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~~September 30, 2019



☐	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
(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,~~October 29, 2019, there were ~~116,646,526~~116,641,109 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED ~~JUNE~~SEPTEMBER 30, 2019

TABLE OF CONTENTS



	Page
PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements — Unaudited	3
Condensed Consolidated Balance Sheets at ~~June~~September 30, 2019 and December 31, 2018	3
Condensed Consolidated Statements of Operations for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2019 and 2018	4
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2019 and 2018	5
Condensed Consolidated Statements of Cash Flows for the ~~Six~~Nine Months Ended ~~June~~September 30, 2019 and 2018	79
Notes to Condensed Consolidated Financial Statements	810
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2527
Item 3. Quantitative and Qualitative Disclosures About Market Risk	4244
Item 4. Controls and Procedures	4244
PART II — OTHER INFORMATION	4345
Item 1. Legal Proceedings	4345
Item 1A. Risk Factors	4345
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4345
Item 6. Exhibits	4446
SIGNATURES	4547

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			September 30, 2019			December 31, 2018
ASSETS
Current assets
Cash	$	59,950		$	64,545		$	15,709		$	64,545
Restricted cash	24,812			19,439			25,097			19,439
Accounts receivable
Oil and natural gas revenues	66,921			68,161			86,333			68,161
Joint interest billings	61,872			61,831			74,880			61,831
Other	18,386			16,159			23,981			16,159
Derivative instruments	8,271			49,929			15,481			49,929
Lease and well equipment inventory	20,281			17,564			14,678			17,564
Prepaid expenses and other assets	12,891			8,057			13,157			8,057
Total current assets	273,384			305,685			269,316			305,685
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	4,094,417			3,780,236			4,363,545			3,780,236
Unproved and unevaluated	1,234,176			1,199,511			1,166,501			1,199,511
Midstream properties	492,420			428,025			557,841			428,025
Other property and equipment	25,170			22,041			26,754			22,041
Less accumulated depletion, depreciation and amortization	(2,462,840		)	(2,306,949		)	(2,554,516		)	(2,306,949		)
Net property and equipment	3,383,343			3,122,864			3,560,125			3,122,864
Other assets
Derivative instruments	2,202			—			4,650			—
Deferred income taxes	7,149			20,457			—			20,457
Other assets	85,373			6,512			102,548			6,512
Total other assets	94,724			26,969			107,198			26,969
Total assets	$	3,751,451		$	3,455,518		$	3,936,639		$	3,455,518
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	19,821		$	66,970		$	40,584		$	66,970
Accrued liabilities	191,608			170,855			222,565			170,855
Royalties payable	66,130			64,776			64,191			64,776
Amounts due to affiliates	10,200			13,052			14,557			13,052
Advances from joint interest owners	4,725			10,968			7,809			10,968
Amounts due to joint ventures	1,588			2,373			469			2,373
Other current liabilities	42,703			1,028			53,182			1,028
Total current liabilities	336,775			330,022			403,357			330,022
Long-term liabilities
Borrowings under Credit Agreement	205,000			40,000			215,000			40,000
Borrowings under San Mateo Credit Facility	240,000			220,000			260,000			220,000
Senior unsecured notes payable	1,038,625			1,037,837			1,039,020			1,037,837
Asset retirement obligations	30,686			29,736			33,507			29,736
Derivative instruments	189			83			—			83
Deferred income taxes	14,845			13,221			21,186			13,221
Other long-term liabilities	44,728			4,962			52,151			4,962
Total long-term liabilities	1,574,073			1,345,839			1,620,864			1,345,839
Commitments and contingencies (Note 10)
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; 116,880,345 and 116,374,503 shares issued; and 116,638,712 and 116,353,590 shares outstanding, respectively							1,169			1,164
Additional paid-in capital	1,955,504			1,924,408			1,970,737			1,924,408
Accumulated deficit	(216,472		)	(236,277		)	(172,519		)	(236,277		)
Treasury stock, at cost, 218,309 and 20,913 shares, respectively	(3,724		)	(415		)
Treasury stock, at cost, 241,633 and 20,913 shares, respectively							(4,080		)	(415		)
Total Matador Resources Company shareholders’ equity	1,736,477			1,688,880			1,795,307			1,688,880
Non-controlling interest in subsidiaries	104,126			90,777			117,111			90,777
Total shareholders’ equity	1,840,603			1,779,657			1,912,418			1,779,657
Total liabilities and shareholders’ equity	$	3,751,451		$	3,455,518		$	3,936,639		$	3,455,518

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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
Revenues
Oil and natural gas revenues	$	211,060		$	209,019		$	404,329		$	390,973		$	229,377		$	216,282		$	633,706		$	607,255
Third-party midstream services revenues	14,359			3,407			26,197			6,475			15,257			6,809			41,454			13,284
Sales of purchased natural gas	8,963			—			20,194			—			19,864			—			40,058			—
Lease bonus - mineral acreage													1,711			—			1,711			—
Realized gain (loss) on derivatives	1,165			(2,488		)	4,435			(6,746		)	3,346			5,424			7,781			(1,322		)
Unrealized gain (loss) on derivatives	6,157			1,429			(39,562		)	11,845			9,847			(21,337		)	(29,715		)	(9,492		)
Total revenues	241,704			211,367			415,593			402,547			279,402			207,178			694,995			609,725
Expenses
Production taxes, transportation and processing	21,542			20,110			41,207			37,901			24,762			20,215			65,969			58,116
Lease operating	26,351			25,006			57,514			47,154			29,714			22,531			87,228			69,685
Plant and other midstream services operating	8,422			5,676			17,738			9,896			8,817			7,291			26,555			17,187
Purchased natural gas	8,172			—			18,806			—			16,608			—			35,414			—
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207			92,498			70,457			249,497			192,664
Accretion of asset retirement obligations	420			375			834			739			520			387			1,354			1,126
General and administrative	19,876			19,369			38,166			37,295			20,381			18,444			58,547			55,739
Total expenses	164,915			137,374			331,264			255,192			193,300			139,325			524,564			394,517
Operating income	76,789			73,993			84,329			147,355			86,102			67,853			170,431			215,208
Other income (expense)
Inventory impairment	(368		)	—			(368		)	—
Net loss on asset sales and inventory impairment													(439		)	(196		)	(807		)	(196		)
Interest expense	(18,068		)	(8,004		)	(35,997		)	(16,495		)	(18,175		)	(10,340		)	(54,172		)	(26,835		)
Prepayment premium on extinguishment of debt													—			(31,226		)	—			(31,226		)
Other expense	(423		)	(352		)	(532		)	(299		)	(245		)	(976		)	(777		)	(1,275		)
Total other expense	(18,859		)	(8,356		)	(36,897		)	(16,794		)	(18,859		)	(42,738		)	(55,756		)	(59,532		)
Income before income taxes	57,930			65,637			47,432			130,561			67,243			25,115			114,675			155,676
Income tax provision
Deferred	12,858			—			11,845			—			13,490			—			25,335			—
Total income tax provision	12,858			—			11,845			—			13,490			—			25,335			—
Net income	45,072			65,637			35,587			130,561			53,753			25,115			89,340			155,676
Net income attributable to non-controlling interest in subsidiaries	(8,320		)	(5,831		)	(15,782		)	(10,861		)	(9,800		)	(7,321		)	(25,582		)	(18,182		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700		$	43,953		$	17,794		$	63,758		$	137,494
Earnings per common share
Basic	$	0.32		$	0.53		$	0.17		$	1.08		$	0.38		$	0.15		$	0.55		$	1.22
Diluted	$	0.31		$	0.53		$	0.17		$	1.08		$	0.38		$	0.15		$	0.54		$	1.21
Weighted average common shares outstanding
Basic	116,571			112,706			116,469			110,809			116,643			116,358			116,541			112,659
Diluted	116,903			113,056			116,839			111,280			116,976			116,912			116,994			113,208

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(In thousands)

For the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2019



														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, 2019	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	—		—			—			—	—			—			—			—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	3	—		—			—			—	—			—			—			—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		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
Restricted stock forfeited	—	—		—			—			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			—
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		2,040			—			—	—			2,040			10,291			12,331
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—			—			—	—			—			(8,330		)	(8,330		)
Current period net (loss) income	—	—		—			(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
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 — CONTINUED

(In thousands)

For the Three and Nine Months Ended September 30, 2019



													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 June 30, 2019	116,866	$	1,169	$	1,955,504	$	(216,472	)	218	$	(3,724	)	$	1,736,477		$	104,126		$	1,840,603
Issuance of common stock pursuant to employee stock compensation plan	12	—		—		—			—	—			—			—			—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	2	—		—		—			—	—			—			—			—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		5,963		—			—	—			5,963			—			5,963
Restricted stock forfeited	—	—		—		—			24	(356		)	(356		)	—			(356		)
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		9,270		—			—	—			9,270			13,230			22,500
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—		—			—	—			—			(10,045		)	(10,045		)
Current period net income	—	—		—		43,953			—	—			43,953			9,800			53,753
Balance at September 30, 2019	116,880	$	1,169	$	1,970,737	$	(172,519	)	242	$	(4,080	)	$	1,795,307		$	117,111		$	1,912,418

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(inIn thousands)

For the Three and ~~Six~~Nine Months Ended ~~June~~September 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		Additional paid-in capital			Accumulated deficit			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 STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED — CONTINUED

(In thousands)

For the Three and Nine Months Ended September 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		Additional paid-in capital		Accumulated deficit			Shares	Amount
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
Issuance of common stock pursuant to employee stock compensation plan	19	—		—		—			—	—			—			—			—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	3	—		—		—			—	—			—			—			—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		5,847		—			—	—			5,847			—			5,847
Stock options exercised, net of options forfeited in net share settlements	24	—		362		—			—	—			362			—			362
Restricted stock forfeited	—	—		—		—			55	(1,369		)	(1,369		)	—			(1,369		)
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—		—			—	—			—			19,600			19,600
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—		—			—	—			—			(6,860		)	(6,860		)
Current period net income	—	—		—		17,794			—	—			17,794			7,321			25,115
Balance at September 30, 2018	116,507	$	1,165	$	1,923,030	$	(372,990	)	158	$	(4,039	)	$	1,547,166		$	175,277		$	1,722,443

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS — UNAUDITED

(In thousands)


	Six Months Ended June 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Operating activities
Net income	$	35,587		$	130,561		$	89,340		$	155,676
Adjustments to reconcile net income to net cash provided by operating activities
Unrealized loss (gain) on derivatives	39,562			(11,845		)
Unrealized loss on derivatives							29,715			9,492
Depletion, depreciation and amortization	156,999			122,207			249,497			192,664
Accretion of asset retirement obligations	834			739			1,354			1,126
Stock-based compensation expense	9,076			8,945			13,740			13,787
Prepayment premium on extinguishment of debt							—			31,226
Deferred income tax provision	11,845			—			25,335			—
Amortization of debt issuance cost	1,189			411			1,814			851
Inventory impairment	368			—
Net loss on asset sales and inventory impairment							807			196
Changes in operating assets and liabilities
Accounts receivable	(378		)	(9,321		)	(37,341		)	(5,654		)
Lease and well equipment inventory	(3,456		)	(8,611		)	2,307			(15,347		)
Prepaid expenses	(4,834		)	(2,167		)	(5,099		)	(502		)
Other assets	(415		)	(149		)	(291		)	—
Accounts payable, accrued liabilities and other current liabilities	(48,746		)	(883		)	(15,540		)	20,823
Royalties payable	1,353			8,393			(586		)	5,665
Advances from joint interest owners	(6,243		)	16,025			(3,159		)	9,565
Other long-term liabilities	1,756			(97		)	1,234			(250		)
Net cash provided by operating activities	194,497			254,208			353,127			419,318
Investing activities
Oil and natural gas properties capital expenditures	(349,915		)	(421,595		)	(536,017		)	(1,106,556		)
Midstream capital expenditures	(64,106		)	(78,302		)	(120,792		)	(120,669		)
Expenditures for other property and equipment	(2,206		)	(1,258		)	(3,911		)	(1,570		)
Proceeds from sale of assets	21,533			7,593			21,671			8,267
Net cash used in investing activities	(394,694		)	(493,562		)	(639,049		)	(1,220,528		)
Financing activities
Repayments of borrowings	—			(45,000		)	(10,000		)	(45,000		)
Borrowings under Credit Agreement	165,000			45,000			185,000			370,000
Borrowings under San Mateo Credit Facility	20,000			—			40,000			—
Cost to amend credit facilities	(415		)	—			(613		)	—
Proceeds from issuance of senior unsecured notes							—			750,000
Cost to issue senior unsecured notes							—			(9,531		)
Purchase of senior unsecured notes							—			(605,780		)
Proceeds from issuance of common stock	—			226,612			—			226,612
Cost to issue equity	—			(73		)	—			(146		)
Proceeds from stock options exercised	3,298			464			3,300			827
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			42,330			73,500
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(17,640		)	(10,535		)	(27,685		)	(17,395		)
Taxes paid related to net share settlement of stock-based compensation	(3,309		)	(4,683		)	(3,665		)	(6,051		)
Cash paid under financing lease obligations	(490		)	—			(623		)	—
Net cash provided by financing activities	200,975			280,385			242,744			751,736
Increase in cash and restricted cash	778			41,031			(43,178		)	(49,474		)
Cash and restricted cash at beginning of period	83,984			102,482			83,984			102,482
Cash and restricted cash at end of period	$	84,762		$	143,513		$	40,806		$	53,008

Supplemental disclosures of cash flow information (Note 11)

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 filed with the SEC on March 1, 2019 (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~~September 30, 2019. Amounts as of December 31, 2018 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~~September 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

Leases. During the first quarter of 2019, the Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and the amendments provided for in ASU 2018-11, Leases (Topic 842), which require the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that the Company chose to apply. These practical expedients relate to (i) the identification and classification of leases that commenced before the effective date, (ii) the treatment of initial direct costs for leases that commenced before the effective date, (iii) the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset and (iv) the ability to initially apply the new lease standard at the adoption date. During the first quarter of 2019, the Company also adopted ASU 2018-01, Leases (Topic 842), which is a land easement practical expedient, and, as a result, the Company began evaluating land easements that are entered into or modified after December 31, 2018. See Note 3 for additional disclosures related to leases.

