SEC Filing | Matador Resources Company

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mtdr-20210630

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, 2021


☐			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 Dallas, Texas			75240
(Address of principal executive offices)			(Zip Code)

(972) 371-5200

(Registrant’s telephone number, including area code)

_________________________________________________________

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

Title of each class

Trading symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.01 per share

MTDR

New York Stock Exchange

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

As of July 27, 2021, there were 116,982,758 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, 2021

TABLE OF CONTENTS


			Page
PART I — FINANCIAL INFORMATION			3
Item 1. Financial Statements — Unaudited			3
Condensed Consolidated Balance Sheets at June 30, 2021 and December 31, 2020			3
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2021 and 2020			4
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three and Six Months Ended June 30, 2021 and 2020			5
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2021 and 2020			7
Notes to Condensed Consolidated Financial Statements			8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
Item 3. Quantitative and Qualitative Disclosures About Market Risk			41
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, 2021		December 31, 2020
ASSETS
Current assets
Cash	$	44,632	$	57,916

Restricted cash	34,576		33,467
Accounts receivable
Oil and natural gas revenues	154,077		85,098
Joint interest billings	42,130		34,823
Other	19,826		17,212
Derivative instruments	6,171		6,727


Lease and well equipment inventory	11,657		10,584
Prepaid expenses and other current assets	20,559		15,802
Total current assets	333,628		261,629
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	5,514,224		5,295,931
Unproved and unevaluated	926,492		902,133
Midstream properties	859,189		841,695
Other property and equipment	29,983		29,561
Less accumulated depletion, depreciation and amortization	(3,867,858)		(3,701,551)
Net property and equipment	3,462,030		3,367,769
Other assets
Derivative instruments	2,424		2,570

Other long-term assets	36,467		55,312

Total assets	$	3,834,549	$	3,687,280
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	13,573	$	13,982
Accrued liabilities	151,051		119,158
Royalties payable	82,256		66,049

Amounts due to affiliates	15,823		4,934
Derivative instruments	127,687		45,186
Advances from joint interest owners	6,208		4,191




Other current liabilities	25,982		37,436
Total current liabilities	422,580		290,936
Long-term liabilities
Borrowings under Credit Agreement	240,000		440,000
Borrowings under San Mateo Credit Facility	352,500		334,000
Senior unsecured notes payable	1,041,789		1,040,998
Asset retirement obligations	39,737		37,919
Derivative instruments	3,024		—

Deferred income taxes	7,847		—

Other long-term liabilities	24,946		30,402
Total long-term liabilities	1,709,843		1,883,319
Commitments and contingencies (Note 9)
Shareholders’ equity

Common stock - $0.01 par value, 160,000,000 shares authorized; 117,123,379 and 116,847,003 shares issued; and 116,992,831 and 116,844,768 shares outstanding, respectively	1,171		1,169
Additional paid-in capital	2,061,815		2,027,069
Accumulated deficit	(580,981)		(741,705)
Treasury stock, at cost, 130,548 and 2,235 shares, respectively	(2,243)		(3)
Total Matador Resources Company shareholders’ equity	1,479,762		1,286,530
Non-controlling interest in subsidiaries	222,364		226,495
Total shareholders’ equity	1,702,126		1,513,025
Total liabilities and shareholders’ equity	$	3,834,549	$	3,687,280

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,
	2021		2020		2021		2020
Revenues
Oil and natural gas revenues	$	412,074	$	118,767	$	728,307	$	316,681
Third-party midstream services revenues	19,850		14,668		35,288		30,498
Sales of purchased natural gas	10,918		13,981		15,428		24,525
Lease bonus - mineral acreage	—		4,062		—		4,062
Realized (loss) gain on derivatives	(42,611)		44,110		(68,524)		54,977
Unrealized (loss) gain on derivatives	(42,804)		(132,668)		(86,227)		3,762
Total revenues	357,427		62,920		624,272		434,505
Expenses
Production taxes, transportation and processing	43,843		18,797		78,017		40,513
Lease operating	28,752		26,162		54,691		57,072
Plant and other midstream services operating	13,746		9,780		27,409		19,744
Purchased natural gas	9,628		10,922		12,483		18,980
Depletion, depreciation and amortization	91,444		93,350		166,307		184,057
Accretion of asset retirement obligations	511		495		1,011		971
Full-cost ceiling impairment	—		324,001		—		324,001
General and administrative	24,397		14,723		46,585		30,945
Total expenses	212,321		498,230		386,503		676,283
Operating income (loss)	145,106		(435,310)		237,769		(241,778)
Other income (expense)
Net loss on asset sales and impairment	—		(2,632)		—		(2,632)
Interest expense	(17,940)		(18,297)		(37,590)		(38,109)

Other income (expense)	14		473		(661)		1,793
Total other expense	(17,926)		(20,456)		(38,251)		(38,948)
Income (loss) before income taxes	127,180		(455,766)		199,518		(280,726)
Income tax provision (benefit)

Deferred	5,349		(109,823)		8,189		(69,866)
Income tax provision (benefit)	5,349		(109,823)		8,189		(69,866)
Net income (loss)	121,831		(345,943)		191,329		(210,860)
Net income attributable to non-controlling interest in subsidiaries	(15,926)		(7,473)		(24,779)		(16,827)
Net income (loss) attributable to Matador Resources Company shareholders	$	105,905	$	(353,416)	$	166,550	$	(227,687)
Earnings (loss) per common share
Basic	$	0.91	$	(3.04)	$	1.43	$	(1.96)
Diluted	$	0.89	$	(3.04)	$	1.40	$	(1.96)
Weighted average common shares outstanding
Basic	116,801		116,071		116,804		115,977
Diluted	118,993		116,071		118,617		115,977

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, 2021


												Total shareholders’ equity attributable to Matador Resources Company


														Non-controlling interest in subsidiaries		Total shareholders’ equity
	Common Stock			Additional paid-in capital	Accumulated deficit		Treasury Stock
	Shares	Amount							Shares	Amount
Balance at January 1, 2021	116,847	$	1,169		$	2,027,069	$	(741,705)	2	$	(3)	$	1,286,530	$	226,495	$	1,513,025
Dividends declared ($0.025 per share)	—	—			—		(2,913)		—	—		(2,913)		—		(2,913)
Issuance of common stock pursuant to employee stock compensation plan	3	—			—		—		—	—		—		—		—



Issuance of common stock pursuant to directors’ and advisors’ compensation plan	9	—			—		—		—	—		—		—		—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—			1,477		—		—	—		1,477		—		1,477
Stock options exercised, net of options forfeited in net share settlements	13	—			—		—		—	—		—		—		—



Restricted stock forfeited	—	—			(219)		—		90	(1,501)		(1,720)		—		(1,720)


Contribution related to formation of San Mateo (see Note 6)	—	—			15,376		—		—	—		15,376		—		15,376


Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—			—		—		—	—		—		(14,210)		(14,210)

Current period net income	—	—			—		60,645		—	—		60,645		8,853		69,498
Balance at March 31, 2021	116,872	1,169			2,043,703		(683,973)		92	(1,504)		1,359,395		221,138		1,580,533
Dividends declared ($0.025 per share)	—	—			—		(2,913)		—	—		(2,913)		—		(2,913)
Issuance of common stock pursuant to employee stock compensation plan	138	1			(1)		—		—	—		—		—		—



Issuance of common stock pursuant to directors’ and advisors’ compensation plan	73	1			(1)		—		—	—		—		—		—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—			2,289		—		—	—		2,289		—		2,289
Stock options exercised, net of options forfeited in net share settlements	40	—			—		—		—	—		—		—		—



Restricted stock forfeited	—	—			(425)		—		38	(739)		(1,164)		—		(1,164)

Contribution related to formation of San Mateo (see Note 6)	—	—			16,250		—		—	—		16,250		—		16,250


Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—			—		—		—	—		—		(14,700)		(14,700)


Current period net income	—	—			—		105,905		—	—		105,905		15,926		121,831
Balance at June 30, 2021	117,123	$	1,171		$	2,061,815	$	(580,981)	130	$	(2,243)	$	1,479,762	$	222,364	$	1,702,126

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, 2020


												Total shareholders’ equity attributable to Matador Resources Company


														Non-controlling interest in subsidiaries		Total shareholders’ equity
	Common Stock			Additional paid-in capital	Accumulated deficit		Treasury Stock
	Shares	Amount							Shares	Amount
Balance at January 1, 2020	116,644	$	1,166		$	1,981,014	$	(148,500)	1	$	(26)	$	1,833,654	$	135,798	$	1,969,452
Issuance of common stock pursuant to employee stock compensation plan	3	—			—		—		—	—		—		—		—



Issuance of common stock pursuant to directors’ and advisors’ compensation plan	2	—			—		—		—	—		—		—		—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—			5,066		—		—	—		5,066		—		5,066
Stock options exercised, net of options forfeited in net share settlements	—	—			(24)		—		—	—		(24)		—		(24)
Liability-based stock option awards settled in equity	22	1			297		—		—	—		298		—		298


Restricted stock forfeited	—	—			—		—		106	(1,267)		(1,267)		—		(1,267)


Contribution related to formation of San Mateo, net of tax of $3.1 million (see Note 6)	—	—			11,613		—		—	—		11,613		—		11,613

Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $4.3 million (see Note 6)	—	—			16,280		—		—	—		16,280		29,394		45,674
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—			—		—		—	—		—		(11,515)		(11,515)
Current period net income	—	—			—		125,729		—	—		125,729		9,354		135,083
Balance at March 31, 2020	116,671	1,167			2,014,246		(22,771)		107	(1,293)		1,991,349		163,031		2,154,380
Issuance of common stock pursuant to employee stock compensation plan	230	2			(2)		—		—	—		—		—		—



Issuance of common stock pursuant to directors’ and advisors’ compensation plan	83	1			(1)		—		—	—		—		—		—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—			4,103		—		—	—		4,103		—		4,103




Restricted stock forfeited	—	—			—		—		33	(156)		(156)		—		(156)



Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $0.5 million (see Note 6)	—	—			1,952		—		—	—		1,952		14,700		16,652
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—			—		—		—	—		—		(10,535)		(10,535)
Current period net (loss) income	—	—			—		(353,416)		—	—		(353,416)		7,473		(345,943)
Balance at June 30, 2020	116,984	$	1,170		$	2,020,298	$	(376,187)	140	$	(1,449)	$	1,643,832	$	174,669	$	1,818,501

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,
	2021		2020
Operating activities
Net income (loss)	$	191,329	$	(210,860)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized loss (gain) on derivatives	86,227		(3,762)
Depletion, depreciation and amortization	166,307		184,057
Accretion of asset retirement obligations	1,011		971
Full-cost ceiling impairment	—		324,001
Stock-based compensation expense	2,650		7,080

Deferred income tax provision (benefit)	8,189		(69,866)
Amortization of debt issuance cost	1,655		1,399
Net loss on asset sales and impairment	—		2,632

Changes in operating assets and liabilities
Accounts receivable	(78,900)		46,628
Lease and well equipment inventory	(437)		(868)
Prepaid expenses and other current assets	(4,483)		(1,610)
Other long-term assets	91		1,806
Accounts payable, accrued liabilities and other current liabilities	34,345		(52,351)
Royalties payable	16,207		(24,198)
Advances from joint interest owners	2,017		5,094



Other long-term liabilities	1,387		232
Net cash provided by operating activities	427,595		210,385
Investing activities
Drilling, completion and equipping capital expenditures	(210,725)		(283,362)
Acquisition of oil and natural gas properties	(15,356)		(51,736)
Midstream capital expenditures	(25,092)		(123,338)
Expenditures for other property and equipment	(245)		(1,381)
Proceeds from sale of assets	296		1,056






Net cash used in investing activities	(251,122)		(458,761)
Financing activities
Repayments of borrowings under Credit Agreement	(240,000)		—
Borrowings under Credit Agreement	40,000		130,000
Repayments of borrowings under San Mateo Credit Facility	(34,000)		—
Borrowings under San Mateo Credit Facility	52,500		32,000
Cost to amend credit facilities	(830)		(660)






Dividends paid	(5,826)		—
Contributions related to formation of San Mateo	31,626		14,700
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	—		67,172
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(28,910)		(22,050)
Taxes paid related to net share settlement of stock-based compensation	(2,884)		(1,493)

Other	(324)		7,087
Net cash (used in) provided by financing activities	(188,648)		226,756
Decrease in cash and restricted cash	(12,175)		(21,620)
Cash and restricted cash at beginning of period	91,383		65,128
Cash and restricted cash at end of period	$	79,208	$	43,508

Supplemental disclosures of cash flow information (Note 10)

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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (collectively with its subsidiaries, “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 produced water gathering services and produced 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, 2020 filed with the SEC on February 26, 2021 (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, 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, 2021. Amounts as of December 31, 2020 are derived from the Company’s audited consolidated financial statements included in the Annual Report.

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.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

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, 2021 and 2020 (in thousands).


