UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

_________________________________________________________



☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June 30, 2019~~March 31, 2020



☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-35410

_________________________________________________________

Matador Resources Company

(Exact name of registrant as specified in its charter)

_________________________________________________________



	Texas			27-4662601
	(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

5400 LBJ Freeway,			Suite 1500	75240
	Dallas,	Texas		75240
	(Address of principal executive offices)			(Zip Code)

(972) 371-5200

(Registrant’s telephone number, including area code)

_________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	MTDR	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

As of ~~July 31, 2019,~~April 28, 2020, there were ~~116,646,526~~116,557,234 shares of the registrant’s common ~~stock,~~stock, par value $0.01 per share, outstanding.

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED ~~JUNE 30, 2019~~MARCH 31, 2020

TABLE OF CONTENTS



	Page
PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements — Unaudited	3
Condensed Consolidated Balance Sheets at ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019	3
Condensed Consolidated Statements of Operations for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	4
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	5
Condensed Consolidated Statements of Cash Flows for the ~~Six~~Three Months Ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2519
Item 3. Quantitative and Qualitative Disclosures About Market Risk	4236
Item 4. Controls and Procedures	4237
PART II — OTHER INFORMATION	4338
Item 1. Legal Proceedings	4338
Item 1A. Risk Factors	4338
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4339
Item 6. Exhibits	4440
SIGNATURES	4541

Part I — FINANCIAL INFORMATION

Item 1. Financial Statements — Unaudited

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS — UNAUDITED

(In thousands, except par value and share data)


	June 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019
ASSETS
Current assets
Cash	$	59,950		$	64,545		$	27,063		$	40,024
Restricted cash	24,812			19,439			29,732			25,104
Accounts receivable
Oil and natural gas revenues	66,921			68,161			52,879			95,228
Joint interest billings	61,872			61,831			70,318			67,546
Other	18,386			16,159			30,592			26,639
Derivative instruments	8,271			49,929			121,179			—
Lease and well equipment inventory	20,281			17,564			11,638			10,744
Prepaid expenses and other assets	12,891			8,057
Prepaid expenses and other current assets							13,234			13,207
Total current assets	273,384			305,685			356,635			278,492
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	4,094,417			3,780,236			4,724,293			4,557,265
Unproved and unevaluated	1,234,176			1,199,511			1,169,751			1,126,992
Midstream properties	492,420			428,025			711,863			643,903
Other property and equipment	25,170			22,041			27,640			27,021
Less accumulated depletion, depreciation and amortization	(2,462,840		)	(2,306,949		)	(2,746,314		)	(2,655,586		)
Net property and equipment	3,383,343			3,122,864			3,887,233			3,699,595
Other assets
Derivative instruments	2,202			—			11,371			—
Deferred income taxes	7,149			20,457
Other assets	85,373			6,512
Other long-term assets							78,432			91,589
Total other assets	94,724			26,969			89,803			91,589
Total assets	$	3,751,451		$	3,455,518		$	4,333,671		$	4,069,676
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	19,821		$	66,970		$	17,659		$	25,230
Accrued liabilities	191,608			170,855			197,305			200,695
Royalties payable	66,130			64,776			85,577			85,193
Amounts due to affiliates	10,200			13,052			234			19,606
Derivative instruments							—			1,897
Advances from joint interest owners	4,725			10,968			11,240			14,837
Amounts due to joint ventures	1,588			2,373			—			486
Other current liabilities	42,703			1,028			47,883			51,828
Total current liabilities	336,775			330,022			359,898			399,772
Long-term liabilities
Borrowings under Credit Agreement	205,000			40,000			315,000			255,000
Borrowings under San Mateo Credit Facility	240,000			220,000			307,500			288,000
Senior unsecured notes payable	1,038,625			1,037,837			1,039,811			1,039,416
Asset retirement obligations	30,686			29,736			37,118			35,592
Derivative instruments	189			83			—			1,984
Deferred income taxes	14,845			13,221			84,700			37,329
Other long-term liabilities	44,728			4,962			35,264			43,131
Total long-term liabilities	1,574,073			1,345,839			1,819,393			1,700,452
Commitments and contingencies (Note 10)
Commitments and contingencies (Note 9)
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 shares authorized; 116,866,013 and 116,374,503 shares issued; and 116,647,704 and 116,353,590 shares outstanding, respectively	1,169			1,164
Common stock - $0.01 par value, 160,000,000 shares authorized; 116,671,325 and 116,644,246 shares issued; and 116,564,598 and 116,642,899 shares outstanding, respectively							1,167			1,166
Additional paid-in capital	1,955,504			1,924,408			2,014,246			1,981,014
Accumulated deficit	(216,472		)	(236,277		)	(22,771		)	(148,500		)
Treasury stock, at cost, 218,309 and 20,913 shares, respectively	(3,724		)	(415		)
Treasury stock, at cost, 106,727 and 1,347 shares, respectively							(1,293		)	(26		)
Total Matador Resources Company shareholders’ equity	1,736,477			1,688,880			1,991,349			1,833,654
Non-controlling interest in subsidiaries	104,126			90,777			163,031			135,798
Total shareholders’ equity	1,840,603			1,779,657			2,154,380			1,969,452
Total liabilities and shareholders’ equity	$	3,751,451		$	3,455,518		$	4,333,671		$	4,069,676

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS — UNAUDITED

(In thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Revenues
Oil and natural gas revenues	$	211,060		$	209,019		$	404,329		$	390,973		$	197,914		$	193,269
Third-party midstream services revenues	14,359			3,407			26,197			6,475			15,830			11,838
Sales of purchased natural gas	8,963			—			20,194			—			10,544			11,231
Realized gain (loss) on derivatives	1,165			(2,488		)	4,435			(6,746		)
Realized gain on derivatives													10,867			3,270
Unrealized gain (loss) on derivatives	6,157			1,429			(39,562		)	11,845			136,430			(45,719		)
Total revenues	241,704			211,367			415,593			402,547			371,585			173,889
Expenses
Production taxes, transportation and processing	21,542			20,110			41,207			37,901			21,716			19,665
Lease operating	26,351			25,006			57,514			47,154			30,910			31,163
Plant and other midstream services operating	8,422			5,676			17,738			9,896			9,964			9,316
Purchased natural gas	8,172			—			18,806			—			8,058			10,634
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207			90,707			76,866
Accretion of asset retirement obligations	420			375			834			739			476			414
General and administrative	19,876			19,369			38,166			37,295			16,222			18,290
Total expenses	164,915			137,374			331,264			255,192			178,053			166,348
Operating income	76,789			73,993			84,329			147,355			193,532			7,541
Other income (expense)
Inventory impairment	(368		)	—			(368		)	—
Interest expense	(18,068		)	(8,004		)	(35,997		)	(16,495		)	(19,812		)	(17,929		)
Other expense	(423		)	(352		)	(532		)	(299		)
Other income (expense)													1,320			(110		)
Total other expense	(18,859		)	(8,356		)	(36,897		)	(16,794		)	(18,492		)	(18,039		)
Income before income taxes	57,930			65,637			47,432			130,561
Income tax provision
Income (loss) before income taxes													175,040			(10,498		)
Income tax provision (benefit)
Deferred	12,858			—			11,845			—			39,957			(1,013		)
Total income tax provision	12,858			—			11,845			—
Net income	45,072			65,637			35,587			130,561
Total income tax provision (benefit)													39,957			(1,013		)
Net income (loss)													135,083			(9,485		)
Net income attributable to non-controlling interest in subsidiaries	(8,320		)	(5,831		)	(15,782		)	(10,861		)	(9,354		)	(7,462		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700
Earnings per common share
Net income (loss) attributable to Matador Resources Company shareholders													$	125,729		$	(16,947	)
Earnings (loss) per common share
Basic	$	0.32		$	0.53		$	0.17		$	1.08		$	1.08		$	(0.15	)
Diluted	$	0.31		$	0.53		$	0.17		$	1.08		$	1.08		$	(0.15	)
Weighted average common shares outstanding
Basic	116,571			112,706			116,469			110,809			116,607			115,315
Diluted	116,903			113,056			116,839			111,280			116,684			115,315

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(In thousands)

For the Three Months Ended March 31, 2020



														Total shareholders’ equity attributable to Matador Resources Company


																	Non-controlling interest in subsidiaries			Total shareholders’ equity
	Common Stock			Additional paid-in capital			Accumulated deficit			Treasury Stock
	Shares	Amount		Additional paid-in capital			Accumulated deficit			Shares	Amount
Balance at January 1, 2020	116,644	$	1,166	$	1,981,014		$	(148,500	)	1	$	(26	)	$	1,833,654		$	135,798		$	1,969,452
Issuance of common stock pursuant to employee stock compensation plan	3	—		—			—			—	—			—			—			—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	2	—		—			—			—	—			—			—			—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		5,066			—			—	—			5,066			—			5,066
Stock options exercised, net of options forfeited in net share settlements	—	—		(24		)	—			—	—			(24		)	—			(24		)
Liability-based stock option awards settled in equity	22	1		297			—			—	—			298			—			298
Restricted stock forfeited	—	—		—			—			106	(1,267		)	(1,267		)	—			(1,267		)
Contribution related to formation of San Mateo I, net of tax of $3.1 million (see Note 6)	—	—		11,613			—			—	—			11,613			—			11,613
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $4.3 million (see Note 6)	—	—		16,280			—			—	—			16,280			29,394			45,674
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—			—			—	—			—			(11,515		)	(11,515		)
Current period net income	—	—		—			125,729			—	—			125,729			9,354			135,083
Balance at March 31, 2020	116,671	$	1,167	$	2,014,246		$	(22,771	)	107	$	(1,293	)	$	1,991,349		$	163,031		$	2,154,380

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(In thousands)

For the Three ~~and~~ ~~Six~~ Months Ended ~~June 30,~~March 31, 2019


																			Total shareholders’ equity attributable to Matador Resources Company																																	Total shareholders’ equity attributable to Matador Resources Company


																						Non-controlling interest in subsidiaries				Total shareholders’ equity																													Non-controlling interest in subsidiaries				Total shareholders’ equity
	Common Stock			Additional paid-in capital				Accumulated deficit				Treasury Stock													Common Stock							Additional paid-in capital				Accumulated deficit				Treasury Stock
	Shares	Amount					Shares	Accumulated deficit					Amount				Total shareholders’ equity attributable to Matador Resources Company	Non-controlling interest in subsidiaries							Shares					Amount									Shares			Amount				Total shareholders’ equity attributable to Matador Resources Company	Non-controlling interest in subsidiaries
Balance at January 1, 2019	116,375	$	1,164	Additional paid-in capital		$	1,924,408			$	(236,277	)		21							$	(415	)		$				1,688,880		$	Additional paid-in capital	90,777		$	Accumulated deficit		1,779,657		116,375			$	1,164					$	1,924,408			$	(236,277	)		21			$	(415	)	$	1,688,880	$	90,777	$	1,779,657
Issuance of common stock pursuant to employee stock compensation plan	6	—		—				—				—			—							—			—			—			6			—				—				—						—			—				—			—			—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	3	—		—				—				—			—						—			—					—			3			—				—				—					—			—				—			—				—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		5,802				—				—			—						5,802			—				5,802			—			—				5,802				—					—			—				5,802			—				5,802
Stock options exercised, net of options forfeited in net share settlements	210	2		3,109				—				—			—					3,111			—				3,111			210			2				3,109				—				—				—				3,111			—				3,111
Restricted stock forfeited	—	—		—				—				184			(3,170		)		(3,170		)		—				(3,170		)	—			—				—				—				184			(3,170		)		(3,170		)		—				(3,170		)
Contribution related to formation of San Mateo I, net of tax of $3.1 million (see Note 7)	—	—		11,613				—				—			—				11,613				—				11,613
Contribution of property related to formation of San Mateo II (see Note 7)	—	—		(506		)		—				—			—				(506		)		506				—
Contribution related to formation of San Mateo I, net of tax of $3.1 million (see Note 6)																														—			—				11,613				—				—			—				11,613				—				11,613
Contribution of property related to formation of San Mateo II (see Note 6)																														—			—				(506		)		—				—			—				(506		)		506				—
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		2,040				—				—			—				2,040				10,291				12,331			—			—				2,040				—				—			—				2,040				10,291				12,331
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—				—				—			—				—				(8,330		)		(8,330		)	—			—				—				—				—			—				—				(8,330		)		(8,330		)
Current period net (loss) income	—	—		—				(16,947		)		—			—				(16,947		)		7,462				(9,485		)	—			—				—				(16,947		)		—			—				(16,947		)		7,462				(9,485		)
Balance at March 31, 2019	116,594	1,166		1,946,466				(253,224		)		205			(3,585		)		1,690,823				100,706				1,791,529			116,594			$	1,166			$	1,946,466			$	(253,224	)		205			$	(3,585	)		$	1,690,823			$	100,706			$	1,791,529
Issuance of common stock pursuant to employee stock compensation plan	220	2		(2		)		—				—			—				—				—				—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	42	1		(1		)		—				—			—				—				—				—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		5,762				—				—			—				5,762				—				5,762
Stock options exercised, net of options forfeited in net share settlements	10	—		189				—				—			—				189				—				189
Restricted stock forfeited	—	—		—				—				13			(139		)		(139		)		—				(139		)
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		3,090				—				—			—				3,090				4,410				7,500
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—				—				—			—				—				(9,310		)		(9,310		)
Current period net income	—	—		—				36,752				—			—				36,752				8,320				45,072
Balance at June 30, 2019	116,866	$	1,169	$	1,955,504			$	(216,472	)		218			$	(3,724	)		$	1,736,477			$	104,126			$	1,840,603

~~Matador Resources Company and Subsidiaries~~

~~CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED~~

~~(in thousands)~~

~~For the Three and Six Months Ended June 30, 2018~~

Total shareholders’ equity attributable to Matador Resources Company

Non-controlling interest in subsidiaries Total shareholders’ equity
Common Stock Additional
paid-in capital Accumulated deficit Treasury Stock
Shares Amount Shares
Amount

Balance at January 1, 2018 108,514
$ 1,085
$ 1,666,024
$ (510,484 ) 3
$ (69 ) $ 1,156,556
$ 100,990
$ 1,257,546
Issuance of common stock pursuant to employee stock compensation plan 697
7
(7 ) —
—
—
—
—
—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan 6
1
(1 ) —
—
—
—
—
—
Stock-based compensation expense related to equity-based awards including amounts capitalized —
—
5,390
—
—
—
5,390
—
5,390
Stock options exercised, net of options forfeited in net share settlements 130
1
(1,918 ) —
—
—
(1,917 ) —
(1,917 )
Restricted stock forfeited —
—
—
—
82
(2,377 ) (2,377 ) —
(2,377 )
Contributions related to formation of San Mateo I (see Note 7) —
—
14,700
—
—
—
14,700
—
14,700
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries —
—
—
—
—
—
—
29,400
29,400
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries
—
—
—
—
—
—
—
(4,900 ) (4,900 )
Current period net income —
—
—
59,894
—
—
59,894
5,030
64,924
Balance at March 31, 2018 109,347
1,094
1,684,188
(450,590 ) 85
(2,446 ) 1,232,246
130,520
1,362,766
Issuance of common stock pursuant to employee stock compensation plan 20
—
—
—
—
—
—
—
—
Issuance of common stock 7,000
70
226,542
—
—
—
226,612
—
226,612
Cost to issue equity —
—
(146 ) —
—
—
(146 ) —
(146 )
Issuance of common stock pursuant to directors’ and advisors’ compensation plan 70
—
—
—
—
—
—
—
—
Stock-based compensation expense related to equity-based awards including amounts capitalized —
—
5,937
—
—
—
5,937
—
5,937
Stock options exercised, net of options forfeited in net share settlements 24
1
300
—
—
—
301
—
301
Restricted stock forfeited —
—
—
—
18
(224 ) (224 ) —
(224 )
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries —
—
—
—
—
—
—
24,500
24,500
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries
—
—
—
—
—
—
—
(5,635 ) (5,635 )
Current period net income —
—
—
59,806
—
—
59,806
5,831
65,637
Balance at June 30, 2018 116,461
$ 1,165
$ 1,916,821
$ (390,784 ) 103
$ (2,670 ) $ 1,524,532
$ 155,216
$ 1,679,748

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS — UNAUDITED

(In thousands)


	Six Months Ended June 30,						Three Months Ended March 31,
	2019			2018			2020			2019
Operating activities
Net income	$	35,587		$	130,561
Adjustments to reconcile net income to net cash provided by operating activities
Unrealized loss (gain) on derivatives	39,562			(11,845		)
Net income (loss)							$	135,083		$	(9,485	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives							(136,430		)	45,719
Depletion, depreciation and amortization	156,999			122,207			90,707			76,866
Accretion of asset retirement obligations	834			739			476			414
Stock-based compensation expense	9,076			8,945			3,794			4,587
Deferred income tax provision	11,845			—
Deferred income tax provision (benefit)							39,957			(1,013		)
Amortization of debt issuance cost	1,189			411			684			643
Inventory impairment	368			—
Changes in operating assets and liabilities
Accounts receivable	(378		)	(9,321		)	36,342			(3,873		)
Lease and well equipment inventory	(3,456		)	(8,611		)	(1,296		)	(1,465		)
Prepaid expenses	(4,834		)	(2,167		)
Other assets	(415		)	(149		)
Prepaid expenses and other current assets							174			(936		)
Other long-term assets							1,749			9,809
Accounts payable, accrued liabilities and other current liabilities	(48,746		)	(883		)	(58,562		)	(41,621		)
Royalties payable	1,353			8,393			384			(7,500		)
Advances from joint interest owners	(6,243		)	16,025			(3,598		)	(6,297		)
Other long-term liabilities	1,756			(97		)	(92		)	(6,608		)
Net cash provided by operating activities	194,497			254,208			109,372			59,240
Investing activities
Oil and natural gas properties capital expenditures	(349,915		)	(421,595		)	(173,994		)	(182,288		)
Midstream capital expenditures	(64,106		)	(78,302		)	(73,439		)	(33,340		)
Expenditures for other property and equipment	(2,206		)	(1,258		)	(787		)	(807		)
Proceeds from sale of assets	21,533			7,593			—			1,555
Net cash used in investing activities	(394,694		)	(493,562		)	(248,220		)	(214,880		)
Financing activities
Repayments of borrowings	—			(45,000		)
Borrowings under Credit Agreement	165,000			45,000			60,000			100,000
Borrowings under San Mateo Credit Facility	20,000			—			19,500			—
Cost to amend credit facilities	(415		)	—
Proceeds from issuance of common stock	—			226,612
Cost to issue equity	—			(73		)
Cost to amend Credit Agreement							(660		)	—
Proceeds from stock options exercised	3,298			464			45			3,150
Contributions related to formation of San Mateo I	14,700			14,700			14,700			14,700
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	19,831			53,900			50,000			12,330
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(17,640		)	(10,535		)	(11,515		)	(8,330		)
Taxes paid related to net share settlement of stock-based compensation	(3,309		)	(4,683		)	(1,336		)	(3,208		)
Cash paid under financing lease obligations	(490		)	—			(219		)	(274		)
Net cash provided by financing activities	200,975			280,385			130,515			118,368
Increase in cash and restricted cash	778			41,031
Decrease in cash and restricted cash							(8,333		)	(37,272		)
Cash and restricted cash at beginning of period	83,984			102,482			65,128			83,984
Cash and restricted cash at end of period	$	84,762		$	143,513		$	56,795		$	46,712

Supplemental disclosures of cash flow information (Note 11)
Supplemental disclosures of cash flow information (Note 10)

The accompanying notes are an integral part of these financial statements.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest ~~Louisiana and East Texas.~~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.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates

The interim unaudited condensed consolidated financial statements of the Company have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 filed with the SEC on March ~~1, 2019~~2, 2020 (the “Annual Report”). 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 accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all normal, recurring adjustments that are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of ~~June 30, 2019.~~March 31, 2020. Amounts as of December 31, ~~2018~~2019 are derived from the Company’s audited consolidated financial statements included in the Annual Report. ~~Certain reclassifications have been made to the December 31, 2018 financial statement amounts in order to conform them to the June 30, 2019 presentations.~~

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 and the reported amounts of revenues and expenses during the reporting period. The Company’s interim unaudited condensed 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 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. 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~~Revenues

~~Leases.~~ ~~During~~The following table summarizes the ~~first quarter of~~Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the three months ended March 31, 2020 and 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 3 for additional disclosures related to leases.(in thousands).