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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~~nine months ended ~~June~~September 30, 2019 and 2018 (in thousands).


	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018			2019		2018			2019			2018
Revenues from contracts with customers	$	234,382	$	212,426		$	450,720		$	397,448		$	264,498	$	223,091		$	715,218		$	620,539
Lease bonus - mineral acreage												1,711		—			1,711			—
Realized gain (loss) on derivatives	1,165		(2,488		)	4,435			(6,746		)	3,346		5,424			7,781			(1,322		)
Unrealized gain (loss) on derivatives	6,157		1,429			(39,562		)	11,845			9,847		(21,337		)	(29,715		)	(9,492		)
Total revenues	$	241,704	$	211,367		$	415,593		$	402,547		$	279,402	$	207,178		$	694,995		$	609,725


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018		2019		2018		2019		2018
Oil revenues	$	189,085	$	166,271	$	343,288	$	314,430	$	198,302	$	169,913	$	541,590	$	484,343
Natural gas revenues	21,975		42,748		61,041		76,543		31,075		46,369		92,116		122,912
Third-party midstream services revenues	14,359		3,407		26,197		6,475		15,257		6,809		41,454		13,284
Sales of purchased natural gas	8,963		—		20,194		—		19,864		—		40,058		—
Total revenues from contracts with customers	$	234,382	$	212,426	$	450,720	$	397,448	$	264,498	$	223,091	$	715,218	$	620,539

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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

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~~nine months ended ~~June~~September 30, 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~~$8.3 million and ~~$6.8~~$8.5 million of its general and administrative costs and approximately ~~$2.6~~$2.7 million and ~~$2.6~~$1.7 million of its interest expense for the three months ended ~~June~~September 30, 2019 and 2018, respectively. The Company capitalized approximately ~~$16.8~~$25.1 million and ~~$14.1~~$22.6 million of its general and administrative costs and approximately ~~$4.2~~$7.0 million and ~~$4.5~~$6.2 million of its interest expense for the ~~six~~nine months ended ~~June~~September 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~~nine months ended ~~June~~September 30, 2019 and 2018 (in thousands).


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018	2019	2018	2019	2018
Weighted average common shares outstanding
Basic	116,571	112,706	116,469	110,809	116,643	116,358	116,541	112,659
Dilutive effect of options and restricted stock units	332	350	370	471	333	554	453	549
Diluted weighted average common shares outstanding	116,903	113,056	116,839	111,280	116,976	116,912	116,994	113,208

A total of ~~2.8~~2.5 million and 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~~nine months ended ~~June~~September 30, 2019, respectively, because their effects were anti-dilutive.

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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 from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rate used for the three months ended ~~June~~September 30, 2019 was ~~3.73%~~3.74%. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the interim unaudited condensed consolidated balance sheet unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its 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~~nine months ended ~~June~~September 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		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating leases
Lease operating	$	2,965	$	5,207	$	3,298	$	8,505
Plant and other midstream services	30		61		30		91
General and administrative	665		1,474		805		2,279
Total operating leases⁽¹⁾	3,660		6,742		4,133		10,875
Short-term leases
Lease operating	3,392		5,601		2,317		7,918
Plant and other midstream services	1,131		2,751		967		3,718
General and administrative	5		17		7		24
Total short-term leases⁽²⁾⁽³⁾	4,528		8,369		3,291		11,660
Financing leases
Depreciation of assets	231		440		231		671
Interest on lease liabilities	33		64		32		96
Total financing leases	264		504		263		767
Total lease expense	$	8,452	$	15,615	$	7,687	$	23,302

_____________________


(1)	Does not include gross payments related to drilling rig leases of ~~$8.2~~$6.3 million and ~~$13.5~~$19.8 million for the three and ~~six~~nine months ended ~~June~~September 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~~September 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~~$24.7 million and ~~$37.2~~$61.8 million for the three and ~~six~~nine months ended ~~June~~September 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~~September 30, 2019.

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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~~September 30, 2019 (in thousands).


	June 30, 2019			September 30, 2019
Operating leases
Other assets	$	78,845		$	96,258
Other current liabilities	$	(40,870	)	$	(51,327	)
Other long-term liabilities	(43,012		)	(50,996		)
Total operating lease liabilities	$	(83,882	)	$	(102,323	)

Financing leases
Other property and equipment, at cost	$	2,846		$	2,677
Accumulated depreciation	(865		)	(1,095		)
Net property and equipment	$	1,981		$	1,582
Other current liabilities	$	(1,108	)	$	(1,098	)
Other long-term liabilities	(1,146		)	(481		)
Total financing lease liabilities	$	(2,254	)	$	(1,579	)

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


	Six Months Ended June 30, 2019		Nine Months Ended September 30, 2019
Cash paid related to lease liabilities
Operating cash payments for operating leases	$	6,790	$	10,504
Investing cash payments for operating leases	$	13,509	$	19,763
Financing cash payments for financing leases	$	490	$	623

Right of use assets obtained in exchange for lease obligations entered into during the period
Operating leases	$	28,884	$	57,637
Financing leases	$	471	$	597

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



Weighted-Average Remaining Lease Term		~~June~~September 30, 2019
Operating leases		~~3.0~~2.9
Financing leases		2.6

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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~~September 30, 2019 and December 31, 2018, respectively (in thousands).


	June 30, 2019						September 30, 2019
	Operating Leases			Financing Leases			Operating Leases			Financing Leases
2019	$	22,075		$	493		$	13,969		$	430
2020	32,051			747			49,285			779
2021	19,981			581			25,889			510
2022	3,989			504			5,008			88
2023	3,234			—			4,167			—
Thereafter	7,679			—			9,934			—
Total lease payments	89,009			2,325			108,252			1,807
Less imputed interest	(5,127		)	(71		)	(5,929		)	(228		)
Total lease obligations	83,882			2,254			102,323			1,579
Less current obligations	(40,870		)	(1,108		)	(51,327		)	(1,098		)
Long-term lease obligations	$	43,012		$	1,146		$	50,996		$	481



	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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

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


Beginning asset retirement obligations	$	31,086		$	31,086
Liabilities incurred during period	1,427			2,194
Liabilities settled during period	(154		)	(155		)
Revisions in estimated cash flows				1,792
Divestitures during period	(951		)	(2,145		)
Accretion expense	834			1,354
Ending asset retirement obligations	32,242			34,126
Less: current asset retirement obligations⁽¹⁾	(1,556		)	(619		)
Long-term asset retirement obligations	$	30,686		$	33,507

_______________


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

NOTE 5 — DEBT

At ~~June~~September 30, ~~2019 and July 31,~~ 2019, the Company had $1.05 billion of outstanding senior notes due 2026 (the “Notes”), ~~$205.0~~$215.0 million in borrowings outstanding under its revolving credit facility (the “Credit Agreement”) and approximately $13.6 million in outstanding letters of credit issued pursuant to the Credit Agreement.

At ~~June~~October 29, 2019, the Company had $1.05 billion of outstanding Notes, $255.0 million in borrowings outstanding under its Credit Agreement and approximately $35.0 million in outstanding letters of credit issued pursuant to the Credit Agreement.

At September 30, 2019 and ~~July 31,~~October 29, 2019, San Mateo I had ~~$240.0~~$260.0 million in borrowings outstanding under its revolving credit facility (the “San Mateo Credit Facility”) and approximately $16.2 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~~October 2019, the lenders completed their review of the Company’s proved oil and natural gas reserves at ~~December 31, 2018,~~June 30, 2019, and, as a result, the borrowing base was ~~increased to~~affirmed at $900.0 million. The Company elected to keep the borrowing commitment at $500.0 million, and the maximum facility amount remained $1.5 billion. This ~~April~~October 2019 redetermination constituted the regularly scheduled ~~May~~November 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 Company believes that it was in compliance with the terms of the Credit Agreement at ~~June~~September 30, 2019.

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~~provides for potential increases to up to $400.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries, but is guaranteed by San Mateo I’s subsidiaries and secured by substantially all of San Mateo I’s assets, including real property. OnIn June ~~12,~~ 2019, pursuant to the accordion feature, the lender commitments under the San Mateo Credit Facility were increased to $325.0 million.

~~The Company believes that San Mateo I was in compliance with~~ In October 2019, pursuant to the ~~terms of~~accordion feature, the lender commitments under the San Mateo Credit Facility ~~at June 30, 2019.~~were further increased to $375.0 million.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 5 — DEBT — Continued

The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at September 30, 2019.

Senior Unsecured Notes

In August and October 2018, the Company issued $750.0 million and $300.0 million, respectively, of 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 6 — INCOME TAXES

The Company’s effective tax rate for the three and ~~six~~nine months ended ~~June~~September 30, 2019 was ~~26%~~23% and ~~37%~~28%, respectively. The Company’s total income tax provision for the three and ~~six~~nine months ended ~~June~~September 30, 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~~September 30, 2019.

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

The Company’s deferred tax assets exceeded its deferred tax liabilities at ~~June~~September 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~~September 30, 2018 due to uncertainties regarding the future realization of its deferred tax assets.

NOTE 7 — EQUITY

Stock-based Compensation

In February 2019, the Company granted awards to certain of its employees of 428,006 service-based restricted stock units to be settled in cash, which are liability instruments, and 428,006 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, 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 million on the grant date. In August 2019, the Company granted awards to certain of its employees of 540,250 stock options that vest ratably over three years. The fair value of these awards was approximately $3.0 million.

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 to San Mateo II. During the three and ~~six~~nine months ended ~~June~~September 30, 2019, the Company contributed ~~$1.5~~$4.5 million and ~~$1.5~~$6.0 million of cash and Five Point contributed ~~$7.5~~$22.5 million and ~~$11.5~~$34.0 million of cash to San Mateo II, respectively.

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NOTE 7 — EQUITY — Continued

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~~nine months ended ~~June~~September 30, 2019 and 2018, and the Company may earn up to an additional $44.1 million in performance incentives over the next three years. These performance incentives are recorded as an increase to additional paid-in capital when received. These performance incentives for the ~~six~~nine months ended ~~June~~September 30, 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 8 — DERIVATIVE FINANCIAL INSTRUMENTS

At ~~June~~September 30, 2019, 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 and fixed price for the swaps. Each contract is set to expire at varying times during 2019 and 2020.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at ~~June~~September 30, 2019.