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues from contracts with customers	$	442,842	$	147,416	$	779,023	$	371,704
Lease bonus - mineral acreage	—		4,062		—		4,062
Realized (loss) gain on derivatives	(42,611)		44,110		(68,524)		54,977
Unrealized (loss) gain on derivatives	(42,804)		(132,668)		(86,227)		3,762
Total revenues	$	357,427	$	62,920	$	624,272	$	434,505


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Oil revenues	$	315,114	$	94,174	$	528,393	$	263,759
Natural gas revenues	96,960		24,593		199,914		52,922
Third-party midstream services revenues	19,850		14,668		35,288		30,498
Sales of purchased natural gas	10,918		13,981		15,428		24,525
Total revenues from contracts with customers	$	442,842	$	147,416	$	779,023	$	371,704

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 the three and six months ended June 30, 2021, 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. At June 30, 2020, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $243.9 million. As a result, the Company recorded an impairment charge of $324.0 million to its net capitalized costs and a deferred income tax benefit of $80.1 million at June 30, 2020. These charges are reflected in the Company’s interim condensed consolidated statements of operations for the three and six months ended June 30, 2020.

The Company capitalized approximately $9.2 million and $8.1 million of its general and administrative costs and approximately $1.9 million and $1.8 million of its interest expense for the three months ended June 30, 2021 and 2020, respectively. The Company capitalized approximately $18.7 million and $16.3 million of its general and administrative costs and approximately $2.5 million and $3.2 million of its interest expense for the six months ended June 30, 2021 and 2020, respectively.

Earnings 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.

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 following table sets forth the computation of diluted weighted average common shares outstanding for the three and six months ended June 30, 2021 and 2020 (in thousands).


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
Weighted average common shares outstanding
Basic	116,801	116,071	116,804	115,977
Dilutive effect of options and restricted stock units	2,192	—	1,813	—
Diluted weighted average common shares outstanding	118,993	116,071	118,617	115,977

A total of 0.5 million and 1.5 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the three and six months ended June 30, 2021, respectively, because their effects were anti-dilutive. A total of 2.5 million and 2.6 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the three and six months ended June 30, 2020, respectively, because their effects were anti-dilutive. Additionally, 0.5 million and 0.6 million restricted shares, which are participating securities, were excluded from the calculations above for the three and six months ended June 30, 2020, respectively, as the security holders do not have the obligation to share in the losses of the Company.

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2021 (in thousands).


Beginning asset retirement obligations	$	38,542
Liabilities incurred during period	635
Liabilities settled during period	(240)


Accretion expense	1,011
Ending asset retirement obligations	39,948
Less: current asset retirement obligations(1)	(211)
Long-term asset retirement obligations	$	39,737

_______________

(1)Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at June 30, 2021.

NOTE 4 — DEBT

At June 30, 2021, the Company had (i) $1.05 billion of outstanding senior notes due 2026 (the “Notes”), (ii) $240.0 million in borrowings outstanding under its reserves-based revolving credit facility (the “Credit Agreement”), (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration loan.

At June 30, 2021, San Mateo had $352.5 million in borrowings outstanding under its revolving credit facility (the “San Mateo Credit Facility”) and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between June 30, 2021 and July 27, 2021, San Mateo repaid $25.0 million of borrowings under the San Mateo Credit Facility.

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UNAUDITED — CONTINUED

NOTE 4 — DEBT — Continued

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 2021, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. The Company elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and no material changes were made to the terms of the Credit Agreement. This April 2021 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 (subject to compliance with the covenant noted below). The Credit Agreement matures October 31, 2023.

The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 4.0 or less. The Company believes that it was in compliance with the terms of the Credit Agreement at June 30, 2021.

San Mateo Midstream, LLC

The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under the revolving credit facility from $375.0 million to $450.0 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $700.0 million.

The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.0 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.5 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at June 30, 2021.

Senior Unsecured Notes

At June 30, 2021, the Company had $1.05 billion of outstanding Notes, which have a 5.875% coupon rate. The Notes 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 5 — INCOME TAXES

The Company recorded an income tax provision of $5.3 million and $8.2 million for the three and six months ended June 30, 2021, respectively, which resulted in an effective tax rate of 5% in each period. The effective tax rate differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due primarily to recording a net deferred tax liability for state taxes, primarily in New Mexico, and continuing to recognize a valuation allowance against its U.S. federal net deferred tax assets. As a result of the full-cost ceiling impairments recorded in 2020, the Company recognized a valuation allowance against its net deferred tax assets for the year ended December 31, 2020. The valuation allowance will continue to be recognized until the future deferred tax benefits are more likely than not to become utilized.

The Company’s effective tax rates for the three and six months ended June 30, 2020 were 24% and 23%, respectively. The Company’s total income tax provision for the three and six months ended June 30, 2020 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due to the impact of permanent differences between book and tax income, as well as state taxes, primarily in New Mexico.

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UNAUDITED — CONTINUED

NOTE 6 — EQUITY

Common Stock Dividend

The Company’s Board of Directors (the “Board”) declared a quarterly cash dividend of $0.025 per share of common stock in both the first and second quarters of 2021. The dividend, which totaled $2.9 million in each quarter, was paid on March 31, 2021 and June 3, 2021. In July 2021, the Board declared a quarterly cash dividend of $0.025 per share of common stock payable on September 3, 2021 to shareholders of record as of August 12, 2021.

San Mateo Distributions and Contributions

During the three months ended June 30, 2021 and 2020, San Mateo distributed $15.3 million and $11.0 million, respectively, to the Company and $14.7 million and $10.5 million, respectively, to a subsidiary of Five Point Energy LLC, the Company’s joint venture partner (“Five Point”). During the six months ended June 30, 2021 and 2020, San Mateo distributed $30.1 million and $23.0 million, respectively, to the Company and $28.9 million and $22.1 million, respectively, to Five Point.

During the three and six months ended June 30, 2021, there were no contributions to San Mateo by either the Company or Five Point. During the three months ended June 30, 2020, the Company contributed $15.4 million and Five Point contributed $17.2 million of cash to San Mateo, of which $2.5 million was paid to carry Matador’s proportionate interest in San Mateo. During the six months ended June 30, 2020, the Company contributed $22.9 million and Five Point contributed $67.2 million of cash to San Mateo, of which $23.1 million was paid to carry Matador’s proportionate interest in San Mateo. The portion of the amount contributed by Five Point to carry Matador’s proportionate interest was recorded in “Additional paid-in capital” in the Company’s interim unaudited condensed consolidated balance sheets for the three and six months ended June 30, 2020, net of the $0.5 million and $4.8 million, respectively, deferred tax impact to Matador related to this equity contribution.

Performance Incentives

Five Point paid to the Company $16.3 million in performance incentives during the three months ended June 30, 2021. No performance incentives were paid by Five Point to the Company during the three months ended June 30, 2020. Five Point paid to the Company $31.6 million and $14.7 million in performance incentives during the six months ended June 30, 2021 and 2020, respectively. These performance incentives are recorded when received, net of the $3.1 million deferred tax impact to Matador during the three months ended March 31, 2020, in “Additional paid-in capital” in the Company’s interim unaudited condensed consolidated balance sheets. These performance incentives for the three and six months ended June 30, 2021 and 2020 are also denoted as “Contributions related to formation of San Mateo” under “Financing activities” in the Company’s interim unaudited condensed consolidated statements of cash flows and changes in shareholders’ equity.

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS

At June 30, 2021, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling for the collars and fixed price for the swaps. At June 30, 2021, each contract was set to expire at varying times during 2021 and 2022. The Company had no open contracts associated with natural gas liquids (“NGL”) prices at June 30, 2021.

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UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at June 30, 2021.


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	07/01/2021 - 12/31/2021	4,740,000	$	42.06	$	55.15	(80,256)
Natural Gas	07/01/2021 - 12/31/2021	21,200,000	$	2.45	$	3.68	(5,148)
Oil	01/01/2022 - 12/31/2022	2,040,000	$	50.00	$	67.85	(7,766)
Natural Gas	01/01/2022 - 03/31/2022	3,000,000	$	2.60	$	4.22	(952)
Total open costless collar contracts							$	(94,122)

The following is a summary of the Company’s open swap contracts for oil at June 30, 2021.


Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil	07/01/2021 - 12/31/2021	1,020,000	$	35.26	(36,590)
Total open swap contracts					$	(36,590)

The following is a summary of the Company’s open basis swap contracts for oil at June 30, 2021.


Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil Basis	07/01/2021 - 12/31/2021	4,200,000	$	0.87	3,714
Oil Basis	01/01/2022 - 12/31/2022	5,520,000	$	0.95	4,882
Total open basis swap contracts					$	8,596

At June 30, 2021, the aggregate liability value for the Company’s open derivative financial instruments was $122.1 million.

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

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UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

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, 2021 and December 31, 2020 (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, 2021
Current assets	$	365,741	$	(359,570)	$	6,171
Other assets	106,711		(104,287)		2,424
Current liabilities	(487,257)		359,570		(127,687)
Long-term liabilities	(107,311)		104,287		(3,024)
Total	$	(122,116)	$	—	$	(122,116)
December 31, 2020
Current assets	$	382,328	$	(375,601)	$	6,727
Other assets	150,194		(147,624)		2,570
Current liabilities	(420,787)		375,601		(45,186)
Long-term liabilities	(147,624)		147,624		—
Total	$	(35,889)	$	—	$	(35,889)

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	2021		2020		2021		2020
Derivative Instrument
Oil	Revenues: Realized (loss) gain on derivatives	$	(42,611)	$	44,110	$	(68,686)	$	54,977
Natural Gas	Revenues: Realized gain on derivatives	—		—		162		—

Realized (loss) gain on derivatives		(42,611)		44,110		(68,524)		54,977
Oil	Revenues: Unrealized (loss) gain on derivatives	(35,163)		(134,567)		(74,432)		1,863
Natural Gas	Revenues: Unrealized (loss) gain on derivatives	(7,641)		1,899		(11,795)		1,899

Unrealized (loss) gain on derivatives		(42,804)		(132,668)		(86,227)		3,762
Total		$	(85,415)	$	(88,558)	$	(154,751)	$	58,739

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UNAUDITED — CONTINUED

NOTE 8 — 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, 2021 and December 31, 2020 (in thousands).


	Fair Value Measurements at June 30, 2021 using
Description	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	(116,016)	$	—	$	(116,016)
Natural gas derivatives	—		(6,100)		—		(6,100)
Total	$	—	$	(122,116)	$	—	$	(122,116)


	Fair Value Measurements at December 31, 2020 using
Description	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	(41,584)	$	—	$	(41,584)
Natural gas derivatives	—		5,695		—		5,695
Total	$	—	$	(35,889)	$	—	$	(35,889)

Additional disclosures related to derivative financial instruments are provided in Note 7.

Other Fair Value Measurements

At June 30, 2021 and December 31, 2020, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities.

At June 30, 2021 and December 31, 2020, 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.

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NOTE 8 — FAIR VALUE MEASUREMENTS — Continued

At June 30, 2021 and December 31, 2020, the fair value of the Notes was $1.08 billion and $1.03 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

Processing, Transportation and Produced 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 produced water from certain portions of its acreage for transportation, gathering, processing, fractionation, sales and disposal. The Company paid approximately $15.1 million and $11.4 million for deliveries under these agreements during the three months ended June 30, 2021 and 2020, respectively, and $27.7 million and $22.4 million for deliveries under these agreements during the six months ended June 30, 2021 and 2020, 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, 2021, the total deficiencies required to be paid by the Company under these agreements would be approximately $601.8 million.

Future Commitments

The Company entered into a 10-year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue gas production at the tailgate of San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico for transportation through the counterparty’s pipeline. The agreement begins when the counterparty’s pipeline is placed in service, which is anticipated to be in the fourth quarter of 2021. Should the pipeline be placed in service, the Company would owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline, and the minimum contractual obligation would be approximately $30.7 million.

San Mateo Commitments

The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at June 30, 2021 was approximately $430.0 million.

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.

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UNAUDITED — CONTINUED

NOTE 10 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at June 30, 2021 and December 31, 2020 (in thousands).


	June 30, 2021		December 31, 2020
Accrued evaluated and unproved and unevaluated property costs	$	61,813	$	44,012
Accrued midstream properties costs	4,957		12,776


Accrued lease operating expenses	30,833		24,276
Accrued interest on debt	18,385		18,315
Accrued asset retirement obligations	211		623
Accrued partners’ share of joint interest charges	8,129		7,407

Accrued payable related to purchased natural gas	1,813		418
Other	24,910		11,331
Total accrued liabilities	$	151,051	$	119,158

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the three months ended June 30, 2021 and 2020 (in thousands).


	Six Months Ended June 30,
	2021		2020

Cash paid for interest expense, net of amounts capitalized	$	37,517	$	38,387
Increase in asset retirement obligations related to mineral properties	$	395	$	1,393
Increase in asset retirement obligations related to midstream properties	$	—	$	26
Increase in liabilities for drilling, completion and equipping capital expenditures	$	16,072	$	6,813
Increase (decrease) in liabilities for acquisition of oil and natural gas properties	$	245	$	(2,344)
(Decrease) increase in liabilities for midstream properties capital expenditures	$	(7,634)	$	9,203



Stock-based compensation expense (benefit) recognized as a liability	$	15,489	$	(223)


Transfer of inventory to oil and natural gas properties	$	(636)	$	(335)

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,
	2021		2020
Cash	$	44,632	$	20,573
Restricted cash	34,576		22,935
Total cash and restricted cash	$	79,208	$	43,508

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UNAUDITED — CONTINUED

NOTE 11 — 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. 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 produced water gathering services and produced water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and Stateline asset areas and the Greater Stebbins Area in the Delaware Basin, which comprise most of the Company’s midstream operations, are conducted through San Mateo. San Mateo and its subsidiaries are not guarantors of the Notes.

