,949)
Net property and equipment	3,699,595	3,122,864
Other assets
Deferred income taxes	0	20,457
Other long-term assets	91,589	6,512
Total other assets	91,589	26,969
Total assets	4,069,676	3,455,518
Current liabilities
Accounts payable	25,230	66,970
Accrued liabilities	200,695	170,855
Royalties payable	85,193	64,776
Amounts due to affiliates	19,606	13,052
Derivative instruments	1,897	0
Advances from joint interest owners	14,837	10,968
Amounts due to joint ventures	486	2,373
Other current liabilities	51,828	1,028
Total current liabilities	399,772	330,022
Long-term liabilities
Borrowings under Credit Agreement	255,000	40,000
Borrowings under San Mateo Credit Facility	288,000	220,000
Senior unsecured notes payable	1,039,416	1,037,837
Asset retirement obligations	35,592	29,736
Derivative instruments	1,984	83
Deferred income taxes	37,329	13,221
Other long-term liabilities	43,131	4,962
Total long-term liabilities	1,700,452	1,345,839
Shareholders' equity
Common stock — $0.01 par value, 160,000,000 shares authorized; 116,644,246 and 116,374,503 shares issued; and 116,642,899 and 116,353,590 shares outstanding, respectively	1,166	1,164
Additional paid-in capital	1,981,014	1,924,408
Accumulated deficit	(148,500)	(236,277)
Treasury stock, at cost, 1,347 and 20,913 shares, respectively	(26)	(415)
Total shareholders' equity	1,833,654	1,688,880
Non-controlling interest in subsidiaries	135,798	90,777
Total shareholders’ equity	1,969,452	1,779,657
Total liabilities and shareholders’ equity	$ 4,069,676	$ 3,455,518

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
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 Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Revenues	$ 1,026,204	$ 829,691
Lease bonus - mineral acreage	1,711	2,489	$ 0
Realized gain (loss) on derivatives	9,482	2,334	(4,321)
Unrealized (loss) gain on derivatives	(53,727)	65,085	9,715
Total revenues	983,670	899,599	544,276
Expenses
Production taxes, transportation and processing	92,273	76,138	58,275
Lease operating	117,305	92,966	67,313
Purchased natural gas	69,398	6,635	0
Depletion, depreciation and amortization	350,540	265,142	177,502
Accretion of asset retirement obligations	1,822	1,530	1,290
Full-cost ceiling impairment	0	0	0
General and administrative	80,054	69,308	66,016
Total expenses	748,190	536,328	383,435
Operating income	235,480	363,271	160,841
Other income (expense)
Net (loss) gain on asset sales and inventory impairment	(967)	(196)	23
Interest expense	(73,873)	(41,327)	(34,565)
Prepayment premium on extinguishment of debt	0	(31,226)	0
Other (expense) income	(2,126)	1,551	3,551
Total other expense	(76,966)	(71,198)	(30,991)
Income before income taxes	158,514	292,073	129,850
Income tax provision (benefit)
Current	0	(455)	(8,157)
Deferred	35,532	(7,236)	0
Total income tax provision (benefit)	35,532	(7,691)	(8,157)
Net income	87,777	274,207	125,867
Net income attributable to non-controlling interest in subsidiaries	(35,205)	(25,557)	(12,140)
Net income attributable to Matador Resources Company shareholders	$ 122,982	$ 299,764	$ 138,007
Earnings per common share attributable to Matador Resources Company shareholders
Basic (usd per share)	$ 0.75	$ 2.41	$ 1.23
Diluted (usd per share)	$ 0.75	$ 2.41	$ 1.23
Weighted average common shares outstanding
Basic (in shares)	116,555	113,580	102,029
Diluted (in shares)	117,063	113,691	102,543
Oil and natural gas revenues
Revenues
Revenues	$ 892,325	$ 800,700	$ 528,684
Third-party midstream services revenues
Revenues
Revenues	59,110	21,920	10,198
Expenses
Cost of Goods and Services Sold	36,798	24,609	13,039
Sales of purchased natural gas
Revenues
Revenues	$ 74,769	$ 7,071	$ 0

Consolidated Statements of Chan

Consolidated Statements of Changes in Shareholders' Equity - USD ($)	Total	Common stock	Additional paid-in capital	Accumulated deficit	Treasury stock	Parent	Noncontrolling Interest	San Mateo I	San Mateo IAdditional paid-in capital	San Mateo IParent	San Mateo II	San Mateo IIAdditional paid-in capital	San Mateo IIParent	San Mateo IINoncontrolling Interest
Beginning Balance at Dec. 31, 2016	$ 691,445,000	$ 995,000	$ 1,325,481,000	$ (636,351,000)	$ 0	$ 690,125,000	$ 1,320,000
Beginning Balance, shares (in shares) at Dec. 31, 2016		99,519,000			6,000
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 San Mateo I (see Note 6)	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		108,514,000			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	0		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		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		0
Stock options expense related to equity based awards	22,660,000		22,660,000	0		22,660,000
Stock options exercised, shares		179,000
Stock options exercised, net of options forfeited in net share settlements	(1,267,000)	$ 2,000	(1,269,000)	0		(1,267,000)
Cost to issue equity	(204,000)		(204,000)	0		(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 San Mateo I (see Note 6)	14,700,000		14,700,000	0		14,700,000
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	108,510,160	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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock pursuant to employee stock compensation plan, shares		240,000
Issuance of common stock pursuant to employee stock compensation plan	0	$ 2,000	(2,000)	0		0	0
Stock Issued During Period, Shares, Issued for Services		50,000
Stock Issued During Period, Value, Issued for Services	0	$ 0	0			0
Stock options expense related to equity based awards	$ 23,396,000		23,396,000			23,396,000
Stock options exercised, shares	223,000	220,000
APIC, Share-based Payment Arrangement, Recognition and Exercise	$ 3,300,000	$ 2,000	3,298,000			3,300,000
Liability-Based Stock Option Awards Settled, Shares		1,000
Liability-Based Stock Option Awards Settled	11,000
Restricted stock forfeited, shares					222,000
Restricted stock forfeited	(3,691,000)				$ (3,691,000)	(3,691,000)
Contributions related to formation of San Mateo I (see Note 6)								$ 11,613,000	$ 11,613,000	$ 11,613,000	$ 0	$ (506,000)	$ (506,000)	$ 506,000
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	71,384,000		22,874,000			22,874,000	48,510,000
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries	(39,200,000)						(39,200,000)
Cancellation of treasury stock, shares		(242,000)			(242,000)
Cancellation of treasury stock		$ (2,000)	(4,078,000)		$ 4,080,000
Net (loss) income	$ 122,982,000			87,777,000		87,777,000	35,205,000
Ending Balance, shares (in shares) at Dec. 31, 2019	116,353,590	116,644,000			1,000
Ending Balance at Dec. 31, 2019	$ 1,969,452,000	$ 1,166,000	$ 1,981,014,000	$ (148,500,000)	$ (26,000)	$ 1,833,654,000	$ 135,798,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net income (loss)	$ 122,982	$ 299,764	$ 138,007
Adjustments to reconcile net income to net cash provided by operating activities
Unrealized loss (gain) on derivatives	53,727	(65,085)	(9,715)
Depletion, depreciation and amortization	350,540	265,142	177,502
Accretion of asset retirement obligations	1,822	1,530	1,290
Full-cost ceiling impairment	0	0	0
Stock-based compensation expense	18,505	17,200	16,654
Prepayment premium on extinguishment of debt	0	31,226	0
Deferred income tax provision (benefit)	35,532	(7,236)	0
Amortization of debt issuance cost	2,484	1,357	468
Net loss (gain) on asset sales and inventory impairment	967	196	(23)
Changes in operating assets and liabilities
Accounts receivable	(43,261)	(4,934)	(82,549)
Lease and well equipment inventory	4,777	(12,176)	(3,623)
Prepaid expenses	(4,844)	(1,770)	(2,960)
Other assets	678	3,418	(6,425)
Accounts payable, accrued liabilities and other current liabilities	(19,004)	68,647	33,559
Royalties payable	20,417	3,418	37,370
Advances from joint interest owners	3,869	8,179	1,089
Other long-term liabilities	2,851	(353)	(1,519)
Net cash provided by operating activities	552,042	608,523	299,125
Investing activities
Oil and natural gas properties capital expenditures	(730,161)	(1,357,802)	(699,445)
Midstream capital expenditures	(192,035)	(163,222)	(115,128)
Expenditures for other property and equipment	(3,701)	(2,562)	(5,688)
Proceeds from sale of assets	21,921	8,333	977
Net cash used in investing activities	(903,976)	(1,515,253)	(819,284)
Financing activities
Repayments of borrowings	(35,000)	(370,000)	0
Borrowings under Credit Agreement	250,000	410,000	0
Borrowings under San Mateo Credit Facility	68,000	220,000	0
Cost to enter into or amend credit facilities	(1,443)	(3,077)	0
Proceeds from issuance of senior unsecured notes	0	1,051,500	0
Cost to issue senior unsecured notes	0	(14,098)	0
Purchase of senior unsecured notes	0	(605,780)	0
Proceeds from issuance of common stock	0	226,612	208,720
Cost to issue equity	0	(204)	(280)
Proceeds from stock options exercised	3,300	815	2,920
Contributions related to formation of San Mateo I	14,700	14,700	171,500
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	77,330	85,750	44,100
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(39,200)	(121,520)	(10,045)
Taxes paid related to net share settlement of stock-based compensation	(3,691)	(6,466)	(5,763)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	0	0	(2,653)
Cash paid under financing lease obligations	(918)	0	0
Net cash provided by financing activities	333,078	888,232	408,499
Decrease in cash and restricted cash	(18,856)	(18,498)	(111,660)
Cash and restricted cash at beginning of year	83,984	102,482	214,142
Cash and restricted cash at end of year	$ 65,128	$ 83,984	$ 102,482

Nature of Operations

Nature of Operations	12 Months Ended
	Dec. 31, 2019
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. Additionally, the Company conducts midstream operations, primarily through its midstream joint ventures, San Mateo Midstream, LLC (“San Mateo I”) and San Mateo Midstream II, LLC (“San Mateo II” and, together with San Mateo I, “San Mateo”), 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 Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	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 and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . 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. 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. 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. Change in Accounting Principles Leases. During the first quarter of 2019, the Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and the amendments provided for in ASU 2018-11, Leases (Topic 842) , which require the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that the Company chose to apply. These practical expedients relate to (i) the identification and classification of leases that commenced before the effective date, (ii) the treatment of initial direct costs for leases that commenced before the effective date, (iii) the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset and (iv) the ability to initially apply the new lease standard at the adoption date. During the first quarter of 2019, the Company also adopted ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient, and, as a result, the Company began evaluating land easements that are entered into or modified after December 31, 2018. See Note 4 for additional disclosures related to leases. The adoption of these ASUs resulted in the Company recording in the consolidated balance sheet beginning January 1, 2019 certain of the Company’s compressor leases, drilling rig leases and office leases, which were previously considered operating leases and not reported on the Company’s consolidated balance sheets. As such, upon adoption, the Company recorded (i) long-term right of use assets of $62.3 million , which are included in “Other assets” and “Other property and equipment,” and (ii) net right of use liabilities of $62.3 million , which are included in “Other current liabilities” and “Other long-term liabilities.” There was no cumulative-effect adjustment to the opening balance of accumulated deficit as a result of the adoption of these ASUs. Stock Compensation. During the first quarter of 2019, the Company also adopted ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting , which extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Previously, the Company accounted for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards was recalculated each reporting period. Upon adoption, all such awards are now measured at fair value on the grant date, and the resulting expense is recognized on a straight-line basis over the awards’ vesting periods. 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. Adoption of this ASU did not have a material impact on the Company’s 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 natural gas liquid (“NGL”) production to various purchasers (See “Revenues” below.) 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, 2019 , two significant purchasers accounted for 67% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 53% ) and BP America Production Company ( 14% ). 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% ). 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, 2019, 2018 and 2017 , approximately 31% , 34% and 43% , 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, 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 $31.1 million , $28.3 million and $23.1 million of its general and administrative costs into oil and natural gas properties in 2019 , 2018 and 2017 , respectively. The Company capitalized $7.6 million , $8.8 million and $7.3 million of its interest expense into oil and natural gas properties for the years ended December 31, 2019, 2018 and 2017 , 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. For the years ended December 31, 2019 , 2018 and 2017, the Company recorded depletion expense of $330.7 million , $251.8 million and $170.3 million , respectively. 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 2019 , these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. 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. 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, 2019, 2018 and 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, 2019, 2018 and 2017. 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 Properties and Other Property and Equipment Midstream properties 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. The Company capitalized $1.8 million and $1.6 million of general and administrative costs into midstream properties in 2019 and 2018, respectively. The Company did not capitalize any general and administrative costs into midstream properties in 2017. The Company capitalized $0.9 million of interest expense into midstream properties for the year ended December 31, 2019. The Company did not capitalize any interest expense into midstream properties for the years ended December 31, 2018 and 2017. 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 properties and other property and equipment. Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations. 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, midstream properties or 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 as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments. Revenues The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606, Revenue from Contracts with Customers (Topic 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 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 revenues 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, NGLs 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 following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2019 and 2018 (in thousands). Year Ended December 31, 2019 2018 Revenues from contracts with customers $ 1,026,204 $ 829,691 Lease bonus - mineral acreage 1,711 2,489 Realized gain on derivatives 9,482 2,334 Unrealized (loss) gain on derivatives (53,727 ) 65,085 Total revenues $ 983,670 $ 899,599 Year Ended December 31, 2019 2018 Oil revenues $ 759,811 $ 635,554 Natural gas revenues 132,514 165,146 Third-party midstream services revenues 59,110 21,920 Sales of purchased natural gas 74,769 7,071 Total revenues from contracts with customers $ 1,026,204 $ 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. 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 recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. 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 recognized on a straight-line basis over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. 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 recognized until the awards are settled as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. All such stock options that were outstanding as of December 31, 2019 were settled in the first quarter of 2020. The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2003 Plan and the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). The Company’s consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017 include a stock-based compensation (non-cash) expense of $18.5 million , $17.2 million and $16.7 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.4 million , $1.6 million and $3.0 million in 2019 , 2018 and 2017 , respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statement of operations for the year ended December 31, 2019 also includes $3.2 million related to liability-based awards expected to be settled in cash. 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, 2019, 2018 and 2017 , 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, 2019, 2018 and 2017 . 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 Per Common Share The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings 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, 2019, 2018 and 2017 (in thousands, exce

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 (in thousands). December 31, 2019 2018 Oil and natural gas properties Evaluated (subject to amortization) $ 4,557,265 $ 3,780,236 Unproved and unevaluated (not subject to amortization) 1,126,992 1,199,511 Total oil and natural gas properties 5,684,257 4,979,747 Accumulated depletion (2,603,681 ) (2,273,010 ) Net oil and natural gas properties 3,080,576 2,706,737 Midstream properties Midstream equipment and facilities 643,903 428,025 Accumulated depreciation (38,473 ) (24,351 ) Net midstream properties 605,430 403,674 Other property and equipment Furniture, fixtures and other equipment 9,170 7,047 Software 8,099 8,039 Leasehold improvements 9,752 6,955 Total other property and equipment 27,021 22,041 Accumulated depreciation (13,432 ) (9,588 ) Net other property and equipment 13,589 12,453 Net property and equipment $ 3,699,595 $ 3,122,864 The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2019 and the year in which these costs were incurred (in thousands). Description 2019 2018 2017 2016 and prior Total Costs incurred for Property acquisition $ 43,795 $ 556,415 $ 204,425 $ 258,296 $ 1,062,931 Exploration wells 10,814 171 361 352 11,698 Development wells 52,144 149 70 — 52,363 Total $ 106,753 $ 556,735 $ 204,856 $ 258,648 $ 1,126,992 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, 2019 are related 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. 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 $64.1 million at December 31, 2019 . Of this total, $11.7 million was associated with exploration wells and $52.4 million was associated with development wells. The Company anticipates that most of the $64.1 million associated with these wells in progress at December 31, 2019 will be transferred to the amortization base during 2020 . Unproved and unevaluated property costs for exploration and development wells incurred from 2016 through 2018 are costs related to the advanced preparation for wells that we intend to drill in the future.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 (in thousands). Year Ended December 31, 2019 2018 Beginning asset retirement obligations $ 31,086 $ 26,256 Liabilities incurred during period 3,811 3,566 Liabilities settled during period (155 ) (708 ) Revisions in estimated cash flows 1,792 442 Divestitures during the period (2,145 ) — Accretion expense 1,822 1,530 Ending asset retirement obligations 36,211 31,086 Less: current asset retirement obligations (1) (619 ) (1,350 ) Long-term asset retirement obligations $ 35,592 $ 29,736 __________________ (1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2019 and 2018 .