Commodity		Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Asset (Liability) (thousands)			Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/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		10/01/2019 - 12/31/2019	1,950,000	$	50.26	$	70.94	$	3,242
Oil		01/01/2020 - 12/31/2020	2,640,000	$	48.50	$	69.50	4,555			01/01/2020 - 12/31/2020	4,860,000	$	48.50	$	67.44	15,657
Natural Gas		07/01/2019 - 12/31/2019	1,200,000	$	2.50	$	3.80	272			10/01/2019 - 12/31/2019	600,000	$	2.50	$	3.80	91
Total open costless collar contracts	Total open costless collar contracts							$	8,181	Total open costless collar contracts							$	18,990

The following is a summary of the Company’s open three-way costless collar contracts for oil and natural gas at ~~June~~September 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 $/MMBtu)		Fair Value of Asset (Liability) (thousands)			Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/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		10/01/2019 - 12/31/2019	330,000	$	60.00	$	75.00	$	78.85	$	2,216
Natural Gas		07/01/2019 - 12/31/2019	2,400,000	$	2.50	$	3.00	$	3.24	528			10/01/2019 - 12/31/2019	1,200,000	$	2.50	$	3.00	$	3.24	177
Total open three-way costless collar contracts	Total open three-way costless collar contracts									$	3,357	Total open three-way costless collar contracts									$	2,393

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


Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)		Fair Value of Asset (Liability) (thousands)			Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil Basis Swaps	08/1/2019 - 12/31/2019	1,377,000	$	0.33	$	(39	)	10/01/2019 - 12/31/2019	1,308,000	$	0.47	$	(248	)
Oil Basis Swaps	01/01/2020 - 12/31/2020	4,494,000	$	0.42	(1,215		)	01/01/2020 - 12/31/2020	4,494,000	$	0.42	(864		)
Oil Basis Swaps								01/01/2021 - 12/31/2021	2,880,000	$	0.65	(140		)
Total open swap contracts					$	(1,254	)					$	(1,252	)

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

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UNAUDITED — CONTINUED

NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

At September 30, 2019, the Company had an aggregate asset value for open derivative financial instruments of $20.1 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~~September 30, 2019 and December 31, 2018 (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
September 30, 2019
Current assets	$	12,671		$	(4,400	)	$	8,271		$	19,405		$	(3,924	)	$	15,481
Other assets	4,710			(2,508		)	2,202			6,365			(1,715		)	4,650
Current liabilities	(4,400		)	4,400			—			(3,924		)	3,924			—
Long-term liabilities	(2,697		)	2,508			(189		)	(1,715		)	1,715			—
Total	$	10,284		$	—		$	10,284		$	20,131		$	—		$	20,131
December 31, 2018
Current assets	$	53,136		$	(3,207	)	$	49,929		$	53,136		$	(3,207	)	$	49,929
Current liabilities	(3,207		)	3,207			—			(3,207		)	3,207			—
Long-term liabilities	(83		)	—			(83		)	(83		)	—			(83		)
Total	$	49,846		$	—		$	49,846		$	49,846		$	—		$	49,846

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 September 30,						Nine Months Ended September 30,
Type of Instrument		Location in Condensed Consolidated Statement of Operations	2019		2018			2019			2018				Location in Condensed Consolidated Statement of Operations	2019			2018			2019			2018
Derivative Instrument
Oil		Revenues: Realized gain (loss) on derivatives	$	1,165	$	(2,488	)	$	4,531		$	(6,797	)		Revenues: Realized gain (loss) on derivatives	$	2,856		$	5,424		$	7,387		$	(1,373	)
Natural Gas		Revenues: Realized (loss) gain on derivatives	—		—			(96		)	51				Revenues: Realized gain on derivatives	490			—			394			51
Realized gain (loss) on derivatives	Realized gain (loss) on derivatives		1,165		(2,488		)	4,435			(6,746		)	Realized gain (loss) on derivatives		3,346			5,424			7,781			(1,322		)
Oil		Revenues: Unrealized gain (loss) on derivatives	5,365		1,829			(40,078		)	12,956				Revenues: Unrealized gain (loss) on derivatives	10,379			(21,240		)	(29,699		)	(8,284		)
Natural Gas		Revenues: Unrealized gain (loss) on derivatives	792		(400		)	516			(1,111		)		Revenues: Unrealized loss on derivatives	(532		)	(97		)	(16		)	(1,208		)
Unrealized gain (loss) on derivatives	Unrealized gain (loss) on derivatives		6,157		1,429			(39,562		)	11,845			Unrealized gain (loss) on derivatives		9,847			(21,337		)	(29,715		)	(9,492		)
Total			$	7,322	$	(1,059	)	$	(35,127	)	$	5,099				$	13,193		$	(15,913	)	$	(21,934	)	$	(10,814	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 9 — 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~~September 30, 2019 and December 31, 2018 (in thousands).


	Fair Value Measurements at June 30, 2019 using								Fair Value Measurements at September 30, 2019 using
Description	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	9,484	$	—	$	9,484	$	—	$	19,863	$	—	$	19,863
Natural gas derivatives	—		800		—		800		—		268		—		268
Total	$	—	$	10,284	$	—	$	10,284	$	—	$	20,131	$	—	$	20,131



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

Additional disclosures related to derivative financial instruments are provided in Note 8.

Other Fair Value Measurements

At ~~June~~September 30, 2019 and December 31, 2018, 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~~September 30, 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~~September 30, 2019 and December 31, 2018, the fair value of the Notes was ~~$1.07~~$1.06 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 10 — 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~~$7.0 million and ~~$5.1~~$6.7 million for deliveries under these agreements during the three months ended ~~June~~September 30, 2019 and 2018, respectively, and ~~$12.9~~$19.9 million and ~~$9.1~~$15.8 million for deliveries under these agreements during the ~~six~~nine months ended ~~June~~September 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~~September 30, 2019, the total deficiencies required to be paid by the Company under these agreements would be approximately ~~$163.4~~$416.1 million, in addition to the commitments described below.

Future Commitments

In late 2017, the Company entered into a fixed-fee natural gas liquids (“NGL”) 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 not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven-year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. Should the pipeline extension and fractionation facility be completed on or prior to February 28, 2021, the minimum contractual obligation during the seven-year period would be approximately $132.3 million.

In ~~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 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 minimum contractual obligation under the Operational Agreements at ~~June~~September 30, 2019 was approximately ~~$183.8~~$161.8 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 minimum contractual obligation under the San Mateo II Operational Agreements at inception was approximately $363.8 million and begins in 2020.

~~Table of Contents~~

~~Matador Resources Company and Subsidiaries~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —~~

~~UNAUDITED — CONTINUED~~

~~NOTE 10 — 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 total commitments under this agreement are ~~$80.1~~$80.3 million. San Mateo II paid approximately ~~$8.3~~$9.9 million under this agreement during the three months ended ~~June~~September 30,

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 10 — COMMITMENTS AND CONTINGENCIES — Continued

2019. As of ~~June~~September 30, 2019, the remaining obligations under this agreement were ~~$71.8~~$62.1 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 11 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

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


	June 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
Accrued evaluated and unproved and unevaluated property costs	$	100,014	$	86,318	$	113,904	$	86,318
Accrued midstream property costs	21,840		16,808		32,647		16,808
Accrued lease operating expenses	20,812		12,705		23,480		12,705
Accrued interest on debt	18,599		22,448		3,107		22,448
Accrued asset retirement obligations	1,556		1,350		619		1,350
Accrued partners’ share of joint interest charges	17,165		17,037		32,769		17,037
Other	11,622		14,189		16,039		14,189
Total accrued liabilities	$	191,608	$	170,855	$	222,565	$	170,855

Supplemental Cash Flow Information

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


	Six Months Ended June 30,					Nine Months Ended September 30,
	2019		2018			2019		2018
Cash paid for interest expense, net of amounts capitalized	$	37,632	$	14,286		$	58,860	$	29,773
Increase in asset retirement obligations related to mineral properties	$	321	$	834		$	6,946	$	1,705
Increase in asset retirement obligations related to midstream properties	$	283	$	296		$	169	$	547
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						$	26,862	$	5,157
Increase in liabilities for midstream properties capital expenditures						$	16,661	$	1,864
Increase in liabilities for accrued cost to issue senior notes						$	—	$	510
Transfer of inventory from oil and natural gas properties	$	370	$	343		$	211	$	305
Transfer of inventory to midstream properties	$	—	$	(2,390	)	$	—	$	(2,691	)

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UNAUDITED — CONTINUED

NOTE 11 — 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,				Nine Months Ended September 30,
	2019		2018		2019		2018
Cash	$	59,950	$	122,450	$	15,709	$	45,942
Restricted cash	24,812		21,063		25,097		7,066
Total cash and restricted cash	$	84,762	$	143,513	$	40,806	$	53,008

NOTE 12 — 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 and Wolf asset areas 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 September 30, 2019
Oil and natural gas revenues	$	209,563	$	1,497	$	—		$	—		$	211,060	$	228,188		$	1,189		$	—		$	—		$	229,377
Midstream services revenues	—		32,166		—			(17,807		)	14,359		—			35,533			—			(20,276		)	15,257
Sales of purchased natural gas	—		8,963		—			—			8,963		3,080			16,784			—			—			19,864
Lease bonus - mineral acreage													1,711			—			—			—			1,711
Realized gain on derivatives	1,165		—		—			—			1,165		3,346			—			—			—			3,346
Unrealized loss on derivatives	6,157		—		—			—			6,157
Unrealized gain on derivatives													9,847			—			—			—			9,847
Expenses⁽¹⁾	141,514		23,425		17,783			(17,807		)	164,915		164,352			30,611			18,613			(20,276		)	193,300
Operating income (loss)⁽²⁾	$	75,371	$	19,201	$	(17,783	)	$	—		$	76,789	$	81,820		$	22,895		$	(18,613	)	$	—		$	86,102
Total assets	$	3,155,577	$	508,074	$	87,800		$	—		$	3,751,451	$	3,332,910		$	566,551		$	37,178		$	—		$	3,936,639
Capital expenditures⁽³⁾	$	166,532	$	41,707	$	1,400		$	—		$	209,639	$	201,323		$	66,438		$	1,705		$	—		$	269,466

_____________________


(1)	Includes depletion, depreciation and amortization expenses of ~~$75.7~~$87.7 million and ~~$3.8~~$4.1 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~~$9.8 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes ~~$8.2~~$6.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and ~~$24.2~~$47.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 12 — 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 September 30, 2018
Oil and natural gas revenues	$	207,229		$	1,790	$	—		$	—		$	209,019		$	215,248			$	1,034		$	—		$	—		$	216,282
Midstream services revenues	—			19,896		—			(16,489		)	3,407			—				24,950			—			(18,141		)	6,809
Realized loss on derivatives	(2,488		)	—		—			—			(2,488		)
Unrealized gain on derivatives	1,429			—		—			—			1,429
Realized gain on derivatives															5,424				—			—			—			5,424
Unrealized loss on derivatives															(21,337		)		—			—			—			(21,337		)
Expenses⁽¹⁾	126,025			9,363		18,475			(16,489		)	137,374			128,263				10,162			19,041			(18,141		)	139,325
Operating income (loss)⁽²⁾	$	80,145		$	12,323	$	(18,475	)	$	—		$	73,993		$	71,072			$	15,822		$	(19,041	)	$	—		$	67,853
Total assets	$	2,058,447		$	354,068	$	143,332		$	—		$	2,555,847		$	2,697,685			$	391,323		$	65,194		$	—		$	3,154,202
Capital expenditures⁽³⁾	$	199,345		$	32,900	$	732		$	—		$	232,977		$	716,751			$	47,153		$	312		$	—		$	764,216

_____________________


(1)	Includes depletion, depreciation and amortization expenses of ~~$64.5~~$67.2 million and ~~$2.3~~$2.6 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~~$7.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes ~~$16.1~~$554.9 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $23.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.


	Exploration and Production								Consolidations and Eliminations			Consolidated Company			Exploration and Production										Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate						Consolidated Company			Exploration and Production			Midstream			Corporate				Consolidations and Eliminations			Consolidated Company
Six Months Ended June 30, 2019									Consolidations and Eliminations
Nine Months Ended September 30, 2019
Oil and natural gas revenues	$	401,226		$	3,103	$	—		$	—		$	404,329		$	629,414			$	4,292		$	—		$	—		$	633,706
Midstream services revenues	—			62,420		—			(36,223		)	26,197			—				97,953			—			(56,499		)	41,454
Sales of purchased natural gas	—			20,194		—			—			20,194			3,080				36,978			—			—			40,058
Lease bonus - mineral acreage															1,711				—			—			—			1,711
Realized gain on derivatives	4,435			—		—			—			4,435			7,781				—			—			—			7,781
Unrealized loss on derivatives	(39,562		)	—		—			—			(39,562		)	(29,715		)		—			—			—			(29,715		)
Expenses⁽¹⁾	283,493			49,260		34,734			(36,223		)	331,264			447,844				79,870			53,349			(56,499		)	524,564
Operating income (loss)⁽²⁾	$	82,606		$	36,457	$	(34,734	)	$	—		$	84,329		$	164,427			$	59,353		$	(53,349	)	$	—		$	170,431
Total assets	$	3,155,577		$	508,074	$	87,800		$	—		$	3,751,451		$	3,332,910			$	566,551		$	37,178		$	—		$	3,936,639
Capital expenditures⁽³⁾	$	364,143		$	71,139	$	2,206		$	—		$	437,488		$	565,466			$	137,577		$	3,911		$	—		$	706,954

_____________________


(1)	Includes depletion, depreciation and amortization expenses of ~~$148.3~~$236.0 million and ~~$7.5~~$11.6 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of ~~$1.2~~$1.9 million.


(2)	Includes ~~$15.8~~$25.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes ~~$31.3~~$37.8 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and ~~$37.9~~$85.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

2224

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 12 — 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
Six Months Ended June 30, 2018									Consolidations and Eliminations
Nine Months Ended September 30, 2018
Oil and natural gas revenues	$	387,489		$	3,484	$	—		$	—		$	390,973		$	602,737			$	4,518		$	—		$	—		$	607,255
Midstream services revenues	—			35,708		—			(29,233		)	6,475			—				60,658			—			(47,374		)	13,284
Realized loss on derivatives	(6,746		)	—		—			—			(6,746		)	(1,322		)		—			—			—			(1,322		)
Unrealized gain on derivatives	11,845			—		—			—			11,845
Unrealized loss on derivatives															(9,492		)		—			—			—			(9,492		)
Expenses⁽¹⁾	232,180			16,561		35,684			(29,233		)	255,192			359,830				26,723			55,338			(47,374		)	394,517
Operating income (loss)⁽²⁾	$	160,408		$	22,631	$	(35,684	)	$	—		$	147,355		$	232,093			$	38,453		$	(55,338	)	$	—		$	215,208
Total assets	$	2,058,447		$	354,068	$	143,332		$	—		$	2,555,847		$	2,697,685			$	391,323		$	65,194		$	—		$	3,154,202
Capital expenditures⁽³⁾	$	388,790		$	78,617	$	1,258		$	—		$	468,665		$	1,105,541			$	125,770		$	1,570		$	—		$	1,232,881

_____________________


(1)	Includes depletion, depreciation and amortization expenses of ~~$117.8~~$184.4 million and ~~$3.9~~$6.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of ~~$0.6~~$1.8 million.


