Matador Resources Co - Quarter Report: 2019 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

_________________________________________________________



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

For the quarterly period ended June 30, 2019



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

Table of Contents

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2019

TABLE OF CONTENTS



	Page
PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements — Unaudited	3
Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018	3
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018	4
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three and Six Months Ended June 30, 2019 and 2018	5
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3. Quantitative and Qualitative Disclosures About Market Risk	42
Item 4. Controls and Procedures	42
PART II — OTHER INFORMATION	43
Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 6. Exhibits	44
SIGNATURES	45

Table of Contents

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
ASSETS
Current assets
Cash	$	59,950		$	64,545
Restricted cash	24,812			19,439
Accounts receivable
Oil and natural gas revenues	66,921			68,161
Joint interest billings	61,872			61,831
Other	18,386			16,159
Derivative instruments	8,271			49,929
Lease and well equipment inventory	20,281			17,564
Prepaid expenses and other assets	12,891			8,057
Total current assets	273,384			305,685
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	4,094,417			3,780,236
Unproved and unevaluated	1,234,176			1,199,511
Midstream properties	492,420			428,025
Other property and equipment	25,170			22,041
Less accumulated depletion, depreciation and amortization	(2,462,840		)	(2,306,949		)
Net property and equipment	3,383,343			3,122,864
Other assets
Derivative instruments	2,202			—
Deferred income taxes	7,149			20,457
Other assets	85,373			6,512
Total other assets	94,724			26,969
Total assets	$	3,751,451		$	3,455,518
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	19,821		$	66,970
Accrued liabilities	191,608			170,855
Royalties payable	66,130			64,776
Amounts due to affiliates	10,200			13,052
Advances from joint interest owners	4,725			10,968
Amounts due to joint ventures	1,588			2,373
Other current liabilities	42,703			1,028
Total current liabilities	336,775			330,022
Long-term liabilities
Borrowings under Credit Agreement	205,000			40,000
Borrowings under San Mateo Credit Facility	240,000			220,000
Senior unsecured notes payable	1,038,625			1,037,837
Asset retirement obligations	30,686			29,736
Derivative instruments	189			83
Deferred income taxes	14,845			13,221
Other long-term liabilities	44,728			4,962
Total long-term liabilities	1,574,073			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
Additional paid-in capital	1,955,504			1,924,408
Accumulated deficit	(216,472		)	(236,277		)
Treasury stock, at cost, 218,309 and 20,913 shares, respectively	(3,724		)	(415		)
Total Matador Resources Company shareholders’ equity	1,736,477			1,688,880
Non-controlling interest in subsidiaries	104,126			90,777
Total shareholders’ equity	1,840,603			1,779,657
Total liabilities and shareholders’ equity	$	3,751,451		$	3,455,518

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

Table of Contents

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,
	2019			2018			2019			2018
Revenues
Oil and natural gas revenues	$	211,060		$	209,019		$	404,329		$	390,973
Third-party midstream services revenues	14,359			3,407			26,197			6,475
Sales of purchased natural gas	8,963			—			20,194			—
Realized gain (loss) on derivatives	1,165			(2,488		)	4,435			(6,746		)
Unrealized gain (loss) on derivatives	6,157			1,429			(39,562		)	11,845
Total revenues	241,704			211,367			415,593			402,547
Expenses
Production taxes, transportation and processing	21,542			20,110			41,207			37,901
Lease operating	26,351			25,006			57,514			47,154
Plant and other midstream services operating	8,422			5,676			17,738			9,896
Purchased natural gas	8,172			—			18,806			—
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207
Accretion of asset retirement obligations	420			375			834			739
General and administrative	19,876			19,369			38,166			37,295
Total expenses	164,915			137,374			331,264			255,192
Operating income	76,789			73,993			84,329			147,355
Other income (expense)
Inventory impairment	(368		)	—			(368		)	—
Interest expense	(18,068		)	(8,004		)	(35,997		)	(16,495		)
Other expense	(423		)	(352		)	(532		)	(299		)
Total other expense	(18,859		)	(8,356		)	(36,897		)	(16,794		)
Income before income taxes	57,930			65,637			47,432			130,561
Income tax provision
Deferred	12,858			—			11,845			—
Total income tax provision	12,858			—			11,845			—
Net income	45,072			65,637			35,587			130,561
Net income attributable to non-controlling interest in subsidiaries	(8,320		)	(5,831		)	(15,782		)	(10,861		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700
Earnings per common share
Basic	$	0.32		$	0.53		$	0.17		$	1.08
Diluted	$	0.31		$	0.53		$	0.17		$	1.08
Weighted average common shares outstanding
Basic	116,571			112,706			116,469			110,809
Diluted	116,903			113,056			116,839			111,280

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

Table of Contents

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(In thousands)

For the Three and Six Months Ended June 30, 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

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

Table of Contents

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(in thousands)

For the Three and Six Months Ended June 30, 2018



														Total shareholders’ equity attributable to Matador Resources Company


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

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

Table of Contents

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS — UNAUDITED

(In thousands)