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


	Exploration and Production						Consolidations and Eliminations		Consolidated Company
			Midstream		Corporate
Three Months Ended June 30, 2021
Oil and natural gas revenues	$	411,134	$	940	$	—	$	—	$	412,074
Midstream services revenues	—		59,691		—		(39,841)		19,850
Sales of purchased natural gas	4,120		6,798		—		—		10,918

Realized loss on derivatives	(42,611)		—		—		—		(42,611)
Unrealized loss on derivatives	(42,804)		—		—		—		(42,804)
Expenses(1)	199,127		30,274		22,761		(39,841)		212,321
Operating income(2)	$	130,712	$	37,155	$	(22,761)	$	—	$	145,106






Total assets	$	2,942,429	$	803,612	$	88,508	$	—	$	3,834,549
Capital expenditures(3)	$	107,928	$	7,863	$	112	$	—	$	115,903

_____________________

(1)Includes depletion, depreciation and amortization expenses of $83.0 million and $7.8 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.7 million.

(2)Includes $15.9 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3)Includes $6.9 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $3.8 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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UNAUDITED — CONTINUED

NOTE 11 — SEGMENT INFORMATION — Continued


	Exploration and Production						Consolidations and Eliminations		Consolidated Company
			Midstream		Corporate
Three Months Ended June 30, 2020
Oil and natural gas revenues	$	118,258	$	509	$	—	$	—	$	118,767
Midstream services revenues	—		36,234		—		(21,566)		14,668
Sales of purchased natural gas	8,327		5,654		—		—		13,981
Lease bonus - mineral acreage	4,062		—		—		—		4,062
Realized gain on derivatives	44,110		—		—		—		44,110
Unrealized loss on derivatives	(132,668)		—		—		—		(132,668)
Expenses(1)	483,812		23,575		12,409		(21,566)		498,230
Operating (loss) income(2)	$	(441,723)	$	18,822	$	(12,409)	$	—	$	(435,310)






Total assets	$	3,159,528	$	765,034	$	76,571	$	—	$	4,001,133
Capital expenditures(3)	$	130,709	$	64,656	$	594	$	—	$	195,959

_____________________

(1)Includes depletion, depreciation and amortization expenses of $87.8 million and $5.0 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $324.0 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $0.7 million.

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

(3)Includes $9.6 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $31.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.


	Exploration and Production						Consolidations and Eliminations		Consolidated Company
			Midstream		Corporate
Six Months Ended June 30, 2021
Oil and natural gas revenues	$	725,780	$	2,527	$	—	$	—	$	728,307
Midstream services revenues	—		103,600		—		(68,312)		35,288
Sales of purchased natural gas	6,582		8,846		—		—		15,428
Lease bonus - mineral acreage	—		—		—		—		—
Realized loss on derivatives	(68,524)		—		—		—		(68,524)
Unrealized loss on derivatives	(86,227)		—		—		—		(86,227)
Expenses(1)	355,571		56,521		42,723		(68,312)		386,503
Operating income(2)	$	222,040	$	58,452	$	(42,723)	$	—	$	237,769






Total assets	$	2,942,429	$	803,612	$	88,508	$	—	$	3,834,549
Capital expenditures(3)	$	242,793	$	17,636	$	245	$	—	$	260,674

_____________________

(1)Includes depletion, depreciation and amortization expenses of $149.4 million and $15.6 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.3 million.

(2)Includes $24.8 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3)Includes $15.6 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $8.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 11 — SEGMENT INFORMATION — Continued


	Exploration and Production						Consolidations and Eliminations		Consolidated Company
			Midstream		Corporate
Six Months Ended June 30, 2020
Oil and natural gas revenues	$	315,053	$	1,628	$	—	$	—	$	316,681
Midstream services revenues	—		73,983		—		(43,485)		30,498
Sales of purchased natural gas	11,922		12,603		—		—		24,525
Lease bonus - mineral acreage	4,062		—		—		—		4,062
Realized gain on derivatives	54,977		—		—		—		54,977
Unrealized gain on derivatives	3,762		—		—		—		3,762
Expenses(1)	645,137		47,905		26,726		(43,485)		676,283
Operating (loss) income(2)	$	(255,361)	$	40,309	$	(26,726)	$	—	$	(241,778)






Total assets	$	3,159,528	$	765,034	$	76,571	$	—	$	4,001,133
Capital expenditures(3)	$	340,444	$	132,729	$	1,381	$	—	$	474,554

_____________________

(1)Includes depletion, depreciation and amortization expenses of $172.9 million and $9.8 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $324.0 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $1.4 million.

(2)Includes $16.8 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3)Includes $49.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $79.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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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, 2020 (the “Annual Report”) filed with the Securities and Exchange Commission (the “SEC”) on February 26, 2021, 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 (this “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, collectively with its subsidiaries. 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; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the impact of the worldwide spread of the novel coronavirus (“COVID-19”) on oil and natural gas demand, oil and natural gas prices and our business; the operating results of San Mateo’s Black River cryogenic natural gas processing plant; the timing and operating results of the buildout by San Mateo of oil, natural gas and water gathering and transportation systems and the drilling of any additional salt water disposal wells; 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, including whether or not a full-cost ceiling impairment could be realized;

•our cash flows and liquidity;

•the amount, timing and payment of dividends, if any;

•our financial strategy, budget, projections and operating results;

•the supply and demand of oil, natural gas and natural gas liquids;

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

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

•the availability of drilling, completion and production equipment;

•the availability of oil storage capacity;

•the availability of oil field labor;

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

•the availability and terms of capital;

•our drilling of wells;

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•our ability to negotiate and consummate acquisition and divestiture opportunities;

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

•our marketing of oil and natural gas;

•our exploitation projects or property acquisitions;

•the integration of acquisitions with our business;

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

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

•our costs and timing 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;

•regulatory risk;

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

•the impact of COVID-19 on the oil and natural gas industry and our business;

•our future operating results; and

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

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

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

Overview

We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. 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 produced water gathering services and produced water disposal services to third parties.

Second Quarter Highlights

For the three months ended June 30, 2021, our total oil equivalent production was 8.5 million BOE, and our average daily oil equivalent production was 93,200 BOE per day, of which 53,400 Bbl per day, or 57%, was oil and 239.1 MMcf per day, or 43%, was natural gas. Our average daily oil production of 53,400 Bbl per day for the three months ended June 30, 2021 increased 24% year-over-year from 43,100 Bbl per day for the three months ended June 30, 2020. Our average daily natural gas production of 239.1 MMcf per day for the three months ended June 30, 2021 increased 32% year-over-year from 181.4 MMcf per day for the three months ended June 30, 2020.

For the second quarter of 2021, we reported net income attributable to Matador shareholders of $105.9 million, or $0.89 per diluted common share, on a generally accepted accounting principles in the United States (“GAAP”) basis, as compared to a net loss attributable to Matador shareholders of $353.4 million, or ($3.04) per diluted common share, for the second quarter of 2020. For the second quarter of 2021, our Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was $261.0 million, as compared to Adjusted EBITDA of $107.6 million during the second

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quarter of 2020. 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 three months ended June 30, 2021, see “—Results of Operations” below.

For the six months ended June 30, 2021, we reported net income attributable to Matador shareholders of $166.6 million, or $1.40 per diluted common share, on a GAAP basis, as compared to a net loss attributable to Matador shareholders of $227.7 million, or ($1.96) per diluted common share, for the six months ended June 30, 2020. For the six months ended June 30, 2021, our Adjusted EBITDA, a non-GAAP financial measure, was $459.1 million, as compared to Adjusted EBITDA of $248.2 million during the six months ended June 30, 2020. 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, 2021, see “—Results of Operations” below.

Operations Update

We operated four drilling rigs in the Delaware Basin during the second quarter of 2021. At July 27, 2021, two of these rigs were drilling in the Stateline asset area in Eddy County, New Mexico. These two rigs recently completed drilling 13 additional Boros wells in the eastern portion of the Stateline asset area and at July 27, 2021 were drilling 11 new Voni wells in the western portion of that asset area. The other two rigs have been drilling 13 wells in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”), nine of which were still in progress at July 27, 2021. Four of these wells, all Second Bone Spring completions, were recently turned to sales. When we complete drilling the nine wells in progress in the Greater Stebbins Area, we plan to use these two rigs to drill two additional wells in the Ranger asset area in Lea County, New Mexico and several additional Rodney Robinson wells in the western portion of the Antelope Ridge asset area in Lea County.

We turned to sales a total of 24 gross (15.6 net) wells in the Delaware Basin during the second quarter of 2021, including 15 gross (14.6 net) operated wells and nine gross (1.0 net) non-operated wells. During the second quarter of 2021, we turned to sales 13 gross (12.7 net) operated wells in the Stateline asset area; four were Wolfcamp A-Lower completions, four were Wolfcamp A-XY completions, four were Second Bone Spring completions and one was a First Bone Spring completion. In the Wolf asset area, we turned to sales two gross (1.9 net) operated wells, both of which were Second Bone Spring completions. We also participated in five gross (0.3 net) non-operated wells turned to sales in the Antelope Ridge asset area, two gross (0.7 net) non-operated wells in the Arrowhead asset area and two gross (less than 0.1 net) non-operated wells in the Rustler Breaks asset area.

Our average daily oil equivalent production in the Delaware Basin for the second quarter of 2021 was 87,500 BOE per day, consisting of 51,700 Bbl of oil per day and 214.7 MMcf of natural gas per day, a 33% increase from 66,000 BOE per day, consisting of 41,500 Bbl of oil per day and 146.9 MMcf of natural gas per day, in the second quarter of 2020. The Delaware Basin contributed approximately 97% of our daily oil production and approximately 90% of our daily natural gas production in the second quarter of 2021, as compared to approximately 96% of our daily oil production and approximately 81% of our daily natural gas production in the second quarter of 2020.

During the second quarter of 2021, we did not complete and turn to sales any operated wells on our leasehold properties in the Eagle Ford shale play in South Texas or in the Haynesville shale and Cotton Valley plays in Northwest Louisiana, but we did participate in four gross (less than 0.1 net) non-operated wells in the Haynesville shale.

2021 Capital Expenditure Budget

At July 27, 2021, our 2021 estimated capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) remained $525 to $575 million, as originally estimated. As a result of savings on our operated D/C/E capital expenditures in the first half of 2021, a faster drilling and completions pace and an anticipated decrease in non-operated D/C/E capital expenditures in the second half of 2021, we intend to advance the next 11 Voni well completions in the Stateline asset area forward into the fourth quarter of 2021 and expect to be able to do so without increasing our estimates for D/C/E capital expenditures for full year 2021.

At July 27, 2021, we increased our anticipated 2021 midstream capital expenditures from $20 to $30 million to $35 to $45 million, primarily to accommodate several new midstream opportunities for San Mateo with producers in Eddy County, New Mexico and to accelerate the installation of compression facilities and other infrastructure prior to the end of 2021 in order to be prepared for the additional volumes from the accelerated Voni completions noted above. Previously, these Voni-related capital expenditures were scheduled for early 2022. The anticipated total 2021 midstream capital expenditures of $35 to $45 million primarily reflect our proportionate share of San Mateo’s estimated 2021 capital expenditures.

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Capital Resources Update

Our Board of Directors (the “Board”) declared a quarterly cash dividend of $0.025 per share of common stock in both the first and second quarters of 2021, which were paid on March 31, 2021 and June 3, 2021, respectively. In July 2021, the Board declared a quarterly cash dividend of $0.025 per share of common stock payable on September 3, 2021 to shareholders of record as of August 12, 2021.

During each of the first and second quarters of 2021, we had net repayments of $100.0 million in borrowings under our third amended and restated credit agreement (the “Credit Agreement”). Our outstanding borrowings under our Credit Agreement at June 30, 2021 were $240.0 million.

In April 2021, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. The Company elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and no material changes were made to the terms of the Credit Agreement. This April 2021 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 2021, San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) was amended to increase the lender commitments under the revolving credit facility from $375.0 million to $450.0 million (subject to San Mateo’s compliance with certain covenants) and the borrowing rate for a base rate loan or Eurodollar loan under such facility was increased by 0.50%. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $700.0 million.

Critical Accounting Policies

There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.

Recent Accounting Pronouncements

There are no recent accounting pronouncements that are expected to have a material impact on our financial statements.

