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, 2020

OR

☐ 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 28, 2020, there were 116,840,409 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2020

TABLE OF CONTENTS

	Page
PART I — FINANCIAL INFORMATION	4
Item 1. Financial Statements — Unaudited	4
Condensed Consolidated Balance Sheets at June 30, 2020 and December 31, 2019	4
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2020 and 2019	5
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three and Six Months Ended June 30, 2020 and 2019	6
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2020 and 2019	8
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Item 4. Controls and Procedures	45
PART II — OTHER INFORMATION	46
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6. Exhibits	47
SIGNATURES	48

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, 2020		December 31, 2019
ASSETS
Current assets
Cash	$	20,573	$	40,024
Restricted cash	22,935		25,104
Accounts receivable
Oil and natural gas revenues	57,854		95,228
Joint interest billings	64,037		67,546
Other	21,623		26,639
Derivative instruments	13,304		—
Lease and well equipment inventory	11,940		10,744
Prepaid expenses and other current assets	15,017		13,207
Total current assets	227,283		278,492
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	5,041,026		4,557,265
Unproved and unevaluated	983,391		1,126,992
Midstream properties	773,314		643,903
Other property and equipment	28,233		27,021
Less accumulated depletion, depreciation and amortization	(3,163,037)		(2,655,586)
Net property and equipment	3,662,927		3,699,595
Other assets
Derivative instruments	6,634		—
Deferred income taxes	35,694		—
Other long-term assets	68,595		91,589
Total assets	$	4,001,133	$	4,069,676
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	15,747	$	25,230
Accrued liabilities	189,115		200,695
Royalties payable	60,995		85,193
Amounts due to affiliates	862		19,606
Derivative instruments	14,073		1,897
Advances from joint interest owners	19,931		14,837
Amounts due to joint ventures	—		486
Other current liabilities	44,046		51,828
Total current liabilities	344,769		399,772
Long-term liabilities
Borrowings under Credit Agreement	385,000		255,000
Borrowings under San Mateo Credit Facility	320,000		288,000
Senior unsecured notes payable	1,040,207		1,039,416
Asset retirement obligations	37,997		35,592
Derivative instruments	5,984		1,984
Deferred income taxes	11,090		37,329
Other long-term liabilities	37,585		43,131
Total long-term liabilities	1,837,863		1,700,452
Commitments and contingencies (Note 9)
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 shares authorized; 116,983,790 and 116,644,246 shares issued; and 116,843,587 and 116,642,899 shares outstanding, respectively	1,170		1,166
Additional paid-in capital	2,020,298		1,981,014
Accumulated deficit	(376,187)		(148,500)
Treasury stock, at cost, 140,203 and 1,347 shares, respectively	(1,449)		(26)
Total Matador Resources Company shareholders’ equity	1,643,832		1,833,654
Non-controlling interest in subsidiaries	174,669		135,798
Total shareholders’ equity	1,818,501		1,969,452
Total liabilities and shareholders’ equity	$	4,001,133	$	4,069,676

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

3

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,
	2020		2019		2020		2019
Revenues
Oil and natural gas revenues	$	118,767	$	211,060	$	316,681	$	404,329
Third-party midstream services revenues	14,668		14,359		30,498		26,197
Sales of purchased natural gas	13,981		8,963		24,525		20,194
Lease bonus - mineral acreage	4,062		—		4,062		—
Realized gain on derivatives	44,110		1,165		54,977		4,435
Unrealized (loss) gain on derivatives	(132,668)		6,157		3,762		(39,562)
Total revenues	62,920		241,704		434,505		415,593
Expenses
Production taxes, transportation and processing	18,797		21,542		40,513		41,207
Lease operating	26,162		26,351		57,072		57,514
Plant and other midstream services operating	9,780		8,422		19,744		17,738
Purchased natural gas	10,922		8,172		18,980		18,806
Depletion, depreciation and amortization	93,350		80,132		184,057		156,999
Accretion of asset retirement obligations	495		420		971		834
Full-cost ceiling impairment	324,001		—		324,001		—
General and administrative	14,723		19,876		30,945		38,166
Total expenses	498,230		164,915		676,283		331,264
Operating (loss) income	(435,310)		76,789		(241,778)		84,329
Other income (expense)
Net loss on asset sales and impairment	(2,632)		(368)		(2,632)		(368)
Interest expense	(18,297)		(18,068)		(38,109)		(35,997)
Other income (expense)	473		(423)		1,793		(532)
Total other expense	(20,456)		(18,859)		(38,948)		(36,897)
(Loss) income before income taxes	(455,766)		57,930		(280,726)		47,432
Income tax (benefit) provision
Deferred	(109,823)		12,858		(69,866)		11,845
Total income tax (benefit) provision	(109,823)		12,858		(69,866)		11,845
Net (loss) income	(345,943)		45,072		(210,860)		35,587
Net income attributable to non-controlling interest in subsidiaries	(7,473)		(8,320)		(16,827)		(15,782)
Net (loss) income attributable to Matador Resources Company shareholders	$	(353,416)	$	36,752	$	(227,687)	$	19,805
(Loss) earnings per common share
Basic	$	(3.04)	$	0.32	$	(1.96)	$	0.17
Diluted	$	(3.04)	$	0.31	$	(1.96)	$	0.17
Weighted average common shares outstanding
Basic	116,071		116,571		115,977		116,469
Diluted	116,071		116,903		115,977		116,839

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

4

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 I, net of tax of $3.1 million (see Note 6)	—	—		11,613		—		—	—		11,613		—		11,613
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $4.3 million (see Note 6)	—	—		16,280		—		—	—		16,280		29,394		45,674
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—		—		—	—		—		(11,515)		(11,515)
Current period net income	—	—		—		125,729		—	—		125,729		9,354		135,083
Balance at March 31, 2020	116,671	1,167		2,014,246		(22,771)		107	(1,293)		1,991,349		163,031		2,154,380
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.

5

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(In thousands)

For the Three and Six Months Ended June 30, 2019

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

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

6

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS — UNAUDITED

(In thousands)

	Six Months Ended June 30,
	2020		2019
Operating activities
Net (loss) income	$	(210,860)	$	35,587
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Unrealized (gain) loss on derivatives	(3,762)		39,562
Depletion, depreciation and amortization	184,057		156,999
Accretion of asset retirement obligations	971		834
Full-cost ceiling impairment	324,001		—
Stock-based compensation expense	7,080		9,076
Deferred income tax (benefit) provision	(69,866)		11,845
Amortization of debt issuance cost	1,399		1,189
Net loss on asset sales and impairment	2,632		368
Changes in operating assets and liabilities
Accounts receivable	46,628		(378)
Lease and well equipment inventory	(868)		(3,456)
Prepaid expenses and other current assets	(1,610)		(4,834)
Other long-term assets	1,806		(415)
Accounts payable, accrued liabilities and other current liabilities	(52,351)		(48,746)
Royalties payable	(24,198)		1,353
Advances from joint interest owners	5,094		(6,243)
Other long-term liabilities	232		1,756
Net cash provided by operating activities	210,385		194,497
Investing activities
Oil and natural gas properties capital expenditures	(335,098)		(349,915)
Midstream capital expenditures	(123,338)		(64,106)
Expenditures for other property and equipment	(1,381)		(2,206)
Proceeds from sale of assets	1,056		21,533
Net cash used in investing activities	(458,761)		(394,694)
Financing activities
Borrowings under Credit Agreement	130,000		165,000
Borrowings under San Mateo Credit Facility	32,000		20,000
Cost to amend Credit Agreement	(660)		(415)
Proceeds from stock options exercised	45		3,298
Contributions related to formation of San Mateo I	14,700		14,700
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	67,172		19,831
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(22,050)		(17,640)
Taxes paid related to net share settlement of stock-based compensation	(1,493)		(3,309)
Other	7,042		(490)
Net cash provided by financing activities	226,756		200,975
(Decrease) increase in cash and restricted cash	(21,620)		778
Cash and restricted cash at beginning of period	65,128		83,984
Cash and restricted cash at end of period	$	43,508	$	84,762
Supplemental disclosures of cash flow information (Note 10)

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

7

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 ventures, San Mateo Midstream, LLC (“San Mateo I”) and San Mateo Midstream II, LLC (“San Mateo II” and, together with San Mateo I, “San Mateo”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

The interim unaudited condensed consolidated financial statements of the Company have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on March 2, 2020 (the “Annual Report”). The Company consolidates certain subsidiaries and joint ventures that are less than wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810). The Company proportionately consolidates certain joint ventures that are less than wholly-owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all normal, recurring adjustments that are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of June 30, 2020. Amounts as of December 31, 2019 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.

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, 2020 and 2019 (in thousands).

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Revenues from contracts with customers	$	147,416	$	234,382	$	371,704	$	450,720
Lease bonus - mineral acreage	4,062		—		4,062		—
Realized gain on derivatives	44,110		1,165		54,977		4,435
Unrealized (loss) gain on derivatives	(132,668)		6,157		3,762		(39,562)
Total revenues	$	62,920	$	241,704	$	434,505	$	415,593

8

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Oil revenues	$	94,174	$	189,085	$	263,759	$	343,288
Natural gas revenues	24,593		21,975		52,922		61,041
Third-party midstream services revenues	14,668		14,359		30,498		26,197
Sales of purchased natural gas	13,981		8,963		24,525		20,194
Total revenues from contracts with customers	$	147,416	$	234,382	$	371,704	$	450,720

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated into a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and certain general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized approximately $8.1 million and $8.4 million of its general and administrative costs and approximately $1.8 million and $2.6 million of its interest expense for the three months ended June 30, 2020 and 2019, respectively. The Company capitalized approximately $16.3 million and $16.8 million of its general and administrative costs and approximately $3.2 million and $4.2 million of its interest expense for the six months ended June 30, 2020 and 2019, respectively.