(2)	Includes ~~$10.9~~$18.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes ~~$38.5~~$613.8 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $61.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

2325

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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~~September 30, 2019, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes.

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


Condensed Consolidating Balance Sheet June 30, 2019
Condensed Consolidating Balance Sheet September 30, 2019												Condensed Consolidating Balance Sheet September 30, 2019
	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	)	$	—		$	1,563,060	$	20,658	$	—	$	(1,583,718	)	$	—
Current assets	3,967		44,100		225,317		—			273,384			3,762		39,545		226,009		—			269,316
Net property and equipment	—		438,681		2,944,662		—			3,383,343			—		502,082		3,058,043		—			3,560,125
Investment in subsidiaries	1,211,056		—		109,227		(1,320,283		)	—			1,285,250		—		122,743		(1,407,993		)	—
Long-term assets	10,589		1,700		92,004		(9,569		)	94,724			3,440		1,605		111,519		(9,366		)	107,198
Total assets	$	2,808,440	$	497,016	$	3,371,210	$	(2,925,215	)	$	3,751,451		$	2,855,512	$	563,890	$	3,518,314	$	(3,001,077	)	$	3,936,639
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	1,595,363	$	(1,595,363	)	$	—		$	—	$	—	$	1,583,718	$	(1,583,718	)	$	—
Current liabilities	18,493		33,080		286,004		(802		)	336,775			—		53,627		350,532		(802		)	403,357
Senior unsecured notes payable	1,038,625		—		—		—			1,038,625			1,039,020		—		—		—			1,039,020
Other long-term liabilities	14,845		250,583		278,787		(8,767		)	535,448			21,185		270,409		298,814		(8,564		)	581,844
Total equity attributable to Matador Resources Company	1,736,477		109,227		1,211,056		(1,320,283		)	1,736,477			1,795,307		122,743		1,285,250		(1,407,993		)	1,795,307
Non-controlling interest in subsidiaries	—		104,126		—		—			104,126			—		117,111		—		—			117,111
Total liabilities and equity	$	2,808,440	$	497,016	$	3,371,210	$	(2,925,215	)	$	3,751,451		$	2,855,512	$	563,890	$	3,518,314	$	(3,001,077	)	$	3,936,639



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


Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2019
Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2019																Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2019
	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			$	—		$	52,776		$	246,235		$	(19,609	)	$	279,402
Total expenses	901			22,564			158,351			(16,901		)	164,915				1,034			30,317			181,558			(19,609		)	193,300
Operating (loss) income	(901		)	19,156			58,534			—			76,789				(1,034		)	22,459			64,677			—			86,102
Inventory impairment	—			—			(368		)	—			(368		)
Net loss on asset sales and inventory impairment																	—			—			(439		)	—			(439		)
Interest expense	(15,888		)	(2,180		)	—			—			(18,068		)		(15,716		)	(2,459		)	—			—			(18,175		)
Other income (expense)	—			3			(426		)	—			(423		)
Other expense																	—			—			(245		)	—			(245		)
Earnings in subsidiaries	66,399			—			8,659			(75,058		)	—				74,193			—			10,200			(84,393		)	—
Income before income taxes	49,610			16,979			66,399			(75,058		)	57,930				57,443			20,000			74,193			(84,393		)	67,243
Total income tax provision	12,858			—			—			—			12,858				13,490			—			—			—			13,490
Net income attributable to non-controlling interest in subsidiaries	—			(8,320		)	—			—			(8,320		)		—			(9,800		)	—			—			(9,800		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	8,659		$	66,399		$	(75,058	)	$	36,752			$	43,953		$	10,200		$	74,193		$	(84,393	)	$	43,953


Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2018
Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2018																Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2018
	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			$	—		$	25,640		$	199,386		$	(17,848	)	$	207,178
Total expenses	1,178			9,466			142,938			(16,208		)	137,374				1,184			10,708			145,281			(17,848		)	139,325
Operating (loss) income	(1,178		)	11,890			63,281			—			73,993				(1,184		)	14,932			54,105			—			67,853
Net loss on asset sales and inventory impairment																	—			—			(196		)	—			(196		)
Interest expense	(8,004		)	—			—			—			(8,004		)		(10,340		)	—			—			—			(10,340		)
Other income (expense)	—			11			(363		)	—			(352		)
Other (expense) income																	(31,232		)	8			(978		)	—			(32,202		)
Earnings in subsidiaries	68,988			—			6,070			(75,058		)	—				60,550			—			7,619			(68,169		)	—
Income before income taxes	59,806			11,901			68,988			(75,058		)	65,637				17,794			14,940			60,550			(68,169		)	25,115
Net income attributable to non-controlling interest in subsidiaries	—			(5,831		)	—			—			(5,831		)		—			(7,321		)	—			—			(7,321		)
Net income attributable to Matador Resources Company shareholders	$	59,806		$	6,070		$	68,988		$	(75,058	)	$	59,806			$	17,794		$	7,619		$	60,550		$	(68,169	)	$	17,794


Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2019
Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2019																Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2019
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated				Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	84,596		$	366,133		$	(35,136	)	$	415,593			$	—		$	137,372		$	612,368		$	(54,745	)	$	694,995
Total expenses	1,936			48,069			316,395			(35,136		)	331,264				2,970			78,386			497,953			(54,745		)	524,564
Operating (loss) income	(1,936		)	36,527			49,738			—			84,329				(2,970		)	58,986			114,415			—			170,431
Inventory impairment	—			—			(368		)	—			(368		)
Net loss on asset sales and inventory impairment																	—			—			(807		)	—			(807		)
Interest expense	(31,675		)	(4,322		)	—			—			(35,997		)		(47,391		)	(6,781		)	—			—			(54,172		)
Other income (expense)	—			3			(535		)	—			(532		)		—			3			(780		)	—			(777		)
Earnings in subsidiaries	65,261			—			16,426			(81,687		)	—				139,454			—			26,626			(166,080		)	—
Income before income taxes	31,650			32,208			65,261			(81,687		)	47,432				89,093			52,208			139,454			(166,080		)	114,675
Total income tax provision	11,845			—			—			—			11,845				25,335			—			—			—			25,335
Net income attributable to non-controlling interest in subsidiaries	—			(15,782		)	—			—			(15,782		)		—			(25,582		)	—			—			(25,582		)
Net income attributable to Matador Resources Company shareholders	$	19,805		$	16,426		$	65,261		$	(81,687	)	$	19,805			$	63,758		$	26,626		$	139,454		$	(166,080	)	$	63,758


Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2018
Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2018																Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2018
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated				Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	38,550		$	392,699		$	(28,702	)	$	402,547			$	—		$	64,190		$	592,085		$	(46,550	)	$	609,725
Total expenses	2,412			16,394			265,088			(28,702		)	255,192				3,596			27,102			410,369			(46,550		)	394,517
Operating (loss) income	(2,412		)	22,156			127,611			—			147,355				(3,596		)	37,088			181,716			—			215,208
Net loss on asset sales and inventory impairment																	—			—			(196		)	—			(196		)
Interest expense	(16,495		)	—			—			—			(16,495		)		(26,835		)	—			—			—			(26,835		)
Other income (expense)	6			11			(316		)	—			(299		)
Other (expense) income																	(31,226		)	19			(1,294		)	—			(32,501		)
Earnings in subsidiaries	138,601			—			11,306			(149,907		)	—				199,151			—			18,925			(218,076		)	—
Income before income taxes	119,700			22,167			138,601			(149,907		)	130,561				137,494			37,107			199,151			(218,076		)	155,676
Net income attributable to non-controlling interest in subsidiaries	—			(10,861		)	—			—			(10,861		)		—			(18,182		)	—			—			(18,182		)
Net income attributable to Matador Resources Company shareholders	$	119,700		$	11,306		$	138,601		$	(149,907	)	$	119,700			$	137,494		$	18,925		$	199,151		$	(218,076	)	$	137,494


Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2019
Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2019																Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 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	$	(109	)	$	51,266		$	143,340		$	—		$	194,497			$	(423	)	$	82,812		$	270,738		$	—		$	353,127
Net cash used in investing activities	—			(59,309		)	(327,195		)	(8,190		)	(394,694		)		—			(116,967		)	(507,938		)	(14,144		)	(639,049		)
Net cash provided by financing activities	—			13,584			179,201			8,190			200,975				—			39,888			188,712			14,144			242,744
(Decrease) increase in cash and restricted cash	(109		)	5,541			(4,654		)	—			778				(423		)	5,733			(48,488		)	—			(43,178		)
Cash and restricted cash at beginning of period	456			18,841			64,687			—			83,984				456			18,841			64,687			—			83,984
Cash and restricted cash at end of period	$	347		$	24,382		$	60,033		$	—		$	84,762			$	33		$	24,574		$	16,199		$	—		$	40,806


Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2018
Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2018																Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2018
	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			$	(361,016	)	$	12,318		$	768,016		$	—		$	419,318
Net cash used in investing activities	—			(79,119		)	(454,478		)	40,035			(493,562		)		—			(120,836		)	(1,152,987		)	53,295			(1,220,528		)
Net cash provided by financing activities	226,539			83,400			10,481			(40,035		)	280,385				361,155			109,400			334,476			(53,295		)	751,736
Increase in cash and restricted cash	2,098			14,506			24,427			—			41,031
Increase (decrease) in cash and restricted cash																	139			882			(50,495		)	—			(49,474		)
Cash and restricted cash at beginning of period	286			5,663			96,533			—			102,482				286			5,663			96,533			—			102,482
Cash and restricted cash at end of period	$	2,384		$	20,169		$	120,960		$	—		$	143,513			$	425		$	6,545		$	46,038		$	—		$	53,008

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 (the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”) on March 1, 2019, 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 producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; our ~~properties and capacity of transportation facilities, availability of~~ability to make acquisitions on economically acceptable terms; our ability to integrate ~~acquisitions with~~acquisitions; availability of sufficient capital to execute our business plan, including from future cash flows, increases in our borrowing base and otherwise; weather and environmental ~~conditions, uncertainties regarding environmental regulations or litigation~~conditions; the operating results of San Mateo’s expansion of the Black River cryogenic processing plant, including the timing of the further expansion of such plant; the timing and ~~other legal or regulatory developments affecting our business,~~ 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;

our cash flows and liquidity;

our financial strategy, budget, projections and operating results;

our oil and natural gas realized prices;

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

the availability of drilling and production equipment;

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 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;

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~~Third Quarter Highlights

For the three months ended ~~June~~September 30, 2019, our total oil equivalent production was ~~5.6~~6.4 million BOE, and our average daily oil equivalent production was ~~61,290~~69,645 BOE per day, of which ~~36,767~~39,776 Bbl per day, or ~~60%~~57%, was oil and ~~147.1~~179.2 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~~September 30, 2019 increased ~~24%~~23% year-over-year from ~~2.7~~3.0 million Bbl for the three months ended ~~June~~September 30, 2018. Our natural gas production of ~~13.4~~16.5 Bcf for the three months ended ~~June~~September 30, 2019 increased 6%34% year-over-year from ~~12.7~~12.3 Bcf for the three months ended ~~June~~September 30, 2018. For the ~~six~~nine months ended ~~June~~September 30, 2019, our total oil equivalent production was ~~11.0~~17.4 million BOE, and our average daily oil equivalent production was ~~60,619~~63,661 BOE per day, of which ~~35,648~~37,039 Bbl per day, or ~~59%~~58%, was oil and ~~149.8~~159.7 MMcf per day, or ~~41%~~42%, was natural gas. Our oil production of ~~6.5~~10.1 million Bbl for the ~~six~~nine months ended ~~June~~September 30, 2019 increased ~~27%~~25% year-over-year from ~~5.1~~8.1 million Bbl for the ~~six~~nine months ended ~~June~~September 30, 2018. Our natural gas production of ~~27.1~~43.6 Bcf for the ~~six~~nine months ended ~~June~~September 30, 2019 increased ~~19%~~24% year-over-year from ~~22.8~~35.1 Bcf for the ~~six~~nine months ended ~~June~~September 30, 2018.