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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,
	2021		2020		2021		2020
Operating Data
Revenues (in thousands)(1)
Oil	$	315,114	$	94,174	$	528,393	$	263,759
Natural gas	96,960		24,593		199,914		52,922
Total oil and natural gas revenues	412,074		118,767		728,307		316,681
Third-party midstream services revenues	19,850		14,668		35,288		30,498
Sales of purchased natural gas	10,918		13,981		15,428		24,525
Lease bonus - mineral acreage	—		4,062		—		4,062
Realized (loss) gain on derivatives	(42,611)		44,110		(68,524)		54,977
Unrealized (loss) gain on derivatives	(42,804)		(132,668)		(86,227)		3,762
Total revenues	$	357,427	$	62,920	$	624,272	$	434,505
Net Production Volumes(1)
Oil (MBbl)(2)	4,855		3,920		8,594		7,617
Natural gas (Bcf)(3)	21.8		16.5		39.3		33.2
Total oil equivalent (MBOE)(4)	8,482		6,670		15,140		13,146
Average daily production (BOE/d)(5)	93,210		73,302		83,650		72,232
Average Sales Prices
Oil, without realized derivatives (per Bbl)	$	64.90	$	24.03	$	61.49	$	34.63
Oil, with realized derivatives (per Bbl)	$	56.13	$	35.28	$	53.49	$	41.85
Natural gas, without realized derivatives (per Mcf)	$	4.46	$	1.49	$	5.09	$	1.60
Natural gas, with realized derivatives (per Mcf)	$	4.46	$	1.49	$	5.09	$	1.60

_________________

(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 Bbl of oil.

(3)One billion cubic feet of natural gas.

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

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

Three Months Ended June 30, 2021 as Compared to Three Months Ended June 30, 2020

Oil and natural gas revenues. Our oil and natural gas revenues increased $293.3 million, or 247%, to $412.1 million for the three months ended June 30, 2021, as compared to $118.8 million for the three months ended June 30, 2020. Our oil revenues increased $220.9 million, or 235%, to $315.1 million for the three months ended June 30, 2021, as compared to $94.2 million for the three months ended June 30, 2020. This increase in oil revenues resulted from a 170% increase in the weighted average oil price realized for the three months ended June 30, 2021 to $64.90 per Bbl, as compared to $24.03 per Bbl for the three months ended June 30, 2020, and from a 24% increase in our oil production to 4.9 million Bbl for the three months ended June 30, 2021, as compared to 3.9 million Bbl for the three months ended June 30, 2020. Our natural gas revenues increased $72.4 million, or 294%, to $97.0 million for the three months ended June 30, 2021, as compared to $24.6 million for the three months ended June 30, 2020. The increase in natural gas revenues resulted from an approximately three-fold increase in the weighted average natural gas price realized for the three months ended June 30, 2021 to $4.46 per Mcf, as compared to a weighted average natural gas price of $1.49 per Mcf realized for the three months ended June 30, 2020, and from a 32% increase in our natural gas production to 21.8 Bcf for the three months ended June 30, 2021, as compared to 16.5 Bcf for the three months ended June 30, 2020.

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Third-party midstream services revenues. Our third-party midstream services revenues increased $5.2 million, or 35%, to $19.9 million for the three months ended June 30, 2021, as compared to $14.7 million for the three months ended June 30, 2020. 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 natural gas gathering, transportation and processing revenues to $10.3 million for the three months ended June 30, 2021, as compared to $6.3 million for the three months ended June 30, 2020, (ii) an increase in our third-party produced water gathering and disposal revenues to $7.0 million for the three months ended June 30, 2021, as compared to $6.2 million for the three months ended June 30, 2020, and (iii) an increase in our third-party oil gathering and transportation revenues to $2.6 million for the three months ended June 30, 2021, as compared to $2.1 million for the three months ended June 30, 2020.

Sales of purchased natural gas. Our sales of purchased natural gas decreased $3.1 million, or 22%, to $10.9 million for the three months ended June 30, 2021, as compared to $14.0 million for the three months ended June 30, 2020. This decrease was primarily the result of a decrease in purchased natural gas volumes sold during the three months ended June 30, 2021. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) 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 statements of operations.

Lease bonus - mineral acreage. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests. We did not lease any of our mineral acreage to third parties during the three months ended June 30, 2021. Our lease bonus - mineral acreage revenues were $4.1 million for the three months ended June 30, 2020.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $42.6 million for the three months ended June 30, 2021, as compared to a realized net gain of $44.1 million for the three months ended June 30, 2020. We realized a net loss of $42.6 million related to our oil costless collar and oil and oil basis swap contracts for the three months ended June 30, 2021, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike prices of certain of our oil and oil basis swap contracts. We realized an average loss on our oil derivatives of approximately $8.77 per Bbl produced during the three months ended June 30, 2021, as compared to an average gain of approximately $11.25 per Bbl produced during the three months ended June 30, 2020.

Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives was $42.8 million for the three months ended June 30, 2021, as compared to an unrealized net loss of $132.7 million for the three months ended June 30, 2020. During the three months ended June 30, 2021, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a net liability of $122.1 million from a net liability of $79.3 million at March 31, 2021, resulting in an unrealized loss on derivatives of $42.8 million for the three months ended June 30, 2021. During the three months ended June 30, 2020, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a net liability of $0.1 million at June 30, 2020 from a net asset of $132.6 million at March 31, 2020, resulting in an unrealized loss on derivatives of $132.7 million for the three months ended June 30, 2020.

Six Months Ended June 30, 2021 as Compared to Six Months Ended June 30, 2020

Oil and natural gas revenues. Our oil and natural gas revenues increased $411.6 million, or 130%, to $728.3 million for the six months ended June 30, 2021, as compared to $316.7 million for the six months ended June 30, 2020. Our oil revenues increased $264.6 million, or 100%, to $528.4 million for the six months ended June 30, 2021, as compared to $263.8 million for the six months ended June 30, 2020. This increase in oil revenues resulted from a 78% increase in the weighted average oil price realized for the six months ended June 30, 2021 to $61.49 per Bbl, as compared to $34.63 per Bbl for the six months ended June 30, 2020, and from a 13% increase in our oil production to 8.6 million Bbl for the six months ended June 30, 2021, as compared to 7.6 million Bbl for the six months ended June 30, 2020. Our natural gas revenues increased by $147.0 million, or 278%, to $199.9 million for the six months ended June 30, 2021, as compared to $52.9 million for the six months ended June 30, 2020. The increase in natural gas revenues resulted from a more than three-fold increase in the weighted average natural gas price realized for the six months ended June 30, 2021 to $5.09 per Mcf, as compared to a weighted average natural gas price of $1.60 per Mcf for the six months ended June 30, 2020, and from an 18% increase in our natural gas production to 39.3 Bcf for the six months ended June 30, 2021, as compared to 33.2 Bcf for the six months ended June 30, 2020.

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Third-party midstream services revenues. Our third-party midstream services revenues increased $4.8 million, or 16%, to $35.3 million for the six months ended June 30, 2021, as compared to $30.5 million for the six months ended June 30, 2020. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $17.1 million for the six months ended June 30, 2021, as compared to $13.4 million for the six months ended June 30, 2020, (ii) an increase in our third-party oil gathering and transportation revenues to $4.7 million for the six months ended June 30, 2021, as compared to $4.2 million for the six months ended June 30, 2020, and (iii) an increase in our third-party produced water gathering and disposal revenues to $13.5 million for the six months ended June 30, 2021, as compared to $12.9 million for the six months ended June 30, 2020.

Sales of purchased natural gas. Our sales of purchased natural gas decreased $9.1 million, or 37%, to $15.4 million for the six months ended June 30, 2021, as compared to $24.5 million for the six months ended June 30, 2020. This decrease was primarily the result of a decrease in natural gas volumes sold during the six months ended June 30, 2021.

Lease bonus - mineral acreage. We did not lease any of our mineral acreage to third parties during the six months ended June 30, 2021. Our lease bonus - mineral acreage revenues were $4.1 million for the six months ended June 30, 2020.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $68.5 million for the six months ended June 30, 2021, as compared to a realized net gain of $55.0 million for the six months ended June 30, 2020. We realized a net loss of $68.7 million related to our oil costless collar and oil and oil basis swap contracts for the six months ended June 30, 2021, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike prices of certain of our oil and oil basis swap contracts. We realized a net gain of $0.2 million related to our natural gas costless collar contracts for the six months ended June 30, 2021, resulting primarily from natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average loss on our oil derivatives of approximately $8.00 per Bbl produced during the six months ended June 30, 2021, as compared to an average gain of $7.22 per Bbl produced during the six months ended June 30, 2020.

Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives was $86.2 million for the six months ended June 30, 2021, as compared to an unrealized net gain of $3.8 million for the six months ended June 30, 2020. During the period from December 31, 2020 through June 30, 2021, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a net liability of $122.1 million from a net liability of $35.9 million, resulting in an unrealized loss on derivatives of $86.2 million for the six months ended June 30, 2021. During the period from December 31, 2019 through June 30, 2020, the aggregate net fair value of our open oil and natural gas derivative contracts increased to a net liability of $0.1 million from a net liability of $3.9 million, resulting in an unrealized gain on derivatives of $3.8 million for the six months ended June 30, 2020.

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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)	2021		2020		2021		2020

Expenses
Production taxes, transportation and processing	$	43,843	$	18,797	$	78,017	$	40,513
Lease operating	28,752		26,162		54,691		57,072
Plant and other midstream services operating	13,746		9,780		27,409		19,744
Purchased natural gas	9,628		10,922		12,483		18,980
Depletion, depreciation and amortization	91,444		93,350		166,307		184,057
Accretion of asset retirement obligations	511		495		1,011		971
Full-cost ceiling impairment	—		324,001		—		324,001
General and administrative	24,397		14,723		46,585		30,945
Total expenses	212,321		498,230		386,503		676,283
Operating income (loss)	145,106		(435,310)		237,769		(241,778)
Other income (expense)
Net loss on asset sales and impairment	—		(2,632)		—		(2,632)
Interest expense	(17,940)		(18,297)		(37,590)		(38,109)

Other income (expense)	14		473		(661)		1,793
Total other expense	(17,926)		(20,456)		(38,251)		(38,948)
Income (loss) before income taxes	127,180		(455,766)		199,518		(280,726)
Income tax provision (benefit)	5,349		(109,823)		8,189		(69,866)

Net income attributable to non-controlling interest in subsidiaries	(15,926)		(7,473)		(24,779)		(16,827)
Net income (loss) attributable to Matador Resources Company shareholders	$	105,905	$	(353,416)	$	166,550	$	(227,687)
Expenses per BOE
Production taxes, transportation and processing	$	5.17	$	2.82	$	5.15	$	3.08
Lease operating	$	3.39	$	3.92	$	3.61	$	4.34
Plant and other midstream services operating	$	1.62	$	1.47	$	1.81	$	1.50
Depletion, depreciation and amortization	$	10.78	$	14.00	$	10.98	$	14.00
General and administrative	$	2.88	$	2.21	$	3.08	$	2.35

Three Months Ended June 30, 2021 as Compared to Three Months Ended June 30, 2020

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $25.0 million, or 133%, to $43.8 million for the three months ended June 30, 2021, as compared to $18.8 million for the three months ended June 30, 2020. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 83% to $5.17 per BOE for the three months ended June 30, 2021, as compared to $2.82 per BOE for the three months ended June 30, 2020. These increases were primarily due to (i) a $22.5 million increase in production taxes to $31.1 million for the three months ended June 30, 2021, as compared to $8.6 million for the three months ended June 30, 2020, primarily due to the significant increase in the weighted average oil and natural gas prices realized between the two periods, and (ii) a $2.5 million increase in transportation and processing expenses to $12.7 million for the three months ended June 30, 2021, as compared to $10.2 million for the three months ended June 30, 2020, primarily due to the 32% increase in our natural gas production of 21.8 Bcf for the three months ended June 30, 2021, as compared to 16.5 Bcf for the three months ended June 30, 2020.

Lease operating. Our lease operating expenses increased $2.6 million, or 10%, to $28.8 million for the three months ended June 30, 2021, as compared to $26.2 million for the three months ended June 30, 2020. This increase was primarily attributable to increases in expenses associated with workovers, chemicals and other expenses of $3.4 million, which were attributable to servicing an increased number of operated wells at June 30, 2021, as compared to June 30, 2020. This increase

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was partially offset by a decrease in produced water trucking and disposal expenses of $1.1 million as more of our operated wells have been connected to produced water pipelines during three months ended June 30, 2021, as compared to the three months ended June 30, 2020. Our lease operating expenses on a unit-of-production basis decreased 14% to $3.39 per BOE for the three months ended June 30, 2021, as compared to $3.92 per BOE for the three months ended June 30, 2020, primarily due to the 27% increase in our total oil equivalent production for the three months ended June 30, 2021, as compared to the three months ended June 30, 2020.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $4.0 million, or 41%, to $13.7 million for the three months ended June 30, 2021, as compared to $9.8 million for the three months ended June 30, 2020. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of $6.6 million for the three months ended June 30, 2021, as compared to $5.4 million for the three months ended June 30, 2020, (ii) increased expenses associated with our expanded pipeline operations of $3.7 million for the three months ended June 30, 2021, as compared to $2.0 million for the three months ended June 30, 2020, and (iii) increased expenses associated with operating the expanded Black River Processing Plant of $3.5 million for the three months ended June 30, 2021, as compared to $2.5 million for the three months ended June 30, 2020.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $1.9 million, or 2%, to $91.4 million for the three months ended June 30, 2021, as compared to $93.4 million for the three months ended June 30, 2020. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 23% to $10.78 per BOE for the three months ended June 30, 2021, as compared to $14.00 per BOE for the three months ended June 30, 2020. These decreases were attributable to the increase in our estimated total proved oil and natural gas reserves, as well as the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2020. The decrease in our depletion, depreciation and amortization expenses was partially offset by a $2.8 million increase in depreciation expenses attributable to our midstream segment to $7.8 million for the three months ended June 30, 2021, as compared to $5.0 million for the three months ended June 30, 2020.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment were recorded for the three months ended June 30, 2021. At June 30, 2020, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $243.9 million. As a result, we recorded an impairment charge of $324.0 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax benefit of $80.1 million. This full-cost ceiling impairment of $324.0 million is reflected in our interim unaudited condensed consolidated statement of operations for the three months ended June 30, 2020.