The net capitalized costs of oil and natural gas properties are limited to the lower of amortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a)the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b)unproved and unevaluated property costs not being amortized, plus

(c)the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d)income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The need for a full-cost ceiling impairment is required to be assessed on a quarterly basis. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The Company’s oil and natural gas reserves estimates are prepared by the Company’s engineering staff in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual agreements. Future net revenues are calculated using prices that represent the arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period, and the guidelines further dictate that a 10% discount factor be used to determine the present value of future revenues. For the period from July 2019 to June 2020, the average oil and natural gas prices were $43.60 per barrel and $2.07 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil and natural gas prices were adjusted by property for quality, energy content, transportation and marketing fees and regional price differentials.

9

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Using average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves 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 unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2020. For the three and six months ended June 30, 2019, the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded no impairment to its net capitalized costs for the three and six months ended June 30, 2019.

Earnings (Loss) Per Common Share

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

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
Weighted average common shares outstanding
Basic	116,071	116,571	115,977	116,469
Dilutive effect of options and restricted stock units	—	332	—	370
Diluted weighted average common shares outstanding	116,071	116,903	115,977	116,839

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

10

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

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, 2020 (in thousands).

Beginning asset retirement obligations	$	36,211
Liabilities incurred during period	1,463
Liabilities settled during period	(109)
Accretion expense	971
Ending asset retirement obligations	38,536
Less: current asset retirement obligations(1)	(539)
Long-term asset retirement obligations	$	37,997

 _______________

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

NOTE 4 — DEBT

At June 30, 2020, the Company had $1.05 billion of outstanding senior notes due 2026 (the “Notes”), $385.0 million in borrowings outstanding under its reserves-based revolving credit facility (the “Credit Agreement”), approximately $45.1 million in outstanding letters of credit issued pursuant to the Credit Agreement and $7.5 million outstanding under an unsecured U.S. Small Business Administration (“SBA”) loan.

At July 28, 2020, the Company had $1.05 billion of outstanding Notes, $404.0 million in borrowings outstanding under the Credit Agreement, approximately $45.1 million in outstanding letters of credit issued pursuant to the Credit Agreement and $7.5 million outstanding under an unsecured SBA loan.

At June 30, 2020 and July 28, 2020, San Mateo I had $320.0 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.

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 February 2020, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2019, and, as a result, the borrowing base was affirmed at $900.0 million. The Company elected to increase the borrowing commitment from $500.0 million to $700.0 million, and the maximum facility amount remained $1.5 billion. This February 2020 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected 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 4.00 or less. The Company believes that it was in compliance with the terms of the Credit Agreement at June 30, 2020.

San Mateo Midstream, LLC

The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries, but is guaranteed by San Mateo I’s subsidiaries and secured by substantially all of San Mateo I’s assets, including real property. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases to up to $400.0 million, and matures December 19, 2023. At June 30, 2020, the lender commitments under the San Mateo Credit Facility were $375.0 million (subject to San Mateo I’s compliance with the covenants noted below).

The San Mateo Credit Facility requires San Mateo I to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter

11

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 4 — DEBT — Continued

EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo I to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo I’s consolidated interest expense, of 2.50 or more. The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at June 30, 2020.

Senior Unsecured Notes

At June 30, 2020, the Company had $1.05 billion of outstanding Notes, which have a 5.875% coupon rate. The Notes will mature September 15, 2026, and interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company.

NOTE 5 — INCOME TAXES

The Company’s effective tax rates for the three and six months ended June 30, 2020 were 24% and 23%, respectively. The Company’s effective tax rates for the three and six months ended June 30, 2019 were 26% and 37%, respectively. The Company’s total income tax provision for the three and six months ended June 30, 2020 and 2019 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of permanent differences between book and tax income, as well as state taxes, primarily in New Mexico.

NOTE 6 — EQUITY

Stock-based Compensation

During the six months ended June 30, 2020, the Company granted awards to certain of its employees of 868,710 service-based restricted stock units to be settled in cash, which are liability instruments, and 641,210 performance-based stock units and 227,500 shares of restricted stock, which are equity instruments. The performance-based stock units vest in an amount between zero and 200% of the target units granted based on the Company’s relative total shareholder return over the three-year period ending December 31, 2022, as compared to a designated peer group. The service-based restricted stock units to be settled in cash vest ratably over three years, and the equity instruments are eligible to vest after three years. The fair value of these awards was approximately $7.7 million on the grant date.

San Mateo II

On February 25, 2019, the Company announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) designed to expand the Company’s midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by the Company and 49% by Five Point. In addition, Five Point committed to pay $125 million of the first $150 million of capital expenditures incurred by San Mateo II to develop facilities in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and the Stateline asset area. As of June 30, 2020, the $150 million threshold for capital expenditures had been reached, and future capital expenditures are the responsibility of Matador and Five Point based on each company’s proportionate interest in San Mateo II. During the three months ended June 30, 2020, the Company contributed $15.4 million and Five Point contributed $17.2 million of cash, of which $2.5 million was paid to carry Matador’s proportionate interest in San Mateo II. During the six months ended June 30, 2020, the Company contributed $22.9 million and Five Point contributed $67.2 million of cash, of which $23.1 million was paid to carry Matador’s proportionate interest in San Mateo II. 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. During the three and six months ended June 30, 2019, the Company contributed $1.5 million and $1.5 million of cash and Five Point contributed $7.5 million and $11.5 million of cash, respectively, in addition to the $1.0 million of property the Company contributed during the first quarter of 2019 related to the formation of San Mateo II. The Company also has the ability to earn up to $150.0 million in deferred performance incentives over the next several years, plus additional performance incentives for securing volumes from third-party customers.

12

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 6 — EQUITY — Continued

Performance Incentives

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

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS

At June 30, 2020, 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, 2020, each contract was set to expire at varying times during 2020, 2021 and 2022. The Company had no open contracts associated with natural gas liquids (“NGL”) prices at June 30, 2020.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at June 30, 2020.

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	07/01/2020 - 12/31/2020	1,758,000	$	48.03	$	66.05	$	16,271
Oil	01/01/2021 - 12/31/2021	2,400,000	$	35.00	$	45.71	179
Natural Gas	11/01/2020 - 12/31/2020	5,200,000	$	2.51	$	3.82	1,354
Natural Gas	01/01/2021 - 03/31/2021	7,800,000	$	2.51	$	3.82	545
Total open costless collar contracts							$	18,349

The following is a summary of the Company’s open swap contracts for oil at June 30, 2020.

Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil	07/01/2020 - 12/31/2020	4,320,000	$	35.00	$	(19,652)
Oil	01/01/2021 - 12/31/2021	2,040,000	$	35.26	(10,526)
Total open swap contracts					$	(30,178)

The following is a summary of the Company’s open basis swap contracts for oil at June 30, 2020.

Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil Basis	07/01/2020 - 12/31/2020	4,896,000	$	0.61	$	2,318
Oil Basis	01/01/2021 - 12/31/2021	8,400,000	$	0.87	5,414
Oil Basis	01/01/2022 - 12/31/2022	5,520,000	$	0.95	3,978
Total open basis swap contracts					$	11,710

At June 30, 2020, the Company had an aggregate liability value for open derivative financial instruments of $0.1 million.

13

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

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

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of June 30, 2020 and December 31, 2019 (in thousands).

Derivative Instruments	Gross amounts recognized		Gross amounts netted in the condensed consolidated balance sheets		Net amounts presented in the condensed consolidated balance sheets
June 30, 2020
Current assets	$	331,474	$	(318,170)	$	13,304
Other assets	298,934		(292,300)		6,634
Current liabilities	(332,243)		318,170		(14,073)
Long-term liabilities	(298,284)		292,300		(5,984)
Total	$	(119)	$	—	$	(119)
December 31, 2019
Current assets	$	442,291	$	(442,291)	$	—
Other assets	280,397		(280,397)		—
Current liabilities	(444,188)		442,291		(1,897)
Long-term liabilities	(282,381)		280,397		(1,984)
Total	$	(3,881)	$	—	$	(3,881)

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	2020		2019		2020		2019
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	44,110	$	1,165	$	54,977	$	4,531
Natural Gas	Revenues: Realized loss on derivatives	—		—		—		(96)
Realized gain on derivatives		44,110		1,165		54,977		4,435
Oil	Revenues: Unrealized (loss) gain on derivatives	(134,567)		5,365		1,863		(40,078)
Natural Gas	Revenues: Unrealized gain on derivatives	1,899		792		1,899		516
Unrealized (loss) gain on derivatives		(132,668)		6,157		3,762		(39,562)
Total		$	(88,558)	$	7,322	$	58,739	$	(35,127)

14

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

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, 2020 and December 31, 2019 (in thousands).

	Fair Value Measurements at June 30, 2020 using
Description	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	(2,018)	$	—	$	(2,018)
Natural gas derivatives	—		1,899		—		1,899
Total	$	—	$	(119)	$	—	$	(119)

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

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

Other Fair Value Measurements

At June 30, 2020 and December 31, 2019, 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, amounts due to joint ventures and other current liabilities approximated their fair values due to their short-term maturities.

At June 30, 2020 and December 31, 2019, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy.