For the ~~second~~third quarter of 2019, we reported net income attributable to Matador ~~Resources Company~~ shareholders of approximately ~~$36.8~~$44.0 million, or ~~$0.31~~$0.38 per diluted common share, on a generally accepted accounting principles in the United States (“GAAP”) basis, as compared to net income attributable to Matador ~~Resources Company~~ shareholders of ~~$59.8~~$17.8 million, or ~~$0.53~~$0.15 per diluted common share, for the ~~second~~third quarter of 2018. For the ~~second~~third quarter of 2019, our Adjusted EBITDA attributable to Matador ~~Resources Company~~ shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was ~~$144.1~~$160.8 million, as compared to Adjusted EBITDA of ~~$137.3~~$155.4 million during

the ~~second~~third quarter of 2018. 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~~third quarter of 2019, see “— Results of Operations” below.

For the ~~six~~nine months ended ~~June~~September 30, 2019, we reported net income attributable to Matador ~~Resources Company~~ shareholders of approximately ~~$19.8~~$63.8 million, or ~~$0.17~~$0.54 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador ~~Resources Company~~ shareholders of ~~$119.7~~$137.5 million, or ~~$1.08~~$1.21 per diluted common share, for the ~~six~~nine months ended ~~June~~September 30, 2018. For the ~~six~~nine months ended ~~June~~September 30, 2019, our Adjusted EBITDA, a non-GAAP financial measure, was ~~$268.9~~$429.7 million, as compared to Adjusted EBITDA of ~~$254.6~~$410.0 million during the ~~six~~nine months ended ~~June~~September 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~~nine months ended ~~June~~September 30, 2019, see “— Results of Operations” below.

Operations Update

During the ~~second~~third quarter of 2019, we continued our 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 six drilling rigs in the Delaware Basin and continued to do so at ~~June~~September 30, 2019. During the ~~second~~third quarter of 2019, these six operated drilling rigs were deployed across our Delaware Basin asset ~~areas, but with an increased focus on the Antelope Ridge asset area.~~areas. 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 the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) for the remainder of 2019.

~~We also concluded completion operations on our nine-well program in South Texas during~~During the ~~second~~third quarter of 2019, ~~which included eight completions~~we received approval for six drilling permits in our western Antelope Ridge asset area from the Bureau of Land Management (“BLM”) and have initiated drilling operations on these “Rodney Robinson” wells. The 1,200 gross and net acre Rodney Robinson tract is one of the key tracts we acquired in the ~~Eagle Ford formation~~BLM New Mexico Oil and ~~one test of the Austin Chalk formation. The final four~~Gas Lease Sale in September 2018 (the “BLM Acquisition”). We are currently drilling these first six wells, ~~in this nine-well program were~~all two-mile laterals, from two separate three-well pads. These wells are scheduled to be completed and turned to sales late in the ~~second~~first quarter of ~~2019. These wells included two~~2020.

During the third quarter of 2019, we did not conduct any operated drilling and completion activities on our leasehold properties in the Eagle Ford ~~completions on~~shale play in South Texas or in the ~~Haverlah leasehold~~Haynesville shale and Cotton Valley plays in ~~Atascosa County, which~~Northwest Louisiana. We did participate in the drilling and completion of 11 gross (1.1 net) non-operated Haynesville shale wells that 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 for the remainderthird quarter of 2019.

We completed and turned to sales a total of 1939 gross ~~(15.1~~(22.6 net) wells in the Delaware Basin during the ~~second~~third quarter of 2019, including 1427 gross ~~(13.1~~(22.2 net) operated horizontal wells ~~two~~and 12 gross ~~(2.0 net) operated vertical wells and three gross (0.1~~(0.4 net) non-operated horizontal wells. During the ~~second~~third quarter of 2019, we began producing oil and natural gas from a total of 1217 gross ~~(8.5~~(8.8 net) wells in the Antelope Ridge asset area, including ~~nine~~10 gross ~~(8.4~~(8.7 net) operated wells and ~~three~~seven gross (0.1 net) non-operated wells. Of the ~~nine~~10 gross operated wells in the Antelope Ridge asset area, ~~two~~one was a Wolfcamp A-XY completion, four were Wolfcamp ~~A-XY~~A-Lower completions, ~~three were First~~one was a Second Bone Spring ~~completions,~~completion, three were Third Bone Spring completions and one was a ~~vertical completion in the Wolfcamp formation.~~Brushy Canyon completion. In the Rustler Breaks asset area, we began producing oil and natural gas from a total of 14 gross (8.9 net) wells, including 10 gross (8.6 net) operated wells and four gross (0.3 net) non-operated wells. Of the 10 gross operated wells in the Rustler Breaks asset area, five were Wolfcamp A-XY completions, one was a Wolfcamp A-Lower completion, three were Wolfcamp B completions and one was a First Bone Spring completion. In the Arrowhead asset ~~areas,~~area, we ~~did not complete or turn to sales any~~began producing oil and natural gas from a total of four gross (2.9 net) operated ~~or non-operated~~ wells, ~~during the second quarter~~ of ~~2019.~~which two were Wolfcamp A-XY completions, one was a Second Bone Spring completion and one was a Third Bone Spring completion. In the Wolf and Jackson Trust asset areas, we began producing oil and natural gas from ~~two~~three gross ~~(1.8~~(2.0 net) operated wells during the ~~second~~third quarter of 2019, including two Wolfcamp A-XY completions and one Wolfcamp ~~B completion and one Second Bone Spring~~A-Lower completion. In addition, we began producing oil and natural gas from ~~a total of four~~one gross ~~(3.9~~(less than 0.1 net) ~~operated wells~~non-operated well 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 secondthird quarter of 2019.

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~~third quarter of 2019 was ~~51,758~~56,422 BOE per day, consisting of ~~32,840~~36,421 Bbl of oil per day and ~~113.5~~120.0 MMcf of natural gas per day, an ~~11%~~18% increase from production of ~~46,489~~47,831 BOE per day, consisting of ~~27,381~~29,931 Bbl of oil per day and ~~114.6~~107.4 MMcf of natural gas per day, in the ~~second~~third quarter of 2018. The Delaware Basin contributed ~~approximately 89% of our daily oil production and approximately 77% of our daily natural gas production in the second quarter of 2019, as compared to~~ approximately 92% of our daily oil production and approximately ~~82%~~67% of our daily natural gas production in the ~~second quarter of 2018.~~

~~We did not conduct any operated drilling and completion activities on our leasehold properties in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas in the second~~third quarter of 2019, ~~although we did participate~~as compared to approximately 93% of our daily oil production and approximately 80% of our daily natural gas production in ~~eight gross (0.3 net) non-operated Haynesville shale wells that were completed and turned to sales.~~the third quarter of 2018.

Capital Resources Update

In ~~April~~October 2019, the lenders under our revolving credit agreement (the “Credit Agreement”), led by Royal Bank of Canada, completed their review of our proved oil and natural gas reserves at ~~December 31, 2018,~~June 30, 2019, and as a result, the borrowing base was ~~increased to~~affirmed at $900.0 million with the elected borrowing commitment remaining at $500.0 million. This ~~April~~October 2019 redetermination constituted the regularly scheduled ~~May~~November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment.

In ~~June~~October 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 by $50.0 million to ~~$325.0~~$375.0 million, using the accordion ~~feature.~~feature, which provides for potential increases to up to $400.0 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.~~

~~2019 Capital Expenditure Budget~~

At July 31, 2019, our 2019 estimated capital expenditures for drilling, completing and equipping wells remained $640 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. See “— Liquidity and Capital Resources — 2019 Capital Expenditure Budget” for more information regarding our 2019 capital expenditure budget.its subsidiaries.

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 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 recent accounting pronouncements and the 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 September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018			2019		2018			2019			2018
Operating Data:
Revenues (in thousands):⁽¹⁾
Oil	$	189,085	$	166,271		$	343,288		$	314,430		$	198,302	$	169,913		$	541,590		$	484,343
Natural gas	21,975		42,748			61,041			76,543			31,075		46,369			92,116			122,912
Total oil and natural gas revenues	211,060		209,019			404,329			390,973			229,377		216,282			633,706			607,255
Third-party midstream services revenues	14,359		3,407			26,197			6,475			15,257		6,809			41,454			13,284
Sales of purchased natural gas	8,963		—			20,194			—			19,864		—			40,058			—
Lease bonus - mineral acreage												1,711		—			1,711			—
Realized gain (loss) on derivatives	1,165		(2,488		)	4,435			(6,746		)	3,346		5,424			7,781			(1,322		)
Unrealized gain (loss) on derivatives	6,157		1,429			(39,562		)	11,845			9,847		(21,337		)	(29,715		)	(9,492		)
Total revenues	$	241,704	$	211,367		$	415,593		$	402,547		$	279,402	$	207,178		$	694,995		$	609,725
Net Production Volumes:⁽¹⁾
Oil (MBbl)⁽²⁾	3,346		2,706			6,452			5,088			3,659		2,973			10,112			8,061
Natural gas (Bcf)⁽³⁾	13.4		12.7			27.1			22.8			16.5		12.3			43.6			35.1
Total oil equivalent (MBOE)⁽⁴⁾	5,577		4,817			10,972			8,892			6,407		5,025			17,379			13,917
Average daily production (BOE/d)⁽⁵⁾	61,290		52,937			60,619			49,126			69,645		54,625			63,661			50,979
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	56.51	$	61.44		$	53.20		$	61.80		$	54.19	$	57.15		$	53.56		$	60.08
Oil, with realized derivatives (per Bbl)	$	56.86	$	60.52		$	53.91		$	60.46		$	54.97	$	58.97		$	54.29		$	59.91
Natural gas, without realized derivatives (per Mcf)	$	1.64	$	3.38		$	2.25		$	3.35		$	1.88	$	3.77		$	2.11		$	3.50
Natural gas, with realized derivatives (per Mcf)	$	1.64	$	3.38		$	2.25		$	3.36		$	1.91	$	3.77		$	2.12		$	3.50

_________________


(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 of oil.


(3)	One billion cubic feet of natural gas.


(4)	One thousand barrels 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~~September 30, 2019 as Compared to Three Months Ended ~~June~~September 30, 2018

Oil and natural gas revenues. Our oil and natural gas revenues increased ~~$2.0~~$13.1 million, or 1%6%, to ~~$211.1~~$229.4 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$209.0~~$216.3 million for the three months ended ~~June~~September 30, 2018. Our oil revenues increased ~~$22.8~~$28.4 million, or ~~14%~~17%, to $~~189.1~~198.3 million for the three months ended ~~June~~September 30, 2019, as compared to $~~166.3~~169.9 million for the three months ended ~~June~~September 30, 2018. The increase in oil revenues resulted from the ~~24%~~23% increase in our oil production to ~~3.3~~3.7 million Bbl of oil for the three months ended ~~June~~September 30, 2019, as compared to ~~2.7~~3.0 million Bbl of oil for the three months ended ~~June~~September 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 three months ended ~~June~~September 30, 2019 of ~~$56.51~~$54.19 per Bbl, a decrease of 8%5% as compared to ~~$61.44~~$57.15 per Bbl realized for the three months ended ~~June~~September 30, 2018. Our natural gas revenues decreased by ~~$20.8~~$15.3 million, or ~~49%~~33%, to ~~$22.0~~$31.1 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$42.7~~$46.4 million for the three months ended ~~June~~September 30, 2018. The decrease in natural gas revenues resulted from a ~~51%~~50% decrease in realized natural gas prices to ~~$1.64~~$1.88 per Mcf for the three months ended ~~June~~September 30, 2019, as compared to ~~$3.38~~$3.77 per Mcf realized for the three months ended ~~June~~September 30, 2018. This decrease was partially offset by the 6%34% increase in our natural gas production to ~~13.4~~16.5 Bcf for the three months ended ~~June~~September 30, 2019, as compared to ~~12.7~~12.3 Bcf for the three months ended ~~June~~September 30, 2018. 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 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~~$8.4 million, or more than ~~four-fold,~~two-fold, to ~~$14.4~~$15.3 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$3.4~~$6.8 million for the three months ended ~~June~~September 30, 2018. 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~~$6.7 million for the three months ended ~~June~~September 30, 2019, as compared to approximately ~~$1.9~~$3.3 million for the three months ended ~~June~~September 30, 2018, and (ii) an increase in our third-party natural gas gathering, transportation and processing revenues to approximately ~~$6.5~~$6.7 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$1.5~~$2.6 million for the three months ended ~~June~~September 30, 2018.

Sales of purchased natural gas. Our sales of purchased natural gas were ~~$9.0~~$19.9 million for the three months ended ~~June~~September 30, 2019. We had no sales of purchased natural gas for the three months ended ~~June~~September 30, 2018. 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 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.

Lease bonus - mineral acreage. Our lease bonus - mineral acreage revenues were $1.7 million for the three months ended September 30, 2019. We had no lease bonus revenues for the three months ended September 30, 2018. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests.