General and administrative. Our general and administrative expenses increased $9.7 million, or 66%, to $24.4 million for the three months ended June 30, 2021, as compared to $14.7 million for the three months ended June 30, 2020. Our general and administrative expenses increased 30% on a unit-of-production basis to $2.88 per BOE for the three months ended June 30, 2021, as compared to $2.21 per BOE for the three months ended June 30, 2020. These increases were largely attributable to employee compensation costs, including a $5.2 million increase in stock-based compensation expense we recorded primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. The share price of our common stock increased by 54% from $23.45 at March 31, 2021 to $36.01 at June 30, 2021. The remainder of the increase for the three months ended June 30, 2021, as compared to the three months ended June 30, 2020, resulted primarily from the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time.

Interest expense. For the three months ended June 30, 2021, we incurred total interest expense of $19.8 million. We capitalized $1.9 million of our interest expense on certain qualifying projects for the three months ended June 30, 2021 and expensed the remaining $17.9 million to operations. For the three months ended June 30, 2020, we incurred total interest expense of $20.1 million. We capitalized $1.8 million of our interest expense on certain qualifying projects for the three months ended June 30, 2020 and expensed the remaining $18.3 million to operations.

Income tax provision (benefit). Our income tax provision was $5.3 million for the three months ended June 30, 2021. Our effective tax rate for the three months ended June 30, 2021 was 5%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to recording the net deferred tax liability for state taxes, primarily in New Mexico, and continuing to recognize a valuation allowance against our U.S. federal net deferred tax assets. As a result of the full-cost ceiling impairments recorded in 2020, we recognized a valuation allowance against our net deferred tax assets for the year ended December 31, 2020. The valuation allowance will continue to be recognized until the future deferred tax benefits are more likely than not to become utilized. We recorded an income tax benefit of $109.8 million for the three months ended June 30, 2020, and our effective tax rate for the three months ended June 30, 2020 was 24%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to the impact of permanent differences between book and tax income, as well as state taxes, primarily in New Mexico.

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Six Months Ended June 30, 2021 as Compared to Six Months Ended June 30, 2020

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $37.5 million, or 93%, to $78.0 million for the six months ended June 30, 2021, as compared to $40.5 million for the six months ended June 30, 2020. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 67% to $5.15 per BOE for the six months ended June 30, 2021, as compared to $3.08 per BOE for the six months ended June 30, 2020. These increases were primarily due to (i) a $32.1 million increase in production taxes to $54.8 million for the six months ended June 30, 2021, as compared to $22.7 million for the six months ended June 30, 2020, primarily due to the significant increase in the weighted average oil and natural gas prices realized between the two periods, and (ii) a $5.4 million increase in transportation and processing expenses to $23.2 million for the six months ended June 30, 2021, as compared to $17.8 million for the six months ended June 30, 2020, primarily due to the 18% increase in our natural gas production to 39.3 Bcf for the six months ended June 30, 2021, as compared to 33.2 Bcf for the six months ended June 30, 2020.

Lease operating. Our lease operating expenses decreased $2.4 million, or 4%, to $54.7 million for the six months ended June 30, 2021, as compared to $57.1 million for the six months ended June 30, 2020. Our lease operating expenses on a unit-of-production basis decreased 17% to $3.61 per BOE for the six months ended June 30, 2021, as compared to $4.34 per BOE for the six months ended June 30, 2020. These decreases were largely attributable to (i) a decrease in produced water trucking and disposal expenses of $1.7 million as more of our operated wells have been connected to produced water pipelines, (ii) a decrease in repairs and maintenance and equipment rentals of $3.1 million and (iii) a decrease in compressor rental charges of $1.1 million. These decreases were partially offset by increases associated with workovers and chemical expenses of $3.3 million, which were attributable to servicing an increased number of operated wells at June 30, 2021, as compared to June 30, 2020.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $7.7 million, or 39%, to $27.4 million for the six months ended June 30, 2021, as compared to $19.7 million for the six months ended June 30, 2020. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of $14.2 million for the six months ended June 30, 2021, as compared to $10.5 million for the six months ended June 30, 2020, (ii) increased expenses associated with our expanded pipeline operations of $7.0 million for the six months ended June 30, 2021, as compared to $4.0 million for the six months ended June 30, 2020, and (iii) increased expenses associated with operating the expanded Black River Processing Plant of $6.2 million for the six months ended June 30, 2021, as compared to $5.2 million for the six months ended June 30, 2020.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $17.8 million, or 10%, to $166.3 million for the six months ended June 30, 2021, as compared to $184.1 million for the six months ended June 30, 2020. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 22% to $10.98 per BOE for the six months ended June 30, 2021, as compared to $14.00 per BOE for the six months ended June 30, 2020. These decreases were attributable to the increase in our estimated total proved oil and natural gas reserves, as well as the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2020. The decrease in our depletion, depreciation and amortization expenses was partially offset by a $5.8 million increase in depreciation expenses attributable to our midstream segment to $15.6 million for the six months ended June 30, 2021 as compared to $9.8 million for the six months ended June 30, 2020.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment were recorded for the six months ended June 30, 2021. At June 30, 2020, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $243.9 million. As a result, we recorded an impairment charge of $324.0 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax benefit of $80.1 million. This full-cost ceiling impairment of $324.0 million is reflected in our interim unaudited condensed consolidated statement of operations for the six months ended June 30, 2020.

General and administrative. Our general and administrative expenses increased $15.6 million, or 51%, to $46.6 million for the six months ended June 30, 2021, as compared to $30.9 million for the six months ended June 30, 2020. Our general and administrative expenses increased 31% on a unit-of-production basis to $3.08 per BOE for the six months ended June 30, 2021, as compared to $2.35 per BOE for the six months ended June 30, 2020. These increases were largely attributable to employee compensation costs, including an $11.0 million increase in stock-based compensation expense we recorded primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. The share price of our common stock increased approximately three-fold from $12.06 at December 31, 2020 to $36.01 at June 30, 2021. The remainder of the increase for the six months ended June 30, 2021, as compared to the six months ended June 30, 2020, resulted primarily from the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time.

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Interest expense. For the six months ended June 30, 2021, we incurred total interest expense of $40.1 million. We capitalized $2.5 million of our interest expense on certain qualifying projects for the six months ended June 30, 2021 and expensed the remaining $37.6 million to operations. For the six months ended June 30, 2020, we incurred total interest expense of $41.3 million. We capitalized $3.2 million of our interest expense on certain qualifying projects for the six months ended June 30, 2020 and expensed the remaining $38.1 million to operations.

Income tax provision (benefit). Our income tax provision was $8.2 million for the six months ended June 30, 2021. Our effective tax rate for the six months ended June 30, 2021 was 5%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to recording the net deferred tax liability for state taxes, primarily in New Mexico, and continuing to recognize a valuation allowance against our U.S. federal net deferred tax assets. As a result of the full-cost ceiling impairments recorded in 2020, we recognized a valuation allowance against our net deferred tax assets for the year ended December 31, 2020. The valuation allowance will continue to be recognized until the future deferred tax benefits are more likely than not to become utilized. We recorded an income tax benefit of $69.9 million for the six months ended June 30, 2020, and our effective tax rate for the six months ended June 30, 2020 was 23%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to the impact of permanent differences between book and tax income, as well as state taxes, primarily in New Mexico.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during the remainder of 2021 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 expenditures for the remainder of 2021 primarily through a combination of cash on hand, operating cash flows and performance incentives paid to us by a subsidiary of Five Point Energy LLC, our joint venture partner, in connection with San Mateo. If capital expenditures were to exceed our operating cash flows during the remainder of 2021, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.

At June 30, 2021, we had cash totaling $44.6 million and restricted cash totaling $34.6 million, which was associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. During each of the first and second quarters of 2021, we had net repayments of $100.0 million in borrowings under the Credit Agreement. In addition, the Board declared our first two quarterly cash dividends of $0.025 per share of common stock, which were paid on March 31, 2021 and June 3, 2021. In July 2021, the Board declared a quarterly cash dividend of $0.025 per share of common stock payable on September 3, 2021 to shareholders of record as of August 12, 2021.

At June 30, 2021, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $240.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration (“SBA”) loan. In April 2021, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. We elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and no material changes were made to the terms of the Credit Agreement. This April 2021 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 (subject to compliance with the covenant noted below). The Credit Agreement matures in October 2023. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 4.0 or less. We believe that we were in compliance with the terms of the Credit Agreement at June 30, 2021.

At June 30, 2021, San Mateo had $352.5 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between June 30, 2021 and July 27, 2021, San Mateo repaid $25.0 million of borrowings under the San Mateo Credit Facility. The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under that facility from $375 million to $450 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender

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commitments to up to $700.0 million. The San Mateo Credit Facility is guaranteed by San Mateo’s subsidiaries, secured by substantially all of San Mateo’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.0 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.5 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at June 30, 2021.

On April 13, 2020, we executed a promissory note evidencing an unsecured loan in the amount of approximately $7.5 million as part of the Paycheck Protection Program. For a discussion of such loan, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in the Annual Report.

During the six months ended June 30 and through July 2021, the oil and natural gas industry has experienced continued improvement in commodity prices as compared to 2020, primarily resulting from (i) improvements in oil demand as the impact from COVID-19 has begun to abate and (ii) actions taken by the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) to reduce the worldwide supply of oil through coordinated production cuts. As a result, West Texas Intermediate (“WTI”) oil prices have increased from $48.52 per barrel at December 31, 2020 to as high as $74.05 per barrel in late June 2021. While oil prices have improved in 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains uncertain, and we can provide no assurances as to when or to what extent economic disruptions resulting from COVID-19 and the corresponding decreases in oil demand may improve further. These economic disruptions have also impacted our ability to access the capital markets on reasonably similar terms as were available prior to 2020. Prices for natural gas and NGLs were also much higher during the six months ended June 30 and through July 2021 as compared to 2020.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 2021. We operated four drilling rigs in the Delaware Basin during the second quarter of 2021. At July 27, 2021, two of these rigs were drilling in the Stateline asset area in Eddy County, New Mexico. These two rigs recently completed drilling 13 additional Boros wells in the eastern portion of the Stateline asset area and at July 27, 2021 were drilling 11 new Voni wells in the western portion of that asset area. The other two rigs have been drilling 13 wells in the Greater Stebbins Area, nine of which were still in progress at July 27, 2021. Four of these wells, all Second Bone Spring completions, were recently turned to sales. When we complete drilling the nine wells in progress in the Greater Stebbins Area, we plan to use these two rigs to drill two additional wells in the Ranger asset area in Lea County, New Mexico and several additional Rodney Robinson wells in the western portion of the Antelope Ridge asset area in Lea County.

At July 27, 2021, our 2021 estimated capital expenditures for D/C/E capital expenditures remained $525 to $575 million, as originally estimated. As a result of savings on our operated D/C/E capital expenditures in the first half of 2021, a faster drilling and completions pace and an anticipated decrease in non-operated D/C/E capital expenditures in the second half of 2021, we intend to advance the next 11 Voni well completions in the Stateline asset area forward into the fourth quarter of 2021 and expect to be able to do so without increasing our estimates for D/C/E capital expenditures for full year 2021.

Substantially all of these 2021 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance 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. Our 2021 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a higher percentage of longer horizontal wells in 2021, including 98% with anticipated completed lateral lengths of two miles or greater. We have built significant optionality into our drilling program, which should generally allow us to increase or decrease the number of rigs we operate as necessary based on changing commodity prices and other factors.

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We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana, as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during the remainder of 2021. 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 2021 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 2021.

Our 2021 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.

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 2021 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting 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 oil and natural gas prices for the remainder of 2021 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 7 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments.