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	LEASES The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheet. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rate used for the year ended December 31, 2019 was 3.52% and 3.70% for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheet unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the year ended December 31, 2019 (in thousands). Lease payments represent gross payments to vendors, which, for certain of our operating assets, are partially offset by amounts received from other working interest owners in our operated wells. Year Ended December 31, 2019 Operating leases Lease operating $ 11,877 Plant and other midstream services 110 General and administrative 3,209 Total operating leases (1) 15,196 Short-term leases Lease operating 10,441 Plant and other midstream services 4,983 General and administrative 27 Total short-term leases (2)(3) 15,451 Financing leases Depreciation of assets 976 Interest on lease liabilities 134 Total financing leases 1,110 Total lease expense $ 31,757 _____________________ (1) Does not include gross payments related to drilling rig leases of $28.1 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 . (2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheet as they are short-term leases. (3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $90.3 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 . The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2019 (in thousands). December 31, 2019 Operating leases Other long-term assets $ 85,668 Other current liabilities $ (50,164 ) Other long-term liabilities (41,459 ) Total operating lease liabilities $ (91,623 ) Financing leases Other property and equipment, at cost $ 2,677 Accumulated depreciation (1,324 ) Net property and equipment $ 1,353 Other current liabilities $ (799 ) Other long-term liabilities (524 ) Total financing lease liabilities $ (1,323 ) The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2019 (in thousands). Year Ended December 31, 2019 Cash paid related to lease liabilities Operating cash payments for operating leases $ 14,941 Investing cash payments for operating leases $ 28,034 Financing cash payments for financing leases $ 918 Right of use assets obtained in exchange for lease obligations entered into during the period Operating leases $ 59,740 Financing leases $ 597 The following table presents the maturities of lease liabilities at December 31, 2019 (in years). Weighted-Average Remaining Lease Term December 31, 2019 Operating leases 2.7 Financing leases 2.1 The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2019 and 2018 , respectively (in thousands). December 31, 2019 Operating Leases Financing Leases 2020 $ 50,164 $ 799 2021 27,279 517 2022 5,010 179 2023 4,177 — 2024 4,217 — Thereafter 5,716 — Total lease payments 96,563 1,495 Less imputed interest (4,940 ) (172 ) Total lease obligations 91,623 1,323 Less current obligations (50,164 ) (799 ) Long-term lease obligations $ 41,459 $ 524 December 31, 2018 Operating Leases Financing Leases 2019 $ 39,457 $ 1,240 2020 12,009 913 2021 3,513 534 2022 3,209 455 2023 3,234 — Thereafter 7,680 — Total lease payments 69,102 3,142 Less imputed interest (4,300 ) (130 ) Total lease obligations 64,802 3,012 Less current obligations (39,457 ) (1,240 ) Long-term lease obligations $ 25,345 $ 1,772
Leases	LEASES The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheet. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rate used for the year ended December 31, 2019 was 3.52% and 3.70% for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheet unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the year ended December 31, 2019 (in thousands). Lease payments represent gross payments to vendors, which, for certain of our operating assets, are partially offset by amounts received from other working interest owners in our operated wells. Year Ended December 31, 2019 Operating leases Lease operating $ 11,877 Plant and other midstream services 110 General and administrative 3,209 Total operating leases (1) 15,196 Short-term leases Lease operating 10,441 Plant and other midstream services 4,983 General and administrative 27 Total short-term leases (2)(3) 15,451 Financing leases Depreciation of assets 976 Interest on lease liabilities 134 Total financing leases 1,110 Total lease expense $ 31,757 _____________________ (1) Does not include gross payments related to drilling rig leases of $28.1 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 . (2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheet as they are short-term leases. (3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $90.3 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 . The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2019 (in thousands). December 31, 2019 Operating leases Other long-term assets $ 85,668 Other current liabilities $ (50,164 ) Other long-term liabilities (41,459 ) Total operating lease liabilities $ (91,623 ) Financing leases Other property and equipment, at cost $ 2,677 Accumulated depreciation (1,324 ) Net property and equipment $ 1,353 Other current liabilities $ (799 ) Other long-term liabilities (524 ) Total financing lease liabilities $ (1,323 ) The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2019 (in thousands). Year Ended December 31, 2019 Cash paid related to lease liabilities Operating cash payments for operating leases $ 14,941 Investing cash payments for operating leases $ 28,034 Financing cash payments for financing leases $ 918 Right of use assets obtained in exchange for lease obligations entered into during the period Operating leases $ 59,740 Financing leases $ 597 The following table presents the maturities of lease liabilities at December 31, 2019 (in years). Weighted-Average Remaining Lease Term December 31, 2019 Operating leases 2.7 Financing leases 2.1 The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2019 and 2018 , respectively (in thousands). December 31, 2019 Operating Leases Financing Leases 2020 $ 50,164 $ 799 2021 27,279 517 2022 5,010 179 2023 4,177 — 2024 4,217 — Thereafter 5,716 — Total lease payments 96,563 1,495 Less imputed interest (4,940 ) (172 ) Total lease obligations 91,623 1,323 Less current obligations (50,164 ) (799 ) Long-term lease obligations $ 41,459 $ 524 December 31, 2018 Operating Leases Financing Leases 2019 $ 39,457 $ 1,240 2020 12,009 913 2021 3,513 534 2022 3,209 455 2023 3,234 — Thereafter 7,680 — Total lease payments 69,102 3,142 Less imputed interest (4,300 ) (130 ) Total lease obligations 64,802 3,012 Less current obligations (39,457 ) (1,240 ) Long-term lease obligations $ 25,345 $ 1,772

Business Combinations and Dives

Business Combinations and Divestitures	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
BUSINESS COMBINATIONS AND DIVESTITURES	Joint Ventures 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 I, a joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). The midstream assets contributed to San Mateo I 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 I’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 I, respectively. Five Point provided initial cash consideration of $176.4 million to San Mateo I in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by San Mateo I to the Company as a special distribution. The Company earned, and Five Point paid to the Company, $14.7 million in performance incentives during each of the twelve months ended December 31, 2019 and 2018. As of February 28, 2020 , the Company had received an additional $14.7 million in performance incentives from Five Point and may earn an additional $29.4 million in performance incentives over the next two years . These performance incentives are recorded as additional contributions related to the formation of the San Mateo I as they are received. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to San Mateo I in exchange for its 51% interest. San Mateo I is consolidated in the Company’s financial statements with Five Point’s interest in San Mateo I 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 I 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 I pursuant to a 15 -year, fixed-fee natural gas processing agreement (see Note 14). On February 25, 2019, the Company announced the formation of 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 surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and the Stateline asset area. Upon formation of San Mateo II, in the first quarter of 2019, the Company contributed $1.0 million of property to San Mateo II. During the year ended December 31, 2019, the Company contributed $15.5 million of cash, and Five Point contributed $69.0 million of cash, of which $28.4 million was paid to carry Matador’s proportionate interest in San Mateo II and was therefore recorded in “Additional paid-in capital” in the consolidated balance sheet, net of the $5.9 million deferred tax impact to Matador related to this equity contribution. In addition, the Company has the ability to earn up to $150.0 million in deferred performance incentives over the next several 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 Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil, natural gas and salt water gathering, natural gas processing and salt water disposal agreements (see Note 14). Divestitures During 2019, we converted approximately $21.9 million of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana and East Texas but included a small portion of our leasehold in a non-operated area of the Delaware Basin.

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
DEBT	Credit Agreements MRC Energy Company On September 28, 2012 , the Company amended and restated its revolving credit facility 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 Credit Agreement matures October 31, 2023. 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. In October 2018, the lenders under the Credit Agreement completed their review of the Company’s proved oil and natural gas reserves at June 30, 2018. In connection with such review, the Company amended the Credit Agreement to, among other items, increase the maximum facility amount to $1.5 billion, increase the borrowing base to $850.0 million, increase the elected borrowing commitment to $500.0 million, extend the maturity to October 31, 2023, reduce borrowing rates by 0.25% per annum and set the maximum leverage ratio at 4.00 to 1.00. In April 2019, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2018, and as a result, the borrowing base was increased from $850.0 million to $900.0 million . In October 2019, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2019, and as a result, the borrowing base was affirmed at $900.0 million . The Company elected to keep the borrowing commitment at $500.0 million , and the maximum facility amount remained $1.5 billion . In February 2020, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2019, and as a result, the borrowing base was again affirmed at $900.0 million . The Company elected to increase the borrowing commitment from $500.0 million to $700.0 million , and the maximum facility amount remained $1.5 billion . This February 2020 redetermination constituted the regularly scheduled May 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. 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 . Total deferred loan costs were $1.6 million at December 31, 2019 , and these costs are being amortized over the term of the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 3.28% at December 31, 2019. At December 31, 2019 and February 25, 2020 , the Company had $255.0 million and $255.0 million in borrowings outstanding under the Credit Agreement and approximately $46.1 million and $46.0 million in outstanding letters of credit issued pursuant to the Credit Agreement, respectively. 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, 2019 . San Mateo Midstream, LLC On December 19, 2018, San Mateo I 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 at that time. The San Mateo Credit Facility, which matures December 19, 2023, includes an accordion feature, which provides for potential increases to up to $400.0 million . The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries, but is guaranteed by San Mateo I’s subsidiaries and secured by substantially all of San Mateo I’s assets, including real property. In June and October 2019, pursuant to the accordion feature, the lender commitments under the San Mateo Credit Facility were increased to $325.0 million and $375.0 million , respectively. Total deferred loan costs were $ 2.7 million at December 31, 2019 , and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo I’s effective interest rate under the San Mateo Credit Facility was 3.55% at December 31, 2019. At both December 31, 2019 and February 25, 2020 , San Mateo I had $288.0 million in borrowings outstanding under the San Mateo Credit Facility and $16.2 million 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 I 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 I’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo I 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 I’s Consolidated Total Leverage Ratio. If San Mateo I has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo I’s interest costs, which may have a material adverse effect on San Mateo I’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 I 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 I to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo I’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 I’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 I’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 I’s assets; and • issue equity interests in San Mateo I 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 I or its subsidiaries; and • a change of control, as defined in the San Mateo Credit Facility. The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at December 31, 2019 . 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 were 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 were 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 were 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 17). 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 $255.0 million at December 31, 2019 under the Credit Agreement mature on October 31, 2023. The outstanding borrowings of $288.0 million at December 31, 2019 under the San Mateo Credit Facility mature on December 19, 2023. The $1.05 billion of outstanding Notes at December 31, 2019

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 is as follows (in thousands). December 31, 2019 2018 Deferred tax assets Net operating loss carryforwards $ 119,900 $ 116,374 Percentage depletion carryover 1,467 1,624 Compensation 13,690 10,574 Lease liabilities 17,107 — Other 9,099 7,207 Total deferred tax assets 161,263 135,779 Valuation allowance on deferred tax assets (6,736 ) (6,519 ) Total deferred tax assets, net of valuation allowance 154,527 129,260 Deferred tax liabilities Unrealized gain on derivatives — (12,326 ) Property and equipment (151,504 ) (100,634 ) Less than wholly-owned subsidiaries (20,604 ) (6,808 ) Lease right of use assets (17,107 ) — Other (2,641 ) (2,256 ) Total deferred tax liabilities (191,856 ) (122,024 ) Net deferred tax (liabilities) assets $ (37,329 ) $ 7,236 At December 31, 2019 , the Company had net operating loss carryforwards of $525.2 million for federal income tax purposes and $163.9 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, 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. 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 provision and the deferred income tax provision for the years ended December 31, 2019, 2018 and 2017 were comprised of the following (in thousands). Year Ended December 31, 2019 2018 2017 Current income tax (benefit) provision Federal income tax $ — $ (455 ) $ (8,178 ) State income tax — — 21 Net current income tax benefit $ — $ (455 ) $ (8,157 ) Deferred income tax provision (benefit) Federal income tax $ 29,171 $ (20,457 ) $ — State income tax 6,361 13,221 — Net deferred income tax provision (benefit) $ 35,532 $ (7,236 ) $ — Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2019, 2018 and 2017 is as follows (in thousands). Year Ended December 31, 2019 2018 2017 Federal tax expense at statutory rate (1) $ 33,441 $ 61,543 $ 45,447 State income tax 6,141 16,181 368 Permanent differences (4,267 ) (2,488 ) (4,740 ) AMT credit refundable — 455 8,178 Tax Cuts and Jobs Act rate change — — 51,525 Change in federal valuation allowance — (80,003 ) (101,917 ) Change in state valuation allowance 217 (2,924 ) 1,139 Net deferred income tax provision (benefit) 35,532 (7,236 ) — Net current income tax benefit — (455 ) (8,157 ) Total income tax provision (benefit) $ 35,532 $ (7,691 ) $ (8,157 ) __________________ (1) The statutory federal tax rate was 21% for the years ended December 31, 2019 and 2018 and 35% for the year ended December 31, 2017 . 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 2016 . The earliest tax year open for examination for the State of Texas tax return is 2015. 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, 2019 , 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