	Six Months Ended June 30,
	2019			2018
Operating activities
Net income	$	35,587		$	130,561
Adjustments to reconcile net income to net cash provided by operating activities
Unrealized loss (gain) on derivatives	39,562			(11,845		)
Depletion, depreciation and amortization	156,999			122,207
Accretion of asset retirement obligations	834			739
Stock-based compensation expense	9,076			8,945
Deferred income tax provision	11,845			—
Amortization of debt issuance cost	1,189			411
Inventory impairment	368			—
Changes in operating assets and liabilities
Accounts receivable	(378		)	(9,321		)
Lease and well equipment inventory	(3,456		)	(8,611		)
Prepaid expenses	(4,834		)	(2,167		)
Other assets	(415		)	(149		)
Accounts payable, accrued liabilities and other current liabilities	(48,746		)	(883		)
Royalties payable	1,353			8,393
Advances from joint interest owners	(6,243		)	16,025
Other long-term liabilities	1,756			(97		)
Net cash provided by operating activities	194,497			254,208
Investing activities
Oil and natural gas properties capital expenditures	(349,915		)	(421,595		)
Midstream capital expenditures	(64,106		)	(78,302		)
Expenditures for other property and equipment	(2,206		)	(1,258		)
Proceeds from sale of assets	21,533			7,593
Net cash used in investing activities	(394,694		)	(493,562		)
Financing activities
Repayments of borrowings	—			(45,000		)
Borrowings under Credit Agreement	165,000			45,000
Borrowings under San Mateo Credit Facility	20,000			—
Cost to amend credit facilities	(415		)	—
Proceeds from issuance of common stock	—			226,612
Cost to issue equity	—			(73		)
Proceeds from stock options exercised	3,298			464
Contributions related to formation of San Mateo I	14,700			14,700
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	19,831			53,900
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(17,640		)	(10,535		)
Taxes paid related to net share settlement of stock-based compensation	(3,309		)	(4,683		)
Cash paid under financing lease obligations	(490		)	—
Net cash provided by financing activities	200,975			280,385
Increase in cash and restricted cash	778			41,031
Cash and restricted cash at beginning of period	83,984			102,482
Cash and restricted cash at end of period	$	84,762		$	143,513

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. 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 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 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.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The adoption of these ASUs resulted in the Company recording in the condensed consolidated balance sheet beginning January 1, 2019 certain of the Company’s compressor leases, drilling rig leases and office leases, which were previously considered operating leases and not reported on the Company’s condensed consolidated balance sheets. As such, upon adoption, the Company recorded (i) long-term right of use assets of $62.3 million, which are included in “Other assets” and “Other property and equipment,” and (ii) net right of use liabilities of $62.3 million, which are included in “Other current liabilities” and “Other long-term liabilities.” There was no cumulative-effect adjustment to the opening balance of accumulated deficit as a result of the adoption of these ASUs.

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

Revenues

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



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



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Oil revenues	$	189,085	$	166,271	$	343,288	$	314,430
Natural gas revenues	21,975		42,748		61,041		76,543
Third-party midstream services revenues	14,359		3,407		26,197		6,475
Sales of purchased natural gas	8,963		—		20,194		—
Total revenues from contracts with customers	$	234,382	$	212,426	$	450,720	$	397,448

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter that determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For both the three and six months ended June 30, 2019 and 2018, the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and, as a result, no impairment charge was necessary.

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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Earnings (Loss) Per Common Share

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

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



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

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

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 3 — LEASES

The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s interim unaudited condensed consolidated balance sheet. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising 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 30, 2019 was 3.73%. 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 months ended June 30, 2019 (in thousands). Lease payments represent gross payments to vendors, which, for certain of our operating assets, are partially offset by amounts received from other working interest owners in our operated wells.



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

_____________________


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


(2)	These costs are related to leases that are not recorded as right of use assets or lease liabilities in the interim unaudited condensed consolidated balance sheet as they are short-term leases.


(3)	Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $10.7 million and $37.2 million for the three and six months ended June 30, 2019, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the interim unaudited condensed consolidated balance sheet at June 30, 2019.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 3 — LEASES — Continued

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



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

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

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



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

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

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



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

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 3 — LEASES — Continued

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



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



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

Table of Contents

Matador Resources Company and Subsidiaries

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 months ended June 30, 2019 (in thousands).



Beginning asset retirement obligations	$	31,086
Liabilities incurred during period	1,427
Liabilities settled during period	(154		)
Divestitures during period	(951		)
Accretion expense	834
Ending asset retirement obligations	32,242
Less: current asset retirement obligations⁽¹⁾	(1,556		)
Long-term asset retirement obligations	$	30,686

_______________


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

NOTE 5 — DEBT

At June 30, 2019 and July 31, 2019, the Company had $1.05 billion of outstanding senior notes due 2026 (the “Notes”), $205.0 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 30, 2019 and July 31, 2019, San Mateo I had $240.0 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 2019, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2018, and, as a result, the borrowing base was increased to $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 2019 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment. The Credit Agreement matures on October 31, 2023.