	Three Months Ended March 31,
	2020		2019
Revenues from contracts with customers	$	224,288	$	216,338
Realized gain on derivatives	10,867		3,270
Unrealized gain (loss) on derivatives	136,430		(45,719		)
Total revenues	$	371,585	$	173,889

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The adoption of these ASUs resulted in the Company recording in the condensed 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 condensed 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 condensed consolidated financial statements.

~~Revenues~~

The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the three and six months ended June 30, 2019 and 2018 (in thousands).

Three Months Ended
June 30, Six Months Ended
June 30,
2019 2018 2019 2018
Revenues from contracts with customers $ 234,382
$ 212,426
$ 450,720
$ 397,448
Realized gain (loss) on derivatives 1,165
(2,488 ) 4,435
(6,746 )
Unrealized gain (loss) on derivatives 6,157
1,429
(39,562 ) 11,845
Total revenues $ 241,704
$ 211,367
$ 415,593
$ 402,547


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
Oil revenues	$	189,085	$	166,271	$	343,288	$	314,430	$	169,585	$	154,204
Natural gas revenues	21,975		42,748		61,041		76,543		28,329		39,065
Third-party midstream services revenues	14,359		3,407		26,197		6,475		15,830		11,838
Sales of purchased natural gas	8,963		—		20,194		—		10,544		11,231
Total revenues from contracts with customers	$	234,382	$	212,426	$	450,720	$	397,448	$	224,288	$	216,338

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter that determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For ~~both~~ the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and 2019, ~~and 2018,~~ the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and, as a result, no0 impairment charge was necessary.

The Company capitalized approximately ~~$8.4~~$8.2 million and ~~$6.8~~$8.4 million of its general and administrative costs and approximately ~~$2.6~~$1.4 million and ~~$2.6~~$1.6 million of its interest expense for the three months ended ~~June 30,~~March 31, 2020 and 2019, ~~and 2018,~~ respectively. The Company capitalized approximately $16.8 million and $14.1 million of its general and administrative costs and approximately $4.2 million and $4.5 million of its interest expense for the six months ended June 30, 2019 and 2018, respectively.

~~Table of Contents~~

~~Matador Resources Company and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

~~NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued~~

Earnings (Loss) Per Common Share

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

The following table sets forth the computation of diluted weighted average common shares outstanding for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~ (in thousands).


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended March 31,
	2019	2018	2019	2018	2020	2019
Weighted average common shares outstanding
Basic	116,571	112,706	116,469	110,809	116,607	115,315
Dilutive effect of options and restricted stock units	332	350	370	471	77	—
Diluted weighted average common shares outstanding	116,903	113,056	116,839	111,280	116,684	115,315

A total of ~~2.8~~2.7 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for ~~both~~ the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 because their effects were anti-dilutive. A total of 2.8 million options to purchase shares of Matador’s common stock and 0.4 million restricted stock units were excluded from the diluted weighted average common shares outstanding for the three months ended March 31, 2019 because their effects were anti-dilutive.

~~Matador Resources Company and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

~~NOTE 3 — 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 interim unaudited condensed consolidated balance sheet. 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 Additionally, 0.8 million restricted shares, which are participating securities, were excluded 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 usedcalculations above for the three months ended ~~June 30,~~March 31, 2019, ~~was 3.73%. For these purposes,~~as the ~~lease term includes options~~security holders do not have the obligation to ~~extend~~share in 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 interim unaudited condensed consolidated balance sheet unless there is a significant cost to terminate the lease, including the cost of removallosses 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 interim unaudited condensed consolidated balance sheets.

The following table presents supplemental interim unaudited condensed consolidated statement of operations information related to lease expenses, on a gross basis, for the three and six months ended June 30, 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.

Three Months Ended
June 30, 2019 Six Months Ended
June 30, 2019
Operating leases
Lease operating $ 2,965
$ 5,207
Plant and other midstream services 30
61
General and administrative 665
1,474
Total operating leases⁽¹⁾
3,660
6,742
Short-term leases
Lease operating 3,392
5,601
Plant and other midstream services 1,131
2,751
General and administrative 5
17
Total short-term leases⁽²⁾⁽³⁾
4,528
8,369
Financing leases
Depreciation of assets 231
440
Interest on lease liabilities 33
64
Total financing leases 264
504
Total lease expense $ 8,452
$ 15,615

~~_____________________~~


~~(1)~~	Does not include gross payments related to drilling rig leases of $8.2 million and $13.5 million for the three and six months ended June 30, 2019, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the interim unaudited condensed consolidated balance sheet at June 30, 2019.


~~(2)~~	~~These costs are related to leases that are not recorded as right of use assets or lease liabilities in the interim unaudited condensed 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 $10.7 million and $37.2 million for the three and six months ended June 30, 2019, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the interim unaudited condensed consolidated balance sheet at June 30, 2019.

Company.

~~Matador Resources Company and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

~~NOTE 3 — LEASES — Continued~~

~~The following table presents supplemental interim unaudited condensed consolidated balance sheet information related to leases as of June 30, 2019 (in thousands).~~

June 30, 2019
Operating leases
Other assets $ 78,845
Other current liabilities $ (40,870 )
Other long-term liabilities (43,012 )
Total operating lease liabilities $ (83,882 )

Financing leases
Other property and equipment, at cost $ 2,846
Accumulated depreciation (865 )
Net property and equipment $ 1,981
Other current liabilities $ (1,108 )
Other long-term liabilities (1,146 )
Total financing lease liabilities $ (2,254 )

~~The following table presents supplemental interim unaudited condensed consolidated cash flow information related to lease payments for the six months ended June 30, 2019 (in thousands).~~

Six Months Ended
June 30, 2019
Cash paid related to lease liabilities
Operating cash payments for operating leases $ 6,790
Investing cash payments for operating leases $ 13,509
Financing cash payments for financing leases $ 490

Right of use assets obtained in exchange for lease obligations entered into during the period
Operating leases $ 28,884
Financing leases $ 471

~~The following table presents the maturities of lease liabilities at June 30, 2019 (in years).~~



~~Weighted-Average Remaining Lease Term~~		~~June 30, 2019~~
~~Operating leases~~		~~3.0~~
~~Financing leases~~		~~2.6~~

~~Matador Resources Company and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

~~NOTE 3 — LEASES — Continued~~

~~The following table presents a schedule of future minimum lease payments required under all lease agreements as of June 30, 2019 and December 31, 2018, respectively (in thousands).~~

June 30, 2019
Operating Leases Financing Leases
2019 $ 22,075
$ 493
2020 32,051
747
2021 19,981
581
2022 3,989
504
2023 3,234
—
Thereafter 7,679
—
Total lease payments 89,009
2,325
Less imputed interest (5,127 ) (71 )
Total lease obligations 83,882
2,254
Less current obligations (40,870 ) (1,108 )
Long-term lease obligations $ 43,012
$ 1,146

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

139

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 43 — ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 (in thousands).


Beginning asset retirement obligations	$	31,086		$	36,211
Liabilities incurred during period	1,427			990
Liabilities settled during period	(154		)	(44		)
Divestitures during period	(951		)
Accretion expense	834			476
Ending asset retirement obligations	32,242			37,633
Less: current asset retirement obligations⁽¹⁾	(1,556		)	(515		)
Long-term asset retirement obligations	$	30,686		$	37,118

_______________


(1)	Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at ~~June 30, 2019.~~March 31, 2020.

NOTE 54 — DEBT

At ~~June 30, 2019 and July~~March 31, ~~2019,~~2020, the Company had $1.05 billion of outstanding senior notes due 2026 (the “Notes”), ~~$205.0~~$315.0 million in borrowings outstanding under its reserves-based revolving credit facility (the “Credit Agreement”) and approximately ~~$13.6~~$46.0 million in outstanding letters of credit issued pursuant to the Credit Agreement. Between March 31 and April 29, 2020, the Company borrowed an additional $30.0 million under the Credit Agreement.

At ~~June 30, 2019 and July~~March 31, ~~2019,~~2020, San Mateo I had ~~$240.0~~$307.5 million in borrowings outstanding under its revolving credit facility (the “San Mateo Credit Facility”) and approximately ~~$16.2~~$9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.

Credit Agreements

MRC Energy Company

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In ~~April 2019,~~February 2020, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, ~~2018,~~2019, and, as a result, the borrowing base was ~~increased to~~affirmed at $900.0 million. The Company elected to ~~keep~~increase the borrowing commitment atfrom $500.0 million to $700.0 million, and the maximum facility amount remained $1.5 billion. This ~~April 2019~~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 commitment. The Credit Agreement matures on October 31, 2023.

The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. The Company believes that it was in compliance with the terms of the Credit Agreement at ~~June 30, 2019.~~March 31, 2020.

San Mateo Midstream, LLC

On December 19, 2018, San Mateo I entered into the $250.0 million San Mateo Credit Facility, which matures December 19, 2023. The San Mateo Credit Facility includes an accordion feature, which could increase the lender commitments to up to $400.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, 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. ~~On June 12, 2019, pursuant~~The San Mateo Credit Facility includes an accordion feature, which provides for potential increases to ~~the accordion feature,~~up to $400.0 million, and matures December 19, 2023. At March 31, 2020, the lender commitments under the San Mateo Credit Facility were ~~increased~~$375.0 million.

The San Mateo Credit Facility requires San Mateo I to ~~$325.0 million.~~

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. The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at ~~June 30, 2019.~~March 31, 2020.

1410

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 54 — DEBT — Continued

Senior Unsecured Notes

~~In August and October 2018,~~At March 31, 2020, the Company ~~issued $750.0 million and $300.0 million, respectively,~~had $1.05 billion of outstanding Notes, which have a 5.875% coupon rate. 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.

NOTE 65 — INCOME TAXES

The Company’s effective tax ~~rate~~rates for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and 2019 ~~was 26%~~were 24% and ~~37%~~33%, respectively. The Company’s total income tax provision for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and 2019 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of permanent differences between book and tax income ~~at June 30, 2019.~~

~~Due to a variety of factors, including the Company’s significant net income~~and state taxes, primarily 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 Company’s deferred tax assets exceeded its deferred tax liabilities at June 30, 2018 due to the deferred tax assets generated by full-cost ceiling impairment charges in prior periods. The Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at June 30, 2018 due to uncertainties regarding the future realization of its deferred tax assets.New Mexico.

NOTE 76 — EQUITY

Stock-based Compensation

In ~~February 2019,~~March 2020, the Company granted awards to certain of its employees of ~~428,006~~601,210 service-based restricted stock units to be settled in cash, which are liability instruments, and ~~428,006~~601,210 performance-based stock units, which are equity instruments. The performance-based stock units vest in an amount between ~~zero~~0 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,~~2022, as compared to a designated peer group. The service-based restricted stock units vest ratably over three years, and the performance-based stock units are eligible to vest after completion of the three-year performance period. The fair value of these awards was approximately $16.8 million on the grant date. In April 2019, the Company granted awards to certain of its employees of 259,038 service-based restricted stock units to be settled in cash, which are liability instruments, and 205,361 shares of service-based restricted stock, which are equity instruments. Both the liability instruments and the equity instruments vest ratably over three years. The fair value of these awards was approximately $9.2$2.5 million on the grant date.

San Mateo II

On February 25, 2019, the Company announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point Energy LLC (“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. ~~The Company also has the ability to earn up to $150 million in deferred performance incentives over the next five years related to the formation of San Mateo II~~, ~~plus additional performance incentives for securing volumes from third-party customers.~~ During the first quarter of 2019, the Company contributed $1.0 million of property and Five Point contributed $4.0 million of cash to San Mateo II. During the ~~three and six months ended June 30, 2019,~~first quarter of 2020, the Company contributed ~~$1.5~~$7.5 million ~~and $1.5 million of cash~~ and Five Point contributed ~~$7.5 million and $11.5~~$50.0 million of cash, of which $20.6 million was paid to carry Matador’s proportionate interest in San Mateo II ~~respectively.~~

~~Table~~and was therefore recorded in “Additional paid-in capital” in the Company’s interim unaudited condensed consolidated balance sheet, net of ~~Contents~~

the $4.3 million deferred tax impact to Matador ~~Resources~~related to this equity contribution. In addition, the Company ~~and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

~~NOTE 7 — EQUITY — Continued~~

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.

Performance Incentives

In connection with the formation of San Mateo I in 2017, the Company has the ability to earn a total of $73.5 million in performance incentives to be paid by Five Point over a five-year period. The Company earned, and Five Point paid to the Company, $14.7 million in performance incentives during each of the ~~six~~three months ended ~~June 30,~~March 31, 2020, 2019 and ~~2018, and the~~2018. The Company may earn up to an additional ~~$44.1~~$29.4 million in performance incentives over the next ~~three~~two years. These performance incentives are recorded, ~~as an increase~~net of the $3.1 million deferred tax impact to ~~additional~~Matador, in “Additional paid-in ~~capital~~capital” in the Company’s interim unaudited condensed consolidated balance sheet when received. These performance incentives for the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~ are also denoted as “Contributions related to formation of San Mateo I” under “Financing activities” in the Company’s interim unaudited condensed consolidated statements of cash flows and changes in shareholders’ equity.

NOTE 87 — DERIVATIVE FINANCIAL INSTRUMENTS

At ~~June 30, 2019,~~March 31, 2020, the Company had various ~~costless collar, three-way~~ costless collar and swap contracts open and in place to mitigate its exposure to oil ~~and natural gas~~ price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling for the collars and fixed price for the swaps. ~~Each~~At March 31, 2020, each contract iswas set to expire at varying times during ~~2019~~2020, 2021 and ~~2020.~~

2022. The ~~following is a summary of the Company’s~~Company had no open ~~costless collar~~ contracts ~~for oil and~~associated with natural gas ~~at June 30, 2019.~~

Commodity Calculation Period Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or
$/MMBtu) Weighted Average Price Ceiling ($/Bbl or
$/MMBtu) Fair Value of Asset (Liability) (thousands)
Oil 07/01/2019 - 12/31/2019 3,900,000
$ 50.26
$ 70.94
$ 3,354
Oil 01/01/2020 - 12/31/2020 2,640,000
$ 48.50
$ 69.50
4,555
Natural Gas 07/01/2019 - 12/31/2019 1,200,000
$ 2.50
$ 3.80
272
Total open costless collar contracts $ 8,181

~~The following is a summary of the Company’s open three-way costless collar contracts for oil and~~or natural gas liquids (“NGL”) prices at ~~June 30, 2019. Open three-way costless collars consist of a long put (the floor), a short call (the ceiling) and a long call that limits losses on the upside.~~

Commodity Calculation Period Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or $/MMBtu) Weighted Average Price, Short Call ($/Bbl or $/MMBtu) Weighted Average Price, Long Call ($/Bbl or $/MMBtu) Fair Value of Asset (Liability) (thousands)
Oil 07/01/2019 - 12/31/2019 660,000
$ 60.00
$ 75.00
$ 78.85
$ 2,829
Natural Gas 07/01/2019 - 12/31/2019 2,400,000
$ 2.50
$ 3.00
$ 3.24
528
Total open three-way costless collar contracts $ 3,357

~~The following is a summary of the Company’s open basis swap contracts for oil at June 30, 2019.~~

Commodity Calculation Period Notional Quantity (Bbl)
Fixed Price
($/Bbl)

Fair Value of
Asset
(Liability)
(thousands)
Oil Basis Swaps 08/1/2019 - 12/31/2019 1,377,000
$ 0.33
$ (39 )
Oil Basis Swaps 01/01/2020 - 12/31/2020 4,494,000
$ 0.42
(1,215 )
Total open swap contracts $ (1,254 )

~~At June 30, 2019, the Company had an aggregate asset value for open derivative financial instruments of $10.3 million.~~March 31, 2020.

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UNAUDITED — CONTINUED

NOTE 87 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

The following is a summary of the Company’s open costless collar contracts for oil at March 31, 2020.



Commodity	Calculation Period	Notional Quantity (Bbl)	Weighted Average Price Floor ($/Bbl)		Weighted Average Price Ceiling ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil	04/01/2020 - 12/31/2020	5,205,000	$	47.68	$	66.69	$	95,553
Total open costless collar contracts							$	95,553

The following is a summary of the Company’s open basis swap contracts for oil at March 31, 2020.



Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil Basis	04/01/2020 - 12/31/2020	7,335,000	$	0.61	$	23,318
Oil Basis	01/01/2021 - 12/31/2021	8,400,000	$	0.87	8,552
Oil Basis	01/01/2022 - 12/31/2022	5,520,000	$	0.95	5,127
Total open basis swap contracts					$	36,997

At March 31, 2020, the Company had an aggregate asset value for open derivative financial instruments of $132.6 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 interim unaudited condensed 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 interim unaudited condensed consolidated balance sheets as of ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 (in thousands).