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [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 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2012 Incentive Plan included employees, directors, contractors or advisors of the Company. In 2019, the Board of Directors adopted and shareholders approved the 2019 Incentive Plan. As of December 31, 2019 , the 2019 Incentive Plan provided for a maximum of 3,433,671 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2003 Plan or the 2012 Incentive Plan, but both plans will remain in place until all awards outstanding under such plans have been settled. As of February 25, 2020 , no awards remained outstanding under the 2003 Plan. The 2003 Plan, the 2012 Incentive Plan and the 2019 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Strategic Planning and 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 had 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 were liability-based awards for which the fair value was remeasured at each reporting period. During the year ended December 31, 2019, the Company began granting both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. Stock Options Under the 2003 Plan, the 2012 Incentive Plan and the 2019 Incentive Plan, 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 10 years . The 2003 Plan and the 2012 Incentive Plan define fair market value as the closing price of Matador’s common stock on the date of grant. Under the 2019 Incentive Plan, such fair market value of a stock option is determined using the closing price of Matador’s common stock on the trading day prior to the date of grant. All option awards granted under the 2003 Plan and still outstanding as of December 31, 2019 were settled in the first quarter of 2020. The fair value of the 65,000 , 67,500 and 75,000 stock option awards outstanding under the 2003 Plan at December 31, 2019, 2018 and 2017 , respectively, was estimated using the following weighted average assumptions. 2019 2018 2017 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 0.14 years 1.14 years 2.14 years Risk-free interest rate 1.54% 2.48% 1.98% Volatility 32.38% 37.94% 43.60% Dividend yield —% —% —% Estimated forfeiture rate —% —% —% The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan and the 2019 Incentive Plan were estimated using the following weighted average assumptions during the years ended December 31, 2019, 2018 and 2017 . 2019 2018 2017 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 4.00 years 4.00 years 4.00 years Risk-free interest rate 1.46% 2.51% 1.77% Volatility 48.52% 45.17% 47.00% Dividend yield —% —% —% Estimated forfeiture rate 4.43% 2.24% 3.66% Weighted average fair value of stock option awards granted during the year $5.04 $12.64 $10.49 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, 2019 under the 2003 Plan, the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. Number of options (in thousands) Weighted average exercise price Options outstanding at December 31, 2018 3,225 $ 23.48 Options granted 540 $ 14.80 Options exercised (223 ) $ 14.93 Options forfeited (10 ) $ 27.91 Options expired (272 ) $ 23.22 Options outstanding at December 31, 2019 3,260 $ 22.64 Options outstanding at December 31, 2019 Options exercisable at December 31, 2019 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 65 0.14 $ 9.00 65 $ 9.00 $13.22 - $15.40 933 3.74 $ 14.87 395 $ 14.97 $20.01 - $22.70 663 0.20 $ 21.94 658 $ 21.95 $25.31 - $29.68 1,599 3.37 $ 28.01 897 $ 27.66 At December 31, 2019 , the aggregate intrinsic value was $3.3 million for outstanding options and $1.8 million for exercisable options, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The remaining weighted average contractual term of exercisable options at December 31, 2019 was 1.69 years. The total intrinsic value of options exercised during the years ended December 31, 2019, 2018 and 2017 was $0.8 million , $7.0 million and $13.2 million , respectively. The tax related benefit realized from the exercise of stock options totaled $2.8 million , $5.7 million and $5.0 million for the years ended December 31, 2019, 2018 and 2017 , respectively. At December 31, 2019 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $5.5 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.72 years. The fair value of options vested during 2019 , 2018 and 2017 was $9.7 million , $11.8 million and $2.1 million , respectively. Service-Based 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 LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2018 and 2017 were service-based awards and vest over the service period, which is one to four years . Restricted stock and restricted stock units granted in 2019 were either service-based awards, which will settle in cash or equity, or performance-based restricted stock units, which vest in an amount between zero and 200% of the target units granted 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, and will be settled in stock. All restricted stock and restricted stock unit awards outstanding at December 31, 2019 were granted under the 2012 Incentive Plan and the 2019 Incentive Plan. Equity-Based A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2019 is presented below (in thousands, except fair value). Restricted Stock Restricted Stock Units Service Based Service Based Performance Based Non-vested restricted stock and restricted stock units Shares Weighted average fair value Shares Weighted average fair value Shares Weighted average fair value Non-vested at December 31, 2018 1,356 $ 25.87 58 $ 27.48 — $ — Granted 240 $ 19.36 100 $ 16.06 428 $ 20.00 Vested (674 ) $ 23.02 (57 ) $ 27.47 — $ — Forfeited (25 ) $ 28.39 (9 ) $ 17.31 — $ — Non-vested at December 31, 2019 897 $ 26.19 92 $ 16.06 428 $ 20.00 Liability-Based A summary of the non-vested liability-based restricted stock units as of December 31, 2019 is presented below (in thousands, except fair value). Non-vested restricted stock units Shares Non-vested at December 31, 2018 — Granted 687 Vested — Forfeited (1 ) Non-vested at December 31, 2019 686 At December 31, 2019 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $37.7 million , of which $12.3 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. At December 31, 2019 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $28.3 million , of which $9.1 million is expected to be settled in cash, and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.80 years. The fair value of restricted stock and restricted stock units vested during 2019 , 2018 and 2017 was $13.6 million , $13.0 million and $9.9 million , respectively. Summary During the years ended December 31, 2019, 2018 and 2017 , the total expense attributable to stock options was $6.4 million , $6.3 million and $7.1 million , respectively. At December 31, 2019, 2018 and 2017 , the Company recorded a decrease of $0.1 million to current liabilities, a decrease of $1.1 million to long-term liabilities and an increase of $0.4 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, 2019, 2018 and 2017 , respectively. During the years ended December 31, 2019, 2018 and 2017 , the total expense attributable to restricted stock and restricted stock units was $20.2 million , $15.3 million and $12.9 million , respectively. During the years ended December 31, 2019, 2018 and 2017 , the Company capitalized $5.0 million , $4.4 million and $4.1 million , respectively, related to stock-based compensation and expensed the remaining $21.6 million , $17.2 million and $16.7 million , respectively. The total tax benefit recognized for all stock-based compensation was $5.6 million , $4.8 million and $6.8 million for the years ended December 31, 2019, 2018 and 2017 , respectively.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2019
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 $1.4 million , $1.1 million and $0.9 million in 2019 , 2018 and 2017 , 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 $1.7 million , $1.4 million and $1.1 million in 2019 , 2018 and 2017 , respectively. The Company made no additional contributions in any reporting period presented.

Equity

Equity	12 Months Ended
	Dec. 31, 2019
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 . 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. Treasury Stock On October 24, 2019, October 25, 2018 and November 1, 2017, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2019, 2018 and 2017, 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, 2019 , 2018 and 2017 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 Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2019
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, 2019 , the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil 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 2020, 2021 and 2022. The Company had no open contracts associated with natural gas or NGL prices at December 31, 2019 . The following is a summary of the Company’s open costless collar contracts for oil at December 31, 2019 . Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or Weighted Average Price Ceiling ($/Bbl or $/MMBtu) Fair Value of Asset (Liability) (thousands) Commodity Calculation Period Oil 01/01/2020 - 12/31/2020 7,200,000 $ 47.69 $ 66.62 $ 630 Total open costless collar contracts $ 630 The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2019 . 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 9,774,000 $ 0.61 $ (2,528 ) Oil Basis Swaps 01/01/2021 - 12/31/2021 6,480,000 $ 0.82 $ (1,523 ) Oil Basis Swaps 01/01/2022 - 12/31/2022 3,600,000 0.90 $ (460 ) Total open swap contracts $ (4,511 ) At December 31, 2019 , the Company had an aggregate net liability value for open derivative financial instruments of $3.9 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, 2019 and December 31, 2018 (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, 2019 Current assets $ 442,291 $ (442,291 ) $ — Other assets 280,397 (280,397 ) — Current liabilities (444,188 ) 442,291 (1,897 ) Long-term liabilities (282,381 ) 280,397 (1,984 ) Total $ (3,881 ) $ — $ (3,881 ) December 31, 2018 Current assets $ 53,136 $ (3,207 ) $ 49,929 Current liabilities (3,207 ) 3,207 — Long-term liabilities (83 ) — (83 ) Total $ 49,846 $ — $ 49,846 The following table summarizes the location and aggregate gain (loss) 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 Statements of Operations 2019 2018 2017 Derivative Instrument Oil Revenues: Realized gain (loss) on derivatives $ 9,026 $ 3,741 $ (3,657 ) Natural Gas Revenues: Realized gain (loss) on derivatives 456 (1,407 ) (608 ) NGLs Revenues: Realized loss on derivatives — — (56 ) Realized gain (loss) on derivatives 9,482 2,334 (4,321 ) Oil Revenues: Unrealized (loss) gain on derivatives (53,443 ) 65,991 2,638 Natural Gas Revenues: Unrealized (loss) gain on derivatives (284 ) (906 ) 7,077 Unrealized (loss) gain on derivatives (53,727 ) 65,085 9,715 Total $ (44,245 ) $ 67,419 $ 5,394

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
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 that 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 that 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, 2019 and 2018 (in thousands). Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil derivatives and basis swaps $ — $ (3,881 ) $ — $ (3,881 ) Total $ — $ (3,881 ) $ — $ (3,881 ) Fair Value Measurements at 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 Additional disclosures related to derivative financial instruments are provided in Note 12. Other Fair Value Measurements At December 31, 2019 and 2018 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current 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, 2019 , the carrying value of 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, 2019 and 2018 , the fair value of the Notes was $1.06 billion and $968.9 million , respectively, based on quoted market prices, which represent 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 2019 and 2018

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Processing, Transportation and Salt Water Disposal Commitments Firm Commitments From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and salt water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and, in the case of salt water, disposal. The Company paid approximately $28.7 million and $20.6 million for deliveries under these agreements during the years ended December 31, 2019 and 2018 , respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2019 , the total deficiencies required to be paid by the Company under these agreements would be approximately $406.8 million , in addition to the commitments described below. Future Commitments In late 2017, the Company entered into a fixed-fee NGL sales agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant to a certain counterparty. The Company is committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline extension 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 amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven-year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. Should the pipeline extension and fractionation facility be completed on or prior to February 28, 2021, the minimum contractual obligation during the seven-year period would be approximately $132.3 million . In October 2019, the Company entered into a 15-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. The agreement begins when the counterparty’s pipeline is placed in service, which is anticipated to be the third quarter of 2020. Should the pipeline be placed in service, the Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline, and the minimum contractual obligation would be approximately $106.9 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 I. 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 I 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, 2019 was approximately $152.9 million . In connection with the February 2019 formation of San Mateo II, the Company dedicated to San Mateo II acreage in the Greater 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 provides 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. In June 2019, a subsidiary of San Mateo II entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed in service in 2020. San Mateo II’s total commitments under this agreement are $80.4 million . San Mateo II paid approximately $40.1 million under this agreement during the year ended December 31, 2019 . As of December 31, 2019 , the remaining obligations under this agreement were $40.3 million , which are expected to be paid within the next year. 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 $41.7 million at December 31, 2019 , of which $1.2 million is related to short-term drilling rig contracts, which are not recorded on the consolidated balance sheet. At December 31, 2019 , 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 $26.9 million at December 31, 2019 . The Company expects these costs to be incurred within the next year. Legal Proceedings The Company is a party to several legal proceedings 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 legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

Supplemental Disclosures

Supplemental Disclosures	12 Months Ended
	Dec. 31, 2019
Supplemental Disclosures [Abstract]
SUPPLEMENTAL DISCLOSURES	Accrued Liabilities The following table summarizes the Company’s current accrued liabilities at December 31, 2019 and 2018 (in thousands). December 31, 2019 2018 Accrued evaluated and unproved and unevaluated property costs $ 72,376 $ 86,318 Accrued midstream properties costs 46,402 16,808 Accrued lease operating expenses 18,223 12,705 Accrued interest on debt 18,569 22,448 Accrued asset retirement obligations 619 1,350 Accrued partners’ share of joint interest charges 14,322 17,037 Accrued payable related to purchased natural gas 17,806 4,442 Other 12,378 9,747 Total accrued liabilities $ 200,695 $ 170,855 Supplemental Cash Flow Information The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2019, 2018 and 2017 (in thousands). Year Ended December 31, 2019 2018 2017 Cash paid for interest expense, net of amounts capitalized $ 75,525 $ 29,474 $ 32,760 Increase in asset retirement obligations related to mineral properties $ 2,912 $ 2,614 $ 4,385 Increase (decrease) in asset retirement obligations related to midstream properties $ 1,204 $ 686 $ (60 ) (Decrease) increase in liabilities for oil and natural gas properties capital expenditures $ (15,877 ) $ (16,802 ) $ 48,929 Increase (decrease) in liabilities for midstream properties capital expenditures $ 30,374 $ 2,499 $ (955 ) Stock-based compensation expense (benefit) recognized as liability $ 3,170 $ (1,069 ) $ 362 Decrease in liabilities for accrued cost to issue equity $ — $ — $ (343 ) Increase in liabilities for accrued cost to issue senior notes $ — $ 232 $ — Transfer of inventory from (to) oil and natural gas properties $ 1,515 $ 409 $ (374 ) Transfer of inventory to midstream properties $ — $ — $ (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, 2019 2018 2017 Cash $ 40,024 $ 64,545 $ 96,505 Restricted cash 25,104 19,439 5,977 Total cash and restricted cash $ 65,128 $ 83,984 $ 102,482