The Company believes that it was in compliance with the terms of the Credit Agreement at June 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 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, but is guaranteed by San Mateo I’s subsidiaries and secured by substantially all of San Mateo I’s assets, including real property. On June 12, 2019, pursuant 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 the terms of the San Mateo Credit Facility at June 30, 2019.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 5 — DEBT — Continued

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 months ended June 30, 2019 was 26% and 37%, respectively. The Company’s total income tax provision for the three and six months ended June 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 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 30, 2018 due to the deferred tax assets generated by full-cost ceiling impairment charges in prior periods. The Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at June 30, 2018 due to uncertainties regarding the future realization of its deferred tax assets.

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 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.

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 months ended June 30, 2019, the Company contributed $1.5 million and $1.5 million of cash and Five Point contributed $7.5 million and $11.5 million of cash to San Mateo II, respectively.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

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 months ended June 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 months ended June 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 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 30, 2019.



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

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



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

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



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

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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its interim unaudited condensed consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of June 30, 2019 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
June 30, 2019
Current assets	$	12,671		$	(4,400	)	$	8,271
Other assets	4,710			(2,508		)	2,202
Current liabilities	(4,400		)	4,400			—
Long-term liabilities	(2,697		)	2,508			(189		)
Total	$	10,284		$	—		$	10,284
December 31, 2018
Current assets	$	53,136		$	(3,207	)	$	49,929
Current liabilities	(3,207		)	3,207			—
Long-term liabilities	(83		)	—			(83		)
Total	$	49,846		$	—		$	49,846

The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the 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,
Type of Instrument	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	)
Natural Gas	Revenues: Realized (loss) gain on derivatives	—		—			(96		)	51
Realized gain (loss) on derivatives		1,165		(2,488		)	4,435			(6,746		)
Oil	Revenues: Unrealized gain (loss) on derivatives	5,365		1,829			(40,078		)	12,956
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	792		(400		)	516			(1,111		)
Unrealized gain (loss) on derivatives		6,157		1,429			(39,562		)	11,845
Total		$	7,322	$	(1,059	)	$	(35,127	)	$	5,099

Table of Contents

Matador Resources Company and Subsidiaries

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



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



	Fair Value Measurements at December 31, 2018 using
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 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 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 30, 2019 and December 31, 2018, the fair value of the Notes was $1.07 billion and $0.97 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

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 million and $5.1 million for deliveries under these agreements during the three months ended June 30, 2019 and 2018, respectively, and $12.9 million and $9.1 million for deliveries under these agreements during the six months ended June 30, 2019 and 2018, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at June 30, 2019, the total deficiencies required to be paid by the Company under these agreements would be approximately $163.4 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, the Company also entered into a 16-year, fixed-fee natural gas transportation agreement that begins on October 1, 2019, whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation at June 30, 2019 was approximately $56.8 million.

In May 2018, the Company also entered into a 10-year, fixed-fee natural gas sales agreement whereby the Company committed to deliver residue gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date of such pipeline, which is expected to be operational in 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 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 30, 2019 was approximately $183.8 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 million. San Mateo II paid approximately $8.3 million under this agreement during the three months ended June 30, 2019. As of June 30, 2019, the remaining obligations under this agreement were $71.8 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 30, 2019 and December 31, 2018 (in thousands).



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

Supplemental Cash Flow Information

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



	Six Months Ended June 30,
	2019		2018
Cash paid for interest expense, net of amounts capitalized	$	37,632	$	14,286
Increase in asset retirement obligations related to mineral properties	$	321	$	834
Increase in asset retirement obligations related to midstream properties	$	283	$	296
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
Transfer of inventory from oil and natural gas properties	$	370	$	343
Transfer of inventory to midstream properties	$	—	$	(2,390	)

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

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,
	2019		2018
Cash	$	59,950	$	122,450
Restricted cash	24,812		21,063
Total cash and restricted cash	$	84,762	$	143,513

NOTE 12 — SEGMENT INFORMATION

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

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



	Exploration and Production							Consolidations and Eliminations			Consolidated Company
	Exploration and Production		Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Three Months Ended June 30, 2019
Oil and natural gas revenues	$	209,563	$	1,497	$	—		$	—		$	211,060
Midstream services revenues	—		32,166		—			(17,807		)	14,359
Sales of purchased natural gas	—		8,963		—			—			8,963
Realized gain on derivatives	1,165		—		—			—			1,165
Unrealized loss on derivatives	6,157		—		—			—			6,157
Expenses⁽¹⁾	141,514		23,425		17,783			(17,807		)	164,915
Operating income (loss)⁽²⁾	$	75,371	$	19,201	$	(17,783	)	$	—		$	76,789
Total assets	$	3,155,577	$	508,074	$	87,800		$	—		$	3,751,451
Capital expenditures⁽³⁾	$	166,532	$	41,707	$	1,400		$	—		$	209,639

_____________________


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


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


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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 12 — SEGMENT INFORMATION — Continued