Our unaudited cash flows for the six months ended June 30, 2021 and 2020 are presented below:


	Six Months Ended June 30,
(In thousands)	2021		2020

Net cash provided by operating activities	$	427,595	$	210,385
Net cash used in investing activities	(251,122)		(458,761)
Net cash (used in) provided by financing activities	(188,648)		226,756
Net change in cash and restricted cash	$	(12,175)	$	(21,620)
Adjusted EBITDA attributable to Matador Resources Company shareholders(1)	$	459,081	$	248,170

__________________

(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 increased $217.2 million to $427.6 million for the six months ended June 30, 2021 from $210.4 million for the six months ended June 30, 2020. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased $221.7 million to $457.4 million for the six months ended June 30, 2021 from $235.7 million for the six months ended June 30, 2020, primarily attributable to significantly higher realized oil and natural gas prices and higher oil and natural gas production for the six months ended June 30, 2021, as compared to the six months ended June 30, 2020. Changes in our operating assets and liabilities between the two periods resulted in a net decrease of approximately $4.5 million in net cash provided by operating activities for the six months ended June 30, 2021, as compared to the six months ended June 30, 2020.

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Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. Furthermore, the effects of COVID-19 and the corresponding decline in oil demand significantly impacted the prices we received for our oil production in recent periods, particularly during 2020. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments at times 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 $207.6 million to $251.1 million for the six months ended June 30, 2021 from $458.8 million for the six months ended June 30, 2020. This decrease in net cash used in investing activities was primarily due to (i) a decrease of $98.2 million in midstream capital expenditures, (ii) a decrease of $72.6 million in D/C/E capital expenditures and (iii) a decrease of $36.4 million in expenditures related to acquisition of oil and natural gas properties for the six months ended June 30, 2021, as compared to the six months ended June 30, 2020. Cash used for D/C/E capital expenditures for the six months ended June 30, 2021 and 2020 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin. Cash used for midstream capital expenditures for the six months ended June 30, 2020 was primarily attributable to the expansion of the Black River Processing Plant and midstream facilities in the Greater Stebbins Area and the Stateline asset area, which were completed in 2020.

Cash Flows (Used in) Provided by Financing Activities

Net cash used in financing activities was $188.6 million for the six months ended June 30, 2021, a significant change from net cash provided by financing activities of $226.8 million for the six months ended June 30, 2020. During the six months ended June 30, 2021, our primary uses of cash related to financing activities were for the net repayment of $200.0 million in borrowings under our Credit Agreement and the payment of our first two quarterly dividends. These payments were partially offset by net borrowings under the San Mateo Credit Facility of $18.5 million. During the six months ended June 30, 2020, our primary sources of cash from financing activities included borrowings under our Credit Agreement of $130.0 million, borrowings under the San Mateo Credit Facility of $32.0 million and net contributions related to the formation of San Mateo and from non-controlling interest owners in less-than-wholly-owned subsidiaries of $59.8 million.

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

Guarantor Financial Information

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, 2021, 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 are not guarantors of the Notes.

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The following tables present summarized financial information of Matador (as issuer of the Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities.


(In thousands)	June 30, 2021
Summarized Balance Sheet
Assets
Current assets	$	283,398
Net property and equipment	$	2,696,347
Other long-term assets	$	51,775
Liabilities
Current liabilities	$	429,891
Long-term debt	$	1,281,789
Other long-term liabilities	$	71,598


	Three Months Ended		Six Months Ended
(In thousands)	June 30, 2021		June 30, 2021
Summarized Statement of Operations
Revenues	$	329,849	$	577,642
Expenses	219,366		394,489
Operating income	$	110,483	$	183,153
Other expense	(15,809)		(34,208)
Tax provision	(5,349)		(8,189)
Net income	$	89,325	$	140,756

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 impairment. Adjusted EBITDA is not a measure of net income 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 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 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.

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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)	2021		2020		2021		2020
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss)
Net income (loss) attributable to Matador Resources Company shareholders	$	105,905	$	(353,416)	$	166,550	$	(227,687)
Net income attributable to non-controlling interest in subsidiaries	15,926		7,473		24,779		16,827
Net income (loss)	121,831		(345,943)		191,329		(210,860)
Interest expense	17,940		18,297		37,590		38,109
Total income tax provision (benefit)	5,349		(109,823)		8,189		(69,866)
Depletion, depreciation and amortization	91,444		93,350		166,307		184,057
Accretion of asset retirement obligations	511		495		1,011		971
Full-cost ceiling impairment	—		324,001		—		324,001
Unrealized loss (gain) on derivatives	42,804		132,668		86,227		(3,762)
Non-cash stock-based compensation expense	1,795		3,286		2,650		7,080
Net loss on asset sales and impairment	—		2,632		—		2,632
Consolidated Adjusted EBITDA	281,674		118,963		493,303		272,362
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(20,708)		(11,369)		(34,222)		(24,192)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	260,966	$	107,594	$	459,081	$	248,170


	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands)	2021		2020		2021		2020
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	258,200	$	101,013	$	427,595	$	210,385
Net change in operating assets and liabilities	6,465		368		29,773		25,267
Interest expense, net of non-cash portion	17,009		17,582		35,935		36,710
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(20,708)		(11,369)		(34,222)		(24,192)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	260,966	$	107,594	$	459,081	$	248,170

For the three months ended June 30, 2021, we reported net income attributable to Matador shareholders of $105.9 million, as compared to a net loss attributable to Matador shareholders of $353.4 million for the three months ended June 30, 2020. This change in net income attributable to Matador shareholders primarily resulted from (i) the $324.0 million full-cost ceiling impairment recorded for the three months ended June 30, 2020, (ii) higher oil and natural gas production and higher realized oil and natural gas prices for the three months ended June 30, 2021, as compared to the three months ended June 30, 2020, and (iii) an unrealized loss on derivatives of $42.8 million for the three months ended June 30, 2021, as compared to an unrealized loss on derivatives of $132.7 million for the three months ended June 30, 2020.

For the six months ended June 30, 2021, we reported net income attributable to Matador shareholders of $166.6 million, as compared to a net loss attributable to Matador shareholders of $227.7 million for the six months ended June 30, 2020. This change in net income attributable to Matador shareholders primarily resulted from the $324.0 million full-cost ceiling impairment recorded for the six months ended June 30, 2020 and was also the result of higher oil and natural gas production and higher realized oil and natural gas prices for the six months ended June 30, 2021, as compared to the six months ended June 30, 2020. This increase was partially offset by an unrealized loss on derivatives of $86.2 million for the six months ended June 30, 2021, as compared to an unrealized gain on derivatives of $3.8 million for the six months ended June 30, 2020.

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Adjusted EBITDA, a non-GAAP financial measure, increased $153.4 million to $261.0 million for the three months ended June 30, 2021, as compared to $107.6 million for the three months ended June 30, 2020. This increase is primarily attributable to higher oil and natural gas production and higher realized oil and natural gas prices for the three months ended June 30, 2021, as compared to the three months ended June 30, 2020.

Adjusted EBITDA, a non-GAAP financial measure, increased $210.9 million to $459.1 million for the six months ended June 30, 2021, as compared to $248.2 million for the six months ended June 30, 2020. This increase is primarily attributable to higher oil and natural gas production and higher realized oil and natural gas prices for the six months ended June 30, 2021, as compared to the six months ended June 30, 2020.

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, 2021, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 9 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, 2021.


	Payments Due by Period
(In thousands)	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
Contractual Obligations
Borrowings, including letters of credit(1)	$	654,773	$	—	$	654,773	$	—	$	—
Senior unsecured notes(2)	1,050,000		—		—		—		1,050,000
Office leases	20,501		4,050		8,441		8,010		—
Non-operated drilling and other capital commitments(3)	44,788		25,263		19,525		—		—
Drilling rig contracts(4)	14,654		14,654		—		—		—
Asset retirement obligations(5)	39,948		211		5,160		1,501		33,076
Transportation, gathering, processing and disposal agreements with non-affiliates(6)	632,458		70,167		149,531		150,593		262,167
Transportation, gathering, processing and disposal agreements with San Mateo(7)	429,978		10,394		129,378		182,740		107,466



Total contractual cash obligations	$	2,887,100	$	124,739	$	966,808	$	342,844	$	1,452,709

__________________

(1)The amounts included in the table above represent principal maturities only. At June 30, 2021, we had $240.0 million in borrowings outstanding under the Credit Agreement, approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and $7.5 million in borrowings outstanding under the SBA loan. The Credit Agreement matures in October 2023. At June 30, 2021, San Mateo had $352.5 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. Assuming the amounts outstanding and interest rates of 1.60% and 2.36%, for the Credit Agreement and the San Mateo Credit Facility, respectively, at June 30, 2021, the interest expense for such facilities is expected to be approximately $3.9 million and $8.4 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, 2021 is expected to be approximately $61.7 million each year until maturity.

(3)At June 30, 2021, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells.

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

(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at June 30, 2021.

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

(7)We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.

General Outlook and Trends

During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices resulting from two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) the increase in global oil supply resulting from actions of OPEC+. The sudden decline in oil prices began to improve later in the second quarter of 2020 and generally continued throughout the remainder of 2020 and the first half of 2021. For the three months ended June 30, 2021, oil prices averaged $66.17 per Bbl, ranging from a low of $58.65 per Bbl in early April to a high of $74.05 per Bbl in late June, based upon the WTI oil futures contract price for the earliest delivery date.

We realized a weighted average oil price of $64.90 per Bbl ($56.13 per Bbl including realized losses from oil derivatives) for our oil production for the three months ended June 30, 2021, as compared to $24.03 per Bbl ($35.28 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended June 30, 2020. At July 27, 2021, the WTI oil futures contract for the earliest delivery date had increased from the average price for the second quarter of 2021 of $66.17 per Bbl, settling at $71.65 per Bbl, which was a significant increase as compared to $41.60 per Bbl at July 27, 2020.

Natural gas prices were also higher in the second quarter of 2021, as compared to the second quarter of 2020. For the three months ended June 30, 2021, natural gas prices averaged $2.98 per MMBtu, ranging from a low of $2.46 per MMBtu in early April to a high of $3.65 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 $4.46 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, 2021, as compared to $1.49 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, 2020. While most of our natural gas production is typically sold at prices established at the beginning of each month by the various markets where we sell our natural gas production, certain volumes of our natural gas production are sold at daily market prices. NGL prices, and especially propane prices, were also strong in the second quarter of 2021, which further contributed to our second quarter weighted average realized natural gas price. At July 27, 2021, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased from the average price for the second quarter of 2021 of $2.98 per MMBtu, settling at $3.97 per MMBtu, which was also a significant increase as compared to $1.73 per MMBtu at July 27, 2020.

The prices we receive for oil, natural gas and NGLs heavily influence our revenues, 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 and our ability to comply with the leverage ratio covenant under our Credit Agreement. We are uncertain if oil and natural gas prices will rise from their current levels, and in fact, oil and natural gas prices may decrease in future periods. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations” in the Annual Report.

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During the first six months of 2021, we incurred realized losses on our oil derivative contracts of approximately $68.7 million primarily as a result of oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike price of certain of our oil swap and oil basis

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swap contracts. Should oil prices remain at or near their current levels for the remainder of 2021, we would expect to have similar or greater losses during the second half of 2021, until these derivative contracts have expired.

The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At June 30, 2021, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years, but began 2020 slightly positive to the WTI oil price and remained positive through much of the first quarter of 2020. With the abrupt decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020, reaching ($6.00) per Bbl before becoming positive in the second quarter and improving through the rest of 2020 and into 2021. At July 27, 2021, this oil price differential was approximately ($0.29) per Bbl. At July 27, 2021, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated oil production for the remainder of 2021 and 2022.

Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years, including in April 2019 when natural gas was sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu. In early 2020, the Waha basis differential remained significant at about ($1.20) per MMBtu and continued to deteriorate. Natural gas prices at the Waha hub were negative on certain days in April 2020. The Waha basis differential narrowed during the remainder of the second quarter of 2020. During the third quarter of 2020 and, in particular, at the beginning of October 2020, the Waha basis differential widened significantly again, including several days when natural gas was being sold at the Waha hub for negative prices, due to seasonal pipeline maintenance and other factors that reduced capacity out of the Waha hub. These capacity issues have been largely resolved and the Waha basis differential improved during the remainder of 2020 and throughout the first half of 2021.

A significant portion of our Delaware Basin natural gas production, however, is typically sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2020 and most of the first half of 2021, we typically realized a premium to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production to other markets to improve our realized natural gas pricing.

Although the natural gas price differentials have recently at times been positive, these price differentials could deteriorate in future periods. Should we experience future periods of negative pricing for natural gas as we have in previous periods, 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 2021 or for future periods.

In addition to concerns regarding oil and natural gas prices and basis differentials, the destruction of global oil demand resulting from the decline in economic activity associated with COVID-19, in conjunction with the actions initiated by Saudi Arabia in March 2020 to increase its oil production to world markets, led to a significant oversupply of oil worldwide. OPEC+ (led by Saudi Arabia) reversed course in April 2020 and reduced oil production significantly for the remainder of 2020 and through the first half of 2021, which has contributed to improving oil prices. The members of OPEC+ have generally adhered to these production cuts, which have contributed to improving oil prices, although OPEC+ has begun to restore production levels as oil prices have improved. It is uncertain to what degree these production cuts may restore the balance between oil supply and demand.