15

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 8 — FAIR VALUE MEASUREMENTS — Continued

At June 30, 2020 and December 31, 2019, the fair value of the Notes was $781.6 million and $1.06 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 Salt Water Disposal Commitments

Firm Commitments

From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and salt water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and, in the case of salt water, disposal. The Company paid approximately $11.4 million and $6.1 million for deliveries under these agreements during the three months ended June 30, 2020 and 2019, respectively, and $22.4 million and $12.9 million for deliveries under these agreements during the six months ended June 30, 2020 and 2019, 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, 2020, the total deficiencies required to be paid by the Company under these agreements would be approximately $387.9 million, in addition to the commitments described below.

Future Commitments

In late 2017, the Company entered into a fixed-fee NGL sales agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) to a certain counterparty. The Company is committed to deliver a minimum amount of NGLs to the counterparty for seven years following the completion of the counterparty’s pipeline extension and fractionation facility, which was completed on July 1, 2020. If the Company does not meet its NGL volume commitment in any quarter during the seven-year commitment period, it would be required to pay a deficiency fee per gallon of NGL below the Company’s commitment. The minimum contractual obligation during the seven-year period is approximately $130.6 million.

In October 2019, the Company entered into a 15-year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The agreement begins when the counterparty’s pipeline is placed in service, which is anticipated to be in the second half of 2020. 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 $106.9 million.

Delaware Basin — San Mateo

In February 2017, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements with subsidiaries of San Mateo I. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). San Mateo I provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at June 30, 2020 was approximately $150.7 million.

In connection with the February 2019 formation of San Mateo II, the Company dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal (collectively, the “San Mateo II Operational Agreements”). San Mateo II will provide the Company with firm service under each of the San Mateo II Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the San Mateo II Operational Agreements at June 30, 2020 was approximately $360.2 million.

In June 2019, a subsidiary of San Mateo II entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed in service in 2020. San Mateo II’s total commitments under this agreement are $81.0 million. San Mateo II paid approximately $12.6 million and $33.7 million under this agreement during the three and six months ended June 30, 2020, respectively. As of June 30, 2020, the remaining obligations of San Mateo II under this agreement were $7.2 million, which are expected to be paid within the next 12 months.

16

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 9 — COMMITMENTS AND CONTINGENCIES — Continued

Legal Proceedings

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

NOTE 10 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

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

	June 30, 2020		December 31, 2019
Accrued evaluated and unproved and unevaluated property costs	$	77,015	$	72,376
Accrued midstream properties costs	55,457		46,402
Accrued lease operating expenses	22,026		18,223
Accrued interest on debt	18,282		18,569
Accrued asset retirement obligations	539		619
Accrued partners’ share of joint interest charges	4,541		14,322
Accrued payable related to purchased natural gas	2,318		17,806
Other	8,937		12,378
Total accrued liabilities	$	189,115	$	200,695

Supplemental Cash Flow Information

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

	Six Months Ended June 30,
	2020		2019
Cash paid for interest expense, net of amounts capitalized	$	38,387	$	37,632
Increase in asset retirement obligations related to mineral properties	$	1,393	$	321
Increase in asset retirement obligations related to midstream properties	$	26	$	283
Increase in liabilities for oil and natural gas properties capital expenditures	$	4,469	$	13,536
Increase in liabilities for midstream properties capital expenditures	$	9,203	$	5,854
Stock-based compensation expense recognized as liability	$	1,188	$	1,010
Transfer of inventory (to) from oil and natural gas properties	$	(335)	$	370

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,
	2020		2019
Cash	$	20,573	$	59,950
Restricted cash	22,935		24,812
Total cash and restricted cash	$	43,508	$	84,762

17

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

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 salt water gathering services and salt water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and Stateline asset areas and the Greater Stebbins Area in the Delaware Basin are conducted through San Mateo.

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

	Exploration and Production						Consolidations and Eliminations		Consolidated Company
			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.

18

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

_____________________

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

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

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

	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 income (loss)(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.

19

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

_____________________

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

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

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

NOTE 12 — SUBSIDIARY GUARANTORS

The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At June 30, 2020, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes.

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

Condensed Consolidating Balance Sheet June 30, 2020
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries		Consolidated
ASSETS
Intercompany receivable	$	1,600,300	$	15,508	$	—	$	(1,615,808)	$	—
Current assets	6,917		34,186		186,180		—		227,283
Net property and equipment	—		707,472		2,955,455		—		3,662,927
Investment in subsidiaries	1,070,647		—		185,216		(1,255,863)		—
Long-term assets	35,694		2,626		83,628		(11,025)		110,923
Total assets	$	2,713,558	$	759,792	$	3,410,479	$	(2,882,696)	$	4,001,133
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	1,615,808	$	(1,615,808)	$	—
Current liabilities	18,429		66,591		260,682		(933)		344,769
Senior unsecured notes payable	1,040,207		—		—		—		1,040,207
Other long-term liabilities	11,090		333,316		463,342		(10,092)		797,656
Total equity attributable to Matador Resources Company	1,643,832		185,216		1,070,647		(1,255,863)		1,643,832
Non-controlling interest in subsidiaries	—		174,669		—		—		174,669
Total liabilities and equity	$	2,713,558	$	759,792	$	3,410,479	$	(2,882,696)	$	4,001,133

Condensed Consolidating Balance Sheet December 31, 2019
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries		Consolidated
ASSETS
Intercompany receivable	$	1,578,133	$	29,217	$	—	$	(1,607,350)	$	—
Current assets	29		37,933		240,530		—		278,492
Net property and equipment	—		583,899		3,115,696		—		3,699,595
Investment in subsidiaries	1,332,237		—		144,697		(1,476,934)		—
Long-term assets	—		3,072		99,049		(10,532)		91,589
Total assets	$	2,910,399	$	654,121	$	3,599,972	$	(3,094,816)	$	4,069,676
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	1,607,350	$	(1,607,350)	$	—
Current liabilities	—		73,086		327,595		(909)		399,772
Senior unsecured notes payable	1,039,416		—		—		—		1,039,416
Other long-term liabilities	37,329		300,540		332,790		(9,623)		661,036
Total equity attributable to Matador Resources Company	1,833,654		144,697		1,332,237		(1,476,934)		1,833,654
Non-controlling interest in subsidiaries	—		135,798		—		—		135,798
Total liabilities and equity	$	2,910,399	$	654,121	$	3,599,972	$	(3,094,816)	$	4,069,676

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2020
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries		Consolidated
Total revenues	$	—	$	41,544	$	42,089	$	(20,713)	$	62,920
Total expenses	1,224		23,190		494,529		(20,713)		498,230
Operating (loss) income	(1,224)		18,354		(452,440)		—		(435,310)
Net loss on asset sales and impairment	—		(1,261)		(1,371)		—		(2,632)
Interest expense	(16,443)		(1,854)		—		—		(18,297)
Other income	—		13		460		—		473
(Loss) earnings in subsidiaries	(445,572)		—		7,779		437,793		—
(Loss) income before income taxes	(463,239)		15,252		(445,572)		437,793		(455,766)
Total income tax benefit	(109,823)		—		—		—		(109,823)
Net income attributable to non-controlling interest in subsidiaries	—		(7,473)		—		—		(7,473)
Net (loss) income attributable to Matador Resources Company shareholders	$	(353,416)	$	7,779	$	(445,572)	$	437,793	$	(353,416)

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2019
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries		Consolidated
Total revenues	$	—	$	41,720	$	216,885	$	(16,901)	$	241,704
Total expenses	901		22,564		158,351		(16,901)		164,915
Operating (loss) income	(901)		19,156		58,534		—		76,789
Net loss on asset sales and impairment	—		—		(368)		—		(368)
Interest expense	(15,888)		(2,180)		—		—		(18,068)
Other income (expense)	—		3		(426)		—		(423)
Earnings in subsidiaries	66,399		—		8,659		(75,058)		—
Income before income taxes	49,610		16,979		66,399		(75,058)		57,930
Total income tax provision	12,858		—		—		—		12,858
Net income attributable to non-controlling interest in subsidiaries	—		(8,320)		—		—		(8,320)
Net income attributable to Matador Resources Company shareholders	$	36,752	$	8,659	$	66,399	$	(75,058)	$	36,752

Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2020
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries		Consolidated
Total revenues	$	—	$	86,863	$	389,776	$	(42,134)	$	434,505
Total expenses	2,145		46,984		669,288		(42,134)		676,283
Operating (loss) income	(2,145)		39,879		(279,512)		—		(241,778)
Net loss on asset sales and impairment	—		(1,261)		(1,371)		—		(2,632)
Interest expense	(33,818)		(4,291)		—		—		(38,109)
Other income	—		13		1,780		—		1,793
(Loss) earnings in subsidiaries	(261,590)		—		17,513		244,077		—
(Loss) income before income taxes	(297,553)		34,340		(261,590)		244,077		(280,726)
Total income tax benefit	(69,866)		—		—		—		(69,866)
Net income attributable to non-controlling interest in subsidiaries	—		(16,827)		—		—		(16,827)
Net (loss) income attributable to Matador Resources Company shareholders	$	(227,687)	$	17,513	$	(261,590)	$	244,077	$	(227,687)

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

Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2020
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries		Consolidated
Net cash provided by operating activities	$	3	$	45,408	$	164,974	$	—	$	210,385
Net cash used in investing activities	—		(124,180)		(334,509)		(72)		(458,761)
Net cash provided by financing activities	—		77,050		149,634		72		226,756
Increase (decrease) in cash and restricted cash	3		(1,722)		(19,901)		—		(21,620)
Cash and restricted cash at beginning of period	29		24,656		40,443		—		65,128
Cash and restricted cash at end of period	$	32	$	22,934	$	20,542	$	—	$	43,508

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

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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, 2019 (the “Annual Report”) filed with the Securities and Exchange Commission (the “SEC”) on March 2, 2020, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” sections of the Annual Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 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 (“San Mateo I”) together with San Mateo Midstream II, LLC (“San Mateo II”). For certain oil and natural gas terms used in this Quarterly Report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.