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Three Months Ended June 30, 2018
Oil and natural gas revenues	$	207,229		$	1,790	$	—		$	—		$	209,019
Midstream services revenues	—			19,896		—			(16,489		)	3,407
Realized loss on derivatives	(2,488		)	—		—			—			(2,488		)
Unrealized gain on derivatives	1,429			—		—			—			1,429
Expenses⁽¹⁾	126,025			9,363		18,475			(16,489		)	137,374
Operating income (loss)⁽²⁾	$	80,145		$	12,323	$	(18,475	)	$	—		$	73,993
Total assets	$	2,058,447		$	354,068	$	143,332		$	—		$	2,555,847
Capital expenditures⁽³⁾	$	199,345		$	32,900	$	732		$	—		$	232,977

_____________________


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


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


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

_____________________


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


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


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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 12 — SEGMENT INFORMATION — Continued



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

_____________________


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


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


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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 13 — SUBSIDIARY GUARANTORS

The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At June 30, 2019, 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
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	1,582,828	$	12,535	$	—	$	(1,595,363	)	$	—
Current assets	3,967		44,100		225,317		—			273,384
Net property and equipment	—		438,681		2,944,662		—			3,383,343
Investment in subsidiaries	1,211,056		—		109,227		(1,320,283		)	—
Long-term assets	10,589		1,700		92,004		(9,569		)	94,724
Total assets	$	2,808,440	$	497,016	$	3,371,210	$	(2,925,215	)	$	3,751,451
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	1,595,363	$	(1,595,363	)	$	—
Current liabilities	18,493		33,080		286,004		(802		)	336,775
Senior unsecured notes payable	1,038,625		—		—		—			1,038,625
Other long-term liabilities	14,845		250,583		278,787		(8,767		)	535,448
Total equity attributable to Matador Resources Company	1,736,477		109,227		1,211,056		(1,320,283		)	1,736,477
Non-controlling interest in subsidiaries	—		104,126		—		—			104,126
Total liabilities and equity	$	2,808,440	$	497,016	$	3,371,210	$	(2,925,215	)	$	3,751,451



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
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	41,720		$	216,885		$	(16,901	)	$	241,704
Total expenses	901			22,564			158,351			(16,901		)	164,915
Operating (loss) income	(901		)	19,156			58,534			—			76,789
Inventory impairment	—			—			(368		)	—			(368		)
Interest expense	(15,888		)	(2,180		)	—			—			(18,068		)
Other income (expense)	—			3			(426		)	—			(423		)
Earnings in subsidiaries	66,399			—			8,659			(75,058		)	—
Income before income taxes	49,610			16,979			66,399			(75,058		)	57,930
Total income tax provision	12,858			—			—			—			12,858
Net income attributable to non-controlling interest in subsidiaries	—			(8,320		)	—			—			(8,320		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	8,659		$	66,399		$	(75,058	)	$	36,752



Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2018
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	21,356		$	206,219		$	(16,208	)	$	211,367
Total expenses	1,178			9,466			142,938			(16,208		)	137,374
Operating (loss) income	(1,178		)	11,890			63,281			—			73,993
Interest expense	(8,004		)	—			—			—			(8,004		)
Other income (expense)	—			11			(363		)	—			(352		)
Earnings in subsidiaries	68,988			—			6,070			(75,058		)	—
Income before income taxes	59,806			11,901			68,988			(75,058		)	65,637
Net income attributable to non-controlling interest in subsidiaries	—			(5,831		)	—			—			(5,831		)
Net income attributable to Matador Resources Company shareholders	$	59,806		$	6,070		$	68,988		$	(75,058	)	$	59,806



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



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



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



Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2018
	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
Net cash used in investing activities	—			(79,119		)	(454,478		)	40,035			(493,562		)
Net cash provided by financing activities	226,539			83,400			10,481			(40,035		)	280,385
Increase in cash and restricted cash	2,098			14,506			24,427			—			41,031
Cash and restricted cash at beginning of period	286			5,663			96,533			—			102,482
Cash and restricted cash at end of period	$	2,384		$	20,169		$	120,960		$	—		$	143,513

Table of Contents

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, 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 as our ability to access them, the proximity to our properties and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions with our business, weather and environmental conditions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, 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;

Table of Contents


•	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. 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 Quarter Highlights

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

For the second quarter of 2019, we reported net income attributable to Matador Resources Company shareholders of approximately $36.8 million, or $0.31 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 million, or $0.53 per diluted common share, for the second quarter of 2018. For the second quarter of 2019, our Adjusted EBITDA attributable to Matador Resources Company shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was $144.1 million, as compared to Adjusted EBITDA of $137.3 million during the second 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

Table of Contents

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

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

Operations Update

During the second 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 30, 2019. During the second 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. 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 the second quarter of 2019, which included eight completions in the Eagle Ford formation and one test of the Austin Chalk formation. The final four wells in this nine-well program were completed and turned to sales in the second quarter of 2019. These wells included two Eagle Ford completions on the Haverlah leasehold in Atascosa County, which were turned to sales in April, and two additional Eagle Ford completions on the Lloyd Hurt leasehold, which were turned to sales in May 2019. The rig used to drill these nine wells was released in early February 2019, and we have no additional operated drilling activities planned in the Eagle Ford shale for the remainder of 2019.