Segment Reporting

Segment Reporting	12 Months Ended
	Dec. 31, 2019
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 exploration, development, production and acquisition of oil and natural gas resources in the United States 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. 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 6). 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 Midstream Corporate Year Ended December 31, 2019 Oil and natural gas revenues $ 886,127 $ 6,198 $ — $ — $ 892,325 Midstream services revenues — 135,953 — (76,843 ) 59,110 Sales of purchased natural gas 4,802 69,967 — — 74,769 Lease bonus - mineral acreage 1,711 — — — 1,711 Realized gain on derivatives 9,482 — — — 9,482 Unrealized loss on derivatives (53,727 ) — — — (53,727 ) Expenses (1) 621,687 130,612 72,734 (76,843 ) 748,190 Operating income (loss) (2) $ 226,708 $ 81,506 $ (72,734 ) $ — $ 235,480 Total assets (3) $ 3,360,725 $ 647,937 $ 61,014 $ — $ 4,069,676 Capital expenditures (4) $ 718,712 $ 223,612 $ 3,701 $ — $ 946,025 _____________________ (1) Includes depletion, depreciation and amortization expenses of $331.7 million and $16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million . (2) Includes $35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate 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 (3) $ 2,910,326 $ 439,953 $ 105,239 $ — $ 3,455,518 Capital expenditures (4) $ 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) Excludes intercompany receivables and investments in subsidiaries. (4) 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 Midstream Corporate 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 (3) $ 1,768,393 $ 257,871 $ 119,426 $ — $ 2,145,690 Capital expenditures (4) $ 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) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2019
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, 2019 , 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 tables present condensed consolidating financial information of Matador (as issuer of the Notes), 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 Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated ASSETS Intercompany receivable $ 1,578,133 $ 29,217 $ — $ (1,607,350 ) $ — Current assets 29 37,933 240,530 — 278,492 Net property and equipment — 583,899 3,115,696 — 3,699,595 Investment in subsidiaries 1,332,237 — 144,697 (1,476,934 ) — Long-term assets — 3,072 99,049 (10,532 ) 91,589 Total assets $ 2,910,399 $ 654,121 $ 3,599,972 $ (3,094,816 ) $ 4,069,676 LIABILITIES AND EQUITY Intercompany payable $ — $ — $ 1,607,350 $ (1,607,350 ) $ — Current liabilities — 73,086 327,595 (909 ) 399,772 Senior unsecured notes payable 1,039,416 — — — 1,039,416 Other long-term liabilities 37,329 300,540 332,790 (9,623 ) 661,036 Total equity attributable to Matador Resources Company 1,833,654 144,697 1,332,237 (1,476,934 ) 1,833,654 Non-controlling interest in subsidiaries — 135,798 — — 135,798 Total liabilities and equity $ 2,910,399 $ 654,121 $ 3,599,972 $ (3,094,816 ) $ 4,069,676 Condensed Consolidating Balance Sheet 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 Statement of Operations Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Total revenues $ — $ 209,887 $ 848,502 $ (74,719 ) $ 983,670 Total expenses (1,458 ) 128,758 695,609 (74,719 ) 748,190 Operating (loss) income 1,458 81,129 152,893 — 235,480 Net loss on asset sales and inventory impairment — — (967 ) — (967 ) Interest expense (64,591 ) (9,282 ) — — (73,873 ) Other income (expense) — 3 (2,129 ) — (2,126 ) Earnings in subsidiaries 186,442 — 36,645 (223,087 ) — Income before income taxes 123,309 71,850 186,442 (223,087 ) 158,514 Total income tax provision 35,532 — — — 35,532 Net income attributable to non-controlling interest in subsidiaries — (35,205 ) — — (35,205 ) Net income attributable to Matador Resources Company shareholders $ 87,777 $ 36,645 $ 186,442 $ (223,087 ) $ 87,777 Condensed Consolidating Statement of Operations 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 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 Cash Flows Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Net cash (used in) provided by operating activities $ (427 ) $ 106,650 $ 445,819 $ — $ 552,042 Net cash used in investing activities — (188,893 ) (698,455 ) (16,628 ) (903,976 ) Net cash provided by financing activities — 88,059 228,391 16,628 333,078 (Decrease) increase in cash and restricted cash (427 ) 5,816 (24,245 ) — (18,856 ) Cash and restricted cash at beginning of year 456 18,840 64,688 — 83,984 Cash and restricted cash at end of year $ 29 $ 24,656 $ 40,443 $ — $ 65,128 Condensed Consolidating Statement of Cash Flows 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 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 (increase) 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

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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 and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . 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. 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. 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.
Change in Accounting Principles	Change in Accounting Principles Leases. During the first quarter of 2019, the Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and the amendments provided for in ASU 2018-11, Leases (Topic 842) , which require the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that the Company chose to apply. These practical expedients relate to (i) the identification and classification of leases that commenced before the effective date, (ii) the treatment of initial direct costs for leases that commenced before the effective date, (iii) the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset and (iv) the ability to initially apply the new lease standard at the adoption date. During the first quarter of 2019, the Company also adopted ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient, and, as a result, the Company began evaluating land easements that are entered into or modified after December 31, 2018. See Note 4 for additional disclosures related to leases. The adoption of these ASUs resulted in the Company recording in the consolidated balance sheet beginning January 1, 2019 certain of the Company’s compressor leases, drilling rig leases and office leases, which were previously considered operating leases and not reported on the Company’s consolidated balance sheets. As such, upon adoption, the Company recorded (i) long-term right of use assets of $62.3 million , which are included in “Other assets” and “Other property and equipment,” and (ii) net right of use liabilities of $62.3 million , which are included in “Other current liabilities” and “Other long-term liabilities.” There was no cumulative-effect adjustment to the opening balance of accumulated deficit as a result of the adoption of these ASUs. Stock Compensation. During the first quarter of 2019, the Company also adopted ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting , which extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Previously, the Company accounted for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards was recalculated each reporting period. Upon adoption, all such awards are now measured at fair value on the grant date, and the resulting expense is recognized on a straight-line basis over the awards’ vesting periods. 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. Adoption of this ASU did not have a material impact on the Company’s consolidated financial statements.
Restricted Cash	Restricted Cash Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.
Accounts Receivable	Accounts Receivable The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (See “Revenues” below.) 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, 2019 , two significant purchasers accounted for 67% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 53% ) and BP America Production Company ( 14% ). 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% ). 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, 2019, 2018 and 2017 , approximately 31% , 34% and 43% , 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	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, 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 $31.1 million , $28.3 million and $23.1 million of its general and administrative costs into oil and natural gas properties in 2019 , 2018 and 2017 , respectively. The Company capitalized $7.6 million , $8.8 million and $7.3 million of its interest expense into oil and natural gas properties for the years ended December 31, 2019, 2018 and 2017 , 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. For the years ended December 31, 2019 , 2018 and 2017, the Company recorded depletion expense of $330.7 million , $251.8 million and $170.3 million , respectively. 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 2019 , these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. 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. 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, 2019, 2018 and 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, 2019, 2018 and 2017. 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 Properties and Other Property and Equipment Midstream properties 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. The Company capitalized $1.8 million and $1.6 million of general and administrative costs into midstream properties in 2019 and 2018, respectively. The Company did not capitalize any general and administrative costs into midstream properties in 2017. The Company capitalized $0.9 million of interest expense into midstream properties for the year ended December 31, 2019. The Company did not capitalize any interest expense into midstream properties for the years ended December 31, 2018 and 2017. 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 properties and other property and equipment. Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations.
Asset Retirement Obligations	Asset Retirement Obligations
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 as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments.
Revenue Recognition	Revenues The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606, Revenue from Contracts with Customers (Topic 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 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 revenues 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, NGLs 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 following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2019 and 2018 (in thousands). Year Ended December 31, 2019 2018 Revenues from contracts with customers $ 1,026,204 $ 829,691 Lease bonus - mineral acreage 1,711 2,489 Realized gain on derivatives 9,482 2,334 Unrealized (loss) gain on derivatives (53,727 ) 65,085 Total revenues $ 983,670 $ 899,599 Year Ended December 31, 2019 2018 Oil revenues $ 759,811 $ 635,554 Natural gas revenues 132,514 165,146 Third-party midstream services revenues 59,110 21,920 Sales of purchased natural gas 74,769 7,071 Total revenues from contracts with customers $ 1,026,204 $ 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.
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 recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. 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 recognized on a straight-line basis over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. 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 recognized until the awards are settled as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. All such stock options that were outstanding as of December 31, 2019 were settled in the first quarter of 2020. The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2003 Plan and the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). The Company’s consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017 include a stock-based compensation (non-cash) expense of $18.5 million , $17.2 million and $16.7 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.4 million , $1.6 million and $3.0 million in 2019 , 2018 and 2017 , respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statement of operations for the year ended December 31, 2019 also includes $3.2 million related to liability-based awards expected to be settled in cash.
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, 2019, 2018 and 2017 , 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, 2019, 2018 and 2017 .
Earnings Per Common Share	Earnings Per Common Share The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings 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, 2019, 2018 and 2017 (in thousands, except per share data). Year Ended December 31, 2019 2018 2017 Net income attributable to Matador Resources Company shareholders — numerator $ 87,777 $ 274,207 $ 125,867 Weighted average common shares outstanding — denominator Basic 116,555 113,580 102,029 Dilutive effect of options and restricted stock units 508 111 514 Diluted weighted average common shares outstanding 117,063 113,691 102,543 Earnings per common share attributable to Matador Resources Company shareholders Basic $ 0.75 $ 2.41 $ 1.23 Diluted $ 0.75 $ 2.41 $ 1.23 A total of 2.6 million , 1.6 million and 1.0 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the years ended December 31, 2019 , 2018 and 2017 , respectively, because their effects were 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, 2019 were with The Bank of Nova Scotia and BMO Harris Financing, Inc. (Bank of Montreal) (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Income Taxes. In December 2019, the Financial Accounting Standards Board issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes , which removes certain exceptions to the general principles in Topic 740 and provides clarifications related to franchise taxes, transactions with a government that result in a step-up in the tax basis of goodwill, allocation of current and deferred income tax expense and the annual effective tax rate. This ASU is effective January 1, 2021, and its adoption is not expected to have a material impact on the Company’s consolidated financial statements.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Disaggregation of Revenue	Year Ended December 31, 2019 2018 Revenues from contracts with customers $ 1,026,204 $ 829,691 Lease bonus - mineral acreage 1,711 2,489 Realized gain on derivatives 9,482 2,334 Unrealized (loss) gain on derivatives (53,727 ) 65,085 Total revenues $ 983,670 $ 899,599 Year Ended December 31, 2019 2018 Oil revenues $ 759,811 $ 635,554 Natural gas revenues 132,514 165,146 Third-party midstream services revenues 59,110 21,920 Sales of purchased natural gas 74,769 7,071 Total revenues from contracts with customers $ 1,026,204 $ 829,691
Reconciliations of basic and diluted distributed and undistributed earnings (loss) per common share	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, 2019, 2018 and 2017 (in thousands, except per share data). Year Ended December 31, 2019 2018 2017 Net income attributable to Matador Resources Company shareholders — numerator $ 87,777 $ 274,207 $ 125,867 Weighted average common shares outstanding — denominator Basic 116,555 113,580 102,029 Dilutive effect of options and restricted stock units 508 111 514 Diluted weighted average common shares outstanding 117,063 113,691 102,543 Earnings per common share attributable to Matador Resources Company shareholders Basic $ 0.75 $ 2.41 $ 1.23 Diluted $ 0.75 $ 2.41 $ 1.23

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 (in thousands). December 31, 2019 2018 Oil and natural gas properties Evaluated (subject to amortization) $ 4,557,265 $ 3,780,236 Unproved and unevaluated (not subject to amortization) 1,126,992 1,199,511 Total oil and natural gas properties 5,684,257 4,979,747 Accumulated depletion (2,603,681 ) (2,273,010 ) Net oil and natural gas properties 3,080,576 2,706,737 Midstream properties Midstream equipment and facilities 643,903 428,025 Accumulated depreciation (38,473 ) (24,351 ) Net midstream properties 605,430 403,674 Other property and equipment Furniture, fixtures and other equipment 9,170 7,047 Software 8,099 8,039 Leasehold improvements 9,752 6,955 Total other property and equipment 27,021 22,041 Accumulated depreciation (13,432 ) (9,588 ) Net other property and equipment 13,589 12,453 Net property and equipment $ 3,699,595 $ 3,122,864
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization	The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2019 and the year in which these costs were incurred (in thousands). Description 2019 2018 2017 2016 and prior Total Costs incurred for Property acquisition $ 43,795 $ 556,415 $ 204,425 $ 258,296 $ 1,062,931 Exploration wells 10,814 171 361 352 11,698 Development wells 52,144 149 70 — 52,363 Total $ 106,753 $ 556,735 $ 204,856 $ 258,648 $ 1,126,992

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 (in thousands). Year Ended December 31, 2019 2018 Beginning asset retirement obligations $ 31,086 $ 26,256 Liabilities incurred during period 3,811 3,566 Liabilities settled during period (155 ) (708 ) Revisions in estimated cash flows 1,792 442 Divestitures during the period (2,145 ) — Accretion expense 1,822 1,530 Ending asset retirement obligations 36,211 31,086 Less: current asset retirement obligations (1) (619 ) (1,350 ) Long-term asset retirement obligations $ 35,592 $ 29,736 __________________ (1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2019 and 2018 .

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease, Cost	The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2019 (in thousands). Year Ended December 31, 2019 Cash paid related to lease liabilities Operating cash payments for operating leases $ 14,941 Investing cash payments for operating leases $ 28,034 Financing cash payments for financing leases $ 918 Right of use assets obtained in exchange for lease obligations entered into during the period Operating leases $ 59,740 Financing leases $ 597 The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the year ended December 31, 2019 (in thousands). Lease payments represent gross payments to vendors, which, for certain of our operating assets, are partially offset by amounts received from other working interest owners in our operated wells. Year Ended December 31, 2019 Operating leases Lease operating $ 11,877 Plant and other midstream services 110 General and administrative 3,209 Total operating leases (1) 15,196 Short-term leases Lease operating 10,441 Plant and other midstream services 4,983 General and administrative 27 Total short-term leases (2)(3) 15,451 Financing leases Depreciation of assets 976 Interest on lease liabilities 134 Total financing leases 1,110 Total lease expense $ 31,757 _____________________ (1) Does not include gross payments related to drilling rig leases of $28.1 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 . (2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheet as they are short-term leases. (3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $90.3 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 .
Assets And Liabilities, Lessee	The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2019 (in thousands). December 31, 2019 Operating leases Other long-term assets $ 85,668 Other current liabilities $ (50,164 ) Other long-term liabilities (41,459 ) Total operating lease liabilities $ (91,623 ) Financing leases Other property and equipment, at cost $ 2,677 Accumulated depreciation (1,324 ) Net property and equipment $ 1,353 Other current liabilities $ (799 ) Other long-term liabilities (524 ) Total financing lease liabilities $ (1,323 )
Lessee, Lease Terms	The following table presents the maturities of lease liabilities at December 31, 2019 (in years). Weighted-Average Remaining Lease Term December 31, 2019 Operating leases 2.7 Financing leases 2.1
Finance Lease, Liability, Maturity	The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2019 and 2018 , respectively (in thousands). December 31, 2019 Operating Leases Financing Leases 2020 $ 50,164 $ 799 2021 27,279 517 2022 5,010 179 2023 4,177 — 2024 4,217 — Thereafter 5,716 — Total lease payments 96,563 1,495 Less imputed interest (4,940 ) (172 ) Total lease obligations 91,623 1,323 Less current obligations (50,164 ) (799 ) Long-term lease obligations $ 41,459 $ 524
Lessee, Operating Lease, Liability, Maturity	The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2019 and 2018 , respectively (in thousands). December 31, 2019 Operating Leases Financing Leases 2020 $ 50,164 $ 799 2021 27,279 517 2022 5,010 179 2023 4,177 — 2024 4,217 — Thereafter 5,716 — Total lease payments 96,563 1,495 Less imputed interest (4,940 ) (172 ) Total lease obligations 91,623 1,323 Less current obligations (50,164 ) (799 ) Long-term lease obligations $ 41,459 $ 524
Schedule of Future Minimum Rental Payments for Operating Leases	December 31, 2018 Operating Leases Financing Leases 2019 $ 39,457 $ 1,240 2020 12,009 913 2021 3,513 534 2022 3,209 455 2023 3,234 — Thereafter 7,680 — Total lease payments 69,102 3,142 Less imputed interest (4,300 ) (130 ) Total lease obligations 64,802 3,012 Less current obligations (39,457 ) (1,240 ) Long-term lease obligations $ 25,345 $ 1,772
Schedule of Future Minimum Lease Payments for Capital Leases	December 31, 2018 Operating Leases Financing Leases 2019 $ 39,457 $ 1,240 2020 12,009 913 2021 3,513 534 2022 3,209 455 2023 3,234 — Thereafter 7,680 — Total lease payments 69,102 3,142 Less imputed interest (4,300 ) (130 ) Total lease obligations 64,802 3,012 Less current obligations (39,457 ) (1,240 ) Long-term lease obligations $ 25,345 $ 1,772