Cautionary Note Regarding Forward-Looking Statements

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

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; 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 expansion of the Black River cryogenic natural gas processing plant, including the timing of the further expansion of such plant; the timing and operating results of the buildout by San Mateo of oil, natural gas and water gathering and transportation systems and the drilling of any additional salt water disposal wells, including in conjunction with the expansion of San Mateo’s services and assets into new areas in Eddy County, New Mexico; and the other factors discussed below and elsewhere in this Quarterly Report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:

•our business strategy;

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

•our cash flows and liquidity;

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

•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 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;

21

•our drilling of wells;

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

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

•our marketing of oil and natural gas;

•our exploitation projects or property acquisitions;

•the integration of acquisitions with our business;

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

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

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

•general economic conditions;

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

•the effectiveness of our risk management and hedging activities;

•our technology;

•environmental liabilities;

•counterparty credit risk;

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

•the impact of 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 salt water gathering services and salt water disposal services to third parties.

Second Quarter Highlights

For the three months ended June 30, 2020, our total oil equivalent production was 6.7 million BOE, and our average daily oil equivalent production was 73,300 BOE per day, of which 43,100 Bbl per day, or 59%, was oil and 181.4 MMcf per day, or 41%, was natural gas. Our oil production of 3.9 million Bbl for the three months ended June 30, 2020 increased 17% year-over-year from 3.3 million Bbl for the three months ended June 30, 2019. Our natural gas production of 16.5 Bcf for the three months ended June 30, 2020 increased 23% year-over-year from 13.4 Bcf for the three months ended June 30, 2019. For the six months ended June 30, 2020, our total oil equivalent production was 13.1 million BOE, and our average daily oil equivalent production was 72,200 BOE per day, of which 41,900 Bbl per day, or 58%, was oil and 182.3 MMcf per day, or 42%, was natural gas. Our oil production of 7.6 million Bbl for the six months ended June 30, 2020 increased 18% year-over-year from 6.5 million Bbl for the six months ended June 30, 2019. Our natural gas production of 33.2 Bcf for the six months ended June 30, 2020 increased 22% year-over-year from 27.1 Bcf for the six months ended June 30, 2019.

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For the second quarter of 2020, we reported a net loss attributable to Matador shareholders of approximately $353.4 million, or $3.04 per diluted common share, on a generally accepted accounting principles in the United States (“GAAP”) basis, as compared to net income attributable to Matador shareholders of $36.8 million, or $0.31 per diluted common share, for the second quarter of 2019. For the second quarter of 2020, our Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was $107.6 million, as compared to Adjusted EBITDA of $144.1 million during the second quarter of 2019. 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 second quarter of 2020, see “— Results of Operations” below.

For the six months ended June 30, 2020, we reported a net loss attributable to Matador shareholders of approximately $227.7 million, or $1.96 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $19.8 million, or $0.17 per diluted common share, for the six months ended June 30, 2019. For the six months ended June 30, 2020, our Adjusted EBITDA, a non-GAAP financial measure, was $248.2 million, as compared to Adjusted EBITDA of $268.9 million during the six months ended June 30, 2019. 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, 2020, see “— Results of Operations” below.

Operations Update

During the first half of 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of the Organization of Petroleum Exporting Countries and Russia (“OPEC+”) to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. Primarily as a result of these unexpected events and the resulting declines in oil prices, we significantly modified our 2020 operational plan.

We began 2020 operating six drilling rigs in the Delaware Basin, as we continued to focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We had originally planned to operate these six drilling rigs in the Delaware Basin throughout 2020. As a result of the events noted above, however, we released (i) one operated drilling rig from our Wolf asset area late in the first quarter of 2020, (ii) a second operated drilling rig from the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) in late April 2020 and (iii) a third operated drilling rig from our Rustler Breaks asset area in late June 2020. We expect to operate three drilling rigs in the Delaware Basin throughout the remainder of 2020. Two of these rigs are anticipated to operate in our Stateline asset area, and the third rig is expected to operate primarily in the Rustler Breaks and Antelope Ridge asset areas.

We completed and turned to sales a total of 13 gross (8.3 net) wells in the Delaware Basin during the second quarter of 2020, including 11 gross (8.3 net) operated horizontal wells and two gross (less than 0.1 net) non-operated horizontal wells. During the second quarter of 2020, we completed and turned to sales a total of three gross (1.0 net) wells in the Antelope Ridge asset area, including one gross (1.0 net) operated well and two gross (less than 0.1 net) non-operated wells. The one gross operated well turned to sales in the Antelope Ridge asset area was a Wolfcamp A completion. In the Rustler Breaks asset area, we began producing oil and natural gas from a total of five gross (2.6 net) operated wells, of which three were Wolfcamp A completions and two were Wolfcamp B completions. In the Wolf and Jackson Trust asset areas, we began producing oil and natural gas from five gross (4.7 net) operated wells during the second quarter of 2020, of which three were Second Bone Spring completions, one was a Third Bone Spring Carbonate completion and one was a Wolfcamp A completion.

Our average daily oil equivalent production in the Delaware Basin for the second quarter of 2020 was 66,000 BOE per day, consisting of 41,500 Bbl of oil per day and 146.9 MMcf of natural gas per day, a 27% increase from production of 51,800 BOE per day, consisting of 32,800 Bbl of oil per day and 113.5 MMcf of natural gas per day, in the second quarter of 2019. The Delaware Basin contributed approximately 96% of our daily oil production and approximately 81% of our daily natural gas production in the second quarter of 2020, as compared to approximately 89% of our daily oil production and approximately 77% of our daily natural gas production in the second quarter of 2019.

During the second quarter of 2020, we did not complete and turn to sales any operated or non-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.

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During April 2020, we restructured a portion of our then-existing 2020 West Texas Intermediate (“WTI”) oil derivative financial instruments, providing additional revenue protection should oil prices decline again to depressed levels, such as those experienced late in the first quarter and early in the second quarter of 2020, for the remainder of 2020 or should further market disruptions occur. As a result of these modifications, we almost doubled our oil volumes hedged for the period from April through December 2020. These restructured derivative financial instruments included approximately 7.6 million Bbl of fixed-price oil swaps at a weighted average price of approximately $35 per Bbl and 2.3 million Bbl of oil collars with a weighted average floor price of approximately $48 per Bbl and a weighted average ceiling price of approximately $66 per Bbl. We also had approximately 0.4 million Bbl in oil put options, which represent options to sell at a specified exercise price, at a weighted average price of approximately $48 per Bbl for the period from April through June 2020. The Company recorded $44.1 million in realized gains on derivatives during the second quarter of 2020.

In addition, during the second quarter of 2020, we added approximately 2.0 million Bbl of oil swaps at a weighted average price of approximately $35 per Bbl and 2.4 million Bbl of oil costless collars with a weighted average floor price of approximately $35 per Bbl and a weighted average ceiling price of approximately $46 per Bbl for 2021. We also added natural gas collars for November and December 2020 for approximately 3.2 million MMBtu and for the first quarter of 2021 for approximately 4.8 million MMBtu, each with a weighted average floor price of approximately $2.52 per MMBtu and a weighted average ceiling price of approximately $3.71 per MMBtu.

See Note 7 to the interim unaudited condensed consolidated financial statements to this Quarterly Report for a summary of our open derivative financial instruments at June 30, 2020.

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.

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,
	2020		2019		2020		2019
Operating Data:
Revenues (in thousands):(1)
Oil	$	94,174	$	189,085	$	263,759	$	343,288
Natural gas	24,593		21,975		52,922		61,041
Total oil and natural gas revenues	118,767		211,060		316,681		404,329
Third-party midstream services revenues	14,668		14,359		30,498		26,197
Sales of purchased natural gas	13,981		8,963		24,525		20,194
Lease bonus - mineral acreage	4,062		—		4,062		—
Realized gain on derivatives	44,110		1,165		54,977		4,435
Unrealized (loss) gain on derivatives	(132,668)		6,157		3,762		(39,562)
Total revenues	$	62,920	$	241,704	$	434,505	$	415,593
Net Production Volumes:(1)
Oil (MBbl)(2)	3,920		3,346		7,617		6,452
Natural gas (Bcf)(3)	16.5		13.4		33.2		27.1
Total oil equivalent (MBOE)(4)	6,670		5,577		13,146		10,972
Average daily production (BOE/d)(5)	73,302		61,290		72,232		60,619
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	24.03	$	56.51	$	34.63	$	53.20
Oil, with realized derivatives (per Bbl)	$	35.28	$	56.86	$	41.85	$	53.91
Natural gas, without realized derivatives (per Mcf)	$	1.49	$	1.64	$	1.60	$	2.25
Natural gas, with realized derivatives (per Mcf)	$	1.49	$	1.64	$	1.60	$	2.25

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_________________

(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, 2020 as Compared to Three Months Ended June 30, 2019

Oil and natural gas revenues. Our oil and natural gas revenues decreased $92.3 million, or 44%, to $118.8 million for the three months ended June 30, 2020, as compared to $211.1 million for the three months ended June 30, 2019. Our oil revenues decreased $94.9 million, or 50%, to $94.2 million for the three months ended June 30, 2020, as compared to $189.1 million for the three months ended June 30, 2019. The decrease in oil revenues resulted from a 57% decrease in the weighted average oil price realized for the three months ended June 30, 2020 to $24.03 per Bbl, as compared to $56.51 per Bbl for the three months ended June 30, 2019. This decrease in oil revenues was partially offset by the 17% increase in oil production to 3.9 million Bbl for the three months ended June 30, 2020, as compared to 3.3 million Bbl for the three months ended June 30, 2019. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $2.6 million, or 12%, to $24.6 million for the three months ended June 30, 2020, as compared to $22.0 million for the three months ended June 30, 2019. The increase in natural gas revenues resulted from a 23% increase in our natural gas production to 16.5 Bcf for the three months ended June 30, 2020, as compared to 13.4 Bcf for the three months ended June 30, 2019. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin as well as from significant volumes of natural gas production associated with two non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. The increase in natural gas revenues was partially offset by a 9% decrease in the weighted average natural gas price realized for the three months ended June 30, 2020 to $1.49 per Mcf, as compared to $1.64 per Mcf for the three months ended June 30, 2019.