We completed and turned to sales a total of 19 gross (15.1 net) wells in the Delaware Basin during the second quarter of 2019, including 14 gross (13.1 net) operated horizontal wells, two gross (2.0 net) operated vertical wells and three gross (0.1 net) non-operated horizontal wells. During the second quarter of 2019, we began producing oil and natural gas from a total of 12 gross (8.5 net) wells in the Antelope Ridge asset area, including nine gross (8.4 net) operated wells and three gross (0.1 net) non-operated wells. Of the nine gross operated wells in the Antelope Ridge asset area, two were Wolfcamp A-XY completions, three were First Bone Spring completions, three were Third Bone Spring completions and one was a vertical completion in the Wolfcamp formation. In the Rustler Breaks and Arrowhead asset areas, we did not complete or turn to sales any operated or non-operated wells during the second quarter of 2019. In the Wolf and Jackson Trust asset areas, we began producing oil and natural gas from two gross (1.8 net) operated wells during the second quarter of 2019, including one Wolfcamp B completion and one Second Bone Spring completion. In addition, we began producing oil and natural gas from a total of four gross (3.9 net) operated wells in the Ranger asset area during the second quarter of 2019, including one First Bone Spring completion, two Second Bone Spring completions and one Third Bone Spring completion. Finally, in the Twin Lakes asset area, we began producing oil and natural gas from one gross (1.0 net) well, a vertical completion in the Morrow formation, during the second quarter of 2019.

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 quarter of 2019 was 51,758 BOE per day, consisting of 32,840 Bbl of oil per day and 113.5 MMcf of natural gas per day, an 11% increase from production of 46,489 BOE per day, consisting of 27,381 Bbl of oil per day and 114.6 MMcf of natural gas per day, in the second 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% 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 quarter of 2019, although we did participate in eight gross (0.3 net) non-operated Haynesville shale wells that were completed and turned to sales.

Table of Contents

Capital Resources Update

In April 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, and as a result, the borrowing base was increased to $900.0 million with the elected borrowing commitment remaining at $500.0 million. This April 2019 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment.

In June 2019, the lender commitments under San Mateo I’s revolving credit facility (the “San Mateo Credit Facility”), led by The Bank of Nova Scotia, were increased to $325.0 million, using the accordion feature. The San Mateo Credit Facility is guaranteed by San Mateo I’s subsidiaries, secured by substantially all of San Mateo I’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II.

2019 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.

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.

Table of Contents

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,
	2019		2018			2019			2018
Operating Data:
Revenues (in thousands):⁽¹⁾
Oil	$	189,085	$	166,271		$	343,288		$	314,430
Natural gas	21,975		42,748			61,041			76,543
Total oil and natural gas revenues	211,060		209,019			404,329			390,973
Third-party midstream services revenues	14,359		3,407			26,197			6,475
Sales of purchased natural gas	8,963		—			20,194			—
Realized gain (loss) on derivatives	1,165		(2,488		)	4,435			(6,746		)
Unrealized gain (loss) on derivatives	6,157		1,429			(39,562		)	11,845
Total revenues	$	241,704	$	211,367		$	415,593		$	402,547
Net Production Volumes:⁽¹⁾
Oil (MBbl)⁽²⁾	3,346		2,706			6,452			5,088
Natural gas (Bcf)⁽³⁾	13.4		12.7			27.1			22.8
Total oil equivalent (MBOE)⁽⁴⁾	5,577		4,817			10,972			8,892
Average daily production (BOE/d)⁽⁵⁾	61,290		52,937			60,619			49,126
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	56.51	$	61.44		$	53.20		$	61.80
Oil, with realized derivatives (per Bbl)	$	56.86	$	60.52		$	53.91		$	60.46
Natural gas, without realized derivatives (per Mcf)	$	1.64	$	3.38		$	2.25		$	3.35
Natural gas, with realized derivatives (per Mcf)	$	1.64	$	3.38		$	2.25		$	3.36

_________________


(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 30, 2019 as Compared to Three Months Ended June 30, 2018

Oil and natural gas revenues. Our oil and natural gas revenues increased $2.0 million, or 1%, to $211.1 million for the three months ended June 30, 2019, as compared to $209.0 million for the three months ended June 30, 2018. Our oil revenues increased $22.8 million, or 14%, to $189.1 million for the three months ended June 30, 2019, as compared to $166.3 million for the three months ended June 30, 2018. The increase in oil revenues resulted from the 24% increase in our oil production to 3.3 million Bbl of oil for the three months ended June 30, 2019, as compared to 2.7 million Bbl of oil for the three months ended June 30, 2018. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. This increase was partially offset by a lower weighted average oil price realized for the three months ended June 30, 2019 of $56.51 per Bbl, a decrease of 8% as compared to $61.44 per Bbl realized for the three months ended June 30, 2018. Our natural gas revenues decreased by $20.8 million, or 49%, to $22.0 million for the three months ended June 30, 2019, as compared to $42.7 million for the three months ended June 30, 2018. The decrease in natural gas revenues resulted from a 51% decrease in realized natural gas prices to $1.64 per Mcf for the three months ended June 30, 2019, as compared to $3.38 per Mcf realized for the three months ended June 30, 2018. This decrease was partially offset by the 6% increase in our natural gas production to 13.4 Bcf for the three months ended June 30, 2019, as compared to 12.7 Bcf for the three months ended June 30, 2018. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