Realized gain (loss) on derivatives. Our realized net gain on derivatives was ~~$1.2~~$3.3 million for the three months ended ~~June~~September 30, 2019, as compared to a realized net ~~loss~~gain of ~~$2.5~~$5.4 million for the three months ended ~~June~~September 30, 2018. We realized a net gain of ~~$1.2~~$2.3 million related to our oil costless collar contracts for the three months ended ~~June~~September 30, 2019, resulting from oil prices that were below the floor prices of certain of our oil costless collar contracts. We realized a net gain of $0.5 million related to our oil basis swap contracts for the three months ended September 30, 2019, resulting from oil basis prices that were below 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~~$0.78 per Bbl produced during the three months ended ~~June~~September 30, 2019, as compared to an average ~~loss~~gain of approximately ~~$0.92~~$1.82 per Bbl produced during the three months ended ~~June~~September 30, 2018. Our total oil volumes hedged for the three months ended ~~June~~September 30, 2019 represented ~~68%~~62% of our total oil production, as compared to ~~51%~~47% of our total oil production for the three months ended ~~June~~September 30, 2018. We realized a net gain of $0.5 million related to our natural gas costless collar contracts for the three months ended September 30, 2019, resulting from natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average gain on our natural gas derivative contracts of $0.03 per Mcf produced during the three months ended September 30, 2019, as compared to no gain or loss realized on our natural

gas costless collar contracts for the three months ended September 30, 2018. Our total natural gas volumes hedged for the three months ended ~~June~~September 30, 2019 represented ~~13%~~11% of our total natural gas production, as compared to ~~33%~~34% of our total natural gas production for the three months ended ~~June~~September 30, 2018.

Unrealized gain (loss) on derivatives. Our unrealized net gain on derivatives was ~~$6.2~~$9.8 million for the three months ended ~~June~~September 30, 2019, as compared to an unrealized net ~~gain~~loss of ~~$1.4~~$21.3 million for the three months ended ~~June~~September 30, 2018. During the three months ended ~~June~~September 30, 2019, the net fair value of our open oil and natural gas derivative contracts increased to a net asset of ~~$10.3~~$20.1 million from a net asset of ~~$4.1~~$10.3 million at ~~March 31,~~June 30, 2019, resulting in an unrealized gain on derivatives of ~~$6.2~~$9.8 million for the three months ended ~~June~~September 30, 2019. During the three months ended ~~June~~September 30, 2018, the net fair value of our open oil and natural gas derivative contracts ~~increased~~decreased to a net liability of $24.7 million from a net liability of $3.4 million ~~from a net liability of $4.8 million~~ at ~~March 31,~~June 30, 2018, resulting in an unrealized ~~gain~~loss on derivatives of ~~$1.4~~$21.3 million for the three months ended ~~June~~September 30, 2018.

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

Oil and natural gas revenues. Our oil and natural gas revenues increased ~~$13.4~~$26.5 million, or 3%4%, to ~~$404.3~~$633.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~$391.0~~$607.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018. Our oil revenues increased ~~$28.9~~$57.2 million, or 9%12%, to ~~$343.3~~$541.6 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~$314.4~~$484.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018. ~~The~~This increase in our oil revenues resulted from the ~~27%~~25% increase in our oil production to ~~6.5~~10.1 million Bbl of oil for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~5.1~~8.1 million Bbl of oil for the ~~six~~nine months ended ~~June~~September 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~~nine months ended ~~June~~September 30, 2019 of ~~$53.20~~$53.56 per Bbl, a decrease of ~~14%~~11% as compared to ~~$61.80~~$60.08 per Bbl realized for the ~~six~~nine months ended ~~June~~September 30, 2018. Our natural gas revenues decreased by ~~$15.5~~$30.8 million, or ~~20%~~25%, to ~~$61.0~~$92.1 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~$76.5~~$122.9 million for the ~~six~~nine months ended ~~June~~September 30, 2018. The decrease in natural gas revenues resulted from a lower weighted average natural gas price realized for the ~~six~~nine months ended ~~June~~September 30, 2019 of ~~$2.25~~$2.11 per Mcf, a decrease of ~~33%~~40% as compared to ~~$3.35~~$3.50 per Mcf realized for the ~~six~~nine months ended ~~June~~September 30, 2018. This decrease was partially offset by the ~~19%~~24% increase in our natural gas production to ~~27.1~~43.6 Bcf for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~22.8~~35.1 Bcf for the ~~six~~nine months ended ~~June~~September 30, 2018. 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 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 ~~$19.7~~$28.2 million to ~~$26.2~~$41.5 million, or just over ~~four-fold,~~three-fold, for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~$6.5~~$13.3 million for the ~~six~~nine months ended ~~June~~September 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~~$18.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to approximately ~~$3.0~~$6.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018, ~~and~~ (ii) an increase in natural gas gathering, transportation and processing revenues to approximately ~~$11.0~~$17.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~$3.4~~$6.8 million for the ~~six~~nine months ended ~~June~~September 30, 2018, and (iii) an increase in our third-party oil transportation revenues to approximately $5.0 million for the nine months ended September 30, 2019, as compared to $0.2 million for the nine months ended September 30, 2018.

Sales of purchased natural gas. Our sales of purchased natural gas were ~~$20.2~~$40.1 million for the ~~six~~nine months ended ~~June~~September 30, 2019. We had no sales of purchased natural gas for the ~~six~~nine months ended ~~June~~September 30, 2018.

Lease bonus - mineral acreage. Our lease bonus - mineral acreage revenues were $1.7 million for the nine months ended September 30, 2019. We had no lease bonus revenues for the nine months ended September 30, 2018.

Realized gain (loss) on derivatives. Our realized net gain on derivatives was ~~$4.4~~$7.8 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to a realized net loss of ~~$6.7~~$1.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018. We realized a net gain of ~~$4.5~~$6.9 million related to our oil costless collar contracts for the ~~six~~nine months ended ~~June~~September 30, 2019, resulting from oil prices that were below the floor prices of certain of our oil costless collar contracts. We realized a net gain of $0.5 million related to our oil basis swap contracts for the nine months ended September 30, 2019, resulting from oil basis prices that were below the fixed prices of certain of our oil basis swaps contracts. We realized a net gain of $0.4 million related to our natural gas costless collar contracts for the nine months ended September 30, 2019, resulting from natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized net losses of ~~$6.7~~$1.3 million from our oil and natural gas derivative contracts for the ~~six~~nine months ended ~~June~~September 30, 2018, primarily resulting from oil ~~and natural gas~~ prices that were above the short call/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~~$0.73 per Bbl produced during the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to an average loss of ~~$1.34~~$0.17 per Bbl produced during the ~~six~~nine months ended ~~June~~September 30, 2018. Our total oil volumes hedged for the ~~six~~nine months ended ~~June~~September 30, 2019 represented ~~57%~~59% of our total oil production, as compared to ~~53%~~50% of our total oil production for the ~~six~~nine months ended ~~June~~September 30, 2018. Our total natural gas volumes hedged for the ~~six~~nine months ended ~~June~~September 30, 2019 represented ~~13%~~12% of our total natural gas production, as compared to ~~37%~~36% of our total natural gas production for the ~~six~~nine months ended ~~June~~September 30, 2018.

Unrealized gain (loss) ~~gain~~ on derivatives. Our unrealized net loss on derivatives was ~~$39.6~~$29.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to an unrealized net ~~gain~~loss of ~~$11.8~~$9.5 million for the ~~six~~nine months ended ~~June~~September 30, 2018. During the period from December 31, 2018 through ~~June~~September 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~~$20.1 million from a net asset of approximately $49.8 million, resulting in an unrealized loss on derivatives of approximately ~~$39.6~~$29.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019. During the period from December 31, 2017 through ~~June~~September 30, 2018, the aggregate net fair value of our open oil and natural gas derivative contracts ~~increased~~decreased from a net liability of approximately $15.2 million to a net liability of approximately ~~$3.4~~$24.7 million, resulting in an unrealized ~~gain~~loss on derivatives of approximately ~~$11.8~~$9.5 million for the ~~six~~nine months ended ~~June~~September 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 September 30,						Nine Months Ended September 30,
(In thousands, except expenses per BOE)	2019			2018			2019			2018			2019			2018			2019			2018
Expenses:
Production taxes, transportation and processing	$	21,542		$	20,110		$	41,207		$	37,901		$	24,762		$	20,215		$	65,969		$	58,116
Lease operating	26,351			25,006			57,514			47,154			29,714			22,531			87,228			69,685
Plant and other midstream services operating	8,422			5,676			17,738			9,896			8,817			7,291			26,555			17,187
Purchased natural gas	8,172			—			18,806			—			16,608			—			35,414			—
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207			92,498			70,457			249,497			192,664
Accretion of asset retirement obligations	420			375			834			739			520			387			1,354			1,126
General and administrative	19,876			19,369			38,166			37,295			20,381			18,444			58,547			55,739
Total expenses	164,915			137,374			331,264			255,192			193,300			139,325			524,564			394,517
Operating income	76,789			73,993			84,329			147,355			86,102			67,853			170,431			215,208
Other income (expense):
Inventory impairment	(368		)	—			(368		)	—
Net loss on asset sales and inventory impairment													(439		)	(196		)	(807		)	(196		)
Interest expense	(18,068		)	(8,004		)	(35,997		)	(16,495		)	(18,175		)	(10,340		)	(54,172		)	(26,835		)
Other expense	(423		)	(352		)	(532		)	(299		)	(245		)	(32,202		)	(777		)	(32,501		)
Total other expense	(18,859		)	(8,356		)	(36,897		)	(16,794		)	(18,859		)	(42,738		)	(55,756		)	(59,532		)
Net income	57,930			65,637			47,432			130,561
Income before income taxes													67,243			25,115			114,675			155,676
Total income tax provision	12,858			—			11,845			—			13,490			—			25,335			—
Net income attributable to non-controlling interest in subsidiaries	(8,320		)	(5,831		)	(15,782		)	(10,861		)	(9,800		)	(7,321		)	(25,582		)	(18,182		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700		$	43,953		$	17,794		$	63,758		$	137,494
Expenses per BOE:
Production taxes, transportation and processing	$	3.86		$	4.17		$	3.76		$	4.26		$	3.86		$	4.02		$	3.80		$	4.18
Lease operating	$	4.72		$	5.19		$	5.24		$	5.30		$	4.64		$	4.48		$	5.02		$	5.01
Plant and other midstream services operating	$	1.51		$	1.18		$	1.62		$	1.11		$	1.38		$	1.45		$	1.53		$	1.23
Depletion, depreciation and amortization	$	14.37		$	13.87		$	14.31		$	13.74		$	14.44		$	14.02		$	14.36		$	13.84
General and administrative	$	3.56		$	4.02		$	3.48		$	4.19		$	3.18		$	3.67		$	3.37		$	4.00

Three Months Ended ~~June~~September 30, 2019 as Compared to Three Months Ended ~~June~~September 30, 2018

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased ~~$1.4~~$4.5 million, or 7%22%, to ~~$21.5~~$24.8 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$20.1~~$20.2 million for the three months ended ~~June~~September 30, 2018. ~~The~~This increase was primarily attributable to the ~~$1.3~~$4.2 million increase in transportation and processing fees to ~~$6.3~~$8.5 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$5.0~~$4.3 million for the three months ended ~~June~~September 30, 2018, principally due to the 6%34% increase in our natural gas production to ~~13.4~~16.5 Bcf of natural gas for the three months ended ~~June~~September 30, 2019, as compared to ~~12.7~~12.3 Bcf of natural gas for the three months ended ~~June~~September 30, 2018. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 7%4% to $3.86 per BOE for the three months ended ~~June~~September 30, 2019, as compared to ~~$4.17~~$4.02 per BOE for the three months ended ~~June~~September 30, 2018. ~~The~~ This

decrease was primarily attributable to 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~~$7.2 million, or 5%32%, to ~~$26.4~~$29.7 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$25.0~~$22.5 million for the three months ended ~~June~~September 30, 2018. ~~The increase was~~On a unit-of-production basis, our lease operating expenses increased 4% to $4.64 per BOE for the three months ended September 30, 2019, as compared to $4.48 per BOE for the three months ended September 30, 2018. These increases were largely attributable to increases in compression, repairs and maintenance and ~~non-operated lease operating~~equipment rental expenses of approximately ~~$2.6~~$3.9 million, ~~for the three months ended June 30, 2019,~~ as ~~compared to the three months ended June 30, 2018. This~~well as an increase ~~was partially offset by a decrease~~ in salt water ~~trucking and~~ disposal ~~costs as more~~expenses of ~~our operated~~approximately $0.8 million for wells where we do not yet have ~~been connected~~connections to salt water disposal pipelines. Our lease operating expenses decreased 9% on a unit-of-production basis to $4.72 per BOE for the three months ended June 30, 2019, as compared to $5.19 per BOE for the three months ended June 30, 2018, as a result of the 16% increase in total oil equivalent production for the three months ended June 30, 2019, as compared to the three months ended June 30, 2018.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased ~~$2.7~~$1.5 million, or ~~48%~~21%, to ~~$8.4~~$8.8 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$5.7~~$7.3 million for the three months ended ~~June~~September 30, 2018. 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~~$4.8 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$3.0~~$3.7 million for the three months ended ~~June~~September 30, 2018, and ~~(iii)~~ increased expenses associated with pipeline operations of ~~$1.6~~$2.0 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$1.0~~$1.5 million for the three months ended ~~June~~September 30, 2018.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased ~~$13.3~~$22.0 million, or ~~20%~~31%, to ~~$80.1~~$92.5 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$66.8~~$70.5 million for the three months ended ~~June~~September 30, 2018. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 4%3% to ~~$14.37~~$14.44 per BOE for the three months ended ~~June~~September 30, 2019, as compared to ~~$13.87~~$14.02 per BOE for the three months ended ~~June~~September 30, 2018. ~~The increase in our total depletion, depreciation and amortization expenses was~~These increases were primarily attributable to (i) the ~~16%~~28% increase in our total oil equivalent production to ~~5.6~~6.4 million BOE for the three months ended ~~June~~September 30, 2019, as compared to ~~4.8~~5.0 million BOE for the three months ended ~~June~~September 30, 2018, and (ii) increased depreciation expenses attributable to our midstream segment ofto approximately ~~$3.8~~$4.1 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$2.3~~$2.6 million for the three months ended ~~June~~September 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~~September 30, 2019, as compared to ~~June~~September 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 ~~$0.5~~$1.9 million, or 3%11%, to ~~$19.9~~$20.4 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$19.4~~$18.4 million for the three months ended ~~June~~September 30, 2018. ~~Our~~This increase was primarily attributable to increased payroll and related expenses. Primarily as a result of the 28% increase in oil and natural gas production for the three months ended September 30, 2019, as compared to the three months ended September 30, 2018, our general and administrative expenses decreased ~~11%~~13% on a unit-of-production basis to ~~$3.56~~$3.18 per BOE for the three months ended ~~June~~September 30, 2019, as compared to ~~$4.02~~$3.67 per BOE for the three months ended ~~June~~September 30, ~~2018, primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.~~2018.