Derivative Instruments	Gross amounts recognized			Gross amounts netted in the condensed consolidated balance sheets			Net amounts presented in the condensed consolidated balance sheets			Gross amounts recognized			Gross amounts netted in the condensed consolidated balance sheets			Net amounts presented in the condensed consolidated balance sheets
June 30, 2019
March 31, 2020
Current assets	$	12,671		$	(4,400	)	$	8,271		$	321,607		$	(200,428	)	$	121,179
Other assets	4,710			(2,508		)	2,202			296,261			(284,890		)	11,371
Current liabilities	(4,400		)	4,400			—			(200,428		)	200,428			—
Long-term liabilities	(2,697		)	2,508			(189		)	(284,890		)	284,890			—
Total	$	10,284		$	—		$	10,284		$	132,550		$	—		$	132,550
December 31, 2018
December 31, 2019
Current assets	$	53,136		$	(3,207	)	$	49,929		$	442,291		$	(442,291	)	$	—
Other assets										280,397			(280,397		)	—
Current liabilities	(3,207		)	3,207			—			(444,188		)	442,291			(1,897		)
Long-term liabilities	(83		)	—			(83		)	(282,381		)	280,397			(1,984		)
Total	$	49,846		$	—		$	49,846		$	(3,881	)	$	—		$	(3,881	)

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UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

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


			Three Months Ended June 30,					Six Months Ended June 30,								Three Months Ended March 31,
Type of Instrument		Location in Condensed Consolidated Statement of Operations	2019		2018			2019			2018				Location in Condensed Consolidated Statement of Operations	2020		2019
Derivative Instrument
Oil		Revenues: Realized gain (loss) on derivatives	$	1,165	$	(2,488	)	$	4,531		$	(6,797	)		Revenues: Realized gain on derivatives	$	10,867	$	3,366
Natural Gas		Revenues: Realized (loss) gain on derivatives	—		—			(96		)	51				Revenues: Realized loss on derivatives	—		(96		)
Realized gain (loss) on derivatives			1,165		(2,488		)	4,435			(6,746		)
Realized gain on derivatives														Realized gain on derivatives		10,867		3,270
Oil		Revenues: Unrealized gain (loss) on derivatives	5,365		1,829			(40,078		)	12,956				Revenues: Unrealized gain (loss) on derivatives	136,430		(45,444		)
Natural Gas		Revenues: Unrealized gain (loss) on derivatives	792		(400		)	516			(1,111		)		Revenues: Unrealized loss on derivatives	—		(275		)
Unrealized gain (loss) on derivatives	Unrealized gain (loss) on derivatives		6,157		1,429			(39,562		)	11,845			Unrealized gain (loss) on derivatives		136,430		(45,719		)
Total			$	7,322	$	(1,059	)	$	(35,127	)	$	5,099				$	147,297	$	(42,449	)

In April 2020, the Company restructured a portion of its oil derivative contracts, increasing its oil volumes hedged during the period from April through December 2020. As part of this restructuring, the Company repurchased the call options on certain existing open costless collars and kept the remaining put options, which represent options to sell at a specific exercise price, exchanged certain existing open costless collars and added swaps.

As a result of this restructuring process, the Company’s open oil derivative contracts for the period from April through December 2020 have changed. The restructuring transactions were executed with the same counterparties and were costless to the Company. As a result, the execution of the restructuring transactions is not expected to have a material impact on the consolidated financial statements of the Company. No changes were made to the Company’s open oil basis swaps from those positions noted above. In April 2020, the Company also entered into oil swaps for 2021 and natural gas collars for late 2020 and early 2021.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at April 29, 2020.



Commodity	Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)
Oil	04/01/2020 - 12/31/2020	2,311,500	$	47.94	$	66.19
Natural Gas	11/01/2020 - 12/31/2020	3,200,000	$	2.52	$	3.71
Natural Gas	01/01/2021 - 03/31/2021	4,800,000	$	2.52	$	3.71

The following is a summary of the Company’s open swap contracts for oil at April 29, 2020.



Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)
Oil	04/01/2020 - 12/31/2020	7,620,000	$	34.93
Oil	01/01/2021 - 12/31/2021	2,040,000	$	35.26

The following is a summary of the Company’s open put option contracts for oil at April 29, 2020.



Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)
Oil	04/01/2020 - 06/30/2020	391,500	$	48.15

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UNAUDITED — CONTINUED

NOTE 98 — 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 ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 (in thousands).

Fair Value Measurements at
June 30, 2019 using
Description Level 1 Level 2 Level 3 Total
Assets (Liabilities)
Oil derivatives and basis swaps $ —
$ 9,484
$ —
$ 9,484
Natural gas derivatives —
800
—
800
Total $ —
$ 10,284
$ —
$ 10,284


	Fair Value Measurements at December 31, 2018 using								Fair Value Measurements at March 31, 2020 using
Description	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	49,562	$	—	$	49,562	$	—	$	132,550	$	—	$	132,550
Natural gas derivatives	—		284		—		284
Total	$	—	$	49,846	$	—	$	49,846	$	—	$	132,550	$	—	$	132,550



	Fair Value Measurements at December 31, 2019 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	(3,881	)	$	—	$	(3,881	)
Total	$	—	$	(3,881	)	$	—	$	(3,881	)

Additional disclosures related to derivative financial instruments are provided in Note 8.7.

Other Fair Value Measurements

At ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses and other assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximated their fair values due to their short-term maturities.

At ~~June 30,~~March 31, 2020 and 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 June 30, 2019 and December 31, 2018, the fair value of the Notes was $1.07 billion and $0.97 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

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UNAUDITED — CONTINUED

NOTE 108 — FAIR VALUE MEASUREMENTS — Continued

At March 31, 2020 and December 31, 2019, the fair value of the Notes was $307.1 million and $1.06 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. At April 29, 2020, the fair value of the Notes was $499.5 million.

NOTE 9 — 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 ~~$6.1~~$11.0 million and ~~$5.1~~$6.8 million for deliveries under these agreements during the three months ended ~~June 30,~~March 31, 2020 and 2019, ~~and 2018, respectively, and $12.9 million and $9.1 million for deliveries under these agreements during the six months ended June 30, 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 ~~June 30, 2019,~~March 31, 2020, the total deficiencies required to be paid by the Company under these agreements would be approximately ~~$163.4~~$398.1 million, in addition to the commitments described below.

Future Commitments

In late 2017, the Company entered into a fixed-fee ~~natural gas liquids (“NGL”)~~NGL sales agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River cryogenic natural gas processing plant in Eddy County, New Mexico (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~~would 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~~would 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~~would be required to pay a deficiency fee per gallon of NGL ~~deficiency.~~below the Company’s commitment. 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~~$129.2 million.

In ~~April 2018,~~October 2019, the Company ~~also~~ entered into a ~~16-year,~~15-year, fixed-fee natural gas transportation agreement ~~that begins on October 1, 2019,~~ whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The 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~~would owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s ~~pipeline. The~~pipeline, and the minimum contractual obligation ~~at June 30, 2019 was~~would be approximately ~~$56.8 million.~~

In May 2018, the Company also entered into a 10-year, fixed-fee natural gas sales agreement whereby the Company committed to deliver residue gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date of such pipeline, which is expected to be operational in the fourth quarter of 2019. If the Company does not meet the volume commitment specified in the natural gas sales agreement, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. The minimum contractual obligation at June 30, 2019 was approximately $202.3$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 remaining minimum contractual obligation under the Operational Agreements at ~~June 30, 2019~~March 31, 2020 was approximately ~~$183.8~~$150.7 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 will provide the Company with firm service under each of the San Mateo II Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the San Mateo II Operational Agreements at ~~inception~~March 31, 2020 was approximately ~~$363.8 million and begins in 2020.~~$361.1 million.

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UNAUDITED — CONTINUED

NOTE 109 — COMMITMENTS AND CONTINGENCIES — Continued

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~~II��s total commitments under this agreement are ~~$80.1~~$80.6 million. San Mateo II paid approximately ~~$8.3~~$21.1 million under this agreement during the three months ended ~~June 30, 2019.~~March 31, 2020. As of ~~June 30, 2019,~~March 31, 2020, the remaining obligations of San Mateo II under this agreement were ~~$71.8~~$19.4 million, which are expected to be paid within the next 12 months.

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 on 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.

NOTE 1110 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 (in thousands).


	June 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Accrued evaluated and unproved and unevaluated property costs	$	100,014	$	86,318	$	107,173	$	72,376
Accrued midstream property costs	21,840		16,808
Accrued midstream properties costs					40,781		46,402
Accrued lease operating expenses	20,812		12,705		20,849		18,223
Accrued interest on debt	18,599		22,448		2,861		18,569
Accrued asset retirement obligations	1,556		1,350		515		619
Accrued partners’ share of joint interest charges	17,165		17,037		18,202		14,322
Accrued payable related to purchased natural gas					1,770		17,806
Other	11,622		14,189		5,154		12,378
Total accrued liabilities	$	191,608	$	170,855	$	197,305	$	200,695

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~ (in thousands).


	Six Months Ended June 30,					Three Months Ended March 31,
	2019		2018			2020			2019
Cash paid for interest expense, net of amounts capitalized	$	37,632	$	14,286		$	35,461		$	35,326
Increase in asset retirement obligations related to mineral properties	$	321	$	834		$	738		$	445
Increase in asset retirement obligations related to midstream properties	$	283	$	296		$	213		$	—
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	$	13,536	$	(26,389	)
Increase (decrease) in liabilities for midstream properties capital expenditures	$	5,854	$	(2,371	)
Decrease in liabilities for accrued cost to issue equity	$	—	$	73
Increase in liabilities for oil and natural gas properties capital expenditures						$	34,602		$	16,184
Decrease in liabilities for midstream properties capital expenditures						$	(5,579	)	$	(3,908	)
Stock-based compensation (benefit) expense recognized as liability						$	(1,411	)	$	605
Transfer of inventory from oil and natural gas properties	$	370	$	343		$	401		$	250
Transfer of inventory to midstream properties	$	—	$	(2,390	)

2016

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 1110 — SUPPLEMENTAL DISCLOSURES — Continued

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


	Six Months Ended June 30,				Three Months Ended March 31,
	2019		2018		2020		2019
Cash	$	59,950	$	122,450	$	27,063	$	20,758
Restricted cash	24,812		21,063		29,732		25,954
Total cash and restricted cash	$	84,762	$	143,513	$	56,795	$	46,712

NOTE 1211 — SEGMENT INFORMATION

The Company operates in ~~two~~2 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 and East Texas.~~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, Wolf and ~~Wolf~~Stateline asset areas and the Greater Stebbins Area in the Delaware Basin are conducted through San Mateo.

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


	Exploration and Production							Consolidations and Eliminations			Consolidated Company		Exploration and Production									Consolidations and Eliminations			Consolidated Company
	Exploration and Production		Midstream		Corporate						Consolidated Company		Exploration and Production		Midstream			Corporate				Consolidations and Eliminations			Consolidated Company
Three Months Ended June 30, 2019								Consolidations and Eliminations
Three Months Ended March 31, 2020
Oil and natural gas revenues	$	209,563	$	1,497	$	—		$	—		$	211,060	$	196,795		$	1,119		$	—		$	—		$	197,914
Midstream services revenues	—		32,166		—			(17,807		)	14,359		—			37,749			—			(21,919		)	15,830
Sales of purchased natural gas	—		8,963		—			—			8,963		3,595			6,949			—			—			10,544
Realized gain on derivatives	1,165		—		—			—			1,165		10,867			—			—			—			10,867
Unrealized loss on derivatives	6,157		—		—			—			6,157
Unrealized gain on derivatives													136,430			—			—			—			136,430
Expenses⁽¹⁾	141,514		23,425		17,783			(17,807		)	164,915		161,325			24,330			14,317			(21,919		)	178,053
Operating income (loss)⁽²⁾	$	75,371	$	19,201	$	(17,783	)	$	—		$	76,789	$	186,362		$	21,487		$	(14,317	)	$	—		$	193,532
Total assets	$	3,155,577	$	508,074	$	87,800		$	—		$	3,751,451	$	3,571,257		$	715,413		$	47,001		$	—		$	4,333,671
Capital expenditures⁽³⁾	$	166,532	$	41,707	$	1,400		$	—		$	209,639	$	209,735		$	68,073		$	787		$	—		$	278,595

_____________________


(1)	Includes depletion, depreciation and amortization expenses of ~~$75.7~~$85.2 million and ~~$3.8~~$4.8 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of ~~$0.6~~$0.7 million.


(2)	Includes ~~$8.3~~$9.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes ~~$8.2~~$39.7 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and ~~$24.2~~$47.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

2117

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 1211 — SEGMENT INFORMATION — Continued


	Exploration and Production								Consolidations and Eliminations			Consolidated Company			Exploration and Production										Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate						Consolidated Company			Exploration and Production			Midstream			Corporate				Consolidations and Eliminations			Consolidated Company
Three Months Ended June 30, 2018									Consolidations and Eliminations
Three Months Ended March 31, 2019
Oil and natural gas revenues	$	207,229		$	1,790	$	—		$	—		$	209,019		$	191,663			$	1,606		$	—		$	—		$	193,269
Midstream services revenues	—			19,896		—			(16,489		)	3,407			—				30,254			—			(18,416		)	11,838
Realized loss on derivatives	(2,488		)	—		—			—			(2,488		)
Unrealized gain on derivatives	1,429			—		—			—			1,429
Sales of purchased natural gas															—				11,231			—			—			11,231
Realized gain on derivatives															3,270				—			—			—			3,270
Unrealized loss on derivatives															(45,719		)		—			—			—			(45,719		)
Expenses⁽¹⁾	126,025			9,363		18,475			(16,489		)	137,374			141,980				25,834			16,950			(18,416		)	166,348
Operating income (loss)⁽²⁾	$	80,145		$	12,323	$	(18,475	)	$	—		$	73,993		$	7,234			$	17,257		$	(16,950	)	$	—		$	7,541
Total assets	$	2,058,447		$	354,068	$	143,332		$	—		$	2,555,847		$	3,043,375			$	477,836		$	62,087		$	—		$	3,583,298
Capital expenditures⁽³⁾	$	199,345		$	32,900	$	732		$	—		$	232,977		$	197,611			$	29,432		$	807		$	—		$	227,850

_____________________


(1)	Includes depletion, depreciation and amortization expenses of ~~$64.5~~$72.6 million and ~~$2.3~~$3.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of ~~$25,000.~~$0.6 million.


(2)	Includes ~~$5.8~~$7.5 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes ~~$16.1~~$23.1 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $13.7 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
Six Months Ended June 30, 2019
Oil and natural gas revenues $ 401,226
$ 3,103
$ —
$ —
$ 404,329
Midstream services revenues —
62,420
—
(36,223 ) 26,197
Sales of purchased natural gas —
20,194
—
—
20,194
Realized gain on derivatives 4,435
—
—
—
4,435
Unrealized loss on derivatives (39,562 ) —
—
—
(39,562 )
Expenses⁽¹⁾
283,493
49,260
34,734
(36,223 ) 331,264
Operating income (loss)⁽²⁾
$ 82,606
$ 36,457
$ (34,734 ) $ —
$ 84,329
Total assets $ 3,155,577
$ 508,074
$ 87,800
$ —
$ 3,751,451
Capital expenditures⁽³⁾
$ 364,143
$ 71,139
$ 2,206
$ —
$ 437,488

~~_____________________~~


~~(1)~~	Includes depletion, depreciation and amortization expenses of $148.3 million and $7.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.2 million.


~~(2)~~	~~Includes $15.8 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.~~


~~(3)~~	Includes $31.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $37.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

~~Table of Contents~~

~~Matador Resources Company and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

NOTE 12 — ~~SEGMENT INFORMATION — Continued~~

Exploration and Production Consolidations and Eliminations Consolidated Company
Midstream Corporate
Six Months Ended June 30, 2018
Oil and natural gas revenues $ 387,489
$ 3,484
$ —
$ —
$ 390,973
Midstream services revenues —
35,708
—
(29,233 ) 6,475
Realized loss on derivatives (6,746 ) —
—
—
(6,746 )
Unrealized gain on derivatives 11,845
—
—
—
11,845
Expenses⁽¹⁾
232,180
16,561
35,684
(29,233 ) 255,192
Operating income (loss)⁽²⁾
$ 160,408
$ 22,631
$ (35,684 ) $ —
$ 147,355
Total assets $ 2,058,447
$ 354,068
$ 143,332
$ —
$ 2,555,847
Capital expenditures⁽³⁾
$ 388,790
$ 78,617
$ 1,258
$ —
$ 468,665

~~_____________________~~


~~(1)~~	Includes depletion, depreciation and amortization expenses of $117.8 million and $3.9 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.6 million.


~~(2)~~	~~Includes $10.9 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.~~


~~(3)~~	~~Includes $38.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.~~

~~Table of Contents~~

~~Matador Resources Company and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

~~NOTE 13 —~~ 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 ~~June 30, 2019,~~March 31, 2020, 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 June 30, 2019
Condensed Consolidating Balance Sheet March 31, 2020												Condensed Consolidating Balance Sheet March 31, 2020
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated			Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	1,582,828	$	12,535	$	—	$	(1,595,363	)	$	—		$	1,595,484	$	13,440	$	—	$	(1,608,924	)	$	—
Current assets	3,967		44,100		225,317		—			273,384			7,024		41,840		307,771		—			356,635
Net property and equipment	—		438,681		2,944,662		—			3,383,343			—		648,361		3,238,872		—			3,887,233
Investment in subsidiaries	1,211,056		—		109,227		(1,320,283		)	—			1,516,219		—		170,552		(1,686,771		)	—
Long-term assets	10,589		1,700		92,004		(9,569		)	94,724			—		2,855		97,278		(10,330		)	89,803
Total assets	$	2,808,440	$	497,016	$	3,371,210	$	(2,925,215	)	$	3,751,451		$	3,118,727	$	706,496	$	3,814,473	$	(3,306,025	)	$	4,333,671
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	1,595,363	$	(1,595,363	)	$	—		$	—	$	—	$	1,608,924	$	(1,608,924	)	$	—
Current liabilities	18,493		33,080		286,004		(802		)	336,775			2,867		52,782		305,123		(874		)	359,898
Senior unsecured notes payable	1,038,625		—		—		—			1,038,625			1,039,811		—		—		—			1,039,811
Other long-term liabilities	14,845		250,583		278,787		(8,767		)	535,448			84,700		320,131		384,207		(9,456		)	779,582
Total equity attributable to Matador Resources Company	1,736,477		109,227		1,211,056		(1,320,283		)	1,736,477			1,991,349		170,552		1,516,219		(1,686,771		)	1,991,349
Non-controlling interest in subsidiaries	—		104,126		—		—			104,126			—		163,031		—		—			163,031
Total liabilities and equity	$	2,808,440	$	497,016	$	3,371,210	$	(2,925,215	)	$	3,751,451		$	3,118,727	$	706,496	$	3,814,473	$	(3,306,025	)	$	4,333,671


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


Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2019
Condensed Consolidating Statement of Operations For the Three Months Ended March 31, 2020																Condensed Consolidating Statement of Operations For the Three Months Ended March 31, 2020
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated				Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	41,720		$	216,885		$	(16,901	)	$	241,704			$	—		$	45,319		$	347,687	$	(21,421	)	$	371,585
Total expenses	901			22,564			158,351			(16,901		)	164,915				921			23,794			174,759		(21,421		)	178,053
Operating (loss) income	(901		)	19,156			58,534			—			76,789				(921		)	21,525			172,928		—			193,532
Inventory impairment	—			—			(368		)	—			(368		)
Interest expense	(15,888		)	(2,180		)	—			—			(18,068		)		(17,375		)	(2,437		)	—		—			(19,812		)
Other income (expense)	—			3			(426		)	—			(423		)
Other income																	—			—			1,320		—			1,320
Earnings in subsidiaries	66,399			—			8,659			(75,058		)	—				183,982			—			9,734		(193,716		)	—
Income before income taxes	49,610			16,979			66,399			(75,058		)	57,930				165,686			19,088			183,982		(193,716		)	175,040
Total income tax provision	12,858			—			—			—			12,858				39,957			—			—		—			39,957
Net income attributable to non-controlling interest in subsidiaries	—			(8,320		)	—			—			(8,320		)		—			(9,354		)	—		—			(9,354		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	8,659		$	66,399		$	(75,058	)	$	36,752			$	125,729		$	9,734		$	183,982	$	(193,716	)	$	125,729


Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2018
Condensed Consolidating Statement of Operations For the Three Months Ended March 31, 2019																Condensed Consolidating Statement of Operations For the Three Months Ended March 31, 2019
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated				Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	21,356		$	206,219		$	(16,208	)	$	211,367			$	—		$	42,876		$	149,248		$	(18,235	)	$	173,889
Total expenses	1,178			9,466			142,938			(16,208		)	137,374				1,035			25,505			158,043			(18,235		)	166,348
Operating (loss) income	(1,178		)	11,890			63,281			—			73,993				(1,035		)	17,371			(8,795		)	—			7,541
Interest expense	(8,004		)	—			—			—			(8,004		)		(15,787		)	(2,142		)	—			—			(17,929		)
Other income (expense)	—			11			(363		)	—			(352		)
Earnings in subsidiaries	68,988			—			6,070			(75,058		)	—
Income before income taxes	59,806			11,901			68,988			(75,058		)	65,637
Other expense																	—			—			(110		)	—			(110		)
(Loss) earnings in subsidiaries																	(1,138		)	—			7,767			(6,629		)	—
(Loss) income before income taxes																	(17,960		)	15,229			(1,138		)	(6,629		)	(10,498		)
Total income tax benefit																	(1,013		)	—			—			—			(1,013		)
Net income attributable to non-controlling interest in subsidiaries	—			(5,831		)	—			—			(5,831		)		—			(7,462		)	—			—			(7,462		)
Net income attributable to Matador Resources Company shareholders	$	59,806		$	6,070		$	68,988		$	(75,058	)	$	59,806
Net (loss) income attributable to Matador Resources Company shareholders																	$	(16,947	)	$	7,767		$	(1,138	)	$	(6,629	)	$	(16,947	)

Condensed Consolidating Statement of Operations
For the Six Months Ended June 30, 2019
Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated
Total revenues $ —
$ 84,596
$ 366,133
$ (35,136 ) $ 415,593
Total expenses 1,936
48,069
316,395
(35,136 ) 331,264
Operating (loss) income (1,936 ) 36,527
49,738
—
84,329
Inventory impairment —
—
(368 ) —
(368 )
Interest expense (31,675 ) (4,322 ) —
—
(35,997 )
Other income (expense) —
3
(535 ) —
(532 )
Earnings in subsidiaries 65,261
—
16,426
(81,687 ) —
Income before income taxes 31,650
32,208
65,261
(81,687 ) 47,432
Total income tax provision
11,845
—
—
—
11,845
Net income attributable to non-controlling interest in subsidiaries —
(15,782 ) —
—
(15,782 )
Net income attributable to Matador Resources Company shareholders $ 19,805
$ 16,426
$ 65,261
$ (81,687 ) $ 19,805



Condensed Consolidating Statement of Cash Flows For the Three Months Ended March 31, 2020
	Matador		Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash provided by operating activities	$	4	$	25,244		$	84,124		$	—		$	109,372
Net cash used in investing activities	—		(73,670		)	(170,065		)	(4,485		)	(248,220		)
Net cash provided by financing activities	—		53,500			72,530			4,485			130,515
Increase (decrease) in cash and restricted cash	4		5,074			(13,411		)	—			(8,333		)
Cash and restricted cash at beginning of period	29		24,656			40,443			—			65,128
Cash and restricted cash at end of period	$	33	$	29,730		$	27,032		$	—		$	56,795

Condensed Consolidating Statement of Operations
For the Six Months Ended June 30, 2018
Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated
Total revenues $ —
$ 38,550
$ 392,699
$ (28,702 ) $ 402,547
Total expenses 2,412
16,394
265,088
(28,702 ) 255,192
Operating (loss) income (2,412 ) 22,156
127,611
—
147,355
Interest expense (16,495 ) —
—
—
(16,495 )
Other income (expense) 6
11
(316 ) —
(299 )
Earnings in subsidiaries 138,601
—
11,306
(149,907 ) —
Income before income taxes 119,700
22,167
138,601
(149,907 ) 130,561
Net income attributable to non-controlling interest in subsidiaries —
(10,861 ) —
—
(10,861 )
Net income attributable to Matador Resources Company shareholders $ 119,700
$ 11,306
$ 138,601
$ (149,907 ) $ 119,700

Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 30, 2019
Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated
Net cash (used in) provided by operating activities $ (109 ) $ 51,266
$ 143,340
$ —
$ 194,497
Net cash used in investing activities —
(59,309 ) (327,195 ) (8,190 ) (394,694 )
Net cash provided by financing activities —
13,584
179,201
8,190
200,975
(Decrease) increase in cash and restricted cash (109 ) 5,541
(4,654 ) —
778
Cash and restricted cash at beginning of period 456
18,841
64,687
—
83,984
Cash and restricted cash at end of period $ 347
$ 24,382
$ 60,033
$ —
$ 84,762


Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2018
Condensed Consolidating Statement of Cash Flows For the Three Months Ended March 31, 2019																Condensed Consolidating Statement of Cash Flows For the Three Months Ended March 31, 2019
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated				Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries		Consolidated
Net cash (used in) provided by operating activities	$	(224,441	)	$	10,225		$	468,424		$	—		$	254,208			$	(109	)	$	32,616		$	26,733		$	—	$	59,240
Net cash used in investing activities	—			(79,119		)	(454,478		)	40,035			(493,562		)		—			(29,988		)	(184,892		)	—		(214,880		)
Net cash provided by financing activities	226,539			83,400			10,481			(40,035		)	280,385				—			3,968			114,400			—		118,368
Increase in cash and restricted cash	2,098			14,506			24,427			—			41,031
(Decrease) Increase in cash and restricted cash																	(109		)	6,596			(43,759		)	—		(37,272		)
Cash and restricted cash at beginning of period	286			5,663			96,533			—			102,482				456			18,840			64,688			—		83,984
Cash and restricted cash at end of period	$	2,384		$	20,169		$	120,960		$	—		$	143,513			$	347		$	25,436		$	20,929		$	—	$	46,712

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our interim unaudited condensed consolidated financial statements and related notes thereto contained herein and the consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (the “Annual Report”) filed with the Securities and Exchange Commission ~~(“SEC”~~(the “SEC”) on March ~~1, 2019,~~2, 2020, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

In this Quarterly Report on Form 10-Q (the “Quarterly Report”), (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC (“San Mateo I”) together with San Mateo Midstream II, LLC (“San Mateo II”). For certain oil and natural gas terms used in this Quarterly Report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic ~~conditions,~~conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, the sufficiency of our cash flow from operations together with available borrowing capacity under our credit facilities, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well asliquids; our ability to ~~access them, the proximity~~replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to ~~our properties~~producing oil, natural gas and ~~capacity of transportation facilities,~~natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; availability of sufficient capital to execute our business plan, including from future cash flows, increases in our borrowing base and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate ~~acquisitions with our business,~~acquisitions; weather and environmental ~~conditions, uncertainties regarding environmental regulations or litigation~~conditions; the impact of the novel coronavirus pandemic on oil and ~~other legal or regulatory developments affecting~~natural gas demand, oil and natural gas prices and our ~~business,~~ business; the operating results of San Mateo’s expansion of the Black River cryogenic natural gas processing plant, including the timing of the further expansion of such plant; the timing and operating results of the buildout by San Mateo of oil, natural gas and water gathering and transportation systems and the drilling of any additional salt water disposal wells, including in conjunction with the expansion of San Mateo’s services and assets into new areas in Eddy County, New Mexico; and the other factors discussed below and elsewhere in this Quarterly Report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:

our business strategy;

our estimated future reserves and the present value ~~thereof;~~thereof, including whether or to what extent a full-cost ceiling impairment could be realized;

our cash flows and liquidity;

our financial strategy, budget, projections and operating results;

~~our~~the supply and demand of oil, natural gas and natural gas liquids;

oil, natural gas and natural gas liquids prices, including our realized ~~prices;~~prices thereof;

the timing and amount of future production of oil and natural gas;

the availability of drilling and production equipment;

the availability of oil storage capacity;

the availability of oil field labor;

the amount, nature and timing of capital expenditures, including future exploration and development costs;

the availability and terms of capital;

our drilling of wells;

our ability to negotiate and consummate acquisition and divestiture opportunities;

government regulation and taxation of the oil and natural gas industry;

our marketing of oil and natural gas;

our exploitation projects or property acquisitions;

the integration of acquisitions with our business;

our ability and the ability of San Mateo to construct and operate midstream facilities, including the operation and expansion of ~~our~~its Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells;

the ability of San Mateo to attract third-party volumes;

our costs of exploiting and developing our properties and conducting other operations;

general economic conditions;

competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;

the effectiveness of our risk management and hedging activities;

our technology;

environmental liabilities;

counterparty credit risk;

developments in oil-producing and natural gas-producing countries;

the impact of the novel coronavirus on the oil and natural gas industry and our business;

our future operating results; and

our plans, objectives, expectations and intentions contained in this Quarterly Report or in our other filings with the SEC that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements in this Quarterly Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

Overview

We are an independent energy company founded in July 2003 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. Our 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. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest ~~Louisiana and East Texas.~~Louisiana. Additionally, we conduct midstream operations, primarily through San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties.

~~Second~~First Quarter Highlights

For the three months ended ~~June 30, 2019,~~March 31, 2020, our total oil equivalent production was ~~5.6~~6.5 million BOE, and our average daily oil equivalent production was ~~61,290~~71,200 BOE per day, of which ~~36,767~~40,600 Bbl per day, or ~~60%~~57%, was oil and ~~147.1~~183.2 MMcf per day, or ~~40%~~43%, was natural gas. Our oil production of ~~3.3~~3.7 million Bbl for the three months ended ~~June 30, 2019~~March 31, 2020 increased ~~24%~~19% year-over-year from ~~2.7~~3.1 million Bbl for the three months ended ~~June 30, 2018.~~March 31, 2019. Our natural gas production of ~~13.4~~16.7 Bcf for the three months ended ~~June 30, 2019~~March 31, 2020 increased 6%22% year-over-year from ~~12.7~~13.7 Bcf for the three months ended June 30, 2018. For the six months ended June 30, 2019, our total oil equivalent production was 11.0 million BOE, and our average daily oil equivalent production was 60,619 BOE per day, of which 35,648 Bbl per day, or 59%, was oil and 149.8 MMcf per day, or 41%, was natural gas. Our oil production of 6.5 million Bbl for the six months ended June 30, 2019 increased 27% year-over-year from 5.1 million Bbl for the six months ended June 30, 2018. Our natural gas production of 27.1 Bcf for the six months ended June 30, 2019 increased 19% year-over-year from 22.8 Bcf for the six months ended June 30, 2018.March 31, 2019.

For the ~~second~~first quarter of ~~2019,~~2020, we reported net income attributable to Matador ~~Resources Company~~ shareholders of approximately ~~$36.8~~$125.7 million, or ~~$0.31~~$1.08 per diluted common share, on a generally accepted accounting principles in the United States (“GAAP”) basis, as compared to a net ~~income~~loss attributable to Matador ~~Resources Company~~ shareholders of ~~$59.8~~$16.9 million, or ~~$0.53~~$0.15 per diluted common share, for the ~~second~~first quarter of ~~2018.~~2019. For the ~~second~~first quarter of ~~2019,~~2020, our Adjusted EBITDA attributable to Matador ~~Resources Company~~ shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was ~~$144.1~~$140.6 million, as compared to Adjusted EBITDA of ~~$137.3~~$124.8 million during the ~~second~~first quarter of ~~2018.~~2019. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and ~~net cash provided by operating activities, see~~

“— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for the second quarter of 2019, see “— Results of Operations” below.

For the six months ended June 30, 2019, we reported net income attributable to Matador Resources Company shareholders of approximately $19.8 million, or $0.17 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador Resources Company shareholders of $119.7 million, or $1.08 per diluted common share, for the six months ended June 30, 2018. For the six months ended June 30, 2019, our Adjusted EBITDA, a non-GAAP financial measure, was $268.9 million, as compared to Adjusted EBITDA of $254.6 million during the six months ended June 30, 2018. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for the ~~six months ended June 30, 2019,~~first quarter of 2020, see “— Results of Operations” below.

Operations Update

During the ~~second~~first quarter of ~~2019,~~2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to just above $20 per Bbl in late March. This sudden decline in oil prices was attributable to two primary factors: (1) the precipitous decline in global oil demand resulting from the worldwide spread of the novel coronavirus (“COVID-19”) and (2) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of the Organization of Petroleum Exporting Countries and Russia (“OPEC+”) to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. Primarily as a result of these unexpected events and the resulting declines in oil prices, Matador has significantly modified its 2020 operational plan.

We began 2020 operating six drilling rigs in the Delaware Basin, as we continued ~~our~~to focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We ~~began 2019 operating~~had originally planned to operate these six drilling rigs in the Delaware Basin ~~and continued to do so at June 30, 2019. During~~throughout 2020. As a result of the ~~second~~events noted above, however, we released one operated drilling rig from our Wolf asset area in Loving County, Texas late in the first quarter of ~~2019, these six~~2020, and we released a second operated drilling rigs were deployed across our Delaware Basin asset areas, but with an increased focus on the Antelope Ridge asset area. We expect to operate six rigs in the Delaware Basin throughout the remainder of 2019, with four rigs operating between the Rustler Breaks and Antelope Ridge asset areas, one rig ~~operating in the Wolf and Jackson Trust asset areas and one rig operating in the Arrowhead, Ranger and Twin Lakes asset areas, although this rig, in particular, is expected to operate primarily in~~from the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) ~~for~~in late April 2020. We anticipate releasing one additional drilling rig by the ~~remainder~~end of ~~2019.~~

~~We also concluded completion operations on our nine-well program in South Texas during~~ the second quarter of ~~2019, which included eight completions~~2020. Thereafter, we expect to operate three drilling rigs in the Eagle Ford formation and one test of the Austin Chalk formation. The final four wells in this nine-well program were completed and turned to sales in the second quarter of 2019. These wells included two Eagle Ford completions on the Haverlah leasehold in Atascosa County, which were turned to sales in April, and two additional Eagle Ford completions on the Lloyd Hurt leasehold, which were turned to sales in May 2019. The rig used to drill these nine wells was released in early February 2019, and we have no additional operated drilling activities planned in the Eagle Ford shale forDelaware Basin throughout the remainder of ~~2019.~~2020. Two of these rigs are anticipated to operate in our Stateline asset area in Eddy County, New Mexico, and the third rig is expected to operate primarily in the Rustler Breaks and Antelope Ridge asset areas.

We completed and turned to sales a total of 1936 gross ~~(15.1~~(15.9 net) wells in the Delaware Basin during the ~~second~~first quarter of ~~2019,~~2020, including 1417 gross ~~(13.1~~(15.6 net) operated horizontal wells ~~two~~and 19 gross ~~(2.0 net) operated vertical wells and three gross (0.1~~(0.3 net) non-operated horizontal wells. During the ~~second~~first quarter of ~~2019,~~2020, we completed and turned to sales a total of 17 gross (10.5 net) wells in the Antelope Ridge asset area, including 11 gross (10.4 net) operated wells and six gross (0.1 net) non-operated wells. The 11 gross operated wells turned to sales in the Antelope Ridge asset area included two Avalon completions, one First Bone Spring completion, four Second Bone Spring completions, one Third Bone Spring completion, two Wolfcamp A completions and one Wolfcamp B completion. These wells also included the first six gross (6.0 net) “Rodney Robinson” wells completed in the western portion of the Antelope Ridge asset area. The 1,200 gross and net acre Rodney Robinson tract is one of the key tracts we acquired in the BLM New Mexico Oil and Gas Lease Sale in September 2018 (the “BLM Acquisition”). These six Rodney Robinson wells, all two-mile laterals, were also the first wells drilled and completed on the 8,400 gross and net acres we acquired in the BLM Acquisition.

In the Rustler Breaks asset area, we began producing oil and natural gas from a total of 1216 gross ~~(8.5~~(2.8 net) wells, ~~in the Antelope Ridge asset area,~~ including ~~nine~~three gross ~~(8.4~~(2.6 net) operated wells and ~~three~~13 gross ~~(0.1~~(0.2 net) non-operated wells. Of the ~~nine~~three gross operated wells completed and turned to sales in the ~~Antelope Ridge~~Rustler Breaks asset area, two were Wolfcamp ~~A-XY completions, three were First Bone Spring completions, three were Third Bone Spring~~A completions and one was a ~~vertical completion in the~~ Wolfcamp ~~formation. In the Rustler Breaks and Arrowhead asset areas, we did not complete or turn to sales any operated or non-operated wells during the second quarter of 2019.~~B completion. In the Wolf and Jackson Trust asset areas, we began producing oil and natural gas from ~~two~~three gross ~~(1.8~~(2.6 net) operated wells during the ~~second~~first quarter of ~~2019, including one~~2020, all of which were Wolfcamp B completion and one Second Bone Spring completion. In addition, we began producing oil and natural gas from a total of four gross (3.9 net) operated wells in the Ranger asset area during the second quarter of 2019, including one First Bone Spring completion, two Second Bone Spring completions and one Third Bone Spring completion. Finally, in the Twin Lakes asset area, we began producing oil and natural gas from one gross (1.0 net) well, a vertical completion in the Morrow formation, during the second quarter of 2019.A completions.

~~As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production has continued to increase over the past 12 months.~~ Our total Delaware Basin production for the ~~second~~first quarter of ~~2019~~2020 was ~~51,758~~60,300 BOE per day, consisting of ~~32,840~~38,500 Bbl of oil per day and ~~113.5~~130.9 MMcf of natural gas per day, ~~an 11%~~a 15% increase from production of ~~46,489~~52,600 BOE per day, consisting of ~~27,381~~32,000 Bbl of oil per day and ~~114.6~~123.9 MMcf of natural gas per day, in the ~~second~~first quarter of ~~2018.~~2019. The Delaware Basin contributed approximately ~~89%~~95% of our daily oil production and approximately ~~77%~~71% of our daily natural gas production in the ~~second~~first quarter of ~~2019,~~2020, as compared to approximately ~~92%~~93% of our daily oil production and approximately ~~82%~~81% of our daily natural gas production in the ~~second~~first quarter of ~~2018.~~2019.

WeDuring the first quarter of 2020, we did not conduct any operated drilling and completion activities on our leasehold properties in the Eagle Ford shale play in South Texas or in the Haynesville shale and Cotton Valley plays in Northwest ~~Louisiana and East Texas in the second quarter of 2019, although we~~Louisiana. We did participate in ~~eight~~the drilling and completion of three gross ~~(0.3~~(less than 0.1 net) non-operated Haynesville shale wells that were ~~completed and~~ turned to ~~sales.~~sales in the first quarter of 2020.