Third-party midstream services revenues. Our third-party midstream services revenues increased $0.3 million, or 2%, to $14.7 million for the three months ended June 30, 2020, as compared to $14.4 million for the three months ended June 30, 2019. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to an increase in our third-party oil gathering and transportation revenues to $2.1 million for the three months ended June 30, 2020, as compared to $1.6 million for the three months ended June 30, 2019, which was partially offset by a decrease in our third-party natural gas gathering, transportation and processing revenues to approximately $6.3 million for the three months ended June 30, 2020, as compared to $6.5 million for the three months ended June 30, 2019.

Sales of purchased natural gas. Our sales of purchased natural gas increased $5.0 million, or 56%, to $14.0 million for the three months ended June 30, 2020, as compared to $9.0 million for the three months ended June 30, 2019. This increase was primarily the result of an increase in natural gas volumes sold during the three months ended June 30, 2020. 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 Black River 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 statement of operations.

Lease bonus - mineral acreage. Our lease bonus - mineral acreage revenues were $4.1 million for the three months ended June 30, 2020. 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 received no lease bonuses on our mineral acreage for the three months ended June 30, 2019.

Realized gain on derivatives. Our realized net gain on derivatives was $44.1 million for the three months ended June 30, 2020, as compared to a realized net gain of $1.2 million for the three months ended June 30, 2019. We realized a net gain of $41.9 million related to our oil costless collar, put and swap contracts for the three months ended June 30, 2020, resulting from oil prices that were below the floor prices of certain of our oil costless collar contracts and below the strike prices of certain of our oil put and swap contracts. We realized a net gain of $2.2 million related to our oil basis swap contracts for the three months ended June 30, 2020, resulting from oil basis prices that were below the fixed prices of certain of our oil basis swap contracts. We realized an average gain on our oil derivatives contracts of approximately $11.25 per Bbl produced during the three months

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ended June 30, 2020, as compared to an average gain of approximately $0.35 per Bbl produced during the three months ended June 30, 2019.

Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives was $132.7 million for the three months ended June 30, 2020, as compared to an unrealized net gain of $6.2 million for the three months ended June 30, 2019. During the three months ended June 30, 2020, the net fair value of our open oil and natural gas derivative contracts decreased to a net liability of $0.1 million 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. During the three months ended June 30, 2019, the net fair value of our open oil and natural gas derivative contracts increased to a net asset of $10.3 million from a net asset of $4.1 million at March 31, 2019, resulting in an unrealized gain on derivatives of $6.2 million for the three months ended June 30, 2019.

Six Months Ended June 30, 2020 as Compared to Six Months Ended June 30, 2019

Oil and natural gas revenues. Our oil and natural gas revenues decreased $87.6 million, or 22%, to $316.7 million for the six months ended June 30, 2020, as compared to $404.3 million for the six months ended June 30, 2019. Our oil revenues decreased $79.5 million, or 23%, to $263.8 million for the six months ended June 30, 2020, as compared to $343.3 million for the six months ended June 30, 2019. This decrease in oil revenues resulted from a 35% decrease in the weighted average oil price realized for the six months ended June 30, 2020 to $34.63 per Bbl, as compared to $53.20 per Bbl for the six months ended June 30, 2019. This decrease was partially offset by the 18% increase in our oil production to 7.6 million Bbl for the six months ended June 30, 2020, as compared to 6.5 million Bbl for the six months ended June 30, 2019. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $8.1 million, or 13%, to $52.9 million for the six months ended June 30, 2020, as compared to $61.0 million for the six months ended June 30, 2019. The decrease in natural gas revenues resulted from a 29% decrease in the weighted average natural gas price realized for the six months ended June 30, 2020 to $1.60 per Mcf, as compared to $2.25 per Mcf for the six months ended June 30, 2019. This decrease was partially offset by the 22% increase in our natural gas production to 33.2 Bcf for the six months ended June 30, 2020, as compared to 27.1 Bcf for the six months ended June 30, 2019. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin as well as from two non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019.

Third-party midstream services revenues. Our third-party midstream services revenues increased $4.3 million, or 16%, to $30.5 million for the six months ended June 30, 2020, as compared to $26.2 million for the six months ended June 30, 2019. This increase was primarily attributable to (i) an increase in natural gas gathering, transportation and processing revenues to approximately $13.4 million for the six months ended June 30, 2020, as compared to $11.0 million for the six months ended June 30, 2019, (ii) an increase in our third-party salt water gathering and disposal revenues to approximately $12.9 million for the six months ended June 30, 2020, as compared to approximately $12.0 million for the six months ended June 30, 2019, and (iii) an increase in our third-party oil gathering and transportation revenues to approximately $4.2 million for the six months ended June 30, 2020, as compared to $3.2 million for the six months ended June 30, 2019.

Sales of purchased natural gas. Our sales of purchased natural gas increased $4.3 million, or 21%, to $24.5 million for the six months ended June 30, 2020, as compared to $20.2 million for the six months ended June 30, 2019. This increase was primarily the result of an increase in natural gas volumes sold during the six months ended June 30, 2020.

Lease bonus - mineral acreage. Our lease bonus - mineral acreage revenues were $4.1 million for the six months ended June 30, 2020. We received no lease bonuses on our mineral acreage for the six months ended June 30, 2019.

Realized gain on derivatives. Our realized net gain on derivatives was $55.0 million for the six months ended June 30, 2020, as compared to a realized net gain of $4.4 million for the six months ended June 30, 2019. We realized a net gain of $53.4 million related to our oil costless collar, put and swap contracts for the six months ended June 30, 2020, resulting from oil prices that were below the floor prices of certain of our oil costless collar contracts and below the strike prices of certain of our oil put and swap contracts. We realized a net gain of $1.5 million related to our oil basis swap contracts for the six months ended June 30, 2020, resulting from oil basis prices that were below the fixed prices of certain of our oil basis swap contracts. We realized an average gain on our oil derivatives of approximately $7.22 per Bbl produced during the six months ended June 30, 2020, as compared to an average gain of $0.71 per Bbl produced during the six months ended June 30, 2019.

Unrealized (loss) gain on derivatives. Our unrealized net gain on derivatives was $3.8 million for the six months ended June 30, 2020, as compared to an unrealized net loss of $39.6 million for the six months ended June 30, 2019. 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 approximately $0.1 million from a net liability of approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $3.8 million for the six months ended June 30, 2020. During the period from December 31, 2018 through June 30, 2019, the aggregate net fair value of our open oil and natural gas derivative contracts

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decreased from a net asset of approximately $49.8 million to a net asset of approximately $10.3 million, resulting in an unrealized loss on derivatives of approximately $39.6 million for the six months ended June 30, 2019.

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)	2020		2019		2020		2019
Expenses:
Production taxes, transportation and processing	$	18,797	$	21,542	$	40,513	$	41,207
Lease operating	26,162		26,351		57,072		57,514
Plant and other midstream services operating	9,780		8,422		19,744		17,738
Purchased natural gas	10,922		8,172		18,980		18,806
Depletion, depreciation and amortization	93,350		80,132		184,057		156,999
Accretion of asset retirement obligations	495		420		971		834
Full-cost ceiling impairment	324,001		—		324,001		—
General and administrative	14,723		19,876		30,945		38,166
Total expenses	498,230		164,915		676,283		331,264
Operating (loss) income	(435,310)		76,789		(241,778)		84,329
Other income (expense):
Net loss on asset sales and impairment	(2,632)		(368)		(2,632)		(368)
Interest expense	(18,297)		(18,068)		(38,109)		(35,997)
Other income (expense)	473		(423)		1,793		(532)
Total other expense	(20,456)		(18,859)		(38,948)		(36,897)
(Loss) income before income taxes	(455,766)		57,930		(280,726)		47,432
Total income tax (benefit) provision	(109,823)		12,858		(69,866)		11,845
Net income attributable to non-controlling interest in subsidiaries	(7,473)		(8,320)		(16,827)		(15,782)
Net (loss) income attributable to Matador Resources Company shareholders	$	(353,416)	$	36,752	$	(227,687)	$	19,805
Expenses per BOE:
Production taxes, transportation and processing	$	2.82	$	3.86	$	3.08	$	3.76
Lease operating	$	3.92	$	4.72	$	4.34	$	5.24
Plant and other midstream services operating	$	1.47	$	1.51	$	1.50	$	1.62
Depletion, depreciation and amortization	$	14.00	$	14.37	$	14.00	$	14.31
General and administrative	$	2.21	$	3.56	$	2.35	$	3.48

Three Months Ended June 30, 2020 as Compared to Three Months Ended June 30, 2019

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses decreased $2.7 million, or 13%, to $18.8 million for the three months ended June 30, 2020, as compared to $21.5 million for the three months ended June 30, 2019. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 27% to $2.82 per BOE for the three months ended June 30, 2020, as compared to $3.86 per BOE for the three months ended June 30, 2019. These decreases were primarily attributable to the $6.6 million decrease in production taxes to $8.6 million for the three months ended June 30, 2020, as compared to $15.2 million for the three months ended June 30, 2019, primarily due to the decrease in the weighted average oil and natural gas prices realized between the two periods. This decrease was partially offset by a $3.9 million increase in transportation and processing expenses to $10.2 million for the three months ended June 30, 2020, as compared to $6.3 million for the three months ended June 30, 2019, primarily due to the 23% increase in our natural gas production to 16.5 Bcf for the three months ended June 30, 2020, as compared to 13.4 Bcf for the three months ended June 30, 2019.