Table of Contents

Third-party midstream services revenues. Our third-party midstream services revenues increased $11.0 million, or more than four-fold, to $14.4 million for the three months ended June 30, 2019, as compared to $3.4 million for the three months ended June 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 million for the three months ended June 30, 2019, as compared to approximately $1.9 million for the three months ended June 30, 2018, and (ii) an increase in our third-party natural gas gathering, transportation and processing revenues to approximately $6.5 million for the three months ended June 30, 2019, as compared to $1.5 million for the three months ended June 30, 2018.

Sales of purchased natural gas. Our sales of purchased natural gas were $9.0 million for the three months ended June 30, 2019. We had no sales of purchased natural gas for the three months ended June 30, 2018. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we 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.

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

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

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

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

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

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

Table of Contents

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

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

Table of Contents

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,
(In thousands, except expenses per BOE)	2019			2018			2019			2018
Expenses:
Production taxes, transportation and processing	$	21,542		$	20,110		$	41,207		$	37,901
Lease operating	26,351			25,006			57,514			47,154
Plant and other midstream services operating	8,422			5,676			17,738			9,896
Purchased natural gas	8,172			—			18,806			—
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207
Accretion of asset retirement obligations	420			375			834			739
General and administrative	19,876			19,369			38,166			37,295
Total expenses	164,915			137,374			331,264			255,192
Operating income	76,789			73,993			84,329			147,355
Other income (expense):
Inventory impairment	(368		)	—			(368		)	—
Interest expense	(18,068		)	(8,004		)	(35,997		)	(16,495		)
Other expense	(423		)	(352		)	(532		)	(299		)
Total other expense	(18,859		)	(8,356		)	(36,897		)	(16,794		)
Net income	57,930			65,637			47,432			130,561
Total income tax provision	12,858			—			11,845			—
Net income attributable to non-controlling interest in subsidiaries	(8,320		)	(5,831		)	(15,782		)	(10,861		)
Net income attributable to Matador Resources Company shareholders	$	36,752		$	59,806		$	19,805		$	119,700
Expenses per BOE:
Production taxes, transportation and processing	$	3.86		$	4.17		$	3.76		$	4.26
Lease operating	$	4.72		$	5.19		$	5.24		$	5.30
Plant and other midstream services operating	$	1.51		$	1.18		$	1.62		$	1.11
Depletion, depreciation and amortization	$	14.37		$	13.87		$	14.31		$	13.74
General and administrative	$	3.56		$	4.02		$	3.48		$	4.19

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

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased $1.4 million, or 7%, to $21.5 million for the three months ended June 30, 2019, as compared to $20.1 million for the three months ended June 30, 2018. The increase was primarily attributable to the $1.3 million increase in transportation and processing fees to $6.3 million for the three months ended June 30, 2019, as compared to $5.0 million for the three months ended June 30, 2018, principally due to the 6% increase in our natural gas production to 13.4 Bcf of natural gas for the three months ended June 30, 2019, as compared to 12.7 Bcf of natural gas for the three months ended June 30, 2018. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 7% to $3.86 per BOE for the three months ended June 30, 2019, as compared to $4.17 per BOE for the three 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 the weighted average oil and natural gas prices realized between the two periods.

Lease operating. Our lease operating expenses increased $1.3 million, or 5%, to $26.4 million for the three months ended June 30, 2019, as compared to $25.0 million for the three months ended June 30, 2018. The increase was largely attributable to increases in compression, repairs and maintenance and non-operated lease operating expenses of approximately $2.6 million for the three months ended June 30, 2019, as compared to the three months ended June 30, 2018. This increase was partially offset by a decrease in salt water trucking and disposal costs as more of our operated wells have been connected 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.

Table of Contents

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

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $13.3 million, or 20%, to $80.1 million for the three months ended June 30, 2019, as compared to $66.8 million for the three months ended June 30, 2018. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 4% to $14.37 per BOE for the three months ended June 30, 2019, as compared to $13.87 per BOE for the three months ended June 30, 2018. The increase in our total depletion, depreciation and amortization expenses was primarily attributable to (i) the 16% increase in our total oil equivalent production to 5.6 million BOE for the three months ended June 30, 2019, as compared to 4.8 million BOE for the three months ended June 30, 2018, and (ii) increased depreciation expenses attributable to our midstream segment of approximately $3.8 million for the three months ended June 30, 2019, as compared to $2.3 million for the three 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 $0.5 million, or 3%, to $19.9 million for the three months ended June 30, 2019, as compared to $19.4 million for the three months ended June 30, 2018. Our general and administrative expenses decreased 11% on a unit-of-production basis to $3.56 per BOE for the three months ended June 30, 2019, as compared to $4.02 per BOE for the three months ended June 30, 2018, primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

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

Total income tax provision. We recorded a total income tax expense of $12.9 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

Table of Contents

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 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 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.