~~Capital Resources Update~~Borrowing Base Increased

In ~~April 2019,~~February 2020, the lenders ~~under~~party to our reserves-based revolving credit ~~agreement~~facility (the “Credit Agreement”)~~, led by Royal Bank of Canada,~~ completed their review of ~~our~~the Company’s proved oil and natural gas reserves at December 31, ~~2018,~~2019, and, as a result, the borrowing base was ~~increased~~affirmed at $900.0 million. The Company elected to ~~$900.0 million with~~increase the ~~elected~~ borrowing commitment ~~remaining at~~from $500.0 ~~million.~~million to $700.0 million, and the maximum facility amount remained $1.5 billion. We also added two new banks to our lending group as part of this redetermination process. This ~~April 2019~~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 June 2019, the lender commitments under San Mateo I’s revolving credit facility (the “San Mateo Credit Facility”), led by The Bank of Nova Scotia, were increased to $325.0 million, using the accordion feature. The San Mateo Credit Facility is guaranteed by San Mateo I’s subsidiaries, secured by substantially all of San Mateo I’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II.

~~2019~~2020 Capital Expenditure Budget

On ~~July 31, 2019,~~April 29, 2020, we ~~increased~~decreased the range of our anticipated 2019 midstream capital expenditures from $55 to $75 million to $70 to $90 million, primarily for capital expenditures necessary to accommodate new customers and increased commitments from existing customers. The anticipated 2019 midstream capital expenditures reflect our proportionate share of San Mateo’s estimated 2019 capital expenditures and also account for portions of the $50 million capital carry that Five Point Energy LLC (“Five Point”) agreed to provide to us in conjunction with the formation of San Mateo II.

~~At July 31, 2019, our 2019 estimated~~full-year 2020 capital expenditures for drilling, completing and equipping wells from $690.0 to $750.0 million to $440.0 to $500.0 million, as we plan to reduce our operated drilling program from six rigs to three rigs by June 30, 2020, as noted above. At April 29, 2020, the range of our estimated 2020 midstream capital expenditures remained ~~$640~~$85.0 to ~~$680 million, despite an increase of four gross (6.8 net) additional operated wells expected to be completed and turned to sales in 2019, as compared to our original estimates.~~$105.0 million. See “— Liquidity and Capital Resources — ~~2019~~2020 Capital Expenditure Budget” for more ~~information regarding~~information.

Restructuring of Derivative Financial Instruments

During April 2020, we restructured a portion of our ~~2019 capital expenditure budget.~~then-existing 2020 West Texas Intermediate (“WTI”) oil derivative financial instruments, providing additional revenue protection should oil prices remain at currently depressed levels for the remainder of 2020 or should further market disruptions occur. As a result of these modifications, we almost doubled our oil volumes hedged for the period from April through December 2020. At April 29, 2020, we had approximately 10.3 million Bbl of oil hedged for the period from April through December 2020. These restructured derivative financial instruments include approximately 7.6 million Bbl of fixed-price oil swaps at a weighted average price of approximately $35 per Bbl and 2.3 million Bbl of oil collars with a weighted average floor price of approximately $48 per Bbl and a weighted average ceiling price of approximately $66 per Bbl. We also have approximately 0.4 million Bbl in oil put options, which represent options to sell at a specified exercise price, at a weighted average price of approximately $48 per Bbl for the period from April through June 2020.

In addition, during April 2020, we added approximately 5.5 million Bbl of oil swaps at a weighted average price of approximately $35 per Bbl for 2021. We also added natural gas collars for November and December 2020 for approximately 3.2 million MMBtu and for the first quarter of 2021 for approximately 4.8 million MMBtu, each with a weighted average floor price of approximately $2.52 per MMBtu and a weighted average ceiling price of approximately $3.71 per MMBtu.

Critical Accounting Policies

Other than as discussed in Note 2 to the interim unaudited condensed consolidated financial statements in this Quarterly Report related to the adoption of Accounting Standards Update (“ASU”) 2016-02, ~~Leases (Topic 842)~~ ~~and the amendments provided for in ASU 2018-11,~~ ~~Leases (Topic 842), along with the adoption of ASU 2018-07,~~ ~~Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting~~,~~there~~There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.

Recent Accounting Pronouncements

~~See Note 2 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of~~There are no recent accounting pronouncements ~~and the~~that are expected to have a material impact ~~of the adoption of these pronouncements~~ on our financial statements.

Results of Operations

Revenues

The following table summarizes our unaudited revenues and production data for the periods indicated:


	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended March 31,
	2019		2018			2019			2018			2020		2019
Operating Data:
Revenues (in thousands):⁽¹⁾
Oil	$	189,085	$	166,271		$	343,288		$	314,430		$	169,585	$	154,204
Natural gas	21,975		42,748			61,041			76,543			28,329		39,065
Total oil and natural gas revenues	211,060		209,019			404,329			390,973			197,914		193,269
Third-party midstream services revenues	14,359		3,407			26,197			6,475			15,830		11,838
Sales of purchased natural gas	8,963		—			20,194			—			10,544		11,231
Realized gain (loss) on derivatives	1,165		(2,488		)	4,435			(6,746		)
Realized gain on derivatives												10,867		3,270
Unrealized gain (loss) on derivatives	6,157		1,429			(39,562		)	11,845			136,430		(45,719		)
Total revenues	$	241,704	$	211,367		$	415,593		$	402,547		$	371,585	$	173,889
Net Production Volumes:⁽¹⁾
Oil (MBbl)⁽²⁾	3,346		2,706			6,452			5,088			3,697		3,107
Natural gas (Bcf)⁽³⁾	13.4		12.7			27.1			22.8			16.7		13.7
Total oil equivalent (MBOE)⁽⁴⁾	5,577		4,817			10,972			8,892			6,476		5,395
Average daily production (BOE/d)⁽⁵⁾	61,290		52,937			60,619			49,126			71,161		59,941
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	56.51	$	61.44		$	53.20		$	61.80		$	45.87	$	49.64
Oil, with realized derivatives (per Bbl)	$	56.86	$	60.52		$	53.91		$	60.46		$	48.81	$	50.72
Natural gas, without realized derivatives (per Mcf)	$	1.64	$	3.38		$	2.25		$	3.35		$	1.70	$	2.85
Natural gas, with realized derivatives (per Mcf)	$	1.64	$	3.38		$	2.25		$	3.36		$	1.70	$	2.84

_________________


(1)	We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues.


(2)	One thousand ~~barrels~~Bbl of oil.


(3)	One billion cubic feet of natural gas.


(4)	One thousand ~~barrels~~Bbl of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.


(5)	Barrels of oil equivalent per day, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Three Months Ended ~~June 30, 2019~~March 31, 2020 as Compared to Three Months Ended ~~June 30, 2018~~March 31, 2019

Oil and natural gas revenues. Our oil and natural gas revenues increased ~~$2.0~~$4.6 million, or 1%2%, to ~~$211.1~~$197.9 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$209.0~~$193.3 million for the three months ended ~~June 30, 2018.~~March 31, 2019. Our oil revenues increased ~~$22.8~~$15.4 million, or ~~14%~~10%, to $~~189.1~~169.6 million for the three months ended ~~June 30, 2019~~March 31, 2020, as compared to $~~166.3~~154.2 million for the three months ended ~~June 30, 2018~~March 31, 2019. The increase in oil revenues resulted from the ~~24%~~19% increase in our oil production to ~~3.3~~3.7 million Bbl of oil for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~2.7~~3.1 million Bbl of oil for the three months ended ~~June 30, 2018.~~March 31, 2019. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. This increase was partially offset by a lower weighted average oil price realized for the three months ended ~~June 30, 2019~~March 31, 2020 of ~~$56.51~~$45.87 per Bbl, a decrease of 8% as compared to ~~$61.44~~$49.64 per Bbl realized for the three months ended ~~June 30, 2018.~~March 31, 2019. Our natural gas revenues decreased by ~~$20.8~~$10.7 million, or ~~49%~~27%, to ~~$22.0~~$28.3 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$42.7~~$39.1 million for the three months ended ~~June 30, 2018.~~March 31, 2019. The decrease in natural gas revenues resulted from a ~~51%~~40% decrease in realized natural gas prices to ~~$1.64~~$1.70 per Mcf for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$3.38~~$2.85 per Mcf realized for the three months ended ~~June 30, 2018.~~March 31, 2019. This decrease was partially offset by the 6%22% increase in our natural gas production to ~~13.4~~16.7 Bcf for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~12.7~~13.7 Bcf for the three months ended ~~June 30, 2018.~~March 31, 2019. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware ~~Basin.~~Basin as well as from significant volumes of natural gas production associated with two non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019.

Third-party midstream services revenues. Our third-party midstream services revenues increased ~~$11.0~~$4.0 million, or ~~more than four-fold,~~34%, to ~~$14.4~~$15.8 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$3.4~~$11.8 million for the three months ended ~~June 30, 2018.~~March 31, 2019. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party salt water gathering and disposal revenues to approximately $6.3 million for the three months ended June 30, 2019, as compared to approximately $1.9 million for the three months ended June 30, 2018, and (ii) an increase in our third-party natural gas gathering, transportation and processing revenues to approximately ~~$6.5~~$7.1 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$1.5~~$4.5 million for the three months ended ~~June 30, 2018.~~March 31, 2019, and (ii) an increase in our third-party salt water gathering and disposal revenues to approximately $6.7 million for the three months ended March 31, 2020, as compared to approximately $5.7 million for the three months ended March 31, 2019.

Sales of purchased natural gas. Our sales of purchased natural gas ~~were $9.0~~decreased $0.7 million, or 6%, to $10.5 million for the three months ended ~~June 30, 2019. We had no sales of purchased natural gas~~March 31, 2020, as compared to $11.2 million for the three months ended ~~June 30, 2018.~~March 31, 2019. The decrease was the result of a decrease in both the volume sold and the weighted average natural gas price realized for the three months ended March 31, 2020. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas, process the ~~third party’s~~ natural gas at ~~the~~San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) ~~and then purchase,~~ and subsequently sell the residue gas and natural gas liquids (“NGL”) to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our interim unaudited condensed consolidated statement of operations.

Realized gain ~~(loss)~~ on derivatives. Our realized net gain on derivatives was ~~$1.2~~$10.9 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to a realized net ~~loss~~gain of ~~$2.5~~$3.3 million for the three months ended ~~June 30, 2018.~~March 31, 2019. We realized a net gain of ~~$1.2~~$11.5 million related to our oil costless collar contracts for the three months ended ~~June 30, 2019,~~March 31, 2020, resulting from oil prices that were below the floor prices of certain of our oil costless collar contracts. We realized a net loss of $0.6 million related to our oil basis swap contracts for the three months ended March 31, 2020, resulting from oil basis prices that were above the fixed prices of certain of our oil basis swap contracts. We realized an average gain on our oil derivatives contracts of approximately ~~$0.35~~$2.94 per Bbl produced during the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to an average ~~loss~~gain of approximately ~~$0.92~~$1.08 per Bbl produced during the three months ended ~~June 30, 2018.~~March 31, 2019. Our total oil volumes hedged for the three months ended ~~June 30, 2019~~March 31, 2020 represented ~~68%~~54% of our total oil production, as compared to ~~51%~~44% of our total oil production for the three months ended June 30, 2018. Our total natural gas volumes hedged for the three months ended June 30, 2019 represented 13% of our total natural gas production, as compared to 33% of our total natural gas production for the three months ended June 30, 2018.March 31, 2019.

Unrealized gain (loss) on derivatives. Our unrealized net gain on derivatives was ~~$6.2~~$136.4 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to an unrealized net ~~gain~~loss of ~~$1.4~~$45.7 million for the three months ended ~~June 30, 2018.~~March 31, 2019. During the three months ended ~~June 30, 2019,~~March 31, 2020, the net fair value of our open oil and natural gas derivative contracts increased to a net asset of ~~$10.3~~$132.6 million from a net ~~asset~~liability of ~~$4.1~~$3.9 million at ~~March~~December 31, 2019, resulting in an unrealized gain on derivatives of ~~$6.2~~$136.4 million for the three months ended ~~June 30, 2019.~~March 31, 2020. During the three months ended ~~June 30, 2018, the net fair value of our open oil and natural gas derivative contracts increased to a net liability of $3.4 million from a net liability of $4.8 million at~~ March 31, ~~2018, resulting in an unrealized gain on derivatives of $1.4 million for the three months ended June 30, 2018.~~

~~Six Months Ended June 30, 2019 as Compared to Six Months Ended June 30, 2018~~

~~Oil and natural gas revenues.~~ Our oil and natural gas revenues increased $13.4 million, or 3%, to $404.3 million for the six months ended June 30, 2019, as compared to $391.0 million for the six months ended June 30, 2018. Our oil revenues increased $28.9 million, or 9%, to $343.3 million for the six months ended June 30, 2019, as compared to $314.4 million for the six months ended June 30, 2018. The increase in oil revenues resulted from the 27% increase in our oil production to 6.5 million Bbl of oil for the six months ended June 30, 2019, as compared to 5.1 million Bbl of oil for the six months ended June 30, 2018. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. This increase was partially offset by a lower weighted average oil price realized for the six months ended June 30, 2019 of $53.20 per Bbl, a decrease of 14% as compared to $61.80 per Bbl realized for the six months ended June 30, 2018. Our natural gas revenues decreased by $15.5 million, or 20%, to $61.0 million for the six months ended June 30, 2019, as compared to $76.5 million for the six months ended June 30, 2018. The decrease in natural gas revenues resulted from a lower weighted average natural gas price realized for the six months ended June 30, 2019 of $2.25 per Mcf, a decrease of 33% as compared to $3.35 per Mcf realized for the six months ended June 30, 2018. This decrease was partially offset by the 19% increase in our natural gas production to 27.1 Bcf for the six months ended June 30, 2019, as compared to 22.8 Bcf for the six months ended June 30, 2018. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

~~Third-party midstream services revenues.~~ Our third-party midstream services revenues increased $19.7 million to $26.2 million, or just over four-fold, for the six months ended June 30, 2019, as compared to $6.5 million for the six months ended June 30, 2018. This increase was primarily attributable to (i) an increase in our third-party salt water gathering and disposal revenues to approximately $12.0 million for the six months ended June 30, 2019, as compared to approximately $3.0 million for the six months ended June 30, 2018, and (ii) an increase in natural gas gathering, transportation and processing revenues to approximately $11.0 million for the six months ended June 30, 2019, as compared to $3.4 million for the six months ended June 30, 2018.

~~Sales of purchased natural gas.~~ ~~Our sales of purchased natural gas were $20.2 million for the six months ended June 30, 2019. We had no sales of purchased natural gas for the six months ended June 30, 2018.~~

~~Realized gain (loss) on derivatives.~~ Our realized net gain on derivatives was $4.4 million for the six months ended June 30, 2019, as compared to a realized net loss of $6.7 million for the six months ended June 30, 2018. We realized a net gain of $4.5 million related to our oil costless collar contracts for the six months ended June 30, 2019, resulting from oil prices that were below the floor prices of certain of our oil costless collar contracts. We realized net losses of $6.7 million from our oil and natural gas derivative contracts for the six months ended June 30, 2018, resulting from oil and natural gas prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts. We realized an average gain on our oil derivatives of approximately $0.70 per Bbl produced during the six months ended June 30, 2019, as compared to an average loss of $1.34 per Bbl produced during the six months ended June 30, 2018. Our total oil volumes hedged for the six months ended June 30, 2019 represented 57% of our total oil production, as compared to 53% of our total oil production for the six months ended June 30, 2018. Our total natural gas volumes hedged for the six months ended June 30, 2019 represented 13% of our total natural gas production, as compared to 37% of our total natural gas production for the six months ended June 30, 2018.

~~Unrealized (loss) gain on derivatives.~~ Our unrealized net loss on derivatives was $39.6 million for the six months ended June 30, 2019, as compared to an unrealized net gain of $11.8 million for the six months ended June 30, 2018. During the period from December 31, 2018 through June 30, 2019, the ~~aggregate~~ net fair value of our open oil and natural gas derivative contracts decreased to a net asset of ~~approximately $10.3~~$4.1 million from a net asset of ~~approximately~~ $49.8 million at December 31, 2018, resulting in an unrealized loss on derivatives of ~~approximately $39.6~~$45.7 million for the ~~six~~three months ended ~~June 30,~~March 31, 2019. During the period from December 31, 2017 through June 30, 2018, the aggregate net fair value of our open oil and natural gas derivative contracts increased from a net liability of approximately $15.2 million to a net liability of approximately $3.4 million, resulting in an unrealized gain on derivatives of approximately $11.8 million for the six months ended June 30, 2018.

Expenses

The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
(In thousands, except expenses per BOE)	2019			2018			2019			2018			2020			2019
Expenses:
Production taxes, transportation and processing	$	21,542		$	20,110		$	41,207		$	37,901		$	21,716		$	19,665
Lease operating	26,351			25,006			57,514			47,154			30,910			31,163
Plant and other midstream services operating	8,422			5,676			17,738			9,896			9,964			9,316
Purchased natural gas	8,172			—			18,806			—			8,058			10,634
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207			90,707			76,866
Accretion of asset retirement obligations	420			375			834			739			476			414
General and administrative	19,876			19,369			38,166			37,295			16,222			18,290
Total expenses	164,915			137,374			331,264			255,192			178,053			166,348
Operating income	76,789			73,993			84,329			147,355			193,532			7,541
Other income (expense):
Inventory impairment	(368		)	—			(368		)	—
Interest expense	(18,068		)	(8,004		)	(35,997		)	(16,495		)	(19,812		)	(17,929		)
Other expense	(423		)	(352		)	(532		)	(299		)
Other income (expense)													1,320			(110		)
Total other expense	(18,859		)	(8,356		)	(36,897		)	(16,794		)	(18,492		)	(18,039		)
Net income	57,930			65,637			47,432			130,561
Total income tax provision	12,858			—			11,845			—
Income (loss) before income taxes													175,040			(10,498		)
Total income tax provision (benefit)													39,957			(1,013		)
Net income attributable to non-controlling interest in subsidiaries	(8,320		)	(5,831		)	(15,782		)	(10,861		)	(9,354		)	(7,462		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700
Net income (loss) attributable to Matador Resources Company shareholders													$	125,729		$	(16,947	)
Expenses per BOE:
Production taxes, transportation and processing	$	3.86		$	4.17		$	3.76		$	4.26		$	3.35		$	3.65
Lease operating	$	4.72		$	5.19		$	5.24		$	5.30		$	4.77		$	5.78
Plant and other midstream services operating	$	1.51		$	1.18		$	1.62		$	1.11		$	1.54		$	1.73
Depletion, depreciation and amortization	$	14.37		$	13.87		$	14.31		$	13.74		$	14.01		$	14.25
General and administrative	$	3.56		$	4.02		$	3.48		$	4.19		$	2.51		$	3.39

Three Months Ended ~~June 30, 2019~~March 31, 2020 as Compared to Three Months Ended ~~June 30, 2018~~March 31, 2019

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased ~~$1.4~~$2.1 million, or 7%10%, to ~~$21.5~~$21.7 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$20.1~~$19.7 million for the three months ended ~~June 30, 2018. The~~March 31, 2019. This increase was primarily attributable to the ~~$1.3~~$1.5 million increase in transportation and processing fees to ~~$6.3~~$7.6 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$5.0~~$6.1 million for the three months ended ~~June 30, 2018,~~March 31, 2019, principally due to the 6%22% increase in our natural gas production to ~~13.4~~16.7 Bcf of natural gas for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~12.7~~13.7 Bcf of natural gas for the three months ended ~~June 30, 2018.~~March 31, 2019. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 7%8% to ~~$3.86~~$3.35 per BOE for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$4.17~~$3.65 per BOE for the three months ended ~~June 30, 2018. The~~March 31, 2019. This decrease was primarily attributable to the 20% increase in our total oil equivalent production to 6.5 million BOE for the three months ended March 31, 2020, as compared to 5.4 million BOE for the three months ended March 31, 2019, and lower production taxes on a per unit basis as a result of the decrease in the weighted average oil and natural gas prices realized between the two periods.