Interest expense. For the three months ended ~~June~~September 30, 2019, we incurred total interest expense of approximately ~~$20.7~~$20.9 million. We capitalized approximately ~~$2.6~~$2.7 million of our interest expense on certain qualifying projects for the three months ended ~~June~~September 30, 2019 and expensed the remaining ~~$18.1~~$18.2 million to operations. For the three months ended ~~June~~September 30, 2018, we incurred total interest expense of approximately ~~$10.6~~$12.1 million. We capitalized approximately ~~$2.6~~$1.7 million of our interest expense on certain qualifying projects for the three months ended ~~June~~September 30, 2018 and expensed the remaining ~~$8.0~~$10.3 million to operations.

Total income tax provision. We recorded a total income tax expense of ~~$12.9~~$13.5 million for the three months ended June 30, 2019, which differs from amounts computed by applying the U.S. federal statutory rate to pre-tax income due primarily 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.

~~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 for the six 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 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). 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 of $11.8 million for the six months ended June~~September 30, 2019, which differs from amounts computed by applying the U.S. federal statutory rate to pre-tax income 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 determined to be more likely than not to be utilized. At ~~June~~September 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~~September 30, 2018 due to uncertainties regarding the future realization of our deferred tax assets.

Nine Months Ended September 30, 2019 as Compared to Nine Months Ended September 30, 2018

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased $7.9 million, or 14%, to $66.0 million for the nine months ended September 30, 2019, as compared to $58.1 million for the nine months ended September 30, 2018. This increase was primarily attributable to the $7.0 million increase in our transportation and processing expenses for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, principally due to the 24% increase in our natural gas production to 43.6 Bcf of natural gas for the nine months ended September 30, 2019, as compared to 35.1 Bcf of natural gas for the nine months ended September 30, 2018. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 9% to $3.80 per BOE for the nine months ended September 30, 2019, as compared to $4.18 per BOE for the nine months ended September 30, 2018. This 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 $17.5 million, or 25%, to $87.2 million for the nine months ended September 30, 2019, as compared to $69.7 million for the nine months ended September 30, 2018. This increase was largely attributable to increases in compression, repairs and maintenance and equipment rental expenses of approximately $7.0 million, as well as an increase in salt water disposal expenses of approximately $3.0 million for wells where we do not yet have connections to salt water disposal pipelines. Our lease operating expenses on a unit-of-production basis remained essentially flat at $5.02 per BOE for the nine months ended September 30, 2019, as compared to $5.01 per BOE for the nine months ended September 30, 2018.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $9.4 million, or 55%, to $26.6 million for the nine months ended September 30, 2019, as compared to $17.2 million for the nine months ended September 30, 2018. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial salt water disposal operations of $12.9 million for the nine months ended September 30, 2019, as compared to $8.8 million for the nine months ended September 30, 2018, (ii) increased expenses associated with the Black River Processing Plant, which was expanded late in the first quarter of 2018, of $8.2 million for the nine months ended September 30, 2019, as compared to $5.3 million for the nine months ended September 30, 2018, and (iii) increased expenses associated with pipeline operations of $5.7 million for the nine months ended September 30, 2019, as compared to $3.1 million for the nine months ended September 30, 2018.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $56.8 million, or 29%, to $249.5 million for the nine months ended September 30, 2019, as compared to $192.7 million for the nine months ended September 30, 2018. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 4% to $14.36 per BOE for the nine months ended September 30, 2019, as compared to $13.84 per BOE for the nine months ended September 30, 2018. These increases were primarily attributable to (i) the 25% increase in our total oil equivalent production to 17.4 million BOE for the nine months ended September 30, 2019, as compared to 13.9 million BOE for the nine months ended September 30, 2018, and (ii) the increase in depreciation expenses attributable to our midstream segment to approximately $11.6 million for the nine months ended September 30, 2019, as compared to $6.5 million for the nine months ended September 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 September 30, 2019, as compared to September 30, 2018, primarily attributable to our ongoing delineation and development activities in the Delaware Basin.

General and administrative. Our general and administrative expenses increased $2.8 million, or 5%, to $58.5 million for the nine months ended September 30, 2019, as compared to $55.7 million for the nine months ended September 30, 2018. This increase was primarily attributable to increased payroll and related expenses. Primarily as a result of the 25% increase in total oil equivalent production for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, our general and administrative expenses decreased 16% on a unit-of-production basis to $3.37 per BOE for the nine months ended September 30, 2019, as compared to $4.00 per BOE for the nine months ended September 30, 2018.

Interest expense. For the nine months ended September 30, 2019, we incurred total interest expense of approximately $61.1 million. We capitalized approximately $7.0 million of our interest expense on certain qualifying projects for the nine months ended September 30, 2019 and expensed the remaining $54.2 million to operations. For the nine months ended September 30, 2018, we incurred total interest expense of approximately $33.0 million. We capitalized approximately $6.2 million of our interest expense on certain qualifying projects for the nine months ended September 30, 2018 and expensed the remaining $26.8 million to operations.

Total income tax provision. We recorded a total income tax expense of $25.3 million for the nine months ended September 30, 2019, which differs from amounts computed by applying the U.S. federal statutory rate to pre-tax income 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 determined to be more likely than not to be utilized. At September 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 September 30, 2018 due to uncertainties regarding the future realization of our deferred tax assets.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during the remainder of 2019 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 and for 2020 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) and borrowings under the San Mateo Credit Facility. 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 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~~September 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~~$215.0 million in borrowings outstanding under the Credit Agreement and (iii) approximately $13.6 million in outstanding

letters of credit issued pursuant to the Credit Agreement, and San Mateo I had ~~$240.0~~$260.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $16.2 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.

At ~~June~~October 29, 2019, we had (i) $1.05 billion of outstanding Notes, (ii) $255.0 million in borrowings outstanding under the Credit Agreement and (iii) approximately $35.0 million in outstanding letters of credit issued pursuant to the Credit Agreement, and San Mateo I had $260.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $16.2 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.

At September 30, 2019, we had cash totaling approximately ~~$60.0~~$15.7 million and restricted cash, most of which was associated with San Mateo, totaling approximately ~~$24.8~~$25.1 million. 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~~October 2019, the lenders under our Credit Agreement, led by Royal Bank of Canada, completed their review of our proved oil and natural gas reserves at ~~December 31, 2018,~~June 30, 2019, and as a result, the borrowing base was ~~increased to~~affirmed at $900.0 million with the elected borrowing commitment remaining at $500.0 million. This ~~April~~October 2019 redetermination constituted the regularly scheduled ~~May~~November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment.

In ~~June~~October 2019, the lender commitments under the San Mateo Credit Facility, led by The Bank of Nova Scotia, were increased by $50.0 million to ~~$325.0~~$375.0 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.~~II and its subsidiaries.

During the ~~second~~third quarter of 2019, we continued our 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 six drilling rigs in the Delaware Basin and continued to do so at ~~June~~September 30, 2019. During the ~~second~~third 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.~~areas. 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 in the Greater Stebbins Area for most of the remainder of 2019. We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of ~~2019.~~2019 and for 2020.

~~During~~We had no operated drilling activities in the ~~second~~Eagle Ford shale or Haynesville shale during the third quarter of 2019 ~~we also finished 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~~there for the remainder of 2019.

2019 Capital Expenditure Budget

At ~~July~~October 31, 2019, our 2019 estimated capital expenditures for drilling, completing and equipping wells (“D/C/E”) remained $640 to $680 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 certain of our operated wells throughout 2019, we ~~now~~ expect to complete and turn to sales ~~four gross (6.8 net)~~7.9 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.plan. Due to the lower well costs and facilities savings achieved thus far in 2019, however, ~~at July 31, 2019,~~ we anticipate that we should be able to deliver these additional well completions within our originally budgeted estimates for D/C/E 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 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. During the first ~~six~~nine months of 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, ~~and~~plus other interruptible volumes, obtained a significant additional acreage ~~dedication and a~~dedications from existing salt water ~~disposal well permit~~customers and added an acreage dedication from ~~an existing salt water~~a new oil customer. In addition, San Mateo is also 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,~~During the third quarter of 2019, San Mateo ~~had~~ also ~~entered into an agreement to acquire~~acquired 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 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 agreed to provide to us in conjunction with the formation of San Mateo II.

Substantially all of our remaining 2019 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 capital expenditures and operating cash flows, we may divest portions of our non-core assets, particularly in our South Texas and Haynesville shale positions, 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, 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. 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 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.

Our 2019 capital expenditures may be adjusted as business conditions warrant, and the amount, timing and allocation of such expenditures is 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 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 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 and the hedges we currently have in place. 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 8 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at ~~June~~September 30, 2019.

Our unaudited cash flows for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018 are presented below:


	Six Months Ended June 30,						Nine Months Ended September 30,
(In thousands)	2019			2018			2019			2018
Net cash provided by operating activities	$	194,497		$	254,208		$	353,127		$	419,318
Net cash used in investing activities	(394,694		)	(493,562		)	(639,049		)	(1,220,528		)
Net cash provided by financing activities	200,975			280,385			242,744			751,736
Net change in cash and restricted cash	$	778		$	41,031		$	(43,178	)	$	(49,474	)
Adjusted EBITDAattributable to Matador Resources Company shareholders⁽¹⁾	$	268,943		$	254,592		$	429,732		$	409,984

__________________


(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~~$66.2 million to ~~$194.5~~$353.1 million for the ~~six~~nine months ended ~~June~~September 30, 2019 from ~~$254.2~~$419.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018. Excluding changes in operating assets and liabilities, net

cash provided by operating activities increased to ~~$255.5~~$411.6 million for the ~~six~~nine months ended ~~June~~September 30, 2019 from ~~$251.0~~$405.0 million for the ~~six~~nine months ended ~~June~~September 30, 2018, primarily attributable to the increase in our total oil equivalent production, which was partially offset by the decrease in realized oil and natural gas prices between the two periods. Changes in our operating assets and liabilities between the two periods resulted in a net decrease of approximately ~~$64.2~~$72.8 million in net cash provided by operating activities for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to the ~~six~~nine months ended ~~June~~September 30, 2018.

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), weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. 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 by ~~$98.9~~$581.5 million to ~~$394.7~~$639.0 million for the ~~six~~nine months ended ~~June~~September 30, 2019 from ~~$493.6 million~~$1.22 billion for the ~~six~~nine months ended ~~June~~September 30, 2018. This decrease in net cash used in investing activities is due in part to a decrease of ~~$71.7~~$570.5 million in oil and natural gas properties capital expenditures for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to the ~~six~~nine months ended ~~June~~September 30, 2018. Cash used for oil and natural gas properties capital expenditures for the ~~six~~nine months ended ~~June~~September 30, 2019 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin and in South Texas. Cash used for oil and natural gas properties capital expenditures for the nine months ended September 30, 2018 was primarily attributable to the acquisition of additional leasehold and mineral interests including, primarily, the BLM Acquisition, and to our operated and non-operated drilling and completion activities in the Delaware Basin. 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~~$13.4 million in proceeds from the sale of assets.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities decreased by ~~$79.4~~$509.0 million to ~~$201.0~~$242.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019 from ~~$280.4~~$751.7 million for the ~~six~~nine months ended ~~June~~September 30, 2018. ~~This decrease in net~~During the nine months ended September 30, 2019, our primary sources of cash ~~provided by~~from financing activities ~~is due in part to a~~included net ~~increase in~~ borrowings under our Credit Agreement of ~~$165.0~~$175.0 million, ~~between~~borrowings under the ~~two periods, offset by a reduction~~San Mateo Credit Facility of $40.0 million and net contributions related to the formation of San Mateo I and from non-controlling interest owners in less-than-wholly-owned subsidiaries of $29.3 million. During the nine months ended September 30, 2018, we (i) received net proceeds from the issuance of common stock of ~~$226.6~~$226.5 million, (ii) had net borrowings under our Credit Agreement of $325.0 million, (iii) received net proceeds from the Notes offering of $740.5 million and ~~a decrease of $34.1~~(iv) had $70.8 million in net contributions related to the formation of San Mateo I and from non-controlling interest owners in less-than-wholly-owned subsidiaries. These cash inflows during the nine months ended September 30, 2018 were offset by the purchase of our senior unsecured notes of $605.8 million.