Lease operating. Our lease operating expenses decreased $0.2 million, or 1%, to $26.2 million for the three months ended June 30, 2020, as compared to $26.4 million for the three months ended June 30, 2019. This decrease was largely

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attributable to a decrease in salt water disposal expenses of $1.7 million, which was partially offset by increases in ad valorem taxes and other expenses related to the increased number of wells at June 30, 2020, as compared to June 30, 2019. Our lease operating expenses on a unit-of-production basis decreased 17% to $3.92 per BOE for the three months ended June 30, 2020, as compared to $4.72 per BOE for the three months ended June 30, 2019, which was further attributable to the 20% increase in our total oil equivalent production to 6.7 million BOE for the three months ended June 30, 2020, as compared to 5.6 million BOE for the three months ended June 30, 2019.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $1.4 million, or 16%, to $9.8 million for the three months ended June 30, 2020, as compared to $8.4 million for the three months ended June 30, 2019. This increase was primarily attributable to increased expenses associated with our expanded commercial salt water disposal operations of $5.4 million for the three months ended June 30, 2020, as compared to $3.8 million for the three months ended June 30, 2019, which were partially offset by decreased expenses associated with the Black River Processing Plant of $2.5 million for the three months ended June 30, 2020, as compared to $3.1 million for the three months ended June 30, 2019.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $13.2 million, or 16%, to $93.4 million for the three months ended June 30, 2020, as compared to $80.1 million for the three months ended June 30, 2019. This increase was primarily attributable to (i) the 20% increase in our total oil equivalent production to 6.7 million BOE for the three months ended June 30, 2020, as compared to 5.6 million BOE for the three months ended June 30, 2019, and (ii) increased depreciation expenses attributable to our midstream segment of $5.0 million for the three months ended June 30, 2020, as compared to $3.8 million for the three months ended June 30, 2019. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 3% to $14.00 per BOE for the three months ended June 30, 2020, as compared to $14.37 per BOE for the three months ended June 30, 2019. On a unit-of-production basis, the impact of the higher total proved oil and natural gas reserves at June 30, 2020, as compared to June 30, 2019, primarily attributable to our ongoing delineation and development activities in the Delaware Basin, was largely offset by the increase in total oil equivalent production for the three months ended June 30, 2020, as compared to the three months ended June 30, 2019.

Full-cost ceiling impairment. 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. 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, 2019. In determining the full-cost ceiling impairment at June 30, 2020, we estimated the present value, discounted at 10%, (“PV-10”) of our total proved oil and natural gas reserves using the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended June 30, 2020, as required under the guidelines established by the SEC, which were $43.60 per Bbl and $2.07 per MMBtu, respectively.

General and administrative. Our general and administrative expenses decreased $5.2 million, or 26%, to $14.7 million for the three months ended June 30, 2020, as compared to $19.9 million for the three months ended June 30, 2019. This decrease was primarily attributable to cost reductions initially implemented during the three months ended March 31, 2020, including headcount and employee salary reductions, that were more fully realized during the three months ended June 30, 2020. Our general and administrative expenses decreased 38% on a unit-of-production basis to $2.21 per BOE for the three months ended June 30, 2020, as compared to $3.56 per BOE for the three months ended June 30, 2019, which was further attributable to the 20% increase in our total oil equivalent production to 6.7 million BOE for the three months ended June 30, 2020, as compared to 5.6 million BOE for the three months ended June 30, 2019.

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

Total income tax (benefit) provision. We recorded a total income tax benefit of $109.8 million for the three months ended June 30, 2020, and the effective tax rate was 24%, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax loss due primarily to the impact of permanent differences between book and tax loss and state taxes, primarily in New Mexico. We recorded a total income tax expense of $12.9 million for the three months ended June 30, 2019, and the effective tax rate was 26%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due primarily to the impact of permanent differences between book and tax income.

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Six Months Ended June 30, 2020 as Compared to Six Months Ended June 30, 2019

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses decreased $0.7 million, or 2%, to $40.5 million for the six months ended June 30, 2020, as compared to $41.2 million for the six months ended June 30, 2019. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 18% to $3.08 per BOE for the six months ended June 30, 2020, as compared to $3.76 per BOE for the six months ended June 30, 2019. These decreases were primarily attributable to the $6.0 million decrease in production taxes to $22.7 million for the six months ended June 30, 2020, as compared to $28.7 million for the six months ended June 30, 2019, primarily due to the decrease in the weighted average oil and natural gas prices realized between the two periods. This decrease was partially offset by a $5.3 million increase in transportation and processing expenses for the six months ended June 30, 2020, as compared to the six months ended June 30, 2019, primarily due to the 22% increase in our natural gas production to 33.2 Bcf for the six months ended June 30, 2020, as compared to 27.1 Bcf for the six months ended June 30, 2019.

Lease operating. Our lease operating expenses decreased $0.4 million, or 1%, to $57.1 million for the six months ended June 30, 2020, as compared to $57.5 million for the six months ended June 30, 2019. This decrease was largely attributable to a decrease in salt water disposal expenses of approximately $6.0 million, which was partially offset by increases in ad valorem taxes and other expenses related to the increased number of wells at June 30, 2020, as compared to June 30, 2019. Our lease operating expenses on a unit-of-production basis decreased 17% to $4.34 per BOE for the six months ended June 30, 2020, as compared to $5.24 per BOE for the six months ended June 30, 2019, which was further attributable to the 20% increase in our total oil equivalent production to 13.1 million BOE for the six months ended June 30, 2020, as compared to 11.0 million BOE for the six months ended June 30, 2019.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $2.0 million, or 11%, to $19.7 million for the six months ended June 30, 2020, as compared to $17.7 million for the six months ended June 30, 2019. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial salt water disposal operations of $10.5 million for the six months ended June 30, 2020, as compared to $8.1 million for the six months ended June 30, 2019, and (ii) increased expenses associated with pipeline operations of $4.0 million for the six months ended June 30, 2020, as compared to $3.7 million for the six months ended June 30, 2019, which were partially offset by decreased expenses associated with the Black River Processing Plant of $5.2 million for the six months ended June 30, 2020, as compared to $6.1 million for the six months ended June 30, 2019.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $27.1 million, or 17%, to $184.1 million for the six months ended June 30, 2020, as compared to $157.0 million for the six months ended June 30, 2019. This increase was primarily attributable to (i) the 20% increase in our total oil equivalent production to 13.1 million BOE for the six months ended June 30, 2020, as compared to 11.0 million BOE for the six months ended June 30, 2019, and (ii) increased depreciation expenses attributable to our midstream segment of $9.8 million for the six months ended June 30, 2020, as compared to $7.5 million for the six months ended June 30, 2019. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 2% to $14.00 per BOE for the six months ended June 30, 2020, as compared to $14.31 per BOE for the six months ended June 30, 2019. On a unit-of-production basis, the impact of the higher total proved oil and natural gas reserves at June 30, 2020, as compared to June 30, 2019, primarily attributable to our ongoing delineation and development activities in the Delaware Basin, was largely offset by the increase in total oil equivalent production for the six months ended June 30, 2020, as compared to the six months ended June 30, 2019.

Full-cost ceiling impairment. 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. 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 March 31, 2020 or for the six months ended June 30, 2019. In determining the full-cost ceiling impairment at June 30, 2020, we estimated the PV-10 of our total proved oil and natural gas reserves using the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended June 30, 2020, as required under the guidelines established by the SEC, which were $43.60 per Bbl and $2.07 per MMBtu, respectively.

General and administrative. Our general and administrative expenses decreased $7.2 million, or 19%, to $30.9 million for the six months ended June 30, 2020, as compared to $38.2 million for the six months ended June 30, 2019. This decrease was primarily attributable to cost reductions initially implemented during the three months ended March 31, 2020, including headcount and employee salary reductions, that were more fully realized during the three months ended June 30, 2020. Our general and administrative expenses decreased 32% on a unit-of-production basis to $2.35 per BOE for the six months ended June 30, 2020, as compared to $3.48 per BOE for the six months ended June 30, 2019, which was further attributable to the

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20% increase in our total oil equivalent production to 13.1 million BOE for the six months ended June 30, 2020, as compared to 11.0 million BOE for the six months ended June 30, 2019.