Lease operating. Our lease operating expenses ~~increased $1.3~~decreased $0.3 million, or 5%1%, to ~~$26.4~~$30.9 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$25.0~~$31.2 million for the three months ended ~~June 30, 2018. The increase~~March 31, 2019. This decrease was largely attributable to decreases in equipment rental and workover expenses of $1.7 million, as well as a decrease in saltwater disposal expenses of $4.3 million associated with connecting more wells to salt water disposal pipelines. These decreases were largely offset by increases in compression, repairs and ~~maintenance and non-operated lease operating~~other expenses of ~~approximately $2.6 million for the three months ended June 30, 2019, as compared to the three months ended June 30, 2018. This increase was partially offset by~~$5.7 million. On a ~~decrease in salt water trucking and disposal costs as more of~~unit-of-production basis, our ~~operated wells have been connected to salt water disposal pipelines. Our~~ lease operating expenses decreased ~~9% on a unit-of-production basis~~17% to ~~$4.72~~$4.77 per BOE for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$5.19~~$5.78 per BOE for the three months ended ~~June 30, 2018, as a result of~~March 31, 2019. This decrease was attributable to the ~~16%~~20% increase in our total oil equivalent production to 6.5 million BOE for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to 5.4 million BOE for the three months ended ~~June 30, 2018.~~March 31, 2019.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased ~~$2.7~~$0.6 million, or ~~48%~~7%, to ~~$8.4~~$10.0 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$5.7~~$9.3 million for the three months ended ~~June 30, 2018.~~March 31, 2019. This increase was primarily attributable to (i) increased expenses associated with the Black River Processing Plant of $3.1 million for the three months ended June 30, 2019, as compared to $1.9 million for the three months ended June 30, 2018, (ii) increased expenses associated with our expanded commercial salt water disposal operations of ~~$3.8~~$5.1 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$3.0~~$4.3 million for the three months ended June 30, 2018, and (iii) increased expenses associated with pipeline operations of $1.6 million for the three months ended June 30, 2019, as compared to $1.0 million for the three months ended June 30, 2018.March 31, 2019.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased ~~$13.3~~$13.8 million, or ~~20%~~18%, to ~~$80.1~~$90.7 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$66.8~~$76.9 million for the three months ended June 30, 2018. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 4% to $14.37 per BOE for the three months ended June 30, 2019, as compared to $13.87 per BOE for the three months ended June 30, 2018. TheMarch 31, 2019. This increase ~~in our total depletion, depreciation and amortization expenses~~ was primarily attributable to (i) the ~~16%~~20% increase in our total oil equivalent production to ~~5.6~~6.5 million BOE for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~4.8~~5.4 million BOE for the three months ended ~~June 30, 2018,~~March 31, 2019, and (ii) increased depreciation expenses attributable to our midstream segment of ~~approximately $3.8~~$4.8 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$2.3~~$3.7 million for the three months ended ~~June 30, 2018.~~March 31, 2019. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 2% to $14.01 per BOE for the three months ended March 31, 2020, as compared to $14.25 per BOE for the three months ended March 31, 2019. On a unit-of-production basis, the impact of the ~~increases in total oil equivalent production and midstream depreciation expenses was largely offset by~~ higher total proved oil and natural gas reserves at ~~June 30, 2019,~~March 31, 2020, as compared to ~~June 30, 2018,~~March 31, 2019, primarily attributable to our ongoing delineation and development ~~drilling~~ activities in the Delaware ~~Basin.~~Basin, was largely offset by the increase in total oil equivalent production for the three months ended March 31, 2020, as compared to the three months ended March 31, 2019.

Full-cost ceiling impairment. We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, we are required to perform a ceiling test each quarter that determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For the three months ended March 31, 2020 and 2019, the full-cost ceiling was higher than the capitalized costs of oil and natural gas properties, and, as a result, no impairment charge was necessary.

The unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended March 31, 2020 were $52.23 per Bbl and $2.30 per MMBtu, respectively. If the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended March 31, 2020 had been $42.42 per Bbl and $2.05 per MMBtu, respectively, while all other factors remained constant, our full-cost ceiling would have been impaired by approximately $550.0 million on a pro forma basis. The aforementioned pro forma prices, as estimated for the twelve month period July 2019 through June 2020, were calculated using a 12-month unweighted arithmetic average of oil and natural gas prices, which included the oil and natural gas prices on the first day of the month for the 10 months ended April 2020, with the price for April 2020 being held constant for May and June 2020. This pro forma excess of our net capitalized costs above the full-cost ceiling is attributable to a pro forma reduction of approximately $840.0 million in the estimated value, discounted at 10%, of our total proved oil and natural gas reserves, including a pro forma decrease in our estimated total proved reserves of approximately 8% from our estimated proved reserves at March 31, 2020, primarily attributable to certain proved undeveloped locations that would no longer be classified as proved undeveloped reserves using the pro forma prices. This calculation of the impact of lower commodity prices on our estimated total proved oil and natural gas reserves and our full-cost ceiling was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, this calculation strictly isolates the impact of commodity prices on our full-cost ceiling and proved reserves. The impact of prices is only one of several variables in the estimation of our proved reserves and full-cost ceiling and other factors could have a significant impact on our future proved reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, acquisitions of proved reserves, changes in drilling and completion and operating costs, drilling results, revisions due to well performance and other factors, changes in development plans and production, among others. There are numerous uncertainties inherent in the estimation of proved oil and natural gas reserves and accounting for oil and natural gas properties in subsequent periods, and this pro forma estimate should not be construed as indicative of our development plans or future results.

General and administrative. Our general and administrative expenses ~~increased $0.5~~decreased $2.1 million, or 3%11%, to ~~$19.9~~$16.2 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$19.4~~$18.3 million for the three months ended ~~June 30, 2018.~~March 31, 2019. The decrease in general and administrative expenses was primarily attributable to a decrease of $2.6 million in stock-based compensation expense related to our liability-based awards as a result of the decrease in the price of our common stock at March 31, 2020, as compared to December 31, 2019. This decrease was partially offset by decreased capitalized general and administrative expenses on certain qualifying projects between the two periods. Our general and administrative expenses decreased ~~11%~~26% on a unit-of-production basis to ~~$3.56~~$2.51 per BOE for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$4.02~~$3.39 per BOE for the three months ended ~~June 30, 2018, primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.~~March 31, 2019.

Interest expense. For the three months ended ~~June 30, 2019,~~March 31, 2020, we incurred total interest expense of ~~approximately $20.7~~$21.3 million. We capitalized ~~approximately $2.6~~$1.4 million of our interest expense on certain qualifying projects for the three months ended ~~June 30, 2019~~March 31, 2020 and expensed the remaining ~~$18.1~~$19.8 million to operations. For the three months ended ~~June 30, 2018,~~March 31, 2019, we incurred total interest expense

of ~~approximately $10.6~~$19.6 million. We capitalized ~~approximately $2.6~~$1.6 million of our interest expense on certain qualifying projects for the three months ended ~~June 30, 2018~~March 31, 2019 and expensed the remaining ~~$8.0~~$17.9 million to operations.

Total income tax provision. We recorded a total income tax expense of ~~$12.9~~$40.0 million for the three months ended ~~June 30, 2019,~~March 31, 2020, which ~~differs~~differed from amounts computed by applying the U.S. federal statutory ~~rate~~tax rates to pre-tax income due primarily to the impact of permanent differences between book and taxable income and state taxes, primarily in New Mexico. The effective tax income. Due to a variety of factors, including our significant net income in 2017 and 2018, our federal valuation allowance and a portion of our 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 our 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. At June 30, 2018, our deferred tax assets exceeded our deferred tax liabilities due to the deferred tax amounts generated by full-cost ceiling impairment charges recorded in prior periods. As a result, we established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015. We retained a full valuation allowance at June 30, 2018 due to uncertainties regarding the future realization of our deferred tax assets.

~~Six Months Ended June 30, 2019 as Compared to Six Months Ended June 30, 2018~~

~~Production taxes, transportation and processing.~~ ~~Our production taxes, transportation and processing expenses increased $3.3 million, or 9%, to $41.2 million~~rate for the ~~six~~three months ended ~~June 30, 2019, as compared to $37.9 million for the six months ended June 30, 2018. The increase in production taxes, transportation and processing expenses~~March 31, 2020 was primarily attributable to the $2.8 million increase in our transportation and processing expenses for the six months ended June 30, 2019, as compared to the six months ended June 30, 2018, principally due to the 19% increase in our natural gas production to 27.1 billion Bcf of natural gas for the six months ended June 30, 2019, as compared to 22.8 billion Bcf of natural gas for the six months ended June 30, 2018. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 12% to $3.76 per BOE for the six months ended June 30, 2019, as compared to $4.26 per BOE for the six months ended June 30, 2018. The decrease was primarily attributable to lower production taxes on a per unit basis as a result of the decrease in weighted average oil and natural gas prices realized between the two periods.

~~Lease operating.~~ Our lease operating expenses increased $10.4 million, or 22%, to $57.5 million for the six months ended June 30, 2019, as compared to $47.2 million for the six months ended June 30, 2018. The increase in lease operating expenses for the six months ended June 30, 2019, as compared to the six months ended June 30, 2018, was primarily attributable to an increase in costs of services and equipment, including salt water disposal costs in asset areas other than Wolf and Rustler Breaks (which are

~~serviced by San Mateo)~~24%. ~~Our lease operating expenses on a unit-of production basis decreased 1% to $5.24 per BOE for the six months ended June 30, 2019, as compared to $5.30 per BOE for the six months ended June 30, 2018.~~

~~Plant and other midstream services operating.~~ Our plant and other midstream services operating expenses increased $7.8 million, or 79%, to $17.7 million for the six months ended June 30, 2019, as compared to $9.9 million for the six months ended June 30, 2018. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial salt water disposal operations of $8.1 million for the six months ended June 30, 2019, as compared to $5.2 million for the six months ended June 30, 2018, (ii) increased expenses associated with the Black River Processing Plant, which was expanded late in the first quarter of 2018, of $6.1 million for the six months ended June 30, 2019, as compared to $3.6 million for the six months ended June 30, 2018, and (iii) increased expenses associated with pipeline operations of $3.7 million for the six months ended June 30, 2019, as compared to $1.6 million for the six months ended June 30, 2018.

~~Depletion, depreciation and amortization.~~ Our depletion, depreciation and amortization expenses increased $34.8 million, or 28%, to $157.0 million for the six months ended June 30, 2019, as compared to $122.2 million for the six months ended June 30, 2018. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 4% to $14.31 per BOE for the six months ended June 30, 2019, as compared to $13.74 per BOE for the six months ended June 30, 2018. The increase in our total depletion, depreciation and amortization expenses was primarily attributable to (i) the 23% increase in our total oil equivalent production to 11.0 million BOE for the six months ended June 30, 2019, as compared to 8.9 million BOE for the six months ended June 30, 2018, and (ii) the increase in depreciation expenses attributable to our midstream segment of approximately $9.3 million for the six months ended June 30, 2019, as compared to $5.2 million for the six months ended June 30, 2018. On a unit-of-production basis, the impact of the increases in total oil equivalent production and midstream depreciation expenses was largely offset by higher total proved oil and natural gas reserves at June 30, 2019, as compared to June 30, 2018, primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

~~General and administrative.~~ Our general and administrative expenses increased $0.9 million, or 2%, to $38.2 million for the six months ended June 30, 2019, as compared to $37.3 million for the six months ended June 30, 2018. Primarily as a result of the 23% increase in total oil equivalent production for the six months ended June 30, 2019, as compared to the six months ended June 30, 2018, our general and administrative expenses decreased 17% on a unit-of-production basis to $3.48 per BOE for the six months ended June 30, 2019, as compared to $4.19 per BOE for the six months ended June 30, 2018.

~~Interest expense.~~ For the six months ended June 30, 2019, we incurred total interest expense of approximately $40.2 million. We capitalized approximately $4.2 million of our interest expense on certain qualifying projects for the six months ended June 30, 2019 and expensed the remaining $36.0 million to operations. For the six months ended June 30, 2018, we incurred total interest expense of approximately $21.0 million. We capitalized approximately $4.5 million of our interest expense on certain qualifying projects for the six months ended June 30, 2018 and expensed the remaining $16.5 million to operations.

~~Total income tax provision.~~ We recorded a total income tax ~~expense~~benefit of ~~$11.8~~$1.0 million for the ~~six~~three months ended ~~June 30,~~March 31, 2019, and the effective tax rate was 33%, which ~~differs~~differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax ~~income~~loss due primarily ~~due~~ to the impact of permanent differences between book and tax income. Due to a variety of factors, including our significant net income in 2017 and 2018, our federal valuation allowance and a portion of our 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 our 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. At June 30, 2018, our deferred tax assets exceeded our deferred tax liabilities due to the deferred tax amounts generated by full-cost ceiling impairment charges recorded in prior periods. As a result, we established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015. We retained a full valuation allowance at June 30, 2018 due to uncertainties regarding the future realization of our deferred tax assets.loss.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during the remainder of ~~2019~~2020 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund ~~our capital expenditure requirements for~~ the remainder of ~~2019~~our 2020 capital expenditures primarily through a combination of cash on hand, operating cash flows, performance incentives in connection with ~~the formation of~~ San Mateo, ~~I that were received in the first quarter of 2019,~~ borrowings under the Credit Agreement (assuming availability under our borrowing ~~base)~~base of $900.0 million) and borrowings under ~~the~~ San Mateo I’s revolving credit facility (the “San Mateo Credit ~~Facility.~~Facility”) (assuming availability under the accordion feature of such facility to up to $400.0 million). In addition, in 2020, we expect to receive the remaining portion of the $50.0 million capital carry Five Point agreed to provide to us in conjunction with the formation of San Mateo II. We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, or oil and natural gas producing assets, or leasehold interests ~~particularly in our non-core asset areas, the sale~~ or ~~joint venture of oil and natural gas~~ mineral interests ~~as well as~~and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows.

~~At June 30, 2019 and July 31, 2019, we had (i) $1.05 billion of outstanding 5.875% senior notes due 2026 (the “Notes”), (ii) $205.0 million in borrowings outstanding~~In February 2020, the lenders under the Credit Agreement completed their review of our proved oil and ~~(iii) approximately $13.6~~natural gas reserves at December 31, 2019, and, as a result, the borrowing base was affirmed at $900.0 million. We elected to increase the borrowing commitment from $500.0 million ~~in outstanding~~

~~letters~~to $700.0 million, and the maximum facility amount remained $1.5 billion. We also added two new banks to our lending group as part of ~~credit issued pursuant to~~this redetermination process. This February 2020 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement ~~and San Mateo I had $240.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $16.2 million in outstanding letters of credit issued pursuant~~are limited to the ~~San Mateo~~lowest of the borrowing base, the maximum facility amount and the elected commitment. The Credit ~~Facility.~~Agreement matures in October 2023. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. The Company believes that it was in compliance with the terms of the Credit Agreement at March 31, 2020.

At ~~June 30, 2019,~~March 31, 2020, we had cash totaling approximately ~~$60.0~~$27.1 million and restricted cash ~~most of~~totaling approximately $29.7 million, which was associated with San ~~Mateo, totaling approximately $24.8 million.~~Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

~~In April 2019, the lenders under our Credit Agreement, led by Royal Bank~~At March 31, 2020, we had (i) $1.05 billion of ~~Canada, completed their review of our proved oil and natural gas reserves at December 31, 2018, and as a result, the borrowing base was increased to $900.0~~outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $315.0 million ~~with the elected borrowing commitment remaining at $500.0 million. This April 2019 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings~~in borrowings outstanding under the Credit Agreement ~~are limited~~and (iii) approximately $46.0 million in outstanding letters of credit issued pursuant to the ~~lowest~~Credit Agreement. Between March 31 and April 29, 2020, we borrowed an additional $30.0 million under the Credit Agreement.

At March 31, 2020, San Mateo had $307.5 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the ~~borrowing base, the maximum facility amount~~San Mateo Credit Facility. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases to up to $400.0 million, and ~~the elected borrowing commitment.~~

~~In June 2019,~~matures in December 2023. At March 31, 2020, the lender commitments under the San Mateo Credit Facility ~~led by The Bank of Nova Scotia,~~ were ~~increased to $325.0 million, using the accordion feature.~~$375.0 million. The San Mateo Credit Facility is guaranteed by San Mateo I’s subsidiaries, secured by substantially all of San Mateo I’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo ~~II.~~II and its subsidiaries. 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 for such period, of 2.50 or more. The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at March 31, 2020.

2020 Capital Expenditure Budget

During the ~~second~~first quarter of ~~2019,~~2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to just above $20 per Bbl in late March. This sudden decline in oil prices was attributable to two primary factors: (1) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (2) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. Primarily as a result of these unexpected events and the resulting declines in oil prices, Matador has significantly modified its 2020 operational plan.

We began 2020 operating six drilling rigs in the Delaware Basin, as we continued ~~our~~to focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We ~~began 2019 operating~~had originally planned to operate these six drilling rigs in the Delaware Basin throughout 2020. As a result of the events noted above, however, we released one operated drilling rig from our Wolf asset area in Loving County, Texas late in the first quarter of 2020, and ~~continued to do so at June 30, 2019. During~~we released a second operated drilling rig from the Greater Stebbins Area in late April 2020. We anticipate releasing one additional drilling rig by the end of the second quarter ~~these six operated drilling rigs were deployed across our Delaware Basin asset areas, but with an increased focus on the Antelope Ridge asset area. We~~of 2020. Thereafter, we expect to operate ~~six~~three drilling rigs in the Delaware Basin throughout the remainder of ~~2019, with four~~2020. Two of these rigs ~~operating between~~are anticipated to operate in our Stateline asset area in Eddy County, New Mexico, and the third rig is expected to operate primarily in the Rustler Breaks and Antelope Ridge asset areas, one rig operating in the Wolf and Jackson Trust asset areas and one rig operating in the Arrowhead, Ranger and Twin Lakes asset areas, although this rig, in particular, is expected to operate in the Greater Stebbins Area for most of the remainder of 2019. We expect that developmentareas.

As a result of our ~~Delaware Basin assets will be~~plans to reduce our operated drilling program from six to three rigs by the ~~primary focus~~end of ~~our operations and capital expenditures for the remainder of 2019.~~

~~During~~ the second quarter of ~~2019,~~2020, on April 29, 2020, we ~~also finished~~decreased the range of our nine-well program in South Texas, which we began in October 2018, including eight Eagle Ford shale wells and one Austin Chalk well. The rig used to drill these nine wells was released in early February 2019, and we have no additional operated drilling activities planned in the Eagle Ford shale for the remainder of 2019.