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 September 30,						Nine Months Ended September 30,
(In thousands)	2019			2018			2019			2018			2019			2018			2019			2018
Unaudited Adjusted EBITDA Reconciliation to Net Income:
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700		$	43,953		$	17,794		$	63,758		$	137,494
Net income attributable to non-controlling interest in subsidiaries	8,320			5,831			15,782			10,861			9,800			7,321			25,582			18,182
Net income	45,072			65,637			35,587			130,561			53,753			25,115			89,340			155,676
Interest expense	18,068			8,004			35,997			16,495			18,175			10,340			54,172			26,835
Total income tax provision	12,858			—			11,845			—			13,490			—			25,335			—
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207			92,498			70,457			249,497			192,664
Accretion of asset retirement obligations	420			375			834			739			520			387			1,354			1,126
Unrealized (gain) loss on derivatives	(6,157		)	(1,429		)	39,562			(11,845		)	(9,847		)	21,337			29,715			9,492
Stock-based compensation expense	4,490			4,766			9,076			8,945			4,664			4,842			13,740			13,787
Inventory impairment	368			—			368			—
Net loss on asset sales and inventory impairment													439			196			807			196
Prepayment premium on extinguishment of debt													—			31,226			—			31,226
Consolidated Adjusted EBITDA	155,251			144,191			290,268			267,102			173,692			163,900			463,960			431,002
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,147		)	(6,853		)	(21,325		)	(12,510		)	(12,903		)	(8,508		)	(34,228		)	(21,018		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	144,104		$	137,338		$	268,943		$	254,592		$	160,789		$	155,392		$	429,732		$	409,984


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2019			2018			2019			2018			2019			2018			2019			2018
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		$	158,630		$	165,111		$	353,127		$	419,318
Net change in operating assets and liabilities	2,472			18,174			60,963			(3,190		)	(2,488		)	(11,111		)	58,475			(14,300		)
Interest expense, net of non-cash portion	17,522			7,958			34,808			16,084			17,550			9,900			52,358			25,984
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,147		)	(6,853		)	(21,325		)	(12,510		)	(12,903		)	(8,508		)	(34,228		)	(21,018		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	144,104		$	137,338		$	268,943		$	254,592		$	160,789		$	155,392		$	429,732		$	409,984

Net income attributable to Matador ~~Resources Company~~ shareholders ~~decreased~~increased by ~~$23.1~~$26.2 million to ~~$36.8~~$44.0 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$59.8~~$17.8 million for the three months ended ~~June~~September 30, 2018. This increase in net income

attributable to Matador shareholders is primarily attributable to an increase of $13.1 million in oil and natural gas revenues, an increase of $8.4 million in third-party midstream services revenues, an increase of $31.2 million in unrealized gain on derivatives and the absence of a prepayment premium of $31.2 million to repurchase our debt, which only occurred during the three months ended September 30, 2018. These increases were offset by an aggregate $35.7 million increase in production taxes, transportation and processing, lease operating, general and administrative and depletion, depreciation and amortization expenses, a $7.8 million increase in interest expense and a $13.5 million increase in the deferred income tax provision.

Net income attributable to Matador shareholders decreased by $73.7 million to $63.8 million for the nine months ended September 30, 2019, as compared to $137.5 million for the nine months ended September 30, 2018. This decrease in net income attributable to Matador ~~Resources Company~~ shareholders is primarily attributable to ~~(i)~~ a ~~$13.3~~$20.2 million increase in unrealized loss on derivatives, a $17.5 million increase in lease operating expenses, a $56.8 million increase in depletion, depreciation and amortization expenses, ~~(ii)~~ a ~~$10.1~~$27.3 million increase in interest expense and ~~(iii)~~ a ~~$12.9~~$25.3 million increase in the deferred income tax ~~provision between the two periods.~~provision. This decrease was partially offset by ana $9.1 million increase ~~of $3.7 million~~ from a 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 in 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 by an increase of $11.2 million from realized loss to realized gain on derivatives, a ~~$13.4~~$26.5 million increase in oil and natural gas revenues, ~~and~~ an increase of ~~$19.7~~$28.2 million in third-party midstream services ~~revenues.~~revenues and the absence of a prepayment premium of $31.2 million to repurchase our debt, which only occurred during the three months ended September 30, 2018.

Adjusted EBITDA, a non-GAAP financial measure, increased by ~~$6.8~~$5.4 million to ~~$144.1~~$160.8 million for the three months ended ~~June~~September 30, 2019, as compared to ~~$137.3~~$155.4 million for the three months ended ~~June~~September 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~~September 30, 2019, as compared to the three months ended ~~June~~September 30, 2018.

Adjusted EBITDA, a non-GAAP financial measure, increased by ~~$14.4~~$19.7 million to ~~$268.9~~$429.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019, as compared to ~~$254.6~~$410.0 million for the ~~six~~nine months ended ~~June~~September 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 ~~six~~nine months ended ~~June~~September 30, 2019, as compared to the ~~six~~nine months ended ~~June~~September 30, 2018.

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~~September 30, 2019, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) termination obligations under short-term drilling rig contracts, (iii) firm transportation, gathering, processing and disposal commitments and (iv) 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 10 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~~September 30, 2019:


	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	$	—	$	504,871	$	—	$	—	$	504,871	$	—
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		27,297		3,936		7,968		8,472		6,921
Non-operated drilling commitments⁽³⁾	51,719		51,719		—				—		27,956		27,956		—		—		—
Drilling rig contracts⁽⁴⁾	39,127		23,870		15,257		—		—		48,198		28,982		19,216		—		—
Asset retirement obligations	32,242		1,556		2,441		537		27,708		34,126		619		3,080		1,637		28,790
Natural gas transportation, gathering and processing agreements with non-affiliates⁽⁵⁾	554,863		43,786		113,567		113,598		283,912		548,432		54,159		113,476		113,507		267,290
Gathering, processing and disposal agreements with San Mateo⁽⁶⁾	547,514		—		96,517		163,408		287,589		525,612		—		74,234		163,614		287,764
Natural gas engineering, construction and installation contract⁽⁷⁾	71,820		71,820		—		—		—		62,131		62,131		—		—		—
Total contractual cash obligations	$	2,850,268	$	196,475	$	235,745	$	760,829	$	1,657,219	$	2,828,623	$	177,783	$	217,974	$	792,101	$	1,640,765

__________________

(1)

The amounts included in the table above represent principal maturities only. At ~~June~~September 30, 2019, we had ~~$205.0~~$215.0 million in borrowings outstanding under our Credit Agreement and approximately $13.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2023. At ~~June~~September 30, 2019, San Mateo I had ~~$240.0~~$260.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $16.2 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%~~3.56% and ~~4.16%~~3.80% (for the Credit Agreement and the San Mateo Credit Facility), respectively, at ~~June~~September 30, 2019, the interest expense is expected to be approximately ~~$7.5~~$7.8 million and $10.0 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~~September 30, 2019 is expected to be approximately $61.7 million each year until maturity.

(3)

At ~~June~~September 30, 2019, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at ~~June~~September 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~~$28.0 million at ~~June~~September 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)

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 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.

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)

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

(7)

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 10 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 and 2019, 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. For the three months ended ~~June~~September 30, 2019, oil prices averaged ~~$59.96~~$56.43 per Bbl, ranging from a ~~high~~low of ~~$66.30~~$51.09 per Bbl in ~~late April~~early August to a ~~low~~high of ~~$51.14~~$62.90 per Bbl in ~~mid-June,~~mid-September, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date.

We realized a weighted average oil price of ~~$56.51~~$54.19 per Bbl ($~~56.86~~54.97 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended ~~June~~September 30, 2019, as compared to ~~$61.44~~$57.15 per Bbl ($~~60.52~~58.97 per Bbl including realized ~~losses~~gains from oil derivatives) for our oil production for the three months ended ~~June~~September 30, 2018. At ~~July 31,~~October 29, 2019, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had decreased from the average price for the ~~second~~third quarter of 2019, settling at ~~$58.58~~$55.54 per Bbl, which was also a decrease as compared to ~~$68.76~~$67.04 per Bbl at ~~July 31,~~October 29, 2018.

For the three months ended ~~June~~September 30, 2019, natural gas prices averaged ~~$2.51~~$2.33 per MMBtu, ranging from a ~~high~~low of approximately ~~$2.71~~$2.07 per MMBtu in early ~~April~~August to a ~~low~~high of approximately ~~$2.19~~$2.68 per MMBtu in ~~late June,~~mid-September, 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~~$1.88 per Mcf ($1.91 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended September 30, 2019, as compared to $3.77 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, as compared to $3.38 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 JuneSeptember 30, 2018. At ~~July 31,~~October 29, 2019, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased from the average price for the ~~second~~third quarter of 2019, settling at ~~$2.23~~$2.60 per MMBtu, which was also a decrease as compared to ~~$2.78~~$3.19 per MMBtu at ~~July 31,~~October 29, 2018.

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. We are uncertain if oil and natural gas prices may rise from their current levels, and, in fact, oil and natural gas prices may decrease in future periods.

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 Credit Agreement and through the capital markets.

In addition, 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 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~~September 30, 2019, 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, most of our natural gas production from the Delaware Basin was sold based on prices established at the Waha Hub in far West Texas. At the end of September 2019, the Kinder Morgan Gulf Coast Express Pipeline Project (the “GCX Pipeline”) 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.

During the second quarter of 2018, the price differentials for oil sold in Midland and natural gas sold at 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.~~2018 and throughout most of 2019.

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~~became positive late in the ~~future,~~third quarter and remained positive early in the fourth quarter, although it is possible that this differential could turn negative and widen ~~further~~again 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 near the end of the year. The natural gas price differential narrowed to between $1.00 and $2.00 per MMBtu at the beginning of 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~~

During the third quarter of 2019, the Waha basis differentials improved, and natural gas ~~sold at Waha were positive for the month of July, although~~ prices at the Waha ~~remained well below Henry Hub prices.~~

~~The majority of~~hub averaged approximately $0.89 per MMBtu in the third quarter. As a result, we did not need to shut in certain high gas-to-oil ratio wells or take other actions to curtail our Delaware Basin natural gas production ~~is expected to remain exposed to~~during the ~~Waha-Henry Hub basis differentials until early~~third quarter. Early in the fourth quarter, ~~of 2019, when~~however, the ~~Kinder Morgan Gulf Coast Express Pipeline Project (“GCX Pipeline”) is expected to become operational. We~~Waha basis differentials have ~~secured firm~~widened further at times, and natural gas ~~transportation and sales~~prices at the Waha hub were less than $0.10 per MMBtu on certain days in October 2019.

Beginning in late September 2019, as the GCX Pipeline ~~for an average~~became operational, we began selling a majority of ~~approximately 110,000 to 115,000 MMBtu per day~~our produced Delaware Basin natural gas at ~~a price based upon~~ Houston Ship Channel ~~pricing.~~pricing and, as of October 29, 2019, we have seen an improvement in the natural gas pricing received despite higher transportation charges we incur to transport the natural gas to the Gulf Coast. Further, approximately ~~23%~~33% of our reported natural gas production in the ~~second~~third quarter of 2019 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 the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. At ~~July 31,~~October 29, 2019, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. During the third quarter of 2018, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin and elsewhere. Although we did not encounter 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 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 or longer until additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets is completed. We can provide no assurances as to how long these volatile differentials may persist, and as noted above, these price differentials could widen further 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 the remainder of 2019 and have limited oil basis hedges in place for the remainder of ~~2019 and 2020.~~2019.

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, 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. New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Although the bills relating to the moratorium on hydraulic fracturing and the tax on natural gas processors were 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.

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.

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, 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 with downside price protection through the purchase of a put option, but they also allow the Company 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. 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.

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~~September 30, 2019, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust 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 8 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at ~~June~~September 30, 2019. 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~~September 30, 2019 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~~September 30, 2019 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.

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.

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

During the quarter ended ~~June~~September 30, 2019, 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
July 1, 2019 to July 31, 2019	3,178	$	18.06	—	—
August 1, 2019 to August 31, 2019	18,087	$	15.63	—	—
September 1, 2019 to September 30, 2019	819	$	16.08	—	—
Total	22,084	$	16.00	—	—

_________________


(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†		~~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).~~

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

~~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 Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug ~~(filed herewith)~~(incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).

~~10.5†~~10.2†		First Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson ~~(filed herewith)~~(incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 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~~September 30, 2019 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,~~November 1, 2019	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer



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

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