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 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 30, 2019 and July 31, 2019, we had (i) $1.05 billion of outstanding 5.875% senior notes due 2026 (the “Notes”), (ii) $205.0 million in borrowings outstanding under the Credit Agreement and (iii) approximately $13.6 million in outstanding

Table of Contents

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

At June 30, 2019, we had cash totaling approximately $60.0 million and restricted cash, most of which was associated with San Mateo, totaling approximately $24.8 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 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, and as a result, the borrowing base was increased to $900.0 million with the elected borrowing commitment remaining at $500.0 million. This April 2019 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment.

In June 2019, the lender commitments under the San Mateo Credit Facility, led by The Bank of Nova Scotia, were increased to $325.0 million, using the accordion feature. The San Mateo Credit Facility is guaranteed by San Mateo I’s subsidiaries, secured by substantially all of San Mateo I’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II.

During the second 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 30, 2019. During the second quarter, these six operated drilling rigs were deployed across our Delaware Basin asset areas, but with an increased focus on the Antelope Ridge asset area. We 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.

During the second 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 for the remainder of 2019.

2019 Capital Expenditure Budget

At July 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) additional operated wells in 2019, as compared to our original 2019 plan, which includes four gross (3.0 net) additional wells resulting from an accelerated pace of drilling and completion activity in 2019 and 3.8 net additional wells attributable to increased working interests acquired or anticipated to be acquired in certain operated wells during the course of the year. Due to the lower well costs and facilities savings achieved thus far in 2019, however, at July 31, 2019, we anticipate we should be able to deliver these additional well completions within our originally budgeted estimates for D/C/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 months of 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer and obtained a significant additional acreage dedication and a salt water disposal well permit from an existing salt water customer. In addition, San Mateo is in negotiations with other third parties to provide oil, natural gas and salt water gathering services, natural gas processing services and salt water disposal services. In order to provide the midstream services under these executed and anticipated agreements, San Mateo expects to undertake additional projects that will require added compression, oil, natural gas and water gathering lines and water disposal infrastructure not originally budgeted for in 2019. At July 31, 2019, San Mateo had also entered into an agreement to acquire an existing commercial salt water disposal well and facility, a salt water disposal permit and surface acreage near the Greater Stebbins Area. The anticipated total 2019 midstream capital expenditures of $70 to $90 million 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 agreed to provide to us in conjunction with the formation of San Mateo II.

Table of Contents

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 30, 2019.

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



	Six Months Ended June 30,
(In thousands)	2019			2018
Net cash provided by operating activities	$	194,497		$	254,208
Net cash used in investing activities	(394,694		)	(493,562		)
Net cash provided by financing activities	200,975			280,385
Net change in cash and restricted cash	$	778		$	41,031
Adjusted EBITDAattributable to Matador Resources Company shareholders⁽¹⁾	$	268,943		$	254,592

__________________


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

Table of Contents

cash provided by operating activities increased to $255.5 million for the six months ended June 30, 2019 from $251.0 million for the six months ended June 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 million in net cash provided by operating activities for the six months ended June 30, 2019, as compared to the six months ended June 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 million to $394.7 million for the six months ended June 30, 2019 from $493.6 million for the six months ended June 30, 2018. This decrease in net cash used in investing activities is due in part to a decrease of $71.7 million in oil and natural gas properties capital expenditures for the six months ended June 30, 2019, as compared to the six months ended June 30, 2018. Cash used for oil and natural gas properties capital expenditures for the six months ended June 30, 2019 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin and in South Texas. The remaining decrease in net cash used in investing activities was primarily attributable to a decrease in cash used for midstream capital expenditures of $14.2 million, primarily related to capital expenditures for San Mateo, and an increase of $13.9 million in proceeds from the sale of assets.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities decreased by $79.4 million to $201.0 million for the six months ended June 30, 2019 from $280.4 million for the six months ended June 30, 2018. This decrease in net cash provided by financing activities is due in part to a net increase in borrowings under our Credit Agreement of $165.0 million between the two periods, offset by a reduction in proceeds from the issuance of common stock of $226.6 million and a decrease of $34.1 million in contributions from non-controlling interest owners in less-than-wholly-owned subsidiaries.

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.