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

Total income tax (benefit) provision. We recorded a total income tax benefit of $69.9 million for the six months ended June 30, 2020, and the effective tax rate was 23%, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax loss due primarily to the impact of permanent differences between book and tax loss and state taxes, primarily in New Mexico. We recorded a total income tax expense of $11.8 million for the six months ended June 30, 2019, and the effective tax rate was 37%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due primarily to the impact of permanent differences between book and tax income.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during the remainder of 2020 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund the remainder of our 2020 capital expenditures primarily through a combination of cash on hand, operating cash flows, performance incentives in connection with San Mateo, borrowings under our reserves-based revolving credit facility (the “Credit Agreement”) (assuming availability under our borrowing base of $900.0 million) and borrowings under San Mateo I’s revolving credit facility (the “San Mateo Credit Facility”) (assuming availability under the accordion feature of such facility to up to $400.0 million). We continually evaluate 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 access outside sources of capital and to generate operating cash flows.

At June 30, 2020, we had cash totaling approximately $20.6 million and restricted cash totaling approximately $22.9 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.

At June 30, 2020, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $385.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.1 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 February 2020, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves at December 31, 2019, and, as a result, the borrowing base was affirmed at $900.0 million. We elected to increase the borrowing commitment from $500.0 million to $700.0 million, and the maximum facility amount remained $1.5 billion. This February 2020 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected 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 4.00 or less. The Company believes that it was in compliance with the terms of the Credit Agreement at June 30, 2020. At July 28, 2020, we had (i) $1.05 billion of outstanding Notes, (ii) $404.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.1 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured SBA loan.

At June 30, 2020 and July 28, 2020, San Mateo I had $320.0 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. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases to up to $400.0 million, and matures in December 2023. At June 30, 2020, the lender commitments under the San Mateo Credit Facility were $375.0 million (subject to San Mateo I’s compliance with the covenants noted below). The San Mateo Credit Facility is guaranteed by San Mateo I’s subsidiaries, secured by substantially all of San Mateo I’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries. The San Mateo Credit Facility requires San Mateo I to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo I to maintain an interest coverage ratio,

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which is defined as a rolling four quarter EBITDA calculation divided by San Mateo I’s consolidated interest expense for such period, of 2.50 or more. The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at June 30, 2020.

During the first half of 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April, although oil prices began to improve in May and June. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria.

Primarily as a result of these unexpected events and the resulting declines in oil prices, we modified our 2020 operational plan. In March 2020, we significantly reduced our capital expenditure budget, including reducing our operated drilling program from six to three drilling rigs by the end of the second quarter of 2020. In addition, we made initial reductions to headcount, employee salaries and lease operating expenses and curtailed or shut in portions of our oil and natural gas production. While we had prepared to make further reductions to headcount, salaries and our capital expenditure budget, we have been able to avoid such reductions to date as a result of realizing greater-than-expected savings from the above changes to our 2020 operational plan, restructuring our hedge portfolio (as described below) and applying for and receiving an SBA loan through the Paycheck Protection Program. The general outlook for the oil and natural gas industry for the remainder of 2020 remains highly uncertain, and we can provide no assurances as to when the economic disruptions resulting from COVID-19 and the corresponding decline in oil demand may improve. Until such time, however, we anticipate that oil prices will remain well below the prices realized in 2019. These economic disruptions have also significantly reduced our ability to access the capital markets on reasonably similar terms as were available in prior periods.

As noted above, 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. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act and is administered by the SBA. The loan was issued through Iberiabank, which is a lender under the Credit Agreement, matures on the second anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. We used the proceeds of the loan for payroll, including salaries, payroll taxes and employee medical benefits, as permitted by the program. The receipt of the loan allowed us to avoid the planned further reductions to employee headcount and salaries discussed above. The loan is eligible for forgiveness for the portion of the loan proceeds used for payroll costs and other designated operating expenses, provided at least 60% of the loan’s proceeds are used for payroll costs.

During April 2020, we also restructured a portion of our then-existing 2020 WTI oil derivative financial instruments, providing additional revenue protection should oil prices decline again to depressed levels, such as those experienced late in the first quarter and early in the second quarter of 2020, for the remainder of 2020 or should further market disruptions occur. As a result of these modifications, we almost doubled our oil volumes hedged for the period from April through December 2020. These restructured derivative financial instruments included approximately 7.6 million Bbl of fixed-price oil swaps at a weighted average price of approximately $35 per Bbl and 2.3 million Bbl of oil collars with a weighted average floor price of approximately $48 per Bbl and a weighted average ceiling price of approximately $66 per Bbl. We also had approximately 0.4 million Bbl in oil put options, which represent options to sell at a specified exercise price, at a weighted average price of approximately $48 per Bbl for the period from April through June 2020.

In addition, during the second quarter of 2020, we added approximately 2.0 million Bbl of oil swaps at a weighted average price of approximately $35 per Bbl and 2.4 million Bbl of oil costless collars with a weighted average floor price of approximately $35 per Bbl and a weighted average ceiling price of approximately $46 per Bbl for 2021. We also added natural gas collars for November and December 2020 for approximately 3.2 million MMBtu and for the first quarter of 2021 for approximately 4.8 million MMBtu, each with a weighted average floor price of approximately $2.52 per MMBtu and a weighted average ceiling price of approximately $3.71 per MMBtu.

We began 2020 operating six drilling rigs in the Delaware Basin, as we continued to focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We had originally planned to operate these six drilling rigs in the Delaware Basin throughout 2020; however, we released (i) one operated drilling rig from our Wolf asset area late in the first quarter of 2020, (ii) a second operated drilling rig from the Greater Stebbins Area in late April 2020 and (iii) a third operated drilling rig from our Rustler Breaks asset area in late June 2020. We expect to operate three drilling rigs in the Delaware Basin throughout the remainder of 2020. Two of these rigs are anticipated to operate in our Stateline asset area, and the third rig is expected to operate primarily in the Rustler Breaks and Antelope Ridge asset areas.

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As a result of our plans to reduce our operated drilling program from six to three rigs by the end of the second quarter of 2020, on April 29, 2020, we decreased the range of our anticipated full-year 2020 capital expenditures for drilling, completing and equipping wells from $690.0 to $750.0 million to $440.0 to $500.0 million. The range of our anticipated full-year 2020 capital expenditures for midstream capital expenditures remained $85.0 to $105.0 million, which reflects our proportionate share of San Mateo’s estimated capital expenditures of $190.0 to $235.0 million and also accounts for the portions of the $50.0 million capital carry remaining as of January 1, 2020 that Five Point provided us in conjunction with the formation of San Mateo II. Substantially all of these 2020 estimated capital expenditures will be allocated to (i) the further delineation and development of our leasehold position, (ii) the continued construction of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities.

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

Our 2020 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures are 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 2020 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we have forecasted and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of realized oil, natural gas and NGL prices for the remainder of 2020 and the hedges we currently have in place. As noted above, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices during the first quarter and early in the second quarter of 2020 that improved during May and June. 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.

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Our unaudited cash flows for the six months ended June 30, 2020 and 2019 are presented below:

	Six Months Ended June 30,
(In thousands)	2020		2019
Net cash provided by operating activities	$	210,385	$	194,497
Net cash used in investing activities	(458,761)		(394,694)
Net cash provided by financing activities	226,756		200,975
Net change in cash and restricted cash	$	(21,620)	$	778
Adjusted EBITDA attributable to Matador Resources Company shareholders(1)	$	248,170	$	268,943

__________________

(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 $15.9 million to $210.4 million for the six months ended June 30, 2020 from $194.5 million for the six months ended June 30, 2019. Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $235.7 million for the six months ended June 30, 2020 from $255.5 million for the six months ended June 30, 2019, primarily attributable to significantly lower realized oil and natural gas prices for the six months ended June 30, 2020, as compared to the six months ended June 30, 2019. Changes in our operating assets and liabilities between the two periods resulted in a net increase of approximately $35.7 million in net cash provided by operating activities for the six months ended June 30, 2020, as compared to the six months ended June 30, 2019.

Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. Furthermore, the continued effect of COVID-19 and the corresponding decline in oil demand will also significantly impact the prices we receive for our oil production. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments 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 increased by $64.1 million to $458.8 million for the six months ended June 30, 2020 from $394.7 million for the six months ended June 30, 2019. This increase in net cash used in investing activities was primarily due to an increase in midstream capital expenditures of approximately $59.2 million, which was partially offset by a decrease of $14.8 million in oil and natural gas properties capital expenditures and a reduction in proceeds from the sales of assets of $20.5 million for the six months ended June 30, 2020, as compared to the six months ended June 30, 2019. 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. Cash used for oil and natural gas properties capital expenditures for the six months ended June 30, 2020 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities increased by $25.8 million to $226.8 million for the six months ended June 30, 2020 from $201.0 million for the six months ended June 30, 2019. During the six months ended June 30, 2020, our primary sources of cash from financing activities included borrowings under the Credit Agreement of $130.0 million, borrowings under the San Mateo Credit Facility of $32.0 million, net contributions related to the formation of San Mateo I and from non-controlling interest owners in less-than-wholly-owned subsidiaries of $59.8 million and the SBA loan of $7.5 million discussed above. During the six months ended June 30, 2019, we had borrowings under our Credit Agreement of $165.0 million, borrowings under the San Mateo Credit Facility of $20.0 million and net contributions related to the formation of San Mateo I and from non-controlling interest owners in less-than-wholly-owned subsidiaries of $16.9 million.

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

Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash

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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 (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

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

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

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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 (loss) and net cash provided by operating activities, respectively.