~~2019 Capital Expenditure Budget~~

~~At July 31, 2019, our 2019 estimated~~anticipated full-year 2020 capital expenditures for drilling, completing and equipping wells ~~(“D/C/E”) remained $640~~from $690.0 to ~~$680~~$750.0 million as originally estimated. As a result of improved drilling and completion and capital efficiencies, an accelerated pace of activity and our expectations for acquiring additional working interests primarily through acreage trades in certainto $440.0 to $500.0 million. The range of our operated wells throughout 2019, we now expect to complete and turn to sales four gross (6.8 net) additional operated wells in 2019, as compared to our original 2019 plan, which includes four gross (3.0 net) additional wells resulting from an accelerated pace of drilling and completion activity in 2019 and 3.8 net additional wells attributable to increased working interests acquired or anticipated to be acquired in certain operated wells during the course of the year. Due to the lower well costs and facilities savings achieved thus far in 2019, however, at July 31, 2019, we anticipate we should be able to deliver these additional well completions within our originally budgeted estimates for D/C/Efull-year 2020 capital expenditures ~~of $640 to $680 million. In addition, at July 31, 2019, we have no plans to add a seventh rig to our 2019 drilling program.~~

~~On July 31, 2019, we increased our anticipated 2019~~for midstream capital expenditures ~~from $55~~remained $85.0 to ~~$75~~$105.0 million, to $70 to $90 million, primarily for capital expenditures necessary to accommodate new customers and increased commitments from existing customers. During the first six months of 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer and obtained a significant additional acreage dedication and a salt water disposal well permit from an existing salt water customer. In addition, San Mateo is in negotiations with other third parties to provide oil, natural gas and salt water gathering services, natural gas processing services and salt water disposal services. In order to provide the midstream services under these executed and anticipated agreements, San Mateo expects to undertake additional projects that will require added compression, oil, natural gas and water gathering lines and water disposal infrastructure not originally budgeted for in 2019. At July 31, 2019, San Mateo had also entered into an agreement to acquire an existing commercial salt water disposal well and facility, a salt water disposal permit and surface acreage near the Greater Stebbins Area. The anticipated total 2019 midstream capital expenditures of $70 to $90 million reflectwhich reflects our proportionate share of San Mateo’s estimated ~~2019~~ capital expenditures of $190.0 million to $235.0 million and also ~~account~~accounts for the remaining portions of the ~~$50~~$50.0 million capital carry that Five Point agreed to provide to us in conjunction with the formation of San Mateo II.

Substantially all of ~~our remaining 2019~~these 2020 estimated capital expenditures will be allocated to (i) the further delineation and development of our leasehold position, (ii) the continued construction of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities.

To narrow any potential difference between our ~~2019~~2020 capital expenditures and operating cash flows, we may divest portions of our non-core assets, particularly in the Haynesville shale and in parts of our South Texas ~~and Haynesville shale~~ positions (as we did in 2019, converting $21.9 million of non-core assets to cash), as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. ~~For example, in the second quarter and early in the third quarter of 2019,~~In addition, we successfully closed and received approximately $22 million in proceeds attributable to the sale of portions of our properties, primarily in our South Texas and Haynesville shale positions, as well as a small portion of our leasehold in a non-operated area of the Delaware Basin. We intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during ~~2019.~~2020. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these ~~2019~~2020 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for ~~2019.~~2020.

Our ~~2019~~2020 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures isare largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. ~~In addition, we attempt to avoid long-term service agreements where possible to minimize ongoing future commitments.~~

Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for the remainder of ~~2019~~2020 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we have forecasted and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of realized oil, natural gas and NGL prices for the remainder of ~~2019~~2020 and the hedges we currently have in place. As noted above, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices

during the first quarter of 2020. As of April 29, 2020, WTI oil prices were below $20 per Bbl and were anticipated to remain below $30 per Bbl for the remainder of 2020. For further discussion of our expectations of such commodity prices, see “— General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 87 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial ~~instruments at June 30, 2019.~~instruments.

Our unaudited cash flows for the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~ are presented below:


	Six Months Ended June 30,						Three Months Ended March 31,
(In thousands)	2019			2018			2020			2019
Net cash provided by operating activities	$	194,497		$	254,208		$	109,372		$	59,240
Net cash used in investing activities	(394,694		)	(493,562		)	(248,220		)	(214,880		)
Net cash provided by financing activities	200,975			280,385			130,515			118,368
Net change in cash and restricted cash	$	778		$	41,031		$	(8,333	)	$	(37,272	)
Adjusted EBITDAattributable to Matador Resources Company shareholders⁽¹⁾	$	268,943		$	254,592		$	140,576		$	124,839

__________________


(1)	Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Non-GAAP Financial Measures” below.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities ~~decreased $59.7~~increased $50.1 million to ~~$194.5~~$109.4 million for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 from ~~$254.2~~$59.2 million for the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019. Excluding changes in operating assets and liabilities, net

cash provided by operating activities increased to ~~$255.5~~$134.3 million for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 from ~~$251.0~~$117.7 million for the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, primarily attributable to ~~the increase in our total~~higher oil ~~equivalent~~and natural gas production, which was partially offset by ~~the decrease in~~lower realized oil and natural gas prices ~~between~~for the ~~two periods.~~three months ended March 31, 2020, as compared to the three months ended March 31, 2019. Changes in our operating assets and liabilities between the two periods resulted in a net ~~decrease~~increase of approximately ~~$64.2~~$33.6 million in net cash provided by operating activities for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, as compared to the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019.

Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of ~~the Organization of Petroleum Exporting Countries (OPEC),~~OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. Furthermore, the continued effect of COVID-19 and the corresponding decline in oil demand will also significantly impact the prices we receive for our oil production. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices.

Cash Flows Used in Investing Activities

Net cash used in investing activities ~~decreased~~increased by ~~$98.9~~$33.3 million to ~~$394.7~~$248.2 million for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 from ~~$493.6~~$214.9 million for the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019. This ~~decrease~~increase in net cash used in investing activities is due to an increase in ~~part to~~midstream capital expenditures of approximately $40.1 million, which was partially offset by a decrease of ~~$71.7~~$8.3 million in oil and natural gas properties capital expenditures for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, as compared to the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019. Cash used for midstream capital expenditures for the three months ended March 31, 2020 was primarily attributable to the expansion of the Black River Processing Plant and midstream facilities in the Greater Stebbins Area and the Stateline asset area. Cash used for oil and natural gas properties capital expenditures for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin and in South Texas. The remaining decrease in net cash used in investing activities was primarily attributable to a decrease in cash used for midstream capital expenditures of $14.2 million, primarily related to capital expenditures for San Mateo, and an increase of $13.9 million in proceeds from the sale of assets.Basin.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities ~~decreased~~increased by ~~$79.4~~$12.1 million to ~~$201.0~~$130.5 million for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 from ~~$280.4~~$118.4 million for the ~~six~~three months ended ~~June 30, 2018. This decrease in net~~March 31, 2019. During the three months ended March 31, 2020, our primary sources of cash ~~provided by~~from financing activities ~~is due~~included borrowings under the Credit Agreement of $60.0 million, borrowings under the San Mateo Credit Facility of $19.5 million and net contributions related to the formation of San Mateo I and from non-controlling interest owners in ~~part to a net increase in~~less-than-wholly-owned subsidiaries of $53.2 million. During the three months ended March 31, 2019, we had borrowings under our Credit Agreement of ~~$165.0~~$100.0 million, ~~between~~as well as net contributions related to the ~~two periods, offset by a reduction in proceeds from the issuance~~formation of ~~common stock of $226.6 million~~San Mateo I and ~~a decrease of $34.1 million in contributions~~ from non-controlling interest owners in less-than-wholly-owned ~~subsidiaries.~~subsidiaries of $18.7 million.

See Note 4 to the unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes.

Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
(In thousands)	2019			2018			2019			2018			2020			2019
Unaudited Adjusted EBITDA Reconciliation to Net Income:
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
Net income (loss) attributable to Matador Resources Company shareholders													$	125,729		$	(16,947	)
Net income attributable to non-controlling interest in subsidiaries	8,320			5,831			15,782			10,861			9,354			7,462
Net income	45,072			65,637			35,587			130,561
Net income (loss)													135,083			(9,485		)
Interest expense	18,068			8,004			35,997			16,495			19,812			17,929
Total income tax provision	12,858			—			11,845			—
Total income tax provision (benefit)													39,957			(1,013		)
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207			90,707			76,866
Accretion of asset retirement obligations	420			375			834			739			476			414
Unrealized (gain) loss on derivatives	(6,157		)	(1,429		)	39,562			(11,845		)	(136,430		)	45,719
Stock-based compensation expense	4,490			4,766			9,076			8,945			3,794			4,587
Inventory impairment	368			—			368			—
Consolidated Adjusted EBITDA	155,251			144,191			290,268			267,102			153,399			135,017
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,147		)	(6,853		)	(21,325		)	(12,510		)	(12,823		)	(10,178		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	144,104		$	137,338		$	268,943		$	254,592		$	140,576		$	124,839


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
(In thousands)	2019			2018			2019			2018			2020			2019
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	135,257		$	118,059		$	194,497		$	254,208		$	109,372		$	59,240
Net change in operating assets and liabilities	2,472			18,174			60,963			(3,190		)	24,899			58,491
Interest expense, net of non-cash portion	17,522			7,958			34,808			16,084			19,128			17,286
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,147		)	(6,853		)	(21,325		)	(12,510		)	(12,823		)	(10,178		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	144,104		$	137,338		$	268,943		$	254,592		$	140,576		$	124,839

Net income attributable to Matador ~~Resources Company~~ shareholders ~~decreased~~increased by ~~$23.1~~$142.7 million to ~~$36.8~~$125.7 million for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$59.8~~a net loss of $16.9 million for the three months ended ~~June 30, 2018.~~March 31, 2019. This ~~decrease~~increase in net income attributable to Matador ~~Resources Company~~ shareholders is primarily attributable to ~~(i)~~an increase of $182.1 million in unrealized gain on derivatives, from an unrealized loss of $45.7 million for the three months ended March 31, 2019 to an unrealized gain of $136.4 million for the three months ended March 31, 2020. This increase was partially offset by a ~~$13.3 million increase in depletion, depreciation and amortization expenses, (ii) a $10.1 million increase in interest expense and (iii) a $12.9~~$41.0 million increase in the deferred income tax provision between the two periods. This decrease was partially offset by an increase of $3.7 million from realized loss to realized gain on derivatives and an increase of $4.7 million in unrealized gain on derivatives.

Net income attributable to Matador Resources Company shareholders decreased by $99.9 million to $19.8 million for the six months ended June 30, 2019, as compared to $119.7 million for the six months ended June 30, 2018. This decrease inprovision. In addition, net income attributable to Matador Resources Company shareholders is primarily attributable to (i) a $51.4 million decrease from unrealized gain to unrealized loss on derivatives, (ii) a $34.8 million increase in depletion, depreciation and amortization expenses, (iii) a $19.5 million increase in interest expense and (iv) an $11.8 million increase in the deferred income tax provision between the two periods. This decrease was ~~partially offset~~positively impacted by an increase of $11.2 million from realized loss to realized gain on derivatives, a $13.4 million increase in oil and natural gas revenues and an increase of $19.7 million in third-party midstream services revenues.

Adjusted EBITDA, a non-GAAP financial measure, increased by $6.8 million to $144.1 million for the three months ended June 30, 2019, as compared to $137.3 million for the three months ended June 30, 2018. This increase is primarily attributable to higher oil and natural gas production, which was partially offset by lower realized oil and natural gas prices for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to the three months ended ~~June 30, 2018.~~

March 31, 2019.

Adjusted EBITDA, a non-GAAP financial measure, increased by ~~$14.4~~$15.7 million to ~~$268.9~~$140.6 million for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$254.6~~$124.8 million for the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019. This increase is primarily attributable to higher oil and natural gas production, which was partially offset by lower realized oil and natural gas prices for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, as compared to the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of ~~June 30, 2019,~~March 31, 2020, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) ~~termination obligations under drilling rig contracts, (iii)~~ firm transportation, gathering, processing and disposal commitments and ~~(iv)~~(iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See “— Obligations and Commitments” below and Note 109 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

Obligations and Commitments

We had the following material contractual obligations and commitments at ~~June 30, 2019~~March 31, 2020:


	Payments Due by Period										Payments Due by Period
(In thousands)	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years		Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
Contractual Obligations:
Borrowings under credit agreements and facilities, including letters of credit⁽¹⁾	$	474,871	$	—	$	—	$	474,871	$	—	$	677,528	$	—	$	—	$	677,528	$	—
Senior unsecured notes⁽²⁾	1,050,000		—		—		—		1,050,000		1,050,000		—		—		—		1,050,000
Office leases	28,112		3,724		7,963		8,415		8,010		25,382		3,997		8,080		8,564		4,741
Non-operated drilling commitments⁽³⁾	51,719		51,719		—				—
Non-operated drilling and other capital commitments⁽³⁾											64,449		30,746		20,000		13,703		—
Drilling rig contracts⁽⁴⁾	39,127		23,870		15,257		—		—		37,444		28,845		8,599		—		—
Asset retirement obligations(5)	32,242		1,556		2,441		537		27,708		37,633		515		3,379		1,995		31,744
Natural gas transportation, gathering and processing agreements with non-affiliates⁽⁵⁾⁽⁶⁾	554,863		43,786		113,567		113,598		283,912		634,239		54,977		133,912		134,070		311,280
Gathering, processing and disposal agreements with San Mateo⁽⁶⁾⁽⁷⁾	547,514		—		96,517		163,408		287,589		511,796		—		60,418		163,614		287,764
Natural gas engineering, construction and installation contract⁽⁷⁾⁽⁸⁾	71,820		71,820		—		—		—		19,416		19,416		—		—		—
Total contractual cash obligations	$	2,850,268	$	196,475	$	235,745	$	760,829	$	1,657,219	$	3,057,887	$	138,496	$	234,388	$	999,474	$	1,685,529

__________________

(1)

The amounts included in the table above represent principal maturities only. At ~~June 30, 2019~~March 31, 2020, we had ~~$205.0~~$315.0 million in borrowings outstanding under ~~our~~the Credit Agreement and approximately ~~$13.6~~$46.0 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2023. At ~~June 30, 2019,~~March 31, 2020, San Mateo I had ~~$240.0~~$307.5 million of borrowings outstanding under the San Mateo Credit Facility and approximately ~~$16.2~~$9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. Assuming the amounts outstanding and interest rates of ~~3.64%~~2.49% and ~~4.16%~~2.74% (for the Credit Agreement and the San Mateo Credit Facility), respectively, at ~~June 30, 2019,~~March 31, 2020, the interest expense is expected to be approximately ~~$7.5~~$8.0 million and ~~$10.0~~$8.5 million each year until maturity.


(2)	The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding as of ~~June 30, 2019~~March 31, 2020 is expected to be approximately $61.7 million each year until maturity.

(3)

At ~~June 30, 2019,~~March 31, 2020, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at June 30, 2019. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $51.7 million at June 30, 2019, which we expect to incur within the next 12 months.


(4)	We do not own or operate our own drilling rigs but instead enter into contracts with third parties for such drilling rigs.


(5)	The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at March 31, 2020.

(6)

From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and salt water from certain portions of our acreage for gathering, transportation, processing, fractionation, sales and, in the case of salt water, disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.

agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we will be required to pay certain deficiency fees. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.

~~(6)~~(7)

In February 2017, in connection with the formation of San Mateo I, we dedicated our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and certain future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. In February 2019, in connection with the formation of San Mateo II, we dedicated our current and certain future leasehold interests 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. See Note 109 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.

~~(7)~~(8)

Beginning 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. See Note 109 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.

General Outlook and Trends

~~In 2018~~During the first quarter of 2020, the oil and ~~2019,~~natural gas industry witnessed an abrupt and significant decline in oil ~~prices generally improved from the lower prices we experienced in 2016 and 2017, although oil prices remained significantly below their most recent highs in 2014.~~prices. For the three months ended ~~June 30, 2019,~~March 31, 2020, oil prices averaged ~~$59.96~~$45.78 per Bbl, ranging from a high of ~~$66.30~~$63.27 per Bbl in early January to a low of $20.09 per Bbl in late ~~April to a low of $51.14 per Bbl in mid-June,~~March, based upon the NYMEX ~~West Texas Intermediate~~WTI oil futures contract price for the earliest delivery date. This sudden decline in oil prices was attributable to two primary factors: (1) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (2) a sudden, unexpected increase in global oil supply resulting

from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria.

As noted previously in this Quarterly Report, Matador has significantly modified its 2020 operational plan primarily as a result of these unexpected events and the resulting decline in oil prices. We began 2020 operating six drilling rigs in the Delaware Basin but plan to reduce our operated drilling program from six to three drilling rigs by the end of the second quarter of 2020. Thereafter, we expect to operate three drilling rigs in the Delaware Basin throughout the remainder of 2020, but we are prepared to reduce our drilling activities further should conditions warrant. At April 29, 2020, the general outlook for the oil and natural gas industry for the remainder of 2020 remains highly uncertain, and we can provide no assurances as to when the economic disruptions resulting from COVID-19 and the corresponding decline in oil demand may begin to improve. Until such time, however, we anticipate that oil prices will remain well below the prices realized in 2019.

We realized a weighted average oil price of ~~$56.51~~$45.87 per Bbl ($~~56.86~~48.81 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$61.44~~$49.64 per Bbl ($~~60.52~~50.72 per Bbl including realized ~~losses~~gains from oil derivatives) for our oil production for the three months ended ~~June 30, 2018.~~March 31, 2019. At ~~July 31, 2019,~~April 29, 2020, the NYMEX ~~West Texas Intermediate~~WTI oil futures contract for the earliest delivery date had decreased significantly from the average price for the ~~second~~first quarter of ~~2019,~~2020, settling at ~~$58.58~~$15.06 per Bbl, which was also a significant decrease as compared to ~~$68.76 per Bbl~~$63.50 at ~~July 31, 2018.~~April 29, 2019.

Natural gas prices were significantly lower in the first quarter of 2020, as compared to the first quarter of 2019. For the three months ended ~~June 30, 2019,~~March 31, 2020, natural gas prices averaged ~~$2.51~~$1.87 per MMBtu, ranging from a high of ~~approximately $2.71~~$2.20 per MMBtu in early ~~April~~January to a low of ~~approximately $2.19~~$1.60 per MMBtu in late ~~June,~~March, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date.

We realized a weighted average natural gas price of ~~$1.64~~$1.70 per Mcf (with no realized gains or losses from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended ~~June 30, 2019,~~March 31, 2020, as compared to ~~$3.38~~$2.85 per Mcf ~~(with no~~($2.84 with realized ~~gains or~~ losses from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended ~~June 30, 2018.~~March 31, 2019. At ~~July 31, 2019,~~April 29, 2020, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had ~~decreased~~increased from the ~~average price for~~end of the ~~second~~first quarter of ~~2019,~~2020, settling at ~~$2.23~~$1.87 per MMBtu, which was ~~also~~ a decrease as compared to ~~$2.78~~$2.59 per MMBtu at ~~July 31, 2018.~~April 29, 2019.