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt Instrument Redemption	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%

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Summary of net deferred tax position	The Company’s net deferred tax position as of December 31, 2019 and 2018 is as follows (in thousands). December 31, 2019 2018 Deferred tax assets Net operating loss carryforwards $ 119,900 $ 116,374 Percentage depletion carryover 1,467 1,624 Compensation 13,690 10,574 Lease liabilities 17,107 — Other 9,099 7,207 Total deferred tax assets 161,263 135,779 Valuation allowance on deferred tax assets (6,736 ) (6,519 ) Total deferred tax assets, net of valuation allowance 154,527 129,260 Deferred tax liabilities Unrealized gain on derivatives — (12,326 ) Property and equipment (151,504 ) (100,634 ) Less than wholly-owned subsidiaries (20,604 ) (6,808 ) Lease right of use assets (17,107 ) — Other (2,641 ) (2,256 ) Total deferred tax liabilities (191,856 ) (122,024 ) Net deferred tax (liabilities) assets $ (37,329 ) $ 7,236
Income tax expense reconciled to the tax computed at the statutory federal rate	The current income tax provision and the deferred income tax provision for the years ended December 31, 2019, 2018 and 2017 were comprised of the following (in thousands). Year Ended December 31, 2019 2018 2017 Current income tax (benefit) provision Federal income tax $ — $ (455 ) $ (8,178 ) State income tax — — 21 Net current income tax benefit $ — $ (455 ) $ (8,157 ) Deferred income tax provision (benefit) Federal income tax $ 29,171 $ (20,457 ) $ — State income tax 6,361 13,221 — Net deferred income tax provision (benefit) $ 35,532 $ (7,236 ) $ — Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2019, 2018 and 2017 is as follows (in thousands). Year Ended December 31, 2019 2018 2017 Federal tax expense at statutory rate (1) $ 33,441 $ 61,543 $ 45,447 State income tax 6,141 16,181 368 Permanent differences (4,267 ) (2,488 ) (4,740 ) AMT credit refundable — 455 8,178 Tax Cuts and Jobs Act rate change — — 51,525 Change in federal valuation allowance — (80,003 ) (101,917 ) Change in state valuation allowance 217 (2,924 ) 1,139 Net deferred income tax provision (benefit) 35,532 (7,236 ) — Net current income tax benefit — (455 ) (8,157 ) Total income tax provision (benefit) $ 35,532 $ (7,691 ) $ (8,157 ) __________________ (1) The statutory federal tax rate was 21% for the years ended December 31, 2019 and 2018 and 35% for the year ended December 31, 2017 .

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 under the 2003 Plan, the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. Number of options (in thousands) Weighted average exercise price Options outstanding at December 31, 2018 3,225 $ 23.48 Options granted 540 $ 14.80 Options exercised (223 ) $ 14.93 Options forfeited (10 ) $ 27.91 Options expired (272 ) $ 23.22 Options outstanding at December 31, 2019 3,260 $ 22.64
Summarized information about outstanding and exercisable stock option	Options outstanding at December 31, 2019 Options exercisable at December 31, 2019 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 65 0.14 $ 9.00 65 $ 9.00 $13.22 - $15.40 933 3.74 $ 14.87 395 $ 14.97 $20.01 - $22.70 663 0.20 $ 21.94 658 $ 21.95 $25.31 - $29.68 1,599 3.37 $ 28.01 897 $ 27.66
Summary of the non-vested restricted stock and restricted stock units	A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2019 is presented below (in thousands, except fair value). Restricted Stock Restricted Stock Units Service Based Service Based Performance Based Non-vested restricted stock and restricted stock units Shares Weighted average fair value Shares Weighted average fair value Shares Weighted average fair value Non-vested at December 31, 2018 1,356 $ 25.87 58 $ 27.48 — $ — Granted 240 $ 19.36 100 $ 16.06 428 $ 20.00 Vested (674 ) $ 23.02 (57 ) $ 27.47 — $ — Forfeited (25 ) $ 28.39 (9 ) $ 17.31 — $ — Non-vested at December 31, 2019 897 $ 26.19 92 $ 16.06 428 $ 20.00
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	The fair value of the 65,000 , 67,500 and 75,000 stock option awards outstanding under the 2003 Plan at December 31, 2019, 2018 and 2017 , respectively, was estimated using the following weighted average assumptions. 2019 2018 2017 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 0.14 years 1.14 years 2.14 years Risk-free interest rate 1.54% 2.48% 1.98% Volatility 32.38% 37.94% 43.60% 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	The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan and the 2019 Incentive Plan were estimated using the following weighted average assumptions during the years ended December 31, 2019, 2018 and 2017 . 2019 2018 2017 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 4.00 years 4.00 years 4.00 years Risk-free interest rate 1.46% 2.51% 1.77% Volatility 48.52% 45.17% 47.00% Dividend yield —% —% —% Estimated forfeiture rate 4.43% 2.24% 3.66% Weighted average fair value of stock option awards granted during the year $5.04 $12.64 $10.49

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
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 at December 31, 2019 . Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or Weighted Average Price Ceiling ($/Bbl or $/MMBtu) Fair Value of Asset (Liability) (thousands) Commodity Calculation Period Oil 01/01/2020 - 12/31/2020 7,200,000 $ 47.69 $ 66.62 $ 630 Total open costless collar contracts $ 630 The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2019 . 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 9,774,000 $ 0.61 $ (2,528 ) Oil Basis Swaps 01/01/2021 - 12/31/2021 6,480,000 $ 0.82 $ (1,523 ) Oil Basis Swaps 01/01/2022 - 12/31/2022 3,600,000 0.90 $ (460 ) Total open swap contracts $ (4,511 )
Summary of offsetting assets	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, 2019 and December 31, 2018 (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, 2019 Current assets $ 442,291 $ (442,291 ) $ — Other assets 280,397 (280,397 ) — Current liabilities (444,188 ) 442,291 (1,897 ) Long-term liabilities (282,381 ) 280,397 (1,984 ) Total $ (3,881 ) $ — $ (3,881 ) December 31, 2018 Current assets $ 53,136 $ (3,207 ) $ 49,929 Current liabilities (3,207 ) 3,207 — Long-term liabilities (83 ) — (83 ) Total $ 49,846 $ — $ 49,846
Summary of offsetting liabilities	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, 2019 and December 31, 2018 (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, 2019 Current assets $ 442,291 $ (442,291 ) $ — Other assets 280,397 (280,397 ) — Current liabilities (444,188 ) 442,291 (1,897 ) Long-term liabilities (282,381 ) 280,397 (1,984 ) Total $ (3,881 ) $ — $ (3,881 ) December 31, 2018 Current assets $ 53,136 $ (3,207 ) $ 49,929 Current liabilities (3,207 ) 3,207 — Long-term liabilities (83 ) — (83 ) Total $ 49,846 $ — $ 49,846
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations	The following table summarizes the location and aggregate gain (loss) 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 Statements of Operations 2019 2018 2017 Derivative Instrument Oil Revenues: Realized gain (loss) on derivatives $ 9,026 $ 3,741 $ (3,657 ) Natural Gas Revenues: Realized gain (loss) on derivatives 456 (1,407 ) (608 ) NGLs Revenues: Realized loss on derivatives — — (56 ) Realized gain (loss) on derivatives 9,482 2,334 (4,321 ) Oil Revenues: Unrealized (loss) gain on derivatives (53,443 ) 65,991 2,638 Natural Gas Revenues: Unrealized (loss) gain on derivatives (284 ) (906 ) 7,077 Unrealized (loss) gain on derivatives (53,727 ) 65,085 9,715 Total $ (44,245 ) $ 67,419 $ 5,394

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
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	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, 2019 and 2018 (in thousands). Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil derivatives and basis swaps $ — $ (3,881 ) $ — $ (3,881 ) Total $ — $ (3,881 ) $ — $ (3,881 ) Fair Value Measurements at 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

Supplemental Disclosures (Table

Supplemental Disclosures (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Disclosures [Abstract]
Summary of current accrued liabilities	The following table summarizes the Company’s current accrued liabilities at December 31, 2019 and 2018 (in thousands). December 31, 2019 2018 Accrued evaluated and unproved and unevaluated property costs $ 72,376 $ 86,318 Accrued midstream properties costs 46,402 16,808 Accrued lease operating expenses 18,223 12,705 Accrued interest on debt 18,569 22,448 Accrued asset retirement obligations 619 1,350 Accrued partners’ share of joint interest charges 14,322 17,037 Accrued payable related to purchased natural gas 17,806 4,442 Other 12,378 9,747 Total accrued liabilities $ 200,695 $ 170,855
Supplemental disclosures of cash flow information	The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2019, 2018 and 2017 (in thousands). Year Ended December 31, 2019 2018 2017 Cash paid for interest expense, net of amounts capitalized $ 75,525 $ 29,474 $ 32,760 Increase in asset retirement obligations related to mineral properties $ 2,912 $ 2,614 $ 4,385 Increase (decrease) in asset retirement obligations related to midstream properties $ 1,204 $ 686 $ (60 ) (Decrease) increase in liabilities for oil and natural gas properties capital expenditures $ (15,877 ) $ (16,802 ) $ 48,929 Increase (decrease) in liabilities for midstream properties capital expenditures $ 30,374 $ 2,499 $ (955 ) Stock-based compensation expense (benefit) recognized as liability $ 3,170 $ (1,069 ) $ 362 Decrease in liabilities for accrued cost to issue equity $ — $ — $ (343 ) Increase in liabilities for accrued cost to issue senior notes $ — $ 232 $ — Transfer of inventory from (to) oil and natural gas properties $ 1,515 $ 409 $ (374 ) Transfer of inventory to midstream properties $ — $ — $ (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, 2019 2018 2017 Cash $ 40,024 $ 64,545 $ 96,505 Restricted cash 25,104 19,439 5,977 Total cash and restricted cash $ 65,128 $ 83,984 $ 102,482

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	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 Midstream Corporate Year Ended December 31, 2019 Oil and natural gas revenues $ 886,127 $ 6,198 $ — $ — $ 892,325 Midstream services revenues — 135,953 — (76,843 ) 59,110 Sales of purchased natural gas 4,802 69,967 — — 74,769 Lease bonus - mineral acreage 1,711 — — — 1,711 Realized gain on derivatives 9,482 — — — 9,482 Unrealized loss on derivatives (53,727 ) — — — (53,727 ) Expenses (1) 621,687 130,612 72,734 (76,843 ) 748,190 Operating income (loss) (2) $ 226,708 $ 81,506 $ (72,734 ) $ — $ 235,480 Total assets (3) $ 3,360,725 $ 647,937 $ 61,014 $ — $ 4,069,676 Capital expenditures (4) $ 718,712 $ 223,612 $ 3,701 $ — $ 946,025 _____________________ (1) Includes depletion, depreciation and amortization expenses of $331.7 million and $16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million . (2) Includes $35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate 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 (3) $ 2,910,326 $ 439,953 $ 105,239 $ — $ 3,455,518 Capital expenditures (4) $ 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) Excludes intercompany receivables and investments in subsidiaries. (4) 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 Midstream Corporate 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 (3) $ 1,768,393 $ 257,871 $ 119,426 $ — $ 2,145,690 Capital expenditures (4) $ 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) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)shares	Dec. 31, 2019USD ($)$ / MMBTU	Dec. 31, 2019USD ($)$ / bbl	Dec. 31, 2019USD ($)Purchasers	Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)shares	Dec. 31, 2018USD ($)$ / MMBTU	Dec. 31, 2018USD ($)$ / bbl	Dec. 31, 2018USD ($)Purchasers	Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017shares	Dec. 31, 2017$ / MMBTU	Dec. 31, 2017$ / bbl	Dec. 31, 2017Purchasers	Dec. 31, 2017	Dec. 31, 2017USD ($)	Jan. 01, 2019USD ($)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
RIght-of-use asset	$ 85,668,000	$ 85,668,000	$ 85,668,000	$ 85,668,000	$ 85,668,000	$ 85,668,000	$ 85,668,000													$ 62,300,000
Lease liability	$ 91,623,000	91,623,000	91,623,000	91,623,000	91,623,000	91,623,000	91,623,000													$ 62,300,000
Billing date	30 days
Outstanding days of account receivable	60 days
Allowance for doubtful accounts	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Number of purchasers | Purchasers					2						4						4
Capitalized general and administrative costs							31,100,000						28,300,000						$ 23,100,000
Capitalized interest expense							7,600,000						8,800,000						7,300,000
Depletion							330,700,000						251,800,000						170,300,000
Present value discounted percent of future net revenues of proved oil and natural gas reserves						10.00%
Average oil and natural gas prices			2.58	52.19					3.10	62.04					2.98	47.79
Impairment charge of net capitalized costs							0						0						0
Stock-based compensation (non-cash) expense							18,505,000						17,200,000						16,654,000
Common stock and restricted stock unit expense							1,400,000						1,600,000						$ 3,000,000
Compensation expense, liability-based awards							3,200,000
Minimum
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Accounts receivable due period	30 days
Contract term after production	1 month
Maximum
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Accounts receivable due period	60 days
Contract term after production	2 months
Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage						67.00%						60.00%						60.00%
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage						31.00%						34.00%						43.00%
Plains Marketing, L.P. | Customer Concentration Risk | Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage						53.00%						19.00%						14.00%
BP America Production Company | Customer Concentration Risk | Sales Revenue, Goods, Net
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Concentration risk, percentage						14.00%						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%
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%
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%
Machinery and Equipment
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Capitalized general and administrative costs							1,800,000						$ 1,600,000
Capitalized interest expense							$ 900,000
Useful life using the straight-line	30 years
Machinery and Equipment | Minimum
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Useful life	5 years
Machinery and Equipment | Maximum
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Useful life	30 years
Employee Stock Options
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Antidilutive options excluded from calculation (in shares) | shares		2,600,000						1,600,000						1,000,000