Table of Contents

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,
(In thousands)	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
Net income attributable to non-controlling interest in subsidiaries	8,320			5,831			15,782			10,861
Net income	45,072			65,637			35,587			130,561
Interest expense	18,068			8,004			35,997			16,495
Total income tax provision	12,858			—			11,845			—
Depletion, depreciation and amortization	80,132			66,838			156,999			122,207
Accretion of asset retirement obligations	420			375			834			739
Unrealized (gain) loss on derivatives	(6,157		)	(1,429		)	39,562			(11,845		)
Stock-based compensation expense	4,490			4,766			9,076			8,945
Inventory impairment	368			—			368			—
Consolidated Adjusted EBITDA	155,251			144,191			290,268			267,102
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,147		)	(6,853		)	(21,325		)	(12,510		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	144,104		$	137,338		$	268,943		$	254,592



	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	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
Net change in operating assets and liabilities	2,472			18,174			60,963			(3,190		)
Interest expense, net of non-cash portion	17,522			7,958			34,808			16,084
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,147		)	(6,853		)	(21,325		)	(12,510		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	144,104		$	137,338		$	268,943		$	254,592

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

Net income attributable to Matador Resources Company shareholders decreased by $99.9 million to $19.8 million for the six months ended June 30, 2019, as compared to $119.7 million for the six months ended June 30, 2018. This decrease 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 million increase in oil and natural gas revenues and an increase of $19.7 million in third-party midstream services revenues.

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

Table of Contents

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



	Payments Due by Period
(In thousands)	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	$	—
Senior unsecured notes⁽²⁾	1,050,000		—		—		—		1,050,000
Office leases	28,112		3,724		7,963		8,415		8,010
Non-operated drilling commitments⁽³⁾	51,719		51,719		—				—
Drilling rig contracts⁽⁴⁾	39,127		23,870		15,257		—		—
Asset retirement obligations	32,242		1,556		2,441		537		27,708
Natural gas transportation, gathering and processing agreements with non-affiliates⁽⁵⁾	554,863		43,786		113,567		113,598		283,912
Gathering, processing and disposal agreements with San Mateo⁽⁶⁾	547,514		—		96,517		163,408		287,589
Natural gas engineering, construction and installation contract⁽⁷⁾	71,820		71,820		—		—		—
Total contractual cash obligations	$	2,850,268	$	196,475	$	235,745	$	760,829	$	1,657,219

__________________

(1)

The amounts included in the table above represent principal maturities only. At June 30, 2019, we had $205.0 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 30, 2019, San Mateo I had $240.0 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% and 4.16% (for the Credit Agreement and the San Mateo Credit Facility), respectively, at June 30, 2019, the interest expense is expected to be approximately $7.5 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 30, 2019 is expected to be approximately $61.7 million each year until maturity.

(3)

At June 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 30, 2019. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $51.7 million at June 30, 2019, which we expect to incur within the next 12 months.


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


(5)	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

Table of Contents

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 30, 2019, oil prices averaged $59.96 per Bbl, ranging from a high of $66.30 per Bbl in late April to a low of $51.14 per Bbl in mid-June, 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 per Bbl ($56.86 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended June 30, 2019, as compared to $61.44 per Bbl ($60.52 per Bbl including realized losses from oil derivatives) for our oil production for the three months ended June 30, 2018. At July 31, 2019, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had decreased from the average price for the second quarter of 2019, settling at $58.58 per Bbl, which was also a decrease as compared to $68.76 per Bbl at July 31, 2018.

For the three months ended June 30, 2019, natural gas prices averaged $2.51 per MMBtu, ranging from a high of approximately $2.71 per MMBtu in early April to a low of approximately $2.19 per MMBtu in late June, 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 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 June 30, 2018. At July 31, 2019, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased from the average price for the second quarter of 2019, settling at $2.23 per MMBtu, which was also a decrease as compared to $2.78 per MMBtu at July 31, 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 30, 2019, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and most of our natural gas production from the Delaware Basin was sold based on prices established at the Waha Hub in far West Texas. During the second quarter 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.

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

Table of Contents

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

Our realized price for our Delaware Basin natural gas production is exposed to the Waha-Henry Hub basis differential. This natural gas price differential increased significantly throughout 2018 from about $0.50 per MMBtu at the beginning of the year to between $1.00 and $2.00 per MMBtu for most of 2018, but reaching highs of greater than $4.00 per MMBtu for a brief period 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 natural gas sold at Waha were positive for the month of July, although prices at Waha remained well below Henry Hub prices.

The majority of our Delaware Basin natural gas production is expected to remain exposed to the Waha-Henry Hub basis differentials until early in the fourth quarter of 2019, when the Kinder Morgan Gulf Coast Express Pipeline Project (“GCX Pipeline”) is expected to become 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 price based upon Houston Ship Channel pricing. Further, approximately 23% of our reported natural gas production in the second 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, 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.

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, 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

Table of Contents

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 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 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 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 30, 2019 that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting.

Table of Contents

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 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	—	—

_________________


(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.

Table of Contents

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).

10.5†		First Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (filed herewith).

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

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

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

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

101		The following financial information from Matador Resources Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 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.

†		Indicates a management contract or compensatory plan or arrangement.

Table of Contents

SIGNATURES

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



		MATADOR RESOURCES COMPANY

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



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