The prices we receive for oil, natural gas and NGLs heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically, and, as a result, could have an adverse effect on our financial condition, results of operations, cash flows and ~~reserves.~~reserves and our ability to comply with the leverage ratio covenant under our Credit Agreement. We are uncertain if or when oil and natural gas prices may rise from their current levels, and, in fact, oil and natural gas prices may decrease in future periods. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” in the Annual Report.

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under ~~our~~the Credit Agreement and through the capital markets.

During April 2020, we restructured a portion of our then-existing 2020 WTI oil hedges, providing additional revenue protection should oil prices remain at currently depressed levels for the remainder of 2020 or should further market disruptions occur. As a result of these modifications, we almost doubled our oil volumes hedged for the period from April through December 2020. At April 29, 2020, we had approximately 10.3 million Bbl of oil hedged for the period from April through December 2020. These hedges include approximately 7.6 million Bbl of fixed-price oil swaps at a weighted average price of approximately $35 per Bbl and 2.3 million Bbl of oil collars with a weighted average floor price of approximately $48 per Bbl and a weighted average ceiling price of approximately $66 per Bbl. We also have approximately 0.4 million Bbl in oil put options at a weighted average price of approximately $48 per Bbl for the period from April through June 2020. In addition, during April 2020, we added approximately 5.5 million Bbl of oil swaps at a weighted average price of approximately $35 per Bbl for 2021. We also added natural gas collars for November and December 2020 for approximately 3.2 million MMBtu and for the first quarter of 2021 for approximately 4.8 million MMBtu, each with a weighted average floor price of approximately $2.52 per MMBtu and a weighted average ceiling price of approximately $3.71 per MMBtu.

The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX ~~West Texas Intermediate~~WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At ~~June 30, 2019,~~March 31, 2020, most of our oil production from the Delaware Basin was

sold based on prices established in Midland, ~~Texas, and~~Texas. For most of the first nine months of 2019, almost all of our natural gas production from the Delaware Basin was sold based on prices established at the Waha Hub in far West ~~Texas. During the second quarter~~Texas, and portions of ~~2018, the price differentials for oil sold in Midland and~~our natural gas are still sold atbased on Waha compared to the benchmark prices for oil and natural gas, respectively, began to widen significantly and continued to widen throughout most of the year. These widening basis differentials negatively impacted our oil and natural gas revenues in 2018.

During 2018, the Midland-Cushing (Oklahoma) oil price differential increased substantially from essentially no difference in the first quarter to as much as $16.00 per Bbl in late September but narrowed to about $5.00 per Bbl at the

beginning of 2019. The Midland-Cushing (Oklahoma) oil price differential narrowed further to less than $1.00 per Bbl during the first quarter of 2019 but widened again during the second quarter to levels experienced at the beginning of the year. The Midland-Cushing (Oklahoma) oil price differential has narrowed again early in the third quarter of 2019 and may become positive in the future, although it is possible that this differential could widen further at certain times during the remainder of 2019.

Our realized price for our Delaware Basin natural gas production is exposed to the Waha-Henry Hub basis differential. This natural gas price differential increased significantly throughout 2018 from about $0.50 per MMBtu at the beginning of the year to between $1.00 and $2.00 per MMBtu for most of 2018, but reaching highs of greater than $4.00 per MMBtu for a brief period nearprices. At the end of ~~the year. The natural gas price differential narrowed to between $1.00 and $2.00 per MMBtu at the beginning of~~September 2019, ~~and remained there throughout much of the first quarter.~~

The natural gas basis differentials widened significantly in April 2019 for a short period of time, including a few days when natural gas was being sold at Waha for negative prices as high as ($7.00) to ($9.00) per MMBtu on a daily market basis, resulting, in part, from a number of simultaneous outages and maintenance projects impacting major pipelines in the area. Natural gas prices at Waha were positive for most of the latter part of April 2019, but daily market prices for natural gas sold at Waha reached negative levels of ($2.00) to ($3.00) per MMBtu in late May. During the second quarter of 2019, the average daily Waha natural gas price was ($0.07) per MMBtu. In response to these basis differentials, we temporarily shut in certain high gas-oil ratio wells and took other actions to mitigate the impact of these negative prices on our results. Daily market prices for natural gas sold at Waha were positive for the month of July, although prices at Waha remained well below Henry Hub prices.

~~The majority of our Delaware Basin natural gas production is expected to remain exposed to the Waha-Henry Hub basis differentials until early in the fourth quarter of 2019, when~~however, the Kinder Morgan Gulf Coast Express Pipeline Project ~~(“GCX~~(the “GCX Pipeline”) ~~is expected to become~~became operational. We have secured firm natural gas transportation and sales on the GCX Pipeline for an average of approximately 110,000 to 115,000 MMBtu per day at a natural gas price based upon Houston Ship Channel pricing.

After a lengthy period beginning in the second quarter of 2018 in which the Midland-Cushing (Oklahoma) oil price differential was negative, reaching as high as ($16.00) per Bbl in late September 2018, this oil price differential became positive late in the third quarter of 2019 and remained positive into the first quarter of 2020. With the abrupt decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020. At April 29, 2020, this oil price differential was approximately $2.50 per Bbl, despite being approximately ($6.00) per Bbl earlier in April. It is possible that the differential could turn negative again at certain times during the remainder of 2020. At April 29, 2020, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated oil production for the remainder of 2020 and throughout 2021 and 2022.

In addition, as a result of oil futures prices being significantly higher than spot prices for oil, the monthly “roll,” which typically has minimal impact on our realized oil pricing, is expected to be significant and negative during the second quarter of 2020. As a result, our weighted average oil price differential relative to the WTI benchmark price is anticipated to be negative and in the range of ($6.00) to ($9.00) per Bbl in the second quarter of 2020, inclusive of the monthly roll and transportation costs.

Our realized prices for a portion of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential. This Waha basis differential has increased significantly over the past two years, including a few days in April 2019 when natural gas was being sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu on a daily market basis. During the second half of 2019, the Waha basis differentials improved, and natural gas prices at the Waha hub averaged approximately $1.00 per MMBtu for the final six months of the year. Despite improving during the second half of 2019, beginning in the fourth quarter, the Waha basis differential widened further at times, and natural gas prices at the Waha hub were slightly negative on certain days in late December 2019. In early 2020, the Waha basis differential continued to deteriorate, and natural gas prices at the Waha hub were negative on certain days in April 2020. However, the Waha basis differential narrowed in late April 2020, with the futures market indicating Waha basis differentials between ($0.30) and ($0.60) per MMBtu throughout the remainder of 2020 as of late April.

Beginning in late September 2019, as the GCX Pipeline became operational, we began selling a majority of our produced Delaware Basin natural gas at Houston Ship Channel pricing, and we have realized an improvement in the natural gas pricing received despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. Further, approximately ~~23%~~29% of our reported natural gas production in the ~~second~~first quarter of ~~2019~~2020 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing.

These widening oil and natural gas basis differentials are largely attributable to industry concerns regarding oil storage capacity and the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. At ~~July 31, 2019,~~April 29, 2020, we had not experienced oil storage concerns or material pipeline-related interruptions to our oil, natural gas or NGL production. ~~During the third quarter of 2018,~~In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware ~~Basin and elsewhere.~~Basin. Although we did not encounter such fractionation capacity problems, ~~then and do not expect to encounter such problems going forward,~~ we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity, oil storage or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected.

We anticipate that the volatility in these oil and natural gas price differentials could persist throughout ~~much of the remainder of 2019~~2020 or longer until additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets is ~~completed.~~completed and as the balance between oil supply and demand is restored. We can provide no assurances as to how long these volatile differentials may persist, and as noted above, these price differentials could ~~widen further~~deteriorate in future periods. Should we experience future periods of negative pricing for natural gas as we did during the second quarter of 2019, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. In addition, we have no derivative contracts in place to mitigate our exposure to these natural gas price differentials during 2020.

In addition to concerns regarding oil and natural gas prices and basis differentials, the ~~remainder~~destruction of ~~2019~~global oil demand resulting from decline in economic activity associated with COVID-19, in conjunction with the recent actions initiated by Saudi Arabia to increase its oil production to world markets, has led to a significant oversupply of oil worldwide. On April 10, 2020, the members of OPEC+ (led by Saudi Arabia) reversed course and ~~have limited~~announced their intentions to reduce oil ~~basis hedges in place~~production

significantly for the remainder of 2020 and into 2021 and 2022. It is uncertain, however, to what degree these production cuts may restore the balance between oil supply and demand, and most oil and natural gas industry observers remain skeptical that oil prices can improve substantially until oil demand begins to improve, most likely as a result of the “re-opening” of the world economy as concerns surrounding COVID-19 begin to subside.

In the near term, and certainly through the second quarter of 2020, there is a significant risk that oil production in the United States may exceed available oil storage capacity. Should this occur, we may be required by our oil purchasers to shut in a portion or all of our oil production for a period of time. Further, the concern over available oil storage capacity may also result in lower oil prices, and as a result, we may elect to shut in or curtail certain volumes of our oil production temporarily rather than sell the oil at further depressed prices. At April 29, 2020, we had determined to voluntarily curtail or shut in portions of our Delaware Basin and Eagle Ford shale oil production in May 2020 and will likely curtail and shut in portions of our oil production during June as well. As most of our natural gas production in the Delaware Basin is associated with oil production, portions of our natural gas production will also be curtailed or shut in. When shut-in wells resume production, they may not produce at their previous rates, and we may be required to expend capital to improve their production. We can provide no assurances as to whether additional portions of our oil production may be shut in or curtailed in the future or how long these periods may persist.

Further, if oil prices remain at their current depressed levels during the second quarter of 2020, we anticipate that we could realize a full-cost ceiling impairment to the net capitalized value of our oil and natural gas properties. In determining whether a full-cost ceiling impairment existed at March 31, 2020, we estimated the value, discounted at 10%, of our total proved oil and natural gas reserves using the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended March 31, 2020 as required under the guidelines established by the SEC, which were $52.23 per Bbl and $2.30 per MMBtu, respectively. No full cost ceiling impairment was required at March 31, 2020. If the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended March 31, 2020 had been $42.42 per Bbl and $2.05 per MMBtu, respectively, while all other factors remained constant, our full-cost ceiling would have been impaired by approximately $550.0 million on a pro forma basis. The aforementioned pro forma prices, as estimated for the twelve month period July 2019 through June 2020, were calculated using a 12-month unweighted arithmetic average of oil and natural gas prices, which included the oil and natural gas prices on the first day of the month for the 10 months ended April 2020, with the price for April 2020 being held constant for May and June 2020. This pro forma excess of our net capitalized costs above the full-cost ceiling is attributable to a pro forma reduction of approximately $840.0 million in the estimated value, discounted at 10%, of our total proved oil and natural gas reserves, including a pro forma decrease in our estimated total proved reserves of approximately 8% from our estimated proved reserves at March 31, 2020, primarily attributable to certain proved undeveloped locations that would no longer be classified as proved undeveloped reserves using the pro forma prices. This calculation of the impact of lower commodity prices on our estimated total proved oil and natural gas reserves and our full-cost ceiling was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, this calculation strictly isolates the impact of commodity prices on our full-cost ceiling and proved reserves. The impact of prices is only one of several variables in the estimation of our proved reserves and full-cost ceiling and other factors could have a significant impact on our future proved reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, acquisitions of proved reserves, changes in drilling and completion and operating costs, drilling results, revisions due to well performance and other factors, changes in development plans and production, among others. There are numerous uncertainties inherent in the estimation of proved oil and natural gas reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, in ~~early~~ 2019 and 2020, separate bills were introduced in the New Mexico Senate proposing to add a surtax on natural gas processors and proposing to place a moratorium on hydraulic fracturing. In 2019, New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Although ~~the~~such bills ~~relating to the moratorium on hydraulic fracturing and the tax on natural gas processors were~~have not passed, ~~in the most recent legislative session,~~ these and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. In addition, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry, recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.

Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production

declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” in the Annual Report.

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Except as set forth below, there have been no material changes to the sources and effects of our market risk since December 31, ~~2018,~~2019, which are disclosed in Part II, Item 7A of the Annual Report and incorporated herein by reference.

Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production.

We typically use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Traditional costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Participating three-way costless collars also provide ~~the Company~~us with downside price protection through the purchase of a put option, but they also allow ~~the Company~~us to participate in price upside through the purchase of a call option; the purchase of both the put option and the call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to ~~the Company.~~us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection.

In response to the decline in the price of oil, in April 2020 we repurchased the call options on certain existing open oil costless collars and kept the remaining put options, exchanged certain existing open oil costless collars and added oil swaps.

We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At ~~June 30, 2019,~~March 31, 2020, The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) were the counterparties for all of our derivative instruments. At April 29, 2020, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and ~~SunTrust~~Truist Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. See Note 87 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial ~~instruments at June 30, 2019.~~instruments. Such information is incorporated herein by reference.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of ~~June 30, 2019~~March 31, 2020 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and ~~that~~ (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls during the three months ended ~~June 30, 2019~~March 31, 2020 that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows.

On November 4, 2019, the Company received a Notice of Violation and Finding of Violation from the EPA and a Notice of Violation from the New Mexico Environment Department (the “NMED”) alleging violations of the Clean Air Act and New Mexico State Implementation Plan at certain of its operated locations in New Mexico. The Company has provided information to the EPA and NMED and is engaged in discussions regarding a resolution of the alleged violations. The Company believes it is remote that the resolution of this matter will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. Resolution of the matter may result in monetary sanctions of more than $100,000.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. For a discussion of such risks and uncertainties, please see “Item 1A. Risk Factors” in the Annual Report. There have been no material changes to the risk factors we have disclosed in the Annual Report, except as follows:

We Face Numerous Risks Related to the COVID-19 Global Pandemic, Which Has Had and Is Likely to Continue to Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows.

Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and industries around the world, including the exploration and production and midstream businesses. The rapid spread of COVID-19 has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures, nearly all of which have materially reduced global demand for crude oil. The extent to which COVID-19 will continue to affect our business, financial condition, results of operations and cash flows and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information which may emerge concerning the severity of COVID-19 and the effectiveness of actions taken to contain COVID-19 or treat its impact now or in the future, among others.

Some impacts of the COVID-19 pandemic that could have an adverse effect on our business, financial condition, results of operations and cash flows include:

significantly reduced prices for our oil, natural gas and NGL production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;

further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of COVID-19;

increased likelihood that we will, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political forces;

significant decreases in the volumes of oil, natural gas and water that are transported, gathered, processed or disposed of by San Mateo due to curtailed or shut-in production by Matador or other of San Mateo’s customers;

increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and NGL production in the markets in which we operate;

increased operational difficulties associated with the delivery of oil, natural gas and NGLs to end-markets, resulting from pipeline and storage constraints;

the potential for the operations of the Black River Processing Plant and other critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19;

the potential for forced curtailment of oil and NGL production by state governmental agencies, resulting in a need to significantly curtail or shut in our production;

the potential for loss of leasehold interests for the failure to produce oil and natural gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing;

increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and storage and the failure of certain of our counterparties to continue as going concerns;

increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions;

the potential impact for delays in construction or increased costs related to the expansion of the Black River Processing Plant and other midstream construction projects, including construction of the natural gas pipelines connecting our Stateline asset area and the Greater Stebbins Area to the Black River Processing Plant;

increased costs, staffing requirements and difficulties sourcing oilfield services related to social distancing measures implemented in connection with federal, state or local government and voluntarily imposed quarantines; and

increased legal and operational costs related to compliance with significant changes in federal, state and local laws and regulations.

The COVID-19 outbreak continues to rapidly evolve, and the extent to which the outbreak may impact our business, financial condition, results of operations and cash flows will depend highly on future developments, which are very uncertain and cannot be predicted with confidence. Additionally, the extent and duration of the impact of the COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors and, as a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the quarter ended ~~June 30, 2019,~~March 31, 2020, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

Period
Total Number of Shares Purchased⁽¹⁾
Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs
April 1, 2019 to April 30, 2019 1,526
$ 20.04
—
—
May 1, 2019 to May 31, 2019 1,460
$ 19.03
—
—
June 1, 2019 to June 30, 2019 1,026
$ 19.00
—
—
Total 4,012
$ 19.41
—
—



Period	Total Number of Shares Purchased⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs
January 1, 2020 to January 31, 2020	199	$	16.70	—	—
February 1, 2020 to February 29, 2020	99,150	$	12.94	—	—
March 1, 2020 to March 31, 2020	542	$	2.29	—	—
Total	99,891	$	12.89	—	—

_________________


(1)	The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

Item 6. Exhibits



Exhibit Number		Description

3.1		Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

3.2		Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

3.3		Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

3.4		Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018).

10.1†		Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan ~~(incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019)~~for employees with employment agreements (filed herewith).

10.2†		Form of ~~Restricted~~Performance Stock Unit Award Agreement for ~~director~~ awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (filed herewith).

~~10.3†~~10.3		~~Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (filed herewith).~~

~~10.4†~~		~~First~~Fourteenth Amendment to ~~the Employment Agreement between Matador Resources Company and G. Gregg Krug (filed herewith).~~

~~10.5†~~		~~First Amendment to the~~Third Amended and Restated ~~Employment~~Credit Agreement, ~~between Matador Resources~~dated as of February 27, 2020, by and among MRC Energy Company, as Borrower, the Lenders party thereto and ~~Bradley M. Robinson (filed herewith)~~Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2019).

31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

31.2		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32.1		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

32.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

101		The following financial information from Matador Resources Company’s Quarterly Report on Form 10-Q for the quarter ended ~~June 30, 2019~~March 31, 2020, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets - Unaudited, (ii) the Condensed Consolidated Statements of Operations - Unaudited, (iii) the Condensed Consolidated Statements of Changes in Shareholders’ Equity - Unaudited, (iv) the Condensed Consolidated Statements of Cash Flows - Unaudited and (v) the Notes to Condensed Consolidated Financial Statements - Unaudited (submitted electronically herewith).

104		Cover Page Interactive Data File, formatted in Inline ~~XBRL.~~XBRL (included as Exhibit 101).

†		Indicates a management contract or compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		MATADOR RESOURCES COMPANY

Date: ~~August 2, 2019~~May 1, 2020	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer



Date: ~~August 2, 2019~~May 1, 2020	By:	/s/ David E. Lancaster
		David E. Lancaster
		Executive Vice President and Chief Financial Officer

4541



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating leases
Lease operating	$	2,965	$	5,207
Plant and other midstream services	30		61
General and administrative	665		1,474
Total operating leases⁽¹⁾	3,660		6,742
Short-term leases
Lease operating	3,392		5,601
Plant and other midstream services	1,131		2,751
General and administrative	5		17
Total short-term leases⁽²⁾⁽³⁾	4,528		8,369
Financing leases
Depreciation of assets	231		440
Interest on lease liabilities	33		64
Total financing leases	264		504
Total lease expense	$	8,452	$	15,615



	Six Months Ended June 30, 2019
Cash paid related to lease liabilities
Operating cash payments for operating leases	$	6,790
Investing cash payments for operating leases	$	13,509
Financing cash payments for financing leases	$	490

Right of use assets obtained in exchange for lease obligations entered into during the period
Operating leases	$	28,884
Financing leases	$	471