During times of low oil prices, we may elect to shut in or curtail certain volumes of our oil production temporarily rather than sell the oil at depressed prices. As most of our natural gas production in the Delaware Basin is associated with oil production, portions of our natural gas production may also be curtailed or shut in. Furthermore, portions of our Delaware Basin production in the first quarter of 2021 were impacted by the historically prolonged cold weather conditions in New Mexico and Texas in February due to Winter Storm Uri, although we were able to produce and sell the majority of our oil and natural gas during this period. We experienced minimal impact to our production volumes due to insufficient storage capacity or damage to refineries downstream of our operations as a result of Winter Storm Uri.

At July 27, 2021, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, 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.

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As a result of the recent increases in oil and natural gas prices, we have begun to experience inflation in the costs of certain oilfield services, including diesel, steel, labor and trucking costs, among others. Should oil and natural gas prices remain at their current levels or increase further, we expect to be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. We budgeted a 10% increase in oilfield service costs for the second half of 2021 in preparing our full-year D/C/E and midstream capital expenditures for 2021. Should we experience service cost inflation above 10% during the second half of 2021, we may be required to increase our 2021 estimated capital expenditure budget.

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, although such bills have not passed, in recent years, separate bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Following that executive order, the governing New Mexico regulatory bodies and New Mexico legislature have proposed various rules, regulations and bills regarding the reduction of natural gas waste and the control of emissions. In 2021, New Mexico adopted a rule that limits the ability of upstream and midstream operators to flare natural gas (which may caused unplanned shut-ins of our production) and requires upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. See “Risk Factors—Risks Related to Laws and Regulations” in our Annual Report. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows.

In January 2021, the Biden administration issued (i) an order signed by the acting Secretary of the Interior dated January 20, 2021 providing for a 60-day pause limiting the authority of local offices of the Bureau of Land Management to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Federal Lease Orders”). While certain of the Biden Federal Lease Orders were allowed to expire in March 2021, others were extended. The pause relating to federal oil and natural gas leases in these orders did not restrict our activities on existing valid leases. As such, we have continued our operations on federal properties. However, we can provide no assurances that federal regulations will not be adopted that limit our ability to develop our federal properties. Should such actions be taken, they would almost certainly impact our drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands” in our Annual Report.

In addition, certain segments of the investor community have expressed negative sentiment towards investing in the oil and natural gas industry, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.

Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth” in the Annual Report.

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves

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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, 2020, 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, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. 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. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and 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 us. In the case of a costless collar, the put option or options and the call option 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, 2021, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), Truist Bank (or affiliates thereof), PNC Bank and the Royal Bank of Canada 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 7 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments. Such information is incorporated herein by reference.

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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, 2021 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 (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, 2021 that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting.

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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.

For information on our legal proceeding with the Environmental Protection Agency and the New Mexico Environment Department, see “Item 3. Legal Proceedings” in the Annual Report. There have been no material changes regarding such legal proceeding.

Item 1A. Risk Factors

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

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

During the quarter ended June 30, 2021, 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, 2021 to April 30, 2021	24,772	$	27.17	—	—
May 1, 2021 to May 31, 2021	975	$	30.64	—	—
June 1, 2021 to June 30, 2021	3,358	$	35.82	—	—
Total	29,105	$	28.28	—	—

_________________

(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†						Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the year ended December 31, 2020).

10.2						Fifteenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 23, 2021, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 29, 2021).

10.3†						Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan (filed herewith).

10.4†						Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan (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, 2021, 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 (included as Exhibit 101).

†						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: July 30, 2021	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer


Date: July 30, 2021	By:	/s/ David E. Lancaster
		David E. Lancaster
		Executive Vice President and Chief Financial Officer

Document

Exhibit 10.3

PHANTOM UNIT AWARD AGREEMENT

MATADOR RESOURCES COMPANY

2019 LONG-TERM INCENTIVE PLAN

1. Award of Phantom Units. Pursuant to the Matador Resources Company 2019 Long-Term Incentive Plan (as the same may be amended, the “Plan”), Matador Resources Company, a Texas corporation (the “Company”), grants to

[●]

(the “Participant”),

an Award of [●] Phantom Units (the “Awarded Units”) subject to the terms and conditions of this Phantom Unit Award Agreement (this “Agreement”) and the Plan. The “Date of Grant” of this Award is [●]. Each Awarded Unit shall represent a notional share of Common Stock, with the value of each Awarded Unit being equal to the Fair Market Value of a share of Common Stock at any given time.

2. Subject to Plan; Definitions. This Agreement is subject to the terms and conditions of the Plan, and the terms of the Plan shall control to the extent not otherwise inconsistent with the provisions of this Agreement. To the extent the terms of the Plan are inconsistent with the provisions of this Agreement, this Agreement shall control. This Agreement is subject to any rules promulgated pursuant to the Plan by the Board or the Committee and communicated to the Participant in writing. Unless defined herein, the capitalized terms used herein that are defined in the Plan shall have the same meanings assigned to them in the Plan, or where indicated, as defined in that certain Employment Agreement, effective as of [●], by and between the Company and the Participant (the “Employment Agreement”).

3. Vesting; Settlement of Awarded Units. Awarded Units which have become vested pursuant to the terms of this Section 3 are collectively referred to herein as “Vested Units.” All other Awarded Units are collectively referred to herein as “Unvested Units.”

a. Except as specifically provided in this Agreement and subject to certain restrictions and conditions set forth in the Plan, the Awarded Units shall vest as follows (each such vesting date referred to below, a “Vesting Date”):

[●].

b. Notwithstanding the foregoing, if within thirty (30) days prior to or twelve (12) months following a Change in Control (as defined in the Employment Agreement), the Participant incurs a Termination of Service by the Company without Just Cause (as defined in the Employment Agreement) or by the Participant with [or without] Good Reason (as defined in the Employment Agreement), then effective immediately prior to such Termination of Service, all Unvested Units shall thereupon immediately become Vested Units, and the date of such Termination of Service shall be the applicable Vesting Date for such Vested Units.

c. Following each Vesting Date, the Awarded Units that vest on such date shall be settled in cash, in an amount equal to the number of Awarded Units that vested on such Vesting Date multiplied by the Fair Market Value of the Common Stock on such Vesting Date.

d. Payment in settlement of the Vested Units shall be made within thirty (30) days of each applicable Vesting Date, and in no event later than two and a half (2½) months following the close of the calendar year in which the applicable Vesting Date occurred.

4. Forfeiture of Awarded Units. Unvested Units shall be forfeited, without the payment of any consideration therefor, immediately upon the Participant’s Termination of Service. Upon forfeiture, all of the Participant’s rights with respect to the forfeited Awarded Units shall cease and terminate, without any further obligations on the part of the Company.

5. Restrictions on Awarded Units. Subject to the provisions of the Plan and the terms of this Agreement, the Participant shall not be permitted to sell, transfer, pledge, hypothecate, margin, assign or otherwise encumber any of the Awarded Units, except that, the Participant may transfer for no consideration some or all of the Awarded Units to (a) one or more members of the Participant’s Immediate Family, (b) a trust in which the Participant or members of his or her Immediate Family have more than fifty percent of the beneficial interest, (c) a foundation in which the Participant or members of his or her Immediate Family control the management of assets or (d) any other entity in which the Participant or members of his or her Immediate Family own more than fifty percent of the voting interests. Any such transferee must agree in writing on a form prescribed by the Company to be bound by all of the provisions of this Agreement to the same extent as they apply to the Participant. Notwithstanding any such transfer, any vesting conditioned upon the Participant’s continued employment or service with the Company or its Subsidiaries shall continue to relate to the Participant’s continued employment or service and any covenants applicable to Participant hereunder shall continue to apply to Participant. In addition, the Committee may in its sole discretion, remove any or all of the restrictions on such Awarded Units whenever it may determine that, by reason of changes in applicable laws or changes in circumstances after the date of this Agreement, such action is appropriate.

6. Rights of a Shareholder. The Participant will have no rights as a shareholder with respect to any of the Awarded Units covered by this Agreement (including, without limitation, any voting rights or the right to receive any dividends).

7. Adjustment to Number of Awarded Units. The number of Awarded Units shall be subject to adjustment in accordance with Articles 11-13 of the Plan.

8. Participant’s Representations. Notwithstanding any of the provisions hereof, the Participant hereby agrees that the Company will not be obligated to settle any Awarded Units hereunder if the settlement of such Awarded Units would constitute a violation by the Participant or the Company of any provision of any law or regulation of any governmental authority or any national securities exchange or inter-dealer quotation system or other forum in which shares of Common Stock are quoted or traded. Any determination in this connection by the Company shall be final, binding, and conclusive. The rights and obligations of the Company and the rights and obligations of the Participant are subject to all Applicable Laws, rules, and regulations.

9. Participant’s Acknowledgments. The Participant acknowledges that a copy of the Plan has been made available for his or her review by the Company, and represents that he or she is familiar with the terms and provisions thereof, and hereby accepts this Award subject to all the terms and provisions thereof. The Participant hereby agrees to accept as binding, conclusive, and final all decisions or interpretations of the Committee or the Board, as appropriate, upon any questions arising under the Plan or this Agreement.

10. Law Governing. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas (excluding any conflict of laws rule or principle of Texas law that might refer the governance, construction, or interpretation of this Agreement to the laws of another state).

restrict in any way the right of the Company or any Subsidiary to discharge the Participant as an Employee, Contractor, or Outside Director at any time.

12. Legal Construction. In the event that any one or more of the terms, provisions, or agreements that are contained in this Agreement shall be held by a court of competent jurisdiction to be invalid, illegal, or unenforceable in any respect for any reason, the invalid, illegal, or unenforceable term, provision, or agreement shall not affect any other term, provision, or agreement that is contained in this Agreement and this Agreement shall be construed in all respects as if the invalid, illegal, or unenforceable term, provision, or agreement had never been contained herein.

13. Covenants and Agreements as Independent Agreements. Each of the covenants and agreements that is set forth in this Agreement shall be construed as a covenant and agreement independent of any other provision of this Agreement. The existence of any claim or cause of action of the Participant against the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of the covenants and agreements that are set forth in this Agreement.

14. Entire Agreement. This Agreement together with the Plan (as each may be amended from time to time) supersede any and all other prior understandings and agreements, either oral or in writing, between the parties with respect to the subject matter hereof and constitute the sole and only agreements between the parties with respect to the said subject matter. All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement and the Plan. Each party to this Agreement acknowledges that no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement or the Plan and that any agreement, statement or promise that is not contained in this Agreement or the Plan shall not be valid or binding or of any force or effect.

15. Parties Bound. The terms, provisions, and agreements that are contained in this Agreement shall apply to, be binding upon, and inure to the benefit of the parties and their respective heirs, executors, administrators, legal representatives, and permitted successors and assigns, subject to the limitation on assignment expressly set forth herein. No person shall be permitted to acquire any Awarded Units without first executing and delivering an agreement in a form satisfactory to the Company making such person subject to the restrictions on transfer contained herein.

16. Modification. The Committee may amend this Agreement at any time and from time to time without the consent of the Participant; provided, however that no such amendment may materially and adversely affect the rights of the Participant without his or her consent; and provided, further, that the Company may change or modify this Agreement without the Participant’s consent or signature if the Company determines, in its sole discretion, that such change or modification is necessary for purposes of compliance with or exemption from the requirements of Code Section 409A or any regulations or other guidance issued thereunder. To the extent that any provision hereof is modified in order to comply with Code Section 409A, such modification shall be made in good faith and shall, to the maximum extent reasonably possible, maintain the original intent and economic benefit to the Participant and the Company of the applicable provision without violating the provisions of Code Section 409A, and in no event may any such amendment modify the time or form of payment of any amount payable pursuant to this Agreement if such modification would be in violation of Code Section 409A. Notwithstanding the provisions of this Section 16, the Company may amend the Plan to the extent permitted by the Plan.

17. Headings. The headings that are used in this Agreement are used for reference and convenience purposes only and do not constitute substantive matters to be considered in construing the terms and provisions of this Agreement.

18. Gender and Number. Words of any gender used in this Agreement shall be held and construed to include any other gender, and words in the singular number shall be held to include the plural, and vice versa, unless the context requires otherwise.

19. Notice. Any notice required or permitted to be delivered hereunder shall be deemed to be delivered only when actually received by the Company or by the Participant, as the case may be, at the addresses set forth below, or at such other addresses as they have theretofore specified by written notice delivered in accordance herewith:

a. Notice to the Company shall be addressed and delivered as follows:

Matador Resources Company

5400 LBJ Fwy, Suite 1500

Dallas, TX 75240

Attn: General Counsel

Facsimile: (972) 371-5201

b. Notice to the Participant shall be addressed and delivered to the Participant’s address as set forth in the Company’s records.