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Net income attributable to Matador Resources Company shareholders — numerator	$ 87,777	$ 274,207	$ 125,867
Weighted average common shares outstanding — denominator
Basic (in shares)	116,555	113,580	102,029
Dilutive effect of options and restricted stock units (in shares)	508	111	514
Diluted weighted average common shares outstanding (in shares)	117,063	113,691	102,543
Earnings per common share attributable to Matador Resources Company shareholders
Basic (usd per share)	$ 0.75	$ 2.41	$ 1.23
Diluted (usd per share)	$ 0.75	$ 2.41	$ 1.23

Summary of Significant Accoun_6

Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Disaggregated Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 1,026,204	$ 829,691
Lease bonus - mineral acreage	1,711	2,489	$ 0
Realized gain on derivatives	9,482	2,334	(4,321)
Unrealized gain on derivatives	(53,727)	65,085	9,715
Total revenues	983,670	899,599	544,276
Oil
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	759,811	635,554
Natural gas revenues
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	132,514	165,146
Third-party midstream services revenues
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	59,110	21,920	10,198
Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 74,769	$ 7,071	$ 0

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties
Evaluated (subject to amortization)	$ 4,557,265	$ 3,780,236
Total unproved and unevaluated	1,126,992	1,199,511
Total oil and natural gas properties	5,684,257	4,979,747
Accumulated depletion	(2,603,681)	(2,273,010)
Net oil and natural gas properties	3,080,576	2,706,737
Midstream Properties [Abstract]
Midstream properties	643,903	428,025
Accumulated depreciation	2,655,586	2,306,949
Other property and equipment
Other property and equipment	27,021	22,041
Accumulated depreciation	(13,432)	(9,588)
Net other property and equipment	13,589	12,453
Net property and equipment	3,699,595	3,122,864
Midstream equipment and facilities
Midstream Properties [Abstract]
Midstream properties	643,903	428,025
Accumulated depreciation	38,473	24,351
Net midstream properties	605,430	403,674
Furniture, fixtures and other equipment
Other property and equipment
Other property and equipment	9,170	7,047
Software
Other property and equipment
Other property and equipment	8,099	8,039
Leasehold improvements
Other property and equipment
Other property and equipment	$ 9,752	$ 6,955

Property and Equipment (Detai_2

Property and Equipment (Details 1) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Costs incurred for
Total unproved and unevaluated	$ 1,126,992	$ 1,199,511
2018
Costs incurred for
Property acquisition	43,795
Exploration wells	10,814
Development wells	52,144
Total unproved and unevaluated	106,753
2017
Costs incurred for
Property acquisition		556,415
Exploration wells		171
Development wells		149
Total unproved and unevaluated		$ 556,735
2016
Costs incurred for
Property acquisition			$ 204,425
Exploration wells			361
Development wells			70
Total unproved and unevaluated			$ 204,856
2015 and prior
Costs incurred for
Property acquisition				$ 258,296
Exploration wells				352
Development wells				0
Total unproved and unevaluated				$ 258,648
Total
Costs incurred for
Property acquisition	1,062,931
Exploration wells	11,698
Development wells	52,363
Total unproved and unevaluated	$ 1,126,992

Property and Equipment (Detai_3

Property and Equipment (Details Textual) $ in Thousands	Sep. 12, 2018USD ($)a	Dec. 31, 2019USD ($)
Property, Plant and Equipment [Line Items]
Amortization costs		$ 64,100
Anticipated amount for wells		64,100
BLM Acquisition
Property, Plant and Equipment [Line Items]
Acres of land, gross | a	8,400
Acres of land, net | a	8,400
Consideration transferred	$ 387,000
Projects Inception to Date
Property, Plant and Equipment [Line Items]
Exploration costs		11,698
Development wells		$ 52,363

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Changes in the Company's asset retirement obligations
Beginning asset retirement obligations	$ 31,086	$ 26,256
Liabilities incurred during period	3,811	3,566
Liabilities settled during period	(155)	(708)
Revisions in estimated cash flows	1,792	442
Asset Retirement Obligation, Divestitures	(2,145)	0
Accretion expense	1,822	1,530
Ending asset retirement obligations	$ 31,086	$ 26,256	$ 36,211	$ 31,086
Less: current asset retirement obligations			(619)	(1,350)
Long-term asset retirement obligations			$ 35,592	$ 29,736

Leases - Narrative (Details)

Leases - Narrative (Details)	Dec. 31, 2019
Leases [Abstract]
Incremental borrowing rate, operating leases	3.52%
Incremental borrowing rate, finance leases	3.70%

Leases - Components of Lease Ex

Leases - Components of Lease Expense (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Operating leases	$ 15,196
Short-term leases	15,451
Financing leases
Depreciation of assets	976
Interest on lease liabilities	134
Total financing leases	1,110
Total lease expense	31,757
Lease operating
Lessee, Lease, Description [Line Items]
Operating leases	11,877
Short-term leases	10,441
Plant and other midstream services
Lessee, Lease, Description [Line Items]
Operating leases	110
Short-term leases	4,983
General and administrative
Lessee, Lease, Description [Line Items]
Operating leases	3,209
Short-term leases	27
Drilling Rig Leases
Financing leases
Gross payments	28,100
Drilling Rig Leases And Other Equipment Rentals
Financing leases
Gross payments	$ 90,300

Leases - Balance Sheet Informat

Leases - Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Operating leases
RIght-of-use asset	$ 85,668	$ 62,300
Other current liabilities	(50,164)
Other long-term liabilities	(41,459)
Total operating lease liabilities	(91,623)	$ (62,300)
Financing leases
Other property and equipment, at cost	2,677
Accumulated depreciation	(1,324)
Net property and equipment	1,353
Other current liabilities	(799)
Other long-term liabilities	(524)
Total financing lease liabilities	$ (1,323)

Leases - Cash Flow Information

Leases - Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash paid related to lease liabilities
Operating cash payments for operating leases	$ 14,941
Investing cash payments for operating leases	28,034
Financing cash payments for financing leases	918	$ 0	$ 0
Right of use assets obtained in exchange for lease obligations entered into during the period
Operating leases	59,740
Financing leases	$ 597

Leases - Lease Terms (Details)

Leases - Lease Terms (Details)	Dec. 31, 2019
Weighted-Average Remaining Lease Term
Operating leases	2 years 8 months 12 days
Financing leases	2 years 1 month 6 days

Leases - Lease Payment Maturity

Leases - Lease Payment Maturity Schedule (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Operating Leases
2020	$ 50,164
2021	27,279
2022	5,010
2023	4,177
2024	4,217
Thereafter	5,716
Total lease payments	96,563
Less imputed interest	(4,940)
Lease liability	91,623	$ 62,300
Less current obligations	(50,164)
Long-term lease obligations	41,459
Financing Leases
2020	799
2021	517
2022	179
2023	0
2024	0
Thereafter	0
Total lease payments	1,495
Less imputed interest	(172)
Total lease obligations	1,323
Less current obligations	(799)
Long-term lease obligations	$ 524

Leases - Disclosure Under Topic

Leases - Disclosure Under Topic 840 (Details) $ in Thousands	Dec. 31, 2018USD ($)
Operating Leases
2019	$ 39,457
2020	12,009
2021	3,513
2022	3,209
2023	3,234
Thereafter	7,680
Total lease payments	69,102
Less imputed interest	(4,300)
Total lease obligations	64,802
Less current obligations	(39,457)
Long-term lease obligations	25,345
Financing Leases
2019	1,240
2020	913
2021	534
2022	455
2023	0
Thereafter	0
Total lease payments	3,142
Less imputed interest	(130)
Total lease obligations	3,012
Less current obligations	(1,240)
Long-term lease obligations	$ 1,772

Leases Leases - Maturities of O

Leases Leases - Maturities of Office Leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 50,164
2021	27,279
2022	5,010
2023	4,177
2024	4,217
Thereafter	5,716
Total lease payments	$ 96,563

Business Combinations and Div_2

Business Combinations and Divestitures (Details) $ in Thousands	Feb. 25, 2019USD ($)	Feb. 16, 2018	Feb. 17, 2017USD ($)well	Mar. 31, 2019USD ($)	Sep. 30, 2018	Jan. 31, 2019USD ($)	Jan. 31, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
Additional paid-in capital								$ 1,981,014	$ 1,924,408
Proceeds from Divestiture of Businesses								$ 21,900
Subsidiary ownership percentage								100.00%
Corporate Joint Venture | San Mateo Midstream
Business Acquisition [Line Items]
Deferred performance incentives, term		2 years			5 years
Contributions to joint venture, operating capital			$ 5,100
Commitment to pay, amount	$ 125,000
Capital expenditures incurred	$ 150,000
Subsidiary ownership percentage			51.00%
Contract agreement term	15 years
Deferred performance incentives	$ 150,000		$ 29,400			$ 14,700	$ 14,700
Five Point | Corporate Joint Venture | San Mateo Midstream
Business Acquisition [Line Items]
Subsidiary ownership percentage			49.00%
Payments to Acquire Interest in Joint Venture			$ 176,400
Proceeds from Divestiture of Interest in Joint Venture			$ 171,500
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
San Mateo Midstream | Five Point | Corporate Joint Venture
Business Acquisition [Line Items]
Subsidiary ownership percentage	49.00%
San Mateo Midstream | Matador Resources Company | Corporate Joint Venture
Business Acquisition [Line Items]
Subsidiary ownership percentage	51.00%
San Mateo Midstream | Five Point | Corporate Joint Venture
Business Acquisition [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party								$ 69,000
Additional paid-in capital								28,400
Tax impact of equity contribution								5,900
San Mateo Midstream | Matador Resources Company | Corporate Joint Venture
Business Acquisition [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party								$ 15,500
San Mateo Midstream | Property Contribution [Member] | Matador Resources Company | Corporate Joint Venture
Business Acquisition [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party				$ 1,000

Debt Credit Agreements (Details

Debt Credit Agreements (Details Textual) (Details) - USD ($)	Dec. 19, 2018	Dec. 31, 2019	Feb. 27, 2020	Feb. 26, 2020	Feb. 25, 2020	Jan. 31, 2020	Oct. 31, 2019	Jun. 30, 2019	Dec. 31, 2018	Oct. 31, 2018
Debt Instrument [Line Items]
Secured debt, percentage of mortgages used as security		80.00%
Repay deficit in agreement, period		6 months
Deferred loan costs		$ 1,600,000
Borrowings under Credit Agreement		255,000,000							$ 40,000,000
Outstanding letters of credit		46,100,000
Long-term line of credit		$ 288,000,000							$ 220,000,000
Third Amended Credit Agreement
Debt Instrument [Line Items]
Senior secured revolving credit maximum facility										$ 850,000,000
Effective interest rate		3.28%
EBITDA ratio, debt outstanding, cash and cash equivalents limit		$ 50,000,000
Debt to EBITDA ratio covenant		4
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%
San Mateo Credit Facility
Debt Instrument [Line Items]
Effective interest rate		3.55%
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										$ 500,000,000
Line of Credit | San Mateo Credit Facility
Debt Instrument [Line Items]
Senior secured revolving credit maximum facility	$ 250,000,000						$ 375,000,000	$ 325,000,000
Outstanding letters of credit		$ 16,200,000
Accordian feature, increase limit	$ 400,000,000
Deferred loan costs		2,700,000
Long-term line of credit		$ 288,000,000
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]
Senior secured revolving credit maximum facility			$ 700,000,000			$ 500,000,000
Borrowings under Credit Agreement				$ 255,000,000	$ 255,000,000
Outstanding letters of credit					$ 46,000,000
Subsequent Event | Third Amended Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity, amended			1,500,000,000
Subsequent Event | Revolving Credit Facility | Third Amended Credit Agreement
Debt Instrument [Line Items]
Line Of Credit Facility, Maximum Borrowing Capacity, Increase In Borrowing Base			$ 900,000,000
Subsequent Event | Line of Credit | San Mateo Credit Facility
Debt Instrument [Line Items]
Outstanding letters of credit				16,200,000
Long-term line of credit				$ 288,000,000
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
Interest coverage ratio	2.50

Debt Senior Unsecured Notes (De

Debt Senior Unsecured Notes (Details Textual) (Details) - USD ($)	Oct. 04, 2018	Aug. 21, 2018	Dec. 09, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 26, 2020	Feb. 25, 2020	Apr. 14, 2015
Debt Instrument [Line Items]
Senior unsecured notes payable				$ 1,039,416,000	$ 1,037,837,000
Proceeds from issuance of debt			$ 181,500,000
Loss on extinguishment of debt		$ (31,200,000)		0	31,226,000	$ 0
Long-term line of credit				288,000,000	220,000,000
Borrowings under Credit Agreement				255,000,000	$ 40,000,000
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
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
Subsequent Event
Debt Instrument [Line Items]
Borrowings under Credit Agreement							$ 255,000,000	$ 255,000,000

Debt Debt Redemption (Details)

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)

Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets
Net operating loss carryforwards	$ 119,900	$ 116,374
Percentage depletion carryover	1,467	1,624
Compensation	13,690	10,574
Lease liabilities	17,107	0
Other	9,099	7,207
Total deferred tax assets	161,263	135,779
Valuation allowance on deferred tax assets	(6,736)	(6,519)
Total deferred tax assets, net of valuation allowance	154,527	129,260
Deferred tax liabilities
Unrealized gain on derivatives	0	12,326
Property and equipment	(151,504)	(100,634)
Less than wholly-owned subsidiaries	(20,604)	(6,808)
Lease right of use assets	(17,107)	0
Other	(2,641)	(2,256)
Total deferred tax liabilities	(191,856)	(122,024)
Net deferred tax (liabilities) assets	$ (37,329)	$ 7,236

Income Taxes (Details Textual)

Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Full-cost ceiling impairment	$ 0	$ 0	$ 0
Provisional income tax		51,500
Net current income tax (benefit) provision	0	$ 455	$ 8,157
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	525,200
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 163,900

Income Taxes (Details 1)

Income Taxes (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current income tax (benefit) provision
Federal income tax	$ 0	$ (455)	$ (8,178)
State income tax	0	0	21
Net current income tax benefit	0	(455)	(8,157)
Deferred income tax provision (benefit)
Federal income tax	29,171	(20,457)	0
State income tax	6,361	13,221	0
Net deferred income tax benefit	35,532	(7,236)	0
Deferred income tax provision (benefit)
Federal tax (benefit) expense at statutory rate	33,441	61,543	45,447
State income tax	6,141	16,181	368
Permanent differences	(4,267)	(2,488)	(4,740)
AMT credit refundable	0	455	8,178
Tax Cuts and Jobs Act rate change	0	0	51,525
Change in federal valuation allowance	0	(80,003)	(101,917)
Change in state valuation allowance	217	(2,924)	1,139
Net deferred income tax benefit	35,532	(7,236)	0
Net current income tax benefit	0	(455)	(8,157)
Total income tax provision (benefit)	$ 35,532	$ (7,691)	$ (8,157)

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Capitalized stock-based compensation	$ 5	$ 4.4	$ 4.1
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	$ 5.04	$ 12.64	$ 10.49
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	4 years
Risk-free interest rate	1.46%	2.51%	1.77%
Volatility	48.52%	45.17%	47.00%
Dividend yield	0.00%	0.00%	0.00%
Estimated forfeiture rate	4.43%	2.24%	3.66%
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 month 20 days	1 year 1 month 20 days	2 years 1 month 20 days
Risk-free interest rate	1.54%	2.48%	1.98%
Volatility	32.38%	37.94%	43.60%
Dividend yield	0.00%	0.00%	0.00%
Estimated forfeiture rate	0.00%	0.00%	0.00%

Stock-Based Compensation (Det_2

Stock-Based Compensation (Details 1) shares in Thousands	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Number of options (in thousands)
Options outstanding at beginning of period (in shares) | shares	3,225
Options granted (in shares) | shares	540
Options exercised (in shares) | shares	(223)
Options forfeited (in shares) | shares	(10)
Options expired (in shares) | shares	(272)
Options outstanding at end of period (in shares) | shares	3,260
Weighted average exercise price
Weighted average exercise price, Options outstanding Beginning Balance (usd per share) | $ / shares	$ 23.48
Weighted average exercise price, Options granted (usd per share) | $ / shares	14.80
Weighted average exercise price, Options exercised (usd per share) | $ / shares	14.93
Weighted average exercise price, Options forfeited (usd per share) | $ / shares	27.91
Weighted average exercise price, Options expired (usd per share) | $ / shares	23.22
Weighted average exercise price, Options outstanding Ending Balance (usd per share) | $ / shares	$ 22.64

Stock-Based Compensation (Det_3

Stock-Based Compensation (Details 2) shares in Thousands	12 Months Ended
	Dec. 31, 2019$ / sharesshares
$9.00
Summarized information about outstanding and exercisable stock option
Shares outstanding (in shares) | shares	65
Weighted average remaining contractual price	1 month 20 days
Weighted average exercise price (usd per share)	$ 9
Shares exercisable | shares	65
Weighted average exercise price (usd per share)	$ 9
$13.22 - $15.40
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	13.22
Range of exercise prices, Upper limit	$ 15
Shares outstanding (in shares) | shares	933
Weighted average remaining contractual price	3 years 8 months 26 days
Weighted average exercise price (usd per share)	$ 14.87
Shares exercisable | shares	395
Weighted average exercise price (usd per share)	$ 14.97
$20.01 - $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	663
Weighted average remaining contractual price	2 months 12 days
Weighted average exercise price (usd per share)	$ 21.94
Shares exercisable | shares	658
Weighted average exercise price (usd per share)	$ 21.95
$25.31 - $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	1,599
Weighted average remaining contractual price	3 years 4 months 13 days
Weighted average exercise price (usd per share)	$ 28.01
Shares exercisable | shares	897
Weighted average exercise price (usd per share)	$ 27.66

Stock-Based Compensation (Det_4

Stock-Based Compensation (Details 3) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 18,505	$ 17,200	$ 16,654
Employee Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 6,400	$ 6,300	$ 7,100
Restricted Stock Service Based
Summary of non-vested stock options
Non-vested Shares, Beginning Balance (in shares)	1,356
Shares Granted (in shares)	240
Shares Vested (in shares)	(674)
Shares Forfeited (in shares)	(25)
Non-vested Shares, Ending Balance (in shares)	897	1,356
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)	$ 25.87
Weighted average fair value, Granted (usd per share)	19.36
Weighted average fair value, Vested (usd per share)	23.02
Weighted average fair value, Forfeited (usd per share)	28.39
Weighted average fair value, Ending Balance (usd per share)	$ 26.19	$ 25.87
Restricted Stock Units Service Based
Summary of non-vested stock options
Non-vested Shares, Beginning Balance (in shares)	58
Shares Granted (in shares)	100
Shares Vested (in shares)	(57)
Shares Forfeited (in shares)	(9)
Non-vested Shares, Ending Balance (in shares)	92	58
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)	$ 27.48
Weighted average fair value, Granted (usd per share)	16.06
Weighted average fair value, Vested (usd per share)	27.47
Weighted average fair value, Forfeited (usd per share)	17.31
Weighted average fair value, Ending Balance (usd per share)	$ 16.06	$ 27.48
Restricted Stock Units Performance Based
Summary of non-vested stock options
Non-vested Shares, Beginning Balance (in shares)	0
Shares Granted (in shares)	428
Shares Vested (in shares)	0
Shares Forfeited (in shares)	0
Non-vested Shares, Ending Balance (in shares)	428	0
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)	$ 0
Weighted average fair value, Granted (usd per share)	20
Weighted average fair value, Vested (usd per share)	0
Weighted average fair value, Forfeited (usd per share)	0
Weighted average fair value, Ending Balance (usd per share)	$ 20	$ 0

Stock Based Compensation (Detai

Stock Based Compensation (Details 4) - Restricted Stock Liability Based shares in Thousands	12 Months Ended
	Dec. 31, 2019shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested Shares, Beginning Balance (in shares)	0
Shares Granted (in shares)	687
Shares Vested (in shares)	0
Shares Forfeited (in shares)	(1)
Non-vested Shares, Ending Balance (in shares)	686

Stock Based Compensation (Det_2

Stock Based Compensation (Details Textual) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Feb. 28, 2019	Feb. 26, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of stock option awards outstanding (in shares)			3,260,000	3,225,000
Aggregate intrinsic value			$ 3,300
Aggregate intrinsic value exercisable			$ 1,800
Weighted average contractual term			1 year 8 months 8 days
Total intrinsic value of options exercised			$ 800	$ 7,000	$ 13,200
Tax related benefits realized from the exercise of stock options			2,800	5,700	5,000
Unrecognized compensation expense related to unvested stock options			$ 5,500
Weighted average remaining requisite service period of unvested stock awards			1 year 8 months 19 days
Fair value of option shares vested			$ 9,700	11,800	2,100
Stock-based compensation expense			18,505	17,200	16,654
Stock based long term liability			$ 100	1,100	400
Options granted (in shares)			540,000
Aggregate intrinsic value for the restricted stock and restricted stock units outstanding			$ 37,700
Aggregate intrinsic value expected to be settled in cash			12,300
Tax benefits recognized for stock based compensation			5,600	4,800	6,800
Capitalized stock-based compensation			5,000	4,400	4,100
Expensed stock-based compensation			$ 21,600	17,200	16,700
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			1 year 9 months 18 days
Unrecognized compensation expense related to unvested restricted stock and restricted stock units			$ 28,300
Unrecognized compensation expense related to unvested restricted stock expected to be settled in cash			9,100
Fair value of restricted stock and restricted stock units vested			13,600	13,000	9,900
Restricted stock or unit expenses			$ 20,200	15,300	12,900
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
Performance-Based Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares		3 years
Performance-Based Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%
Performance-Based Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%
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			$ 6,400	$ 6,300	$ 7,100
Restricted Stock Service Based [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock grants (in shares)			240,000
Restricted stock grants (in shares)			674,000
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)			65,000	67,500	75,000
2012 Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares of common stock provided (in shares)			8,700,000
2019 Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares of common stock provided (in shares)			3,433,671

Employee Benefit Plans (Details

Employee Benefit Plans (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Employee Benefit Plan (Textual) [Abstract]
Employees annual compensation	3.00%
Safe Harbor match	$ 1,400,000	$ 1,100,000	$ 900,000
Discretionary matching contributions	1,700,000	$ 1,400,000	$ 1,100,000
No additional discretionary contributions	$ 0

Equity (Details)

Equity (Details) - USD ($) $ in Thousands	May 17, 2018	Oct. 10, 2017	Mar. 11, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jun. 01, 2017	May 31, 2017
Subsidiary, Sale of Stock [Line Items]
Offering costs	$ 200	$ 300		$ 0	$ 204	$ 280
Consideration received on sale of stock			$ 226,400
Common stock, shares authorized (in shares)				160,000,000	160,000,000
Issuance cost of equity					$ 204	$ 280
Preferred shares authorized (in shares)				2,000,000
Common Stock
Subsidiary, Sale of Stock [Line Items]
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		$ 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 Instrume_3

Derivative Financial Instruments (Details) $ in Thousands	Dec. 31, 2019USD ($)bbl$ / bbl	Dec. 31, 2018USD ($)
Derivative [Line Items]
Derivative Asset (Liability), Net	$ (3,881)
Summary of contracts for oil and natural gas
Derivative liability		$ 49,846
Open costless collar contracts
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ 630
Open costless collar contracts | Oil - WTI
Derivative [Line Items]
Notional Quantity (Bbl) | bbl	7,200,000
Summary of contracts for oil and natural gas
Weighted Average Price Floor (usd per Bbl) | $ / bbl	47.69
Weighted Average Price Ceiling (usd per Bbl) | $ / bbl	66.62
Fair Value of Asset (Liability)	$ 630
Open Swap Contracts
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ (4,511)
Open Swap Contracts | Oil, Calculation Period Two
Derivative [Line Items]
Notional Quantity (Bbl) | bbl	6,480,000
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ (1,523)
Fixed price (usd per Bbl) | $ / bbl	0.82

Derivative Financial Instrume_4

Derivative Financial Instruments (Details 2) $ in Thousands	Dec. 31, 2019USD ($)bbl$ / bbl	Dec. 31, 2018USD ($)
Offsetting Derivative Assets [Abstract]
Derivative liability		$ (49,846)
Total	$ (3,881)
Derivative Asset (Liability) Subject to Master Netting Arrangement	0
Derivative Asset (Liability), Net	(3,881)
Offsetting Derivative Liabilities [Abstract]
Derivative Asset		0
Current assets
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities		53,136
Gross amounts netted in the consolidated balance sheet		3,207
Derivative liability		49,929
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets	442,291
Gross amounts netted in the consolidated balance sheets	(442,291)
Derivative Asset	0
Other Assets
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets	280,397
Gross amounts netted in the consolidated balance sheets	(280,397)
Derivative Asset	0
Long-term liabilities
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities	(282,381)	(83)
Gross amounts netted in the consolidated balance sheet	(280,397)	0
Derivative liability	(1,984)	(83)
Current liabilities
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities	(444,188)	(3,207)
Gross amounts netted in the consolidated balance sheet	(442,291)	(3,207)
Derivative liability	(1,897)	$ 0
Open Swap Contracts
Derivatives, Fair Value [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (4,511)
Open Swap Contracts | Oil, Calculation Period One [Member]
Derivatives, Fair Value [Line Items]
Notional Quantity (Bbl) | bbl	9,774,000
Fixed price (usd per Bbl) | $ / bbl	0.61
Derivative Assets (Liabilities), at Fair Value, Net	$ (2,528)
Open Swap Contracts | Oil, Calculation Period Two
Derivatives, Fair Value [Line Items]
Notional Quantity (Bbl) | bbl	6,480,000
Fixed price (usd per Bbl) | $ / bbl	0.82
Derivative Assets (Liabilities), at Fair Value, Net	$ (1,523)
Open Swap Contracts | Oil, Calculation Period Three [Member]
Derivatives, Fair Value [Line Items]
Notional Quantity (Bbl) | bbl	3,600,000
Fixed price (usd per Bbl) | $ / bbl	0.90
Derivative Assets (Liabilities), at Fair Value, Net	$ (460)

Derivative Financial Instrume_5

Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	$ 9,482	$ 2,334	$ (4,321)
Unrealized (loss) gain on derivatives	(53,727)	65,085	9,715
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	9,482	2,334	(4,321)
Unrealized (loss) gain on derivatives	(53,727)	65,085	9,715
Total	(44,245)	67,419	5,394
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	9,026	3,741	(3,657)
Unrealized (loss) gain on derivatives	(53,443)	65,991	2,638
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	456	(1,407)	(608)
Unrealized (loss) gain on derivatives	(284)	(906)	7,077
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	$ 0	$ (56)

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets (Liabilities)
Oil derivatives and basis swaps		$ 0
Natural gas derivatives		(49,846)
Total	$ (3,881)
Fair value on a recurring basis
Assets (Liabilities)
Oil derivatives and basis swaps	(3,881)	49,562
Natural gas derivatives		284
Total	(3,881)	49,846
Fair value on a recurring basis | Level 1
Assets (Liabilities)
Oil derivatives and basis swaps	0	0
Natural gas derivatives		0
Total	0	0
Fair value on a recurring basis | Level 2
Assets (Liabilities)
Oil derivatives and basis swaps	(3,881)	49,562
Natural gas derivatives		284
Total	(3,881)	49,846
Fair value on a recurring basis | Level 3
Assets (Liabilities)
Oil derivatives and basis swaps	0	0
Natural gas derivatives		0
Total	$ 0	$ 0

Fair Value Measurements (Deta_2

Fair Value Measurements (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of notes payable	$ 1,060,000,000	$ 968,900,000
Pipe and other equipment
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Impairment charge for equipments held in inventory	$ 0

Commitments and Contingencies (

Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	Feb. 25, 2019	Feb. 17, 2017	Oct. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Long-term Purchase Commitment [Line Items]
Minimum outstanding commitments				$ 26.9
Delivery Of Natural Gas And Oil Production To Third Parties
Long-term Purchase Commitment [Line Items]
Payment for other commitment				28.7	$ 20.6
Other commitment				406.8
Drilling Rig Commitments
Long-term Purchase Commitment [Line Items]
Maximum termination outstanding obligations of contracts				41.7
Short-Term Drilling Rig Commitments
Long-term Purchase Commitment [Line Items]
Maximum termination outstanding obligations of contracts				1.2
Corporate Joint Venture | San Mateo Midstream
Long-term Purchase Commitment [Line Items]
Related party transaction, contract agreement term	15 years
Contractual obligation				$ 152.9
Natural Gas Transportation Agreement
Long-term Purchase Commitment [Line Items]
Supply agreement, term			15 years
Natural Gas Transportation and Fractionation Agreement | Eddy County
Long-term Purchase Commitment [Line Items]
Supply agreement, term				7 years
Contractual obligation				$ 132.3
2019 15-Year Fixed Fee Natural Gas Transportation Agreement | Eddy County
Long-term Purchase Commitment [Line Items]
Contractual obligation			$ 106.9
Operational Agreements | San Mateo Midstream
Long-term Purchase Commitment [Line Items]
Contractual obligation	$ 363.8
Engineering, Procurement, Construction And Installation Of Processing Plant | San Mateo Midstream
Long-term Purchase Commitment [Line Items]
Contractual obligation				80.4
Payment for purchase agreement				40.1
Contractual obligation, due in next fiscal year				$ 40.3
Rustler Breaks Asset Area | Corporate Joint Venture | San Mateo Midstream
Long-term Purchase Commitment [Line Items]
Contractual obligation, term		15 years