20. Tax Requirements. The Participant is hereby advised to consult immediately with his or her own tax advisor regarding the tax consequences of this Agreement. The Company or, if applicable, any Subsidiary (for purposes of this Section 20, the term “Company” shall be deemed to include any applicable Subsidiary), shall have the right to deduct from all amounts paid or payable to the Participant in cash or other form in connection with the Plan, any Federal, state, local, or other taxes permitted by law to be withheld in connection with this Award. Such payments shall be required to be made when requested by Company and may be required to be made prior to the delivery of the payment discussed in Section 3 above. Such payments may be made, in the sole discretion of the Company, (i) by the delivery of cash to the Company in an amount that equals the applicable tax withholding obligations of the Company; (ii) the actual delivery by the Participant to the Company of shares of Common Stock that the Participant has not acquired from the Company within six (6) months prior thereto, which shares so delivered have an aggregate Fair Market Value that equals or exceeds the applicable tax withholding payment; (iii) the Company’s withholding an amount upon the vesting of the Awarded Units with aggregate Fair Market Value that equals the applicable tax withholding payment; or (iv) any combination of the foregoing or any other method consented to by the Company in writing. The Company may, in its sole discretion, withhold any such taxes from any other cash remuneration otherwise paid by the Company to the Participant.

21. Code Section 409A. This Agreement is intended to be interpreted and applied so that the payments and benefits set forth herein shall comply with or be exempt from the requirements of Code Section 409A, and, accordingly, to the maximum extent permitted, this Agreement shall be interpreted to the fullest extent possible to reflect and implement such intent. Notwithstanding anything in this Agreement and in the event the payments and benefits set forth herein are subject to Code Section 409A, a Termination of Service shall not be deemed to have occurred for purposes of any provision of this Agreement unless such termination is also a “separation from service” within the meaning of Code Section 409A. Notwithstanding any provision in this Agreement to the contrary, if on his or her Termination of Service, the Participant is deemed to be a “specified employee” within the meaning of Code Section 409A, any payments or benefits due upon such Termination of Service that constitutes a “deferral of compensation” within the meaning of Code Section 409A and which do not otherwise qualify under the exemptions under Treas. Reg. § 1.409A-1 (including without limitation, the short-term deferral exemption and the permitted payments under Treas. Reg. § 1.409A-1(b)(9)(iii)(A)), shall be delayed and

paid or provided to the Participant on the earlier of the date which immediately follows six (6) months after the Participant’s separation from service or, if earlier, the date of the Participant’s death.

22. Electronic Delivery. By executing this Agreement (including via digital acceptance), the Participant hereby consents to the delivery of information (including, without limitation, information required to be delivered to the Participant pursuant to applicable securities laws) regarding the Company and its Subsidiaries, the Plan, and the Awarded Units via Company web site or other electronic delivery.

* * * * * * * * * *

[Remainder of Page Intentionally Left Blank.

Signature Page Follows]

IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant, to evidence his or her consent and approval of all the terms hereof, has duly executed this Agreement, as of the Date of Grant specified in Section 1 hereof.


COMPANY:

MATADOR RESOURCES COMPANY

By:
Name:						David E. Lancaster
Title:						Executive Vice President

PARTICIPANT:


Signature

Name:						[●]

Document

Exhibit 10.4

PERFORMANCE STOCK UNIT AWARD AGREEMENT

MATADOR RESOURCES COMPANY

2019 LONG-TERM INCENTIVE PLAN

1. Award of Performance Stock Units. Pursuant to the Matador Resources Company 2019 Long-Term Incentive Plan (as the same may be amended, the “Plan”), Matador Resources Company, a Texas corporation (the “Company”), grants to

[●]

(the “Participant”),

an Award of Performance Stock Units (the “Performance Stock Units”) subject to the terms and conditions of this Performance Stock Unit Award Agreement (including Appendix A attached hereto, this “Agreement”) and the Plan. The target number of Performance Stock Units awarded under this Agreement is [●] (the “Target Units”). The “Date of Grant” of this Award is [●]. Each Performance Stock Unit subject to this Award shall represent a notional share of Common Stock, with the value of each Performance Stock Unit being equal to the Fair Market Value of a share of Common Stock at any given time.

3. Vesting; Settlement of Performance Stock Units.

a. Subject to the Participant’s continuous employment with or service to the Company or a Subsidiary through the end of the Performance Period (as defined in Appendix A), the actual number of shares of Common Stock that may become issuable pursuant to the Performance Stock Units shall be determined in accordance with the performance-based vesting requirements set forth in Appendix A attached hereto and this Section 3. Performance Stock Units that become vested pursuant to the terms of Appendix A or this Section 3 are collectively referred to herein as “Vested Units.” All other Performance Stock Units are collectively referred to herein as “Unvested Units.”

b. The Vested Units, as determined pursuant to Appendix A, shall vest on the Vesting Date (as defined in Appendix A). Subject to the provisions of the Plan and this Agreement, within thirty (30) days following the Vesting Date, and in no event later than two and a half (2½) months following the close of the calendar year in which the Performance Period (as defined in Appendix A) ends, the Company shall deliver to the Participant or the Participant’s personal representative a number of shares of Common Stock equal to the number of Vested Units credited to the Participant. Vested Units may be converted only with respect to full shares, and no fractional share of Common Stock shall be issued. Notwithstanding anything herein to the contrary, if the Participant incurs a Termination of Service for any reason after the last day of the Performance Period, but prior to the Vesting Date, the Participant shall not forfeit the Performance Stock Units by reason of such Termination of Service to the extent such Performance Stock Units would have otherwise vested in accordance with this Section 3.

c. Notwithstanding the foregoing, if within thirty (30) days prior to a Change in Control (as defined in the Employment Agreement), the Participant incurs a Termination of Service by the Company without Just Cause (as defined in the Employment Agreement) or by the Participant with [or without] Good Reason (as defined in the Employment Agreement), then effective immediately prior to such Termination of Service, Participant shall vest in a number of shares of Common Stock equal to the number of Performance Stock Units that would have otherwise vested based on the Company’s performance, as determined by the Committee, through an abbreviated Performance Period that ends as of immediately prior to the effective date of such Termination of Service.

d. In the event a Change in Control occurs prior to the completion of the Performance Period and Participant has not experienced a Termination of Service prior to the effective date of the Change in Control, Participant shall vest immediately prior to the consummation of such Change in Control in a number of shares of Common Stock equal to the number of Performance Stock Units that would have otherwise vested based on the Company’s performance, as determined by the Committee, through an abbreviated Performance Period that ends as of immediately prior to the effective date of the Change in Control.

4. Forfeiture of Performance Stock Units. Unvested Units shall be forfeited, without the payment of any consideration therefor, immediately upon the earlier of (i) the Vesting Date, to the extent the performance-based vesting conditions have not been satisfied and the Performance Stock Units have not vested in accordance with Section 3, and (ii) subject to Section 3, the Participant’s Termination of Service. Upon forfeiture, all of the Participant’s rights with respect to the forfeited Unvested Units shall cease and terminate, without any further obligations on the part of the Company.

5. Restrictions on Performance Stock Units. Subject to the provisions of the Plan and the terms of this Agreement, the Participant shall not be permitted to sell, transfer, pledge, hypothecate, margin, assign or otherwise encumber any of the Performance Stock Units, except that, the Participant may transfer for no consideration some or all of the Performance Stock Units to (a) one or more members of the Participant’s Immediate Family, (b) a trust in which the Participant or members of his or her Immediate Family have more than fifty percent of the beneficial interest, (c) a foundation in which the Participant or members of his or her Immediate Family control the management of assets or (d) any other entity in which the Participant or members of his or her Immediate Family own more than fifty percent of the voting interests. Any such transferee must agree in writing on a form prescribed by the Company to be bound by all of the provisions of this Agreement to the same extent as they apply to the Participant. Notwithstanding any such transfer, any vesting conditioned upon the Participant’s continued employment or service with the Company or its Subsidiaries shall continue to relate to the Participant’s continued employment or service and any covenants applicable to Participant hereunder shall continue to apply to Participant. In addition, the Committee may in its sole discretion, remove any or all of the restrictions on such Performance Stock Units whenever it may determine that, by reason of changes in applicable laws or changes in circumstances after the date of this Agreement, such action is appropriate.

6. Rights of a Shareholder. The Participant will have no rights as a shareholder with respect to any Performance Stock Units covered by this Agreement (including, without limitation, any voting rights or the right to receive any dividends) until the issuance of a certificate or certificates to the Participant or the registration of such shares in the Participant’s name for shares of Common Stock. Except as otherwise provided in Section 7 hereof, no adjustment shall be made for dividends or other rights for which the record date is prior to the issuance of such shares of Common Stock. The Participant, by his or her execution of this Agreement, agrees to execute any documents requested by the Company in connection with the issuance of such shares of Common Stock.

7. Adjustment to Number of Performance Stock Units. The number of Target Units shall be subject to adjustment in accordance with Articles 11-13 of the Plan.

8. Participant’s Representations. Notwithstanding any of the provisions hereof, the Participant hereby agrees that he or she will not acquire any shares of Common Stock, and that the Company will not be obligated to issue any shares of Common Stock to the Participant hereunder if the issuance of such shares would constitute a violation by the Participant or the Company of any provision of any law or regulation of any governmental authority or any national securities exchange or inter-dealer quotation system or other forum in which shares of Common Stock are quoted or traded. Any determination in this connection by the Company shall be final, binding, and conclusive. The rights and obligations of the Company and the rights and obligations of the Participant are subject to all Applicable Laws, rules, and regulations.

11. No Right to Continue Service or Employment. Nothing herein shall be construed to confer upon the Participant the right to continue in the employ or to provide services to the Company or any Subsidiary, whether as an Employee or as a Contractor or as an Outside Director, or interfere with or restrict in any way the right of the Company or any Subsidiary to discharge the Participant as an Employee, Contractor, or Outside Director at any time.

15. Parties Bound. The terms, provisions, and agreements that are contained in this Agreement shall apply to, be binding upon, and inure to the benefit of the parties and their respective

heirs, executors, administrators, legal representatives, and permitted successors and assigns, subject to the limitation on assignment expressly set forth herein. No person shall be permitted to acquire any Performance Stock Units without first executing and delivering an agreement in a form satisfactory to the Company making such person subject to the restrictions on transfer contained herein.

a. Notice to the Company shall be addressed and delivered as follows:

Matador Resources Company

5400 LBJ Fwy, Suite 1500

Dallas, TX 75240

Attn: General Counsel

Facsimile: (972) 371-5201

b. Notice to the Participant shall be addressed and delivered to the Participant’s address as set forth in the Company’s records.

may be required to be made prior to the delivery of any certificate representing shares of Common Stock. Such payments may be made, in the sole discretion of the Company, (i) by the delivery of cash to the Company in an amount that equals or exceeds (to avoid the issuance of fractional shares under (iii) below) the applicable tax withholding obligations of the Company; (ii) the actual delivery by the Participant to the Company of shares of Common Stock that the Participant has not acquired from the Company within six (6) months prior thereto, which shares so delivered have an aggregate Fair Market Value that equals or exceeds (to avoid the issuance of fractional shares under (iii) below) the applicable tax withholding payment; (iii) the Company’s withholding of a number of shares to be delivered upon the vesting of this Award, which shares so withheld have an aggregate Fair Market Value that equals or exceeds (solely to avoid the issuance of fractional shares) the applicable tax withholding payment; or (iv) any combination of (i), (ii) or (iii) or any other method consented to by the Company in writing. The Company may, in its sole discretion, withhold any such taxes from any other cash remuneration otherwise paid by the Company to the Participant.

22. Electronic Delivery. By executing this Agreement (including via digital acceptance), the Participant hereby consents to the delivery of information (including, without limitation, information required to be delivered to the Participant pursuant to applicable securities laws) regarding the Company and its Subsidiaries, the Plan, and the Performance Stock Units via Company web site or other electronic delivery.

* * * * * * * * * *

[Remainder of Page Intentionally Left Blank.

Signature Page Follows]


COMPANY:

MATADOR RESOURCES COMPANY

By:
Name:						David E. Lancaster
Title:						Executive Vice President

PARTICIPANT:


Signature

Name:						[●]

APPENDIX A

PERFORMANCE GOALS AND PERFORMANCE PERIOD

A.PERFORMANCE PERIOD

[●]

B.PERFORMANCE GOAL

[●]

Document

Exhibit 31.1

CERTIFICATION

I, Joseph Wm. Foran, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Matador Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


July 30, 2021			/s/ Joseph Wm. Foran
			Joseph Wm. Foran
			Chairman and Chief Executive Officer (Principal Executive Officer)

Document

Exhibit 31.2

CERTIFICATION

I, David E. Lancaster, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Matador Resources Company;

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


July 30, 2021			/s/ David E. Lancaster
			David E. Lancaster Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Document

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Matador Resources Company (the “Company”) on Form 10-Q for the period ended June 30, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Joseph Wm. Foran, hereby certify in my capacity as Chairman and Chief Executive Officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.


July 30, 2021			/s/ Joseph Wm. Foran
			Joseph Wm. Foran
			Chairman and Chief Executive Officer (Principal Executive Officer)

Document

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Matador Resources Company (the “Company”) on Form 10-Q for the period ended June 30, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, David E. Lancaster, hereby certify in my capacity as Executive Vice President and Chief Financial Officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.


July 30, 2021			/s/ David E. Lancaster
			David E. Lancaster
			Executive Vice President and Chief Financial Officer (Principal Financial Officer)