Supplemental Disclosures (Detai

Supplemental Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Summary of current accrued liabilities
Total accrued liabilities	$ 200,695	$ 170,855
Other	12,378	9,747
Accrued evaluated and unproved and unevaluated property costs
Summary of current accrued liabilities
Total accrued liabilities	72,376	86,318
Accrued midstream properties costs
Summary of current accrued liabilities
Total accrued liabilities	46,402	16,808
Accrued lease operating expenses
Summary of current accrued liabilities
Total accrued liabilities	18,223	12,705
Accrued interest on debt
Summary of current accrued liabilities
Total accrued liabilities	18,569	22,448
Accrued asset retirement obligations
Summary of current accrued liabilities
Total accrued liabilities	619	1,350
Accrued partners’ share of joint interest charges
Summary of current accrued liabilities
Total accrued liabilities	14,322	17,037
Accrued payable related to purchased natural gas
Summary of current accrued liabilities
Total accrued liabilities	$ 17,806	$ 4,442

Supplemental Disclosures (Det_2

Supplemental Disclosures (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental disclosures of cash flow information
Cash paid for interest expense, net of amounts capitalized	$ 75,525	$ 29,474	$ 32,760
Increase in asset retirement obligations related to mineral properties	2,912	2,614	4,385
Increase (decrease) in asset retirement obligations related to midstream properties	1,204	686	(60)
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures	(15,877)	(16,802)	48,929
Increase (decrease) in liabilities for midstream properties capital expenditures	30,374	2,499	(955)
Stock-based compensation expense (benefit) recognized as liability	3,170	(1,069)	362
Decrease in liabilities for accrued cost to issue equity	0	0	(343)
Increase in liabilities for accrued cost to issue senior notes	0	232	0
Transfer of inventory from (to) oil and natural gas properties	1,515	409	(374)
Transfer of inventory to midstream properties	$ 0	$ 0	$ (317)

Supplemental Disclosures Supple

Supplemental Disclosures Supplemental Disclosures (Details 2) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Disclosures [Abstract]
Cash	$ 40,024	$ 64,545	$ 96,505
Restricted cash	25,104	19,439	5,977
Total cash and restricted cash	$ 65,128	$ 83,984	$ 102,482	$ 214,142

Segment Reporting (Details)

Segment Reporting (Details)	12 Months Ended
	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of business segments | segment	2
Revenues	$ 1,026,204,000	$ 829,691,000
Lease bonus - mineral acreage	1,711,000	2,489,000	$ 0
Realized gain on derivatives	9,482,000	2,334,000	(4,321,000)
Unrealized gain on derivatives	(53,727,000)	65,085,000	9,715,000
Expenses	748,190,000	536,328,000	383,435,000
Operating income	235,480,000	363,271,000	160,841,000
Assets	4,069,676,000	3,455,518,000	2,145,690,000
Capital expenditures	946,025,000	1,504,659,000	872,958,000
Depletion, depreciation and amortization	350,540,000	265,142,000	177,502,000
Income (loss) attributable to noncontrolling interest	35,205,000	25,557,000	12,140,000
Impairment charge of net capitalized costs	0	0	0
Other (expense) income	(2,126,000)	1,551,000	3,551,000
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	158,514,000	292,073,000	129,850,000
Total income tax provision	35,532,000	(7,691,000)	(8,157,000)
Net (loss) income	122,982,000	299,764,000	138,007,000
Net Income (Loss) Attributable to Parent	87,777,000	274,207,000	125,867,000
Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	1,711,000	2,489,000
Realized gain on derivatives	9,482,000	2,334,000	(4,321,000)
Unrealized gain on derivatives	(53,727,000)	65,085,000	9,715,000
Expenses	621,687,000	487,539,000	333,923,000
Operating income	226,708,000	377,532,000	197,333,000
Assets	3,360,725,000	2,910,326,000	1,768,393,000
Capital expenditures	718,712,000	1,335,690,000	753,157,000
Depletion, depreciation and amortization	331,700,000	252,300,000	170,500,000
Payments to acquire productive assets		656,900,000
Operating Segments | Midstream
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	0	0
Realized gain on derivatives	0	0	0
Unrealized gain on derivatives	0	0	0
Expenses	130,612,000	44,098,000	23,420,000
Operating income	81,506,000	55,247,000	26,439,000
Assets	647,937,000	439,953,000	257,871,000
Capital expenditures	223,612,000	166,407,000	114,113,000
Depletion, depreciation and amortization	16,100,000	10,500,000	5,200,000
Income (loss) attributable to noncontrolling interest	35,200,000	25,600,000	12,100,000
Land and seismic acquisition expenditures	48,300,000
Payments to acquire productive assets	145,400,000	80,200,000	54,900,000
Corporate
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	0	0
Realized gain on derivatives	0	0	0
Unrealized gain on derivatives	0	0	0
Expenses	72,734,000	69,508,000	62,931,000
Operating income	(72,734,000)	(69,508,000)	(62,931,000)
Assets	61,014,000	105,239,000	119,426,000
Capital expenditures	3,701,000	2,562,000	5,688,000
Depletion, depreciation and amortization	2,700,000	2,400,000	1,700,000
Consolidations and Eliminations
Segment Reporting Information [Line Items]
Lease bonus - mineral acreage	0	0
Realized gain on derivatives	0	0	0
Unrealized gain on derivatives	0	0	0
Expenses	(76,843,000)	(64,817,000)	(36,839,000)
Operating income	0	0	0
Assets	0	0	0
Capital expenditures	0	0	0
Oil and natural gas revenues
Segment Reporting Information [Line Items]
Revenues	892,325,000	800,700,000	528,684,000
Oil and natural gas revenues | Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Revenues	886,127,000	794,261,000	525,862,000
Oil and natural gas revenues | Operating Segments | Midstream
Segment Reporting Information [Line Items]
Revenues	6,198,000	6,439,000	2,822,000
Oil and natural gas revenues | Corporate
Segment Reporting Information [Line Items]
Revenues	0	0	0
Oil and natural gas revenues | Consolidations and Eliminations
Segment Reporting Information [Line Items]
Revenues	0	0	0
Third-party midstream services revenues
Segment Reporting Information [Line Items]
Revenues	59,110,000	21,920,000	10,198,000
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	135,953,000	86,737,000	47,037,000
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	(76,843,000)	(64,817,000)	(36,839,000)
Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenues	74,769,000	7,071,000	$ 0
Sales of purchased natural gas | Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Revenues	4,802,000	902,000
Sales of purchased natural gas | Operating Segments | Midstream
Segment Reporting Information [Line Items]
Revenues	69,967,000	6,169,000
Sales of purchased natural gas | Corporate
Segment Reporting Information [Line Items]
Revenues	0	0
Sales of purchased natural gas | Consolidations and Eliminations
Segment Reporting Information [Line Items]
Revenues	$ 0	$ 0

Subsidiary Guarantors Consolida

Subsidiary Guarantors Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	$ 0	$ 0
Current assets	278,492	305,685
Net property and equipment	3,699,595	3,122,864
Investment in subsidiaries	0	0
Long-term assets	91,589	26,969
Total assets	4,069,676	3,455,518	$ 2,145,690
Intercompany payable	0	0
Current liabilities	399,772	330,022
Senior unsecured notes payable	1,039,416	1,037,837
Other long-term liabilities	661,036	308,002
Total shareholders' equity	1,833,654	1,688,880
Non-controlling interest in subsidiaries	135,798	90,777
Total liabilities and shareholders’ equity	$ 4,069,676	3,455,518
Subsidiary ownership percentage	100.00%
Eliminating Entries
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	$ (1,607,350)	(1,274,221)
Current assets	0	0
Net property and equipment	0	0
Investment in subsidiaries	(1,476,934)	(1,585,747)
Long-term assets	(10,532)	(9,502)
Total assets	(3,094,816)	(2,869,470)
Intercompany payable	(1,607,350)	(1,274,221)
Current liabilities	(909)	(724)
Senior unsecured notes payable	0	0
Other long-term liabilities	(9,623)	(8,778)
Total shareholders' equity	(1,476,934)	(1,585,747)
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	(3,094,816)	(2,869,470)
Matador | Reportable Legal Entities
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	1,578,133	1,244,405
Current assets	29	4,109
Net property and equipment	0	0
Investment in subsidiaries	1,332,237	1,490,401
Long-term assets	0	23,897
Total assets	2,910,399	2,762,812
Intercompany payable	0	0
Current liabilities	0	22,874
Senior unsecured notes payable	1,039,416	1,037,837
Other long-term liabilities	37,329	13,221
Total shareholders' equity	1,833,654	1,688,880
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	2,910,399	2,762,812
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	29,217	29,816
Current assets	37,933	34,027
Net property and equipment	583,899	379,052
Investment in subsidiaries	0	0
Long-term assets	3,072	1,479
Total assets	654,121	444,374
Intercompany payable	0	0
Current liabilities	73,086	27,988
Senior unsecured notes payable	0	0
Other long-term liabilities	300,540	230,263
Total shareholders' equity	144,697	95,346
Non-controlling interest in subsidiaries	135,798	90,777
Total liabilities and shareholders’ equity	654,121	444,374
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	0	0
Current assets	240,530	267,549
Net property and equipment	3,115,696	2,743,812
Investment in subsidiaries	144,697	95,346
Long-term assets	99,049	11,095
Total assets	3,599,972	3,117,802
Intercompany payable	1,607,350	1,274,221
Current liabilities	327,595	279,884
Senior unsecured notes payable	0	0
Other long-term liabilities	332,790	73,296
Total shareholders' equity	1,332,237	1,490,401
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	$ 3,599,972	$ 3,117,802

Subsidiary Guarantors Consoli_2

Subsidiary Guarantors Consolidated Income Statement (Details) - USD ($) $ in Thousands	Aug. 21, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Income Statements, Captions [Line Items]
Total revenues		$ 983,670	$ 899,599	$ 544,276
Total expenses		748,190	536,328	383,435
Operating income		235,480	363,271	160,841
Net loss on asset sales and inventory impairment		(967)	(196)	23
Interest expense		(73,873)	(41,327)	(34,565)
Prepayment Premium On Extinguishment Of Debt		0	(31,226)	0
Prepayment penalty on extinguishment of debt	$ 31,200	0	(31,226)	0
Other income (expense)		(2,126)	1,551	3,551
Earnings in subsidiaries		0	0	0
Income before income taxes		158,514	292,073	129,850
Total income tax provision		35,532	(7,691)	(8,157)
Net income attributable to non-controlling interest in subsidiaries		(35,205)	(25,557)	(12,140)
Net income		87,777	274,207	125,867
Eliminating Entries
Condensed Income Statements, Captions [Line Items]
Total revenues		(74,719)	(64,791)	(35,115)
Total expenses		(74,719)	(64,791)	(35,115)
Operating income		0	0	0
Net loss on asset sales and inventory impairment		0	0	0
Interest expense		0	0	0
Prepayment Premium On Extinguishment Of Debt			0
Other income (expense)		0	0	0
Earnings in subsidiaries		(223,087)	(369,707)	(171,840)
Income before income taxes		(223,087)	(369,707)	(171,840)
Total income tax provision		0	0	0
Net income attributable to non-controlling interest in subsidiaries		0	0	0
Net income		(223,087)	(369,707)	(171,840)
Matador | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total revenues		0	0	0
Total expenses		(1,458)	4,935	5,610
Operating income		1,458	(4,935)	(5,610)
Net loss on asset sales and inventory impairment		0	0	0
Interest expense		(64,591)	(40,994)	(34,565)
Prepayment Premium On Extinguishment Of Debt			(31,226)
Other income (expense)			565	27
Earnings in subsidiaries		186,442	343,106	157,589
Income before income taxes		123,309	266,516	117,441
Total income tax provision		35,532	(7,691)	(8,426)
Net income attributable to non-controlling interest in subsidiaries		0	0	0
Net income		87,777	274,207	125,867
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total revenues		209,887	98,665	47,883
Total expenses		128,758	46,236	21,260
Operating income		81,129	52,429	26,623
Net loss on asset sales and inventory impairment		0	0	0
Interest expense		(9,282)	(333)	0
Prepayment Premium On Extinguishment Of Debt			0
Other income (expense)		3	62	37
Earnings in subsidiaries		0	0	0
Income before income taxes		71,850	52,158	26,660
Total income tax provision		0	0	269
Net income attributable to non-controlling interest in subsidiaries		(35,205)	(25,557)	(12,140)
Net income		36,645	26,601	14,251
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total revenues		848,502	865,725	531,508
Total expenses		695,609	549,948	391,680
Operating income		152,893	315,777	139,828
Net loss on asset sales and inventory impairment		(967)	(196)	23
Interest expense		0	0	0
Prepayment Premium On Extinguishment Of Debt			0
Other income (expense)		(2,129)	924	3,487
Earnings in subsidiaries		36,645	26,601	14,251
Income before income taxes		186,442	343,106	157,589
Total income tax provision		0	0	0
Net income attributable to non-controlling interest in subsidiaries		0	0	0
Net income		$ 186,442	$ 343,106	$ 157,589

Subsidiary Guarantors Consoli_3

Subsidiary Guarantors Consolidated Cash Flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 552,042	$ 608,523	$ 299,125
Net cash used in investing activities	(903,976)	(1,515,253)	(819,284)
Net cash provided by financing activities	333,078	888,232	408,499
Decrease in cash and restricted cash	(18,856)	(18,498)	(111,660)
Cash and restricted cash at beginning of year	83,984	102,482	214,142
Cash and restricted cash at end of year	65,128	83,984	102,482
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	(16,628)	(42,330)	(106,595)
Net cash provided by financing activities	16,628	42,330	106,595
Decrease 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	(427)	(657,860)	(307,982)
Net cash used in investing activities	0	0	33
Net cash provided by financing activities	0	658,030	208,440
Decrease in cash and restricted cash	(427)	170	(99,509)
Cash and restricted cash at beginning of year	456	286	99,795
Cash and restricted cash at end of year	29	456	286
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	106,650	35,119	21,308
Net cash used in investing activities	(188,893)	(162,147)	(114,852)
Net cash provided by financing activities	88,059	140,205	96,307
Decrease in cash and restricted cash	5,816	13,177	2,763
Cash and restricted cash at beginning of year	18,840	5,663	2,900
Cash and restricted cash at end of year	24,656	18,840	5,663
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	445,819	1,231,264	585,799
Net cash used in investing activities	(698,455)	(1,310,776)	(597,870)
Net cash provided by financing activities	228,391	47,667	(2,843)
Decrease in cash and restricted cash	(24,245)	(31,845)	(14,914)
Cash and restricted cash at beginning of year	64,688	96,533	111,447
Cash and restricted cash at end of year	$ 40,443	$ 64,688	$ 96,533