	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands)	2020		2019		2020		2019
Unaudited Adjusted EBITDA Reconciliation to Net (Loss) Income:
Net (loss) income attributable to Matador Resources Company shareholders	$	(353,416)	$	36,752	$	(227,687)	$	19,805
Net income attributable to non-controlling interest in subsidiaries	7,473		8,320		16,827		15,782
Net (loss) income	(345,943)		45,072		(210,860)		35,587
Interest expense	18,297		18,068		38,109		35,997
Total income tax (benefit) provision	(109,823)		12,858		(69,866)		11,845
Depletion, depreciation and amortization	93,350		80,132		184,057		156,999
Accretion of asset retirement obligations	495		420		971		834
Full-cost ceiling impairment	324,001		—		324,001		—
Unrealized loss (gain) on derivatives	132,668		(6,157)		(3,762)		39,562
Stock-based compensation expense	3,286		4,490		7,080		9,076
Net loss on asset sales and impairment	2,632		368		2,632		368
Consolidated Adjusted EBITDA	118,963		155,251		272,362		290,268
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,369)		(11,147)		(24,192)		(21,325)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	107,594	$	144,104	$	248,170	$	268,943

	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands)	2020		2019		2020		2019
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	101,013	$	135,257	$	210,385	$	194,497
Net change in operating assets and liabilities	368		2,472		25,267		60,963
Interest expense, net of non-cash portion	17,582		17,522		36,710		34,808
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(11,369)		(11,147)		(24,192)		(21,325)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	107,594	$	144,104	$	248,170	$	268,943

For the three months ended June 30, 2020, we reported a net loss attributable to Matador shareholders of approximately $353.4 million, as compared to net income of $36.8 million for the three months ended June 30, 2019. This decrease in net income attributable to Matador shareholders is primarily attributable to the full-cost ceiling impairment of $324.0 million we recorded for the three months ended June 30, 2020. In addition, we recorded an unrealized loss on derivatives of $132.7 million for the three months ended June 30, 2020, as compared to an unrealized gain on derivatives of $6.2 million for the three months ended June 30, 2019, and an income tax benefit of $109.8 million for the three months ended June 30, 2020, as compared to an income tax provision of $12.9 million for the three months ended June 30, 2019.

For the six months ended June 30, 2020, we reported a net loss attributable to Matador shareholders of approximately $227.7 million, as compared to net income attributable to Matador shareholders of $19.8 million for the six months ended June 30, 2019. This decrease in net income attributable to Matador Resources Company shareholders is primarily attributable to the full-cost ceiling impairment of $324.0 million we recorded for the six months ended June 30, 2020. In addition, we recorded an unrealized gain on derivatives of $3.8 million for the six months ended June 30, 2020, as compared to an unrealized loss on derivatives of $39.6 million for the six months ended June 30, 2019, and we recorded an income tax benefit of $69.9 million for the six months ended June 30, 2020, as compared to an income tax provision of $11.8 million for the six months ended June 30, 2019.

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Adjusted EBITDA, a non-GAAP financial measure, decreased by $36.5 million to $107.6 million for the three months ended June 30, 2020, as compared to $144.1 million for the three months ended June 30, 2019. This decrease is primarily attributable to significantly lower realized oil and natural gas prices, partially offset by higher oil and natural gas production for the three months ended June 30, 2020, as compared to the three months ended June 30, 2019.

Adjusted EBITDA, a non-GAAP financial measure, decreased by $20.8 million to $248.2 million for the six months ended June 30, 2020, as compared to $268.9 million for the six months ended June 30, 2019. This decrease is primarily attributable to significantly lower realized oil and natural gas prices, partially offset by higher oil and natural gas production for the six months ended June 30, 2020, as compared to the six months ended June 30, 2019.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2020, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm transportation, gathering, processing 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 the Company’s 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, 2020:

	Payments Due by Period
(In thousands)	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
Contractual Obligations:
Borrowings under credit agreements and facilities, including letters of credit(1)	$	759,108	$	—	$	—	$	759,108	$	—
Senior unsecured notes(2)	1,050,000		—		—		—		1,050,000
Office leases	24,389		3,993		8,147		8,600		3,649
Non-operated drilling and other capital commitments(3)	57,208		23,505		20,000		13,703		—
Drilling rig contracts(4)	29,961		19,835		10,126		—		—
Asset retirement obligations(5)	38,536		539		3,379		2,009		32,609
Natural gas transportation, gathering and processing agreements with non-affiliates(6)	625,477		58,284		134,355		134,386		298,452
Gathering, processing and disposal agreements with San Mateo(7)	510,896		—		59,518		163,614		287,764
Natural gas engineering, construction and installation contract(8)	7,230		7,230		—		—		—
Total contractual cash obligations	$	3,102,805	$	113,386	$	235,525	$	1,081,420	$	1,672,474

__________________

(1)The amounts included in the table above represent principal maturities only. At June 30, 2020, we had $385.0 million in borrowings outstanding under the Credit Agreement and approximately $45.1 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2023. At June 30, 2020, San Mateo I had $320.0 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 1.68% and 1.93% (for the Credit Agreement and the San Mateo Credit Facility), respectively, at June 30, 2020, the interest expense is expected to be approximately $6.6 million and $6.3 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, 2020 is expected to be approximately $61.7 million each year until maturity.

(3)At June 30, 2020, 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 enter into contracts with third parties for such drilling rigs.

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(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at June 30, 2020.

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

(7)In February 2017, in connection with the formation of San Mateo I, we dedicated our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and certain future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. In February 2019, in connection with the formation of San Mateo II, we dedicated our current and certain future leasehold interests in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. See Note 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.

(8)In June 2019, a subsidiary of San Mateo II entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. See Note 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 of 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices, which continued through April but began to improve in May and June. For the three months ended June 30, 2020, oil prices averaged $28.00 per Bbl, ranging from a low of ($37.63) per Bbl in mid-April to a high of $40.46 per Bbl in late June, based upon the NYMEX WTI oil futures contract price for the earliest delivery date. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria.

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

We realized a weighted average oil price of $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, as compared to $56.51 per Bbl ($56.86 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended June 30, 2019. At July 28, 2020, the NYMEX WTI oil futures contract for the earliest delivery date had increased from the average price for the second quarter of 2020 of $28.00 per Bbl, settling at $41.04 per Bbl, which was a decrease as compared to $56.20 per Bbl at July 26, 2019.

Natural gas prices were also lower in the second quarter of 2020, as compared to the second quarter of 2019. For the three months ended June 30, 2020, natural gas prices averaged $1.75 per MMBtu, ranging from a high of $2.13 per MMBtu in early May to a low of $1.48 per MMBtu in late June, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $1.49 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, as compared to $1.64 per Mcf (including negligible realized losses from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended June 30, 2019. At July 28, 2020, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased slightly from the end of the second quarter of 2020, settling at $1.80 per MMBtu, which was a decrease as compared to $2.17 per MMBtu at July 26, 2019.

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

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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.

The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX 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, 2020, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas. For most of the first nine months of 2019, almost all of our natural gas production from the Delaware Basin was sold based on prices established at the Waha Hub in far West Texas, and portions of our natural gas are still sold based on Waha prices. At the end of September 2019, however, the Kinder Morgan Gulf Coast Express Pipeline Project (the “GCX Pipeline”) became operational. We have secured firm natural gas transportation and sales on the GCX Pipeline for an average of approximately 110,000 to 115,000 MMBtu per day at a natural gas price based upon Houston Ship Channel pricing.

After a lengthy period beginning in the second quarter of 2018 in which the Midland-Cushing (Oklahoma) oil price differential was negative, reaching as high as ($16.00) per Bbl in late September 2018, this oil price differential became positive late in the third quarter of 2019 and remained positive into the first quarter of 2020. With the abrupt decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020, reaching ($6.00) per Bbl before improving throughout the rest of the second quarter of 2020, especially for the month of June 2020. At July 28, 2020, this oil price differential was approximately $0.25 per Bbl. It is possible that the differential could turn negative again at certain times during the remainder of 2020. At July 28, 2020, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated oil production for the remainder of 2020 and throughout 2021 and 2022.

Our realized prices for a portion of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential. This Waha basis differential has increased significantly over the past two years, including a few days in April 2019 when natural gas was being sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu on a daily market basis. During the second half of 2019, the Waha basis differentials improved and natural gas prices at the Waha hub averaged approximately $1.00 per MMBtu for the final six months of the year. Despite improving during the second half of 2019, beginning in the fourth quarter, the Waha basis differential widened further at times, and natural gas prices at the Waha hub were slightly negative on certain days in late December 2019. In early 2020, the Waha basis differential continued to deteriorate, and natural gas prices at the Waha hub were negative on certain days in April 2020. However, the Waha basis differential narrowed during the remainder of the second quarter of 2020. At July 28, 2020, the Waha basis differential was approximately ($0.50) per MMBtu.

Beginning in late September 2019, as the GCX Pipeline became operational, we began selling a majority of our produced Delaware Basin natural gas at Houston Ship Channel pricing, and we have realized an improvement in the natural gas pricing received despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. Further, approximately 24% of our reported natural gas production in the first half of 2020 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing.

We anticipate that the volatility in these oil and natural gas price differentials could persist throughout 2020 or longer until additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets is completed and as the balance between oil supply and demand is restored. We can provide no assurances as to how long these volatile differentials may persist, and as noted above, these price differentials could 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 2020.

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 recent actions initiated by Saudi Arabia to increase its oil production to world markets, has led to a significant oversupply of oil worldwide. On April 10, 2020, the members of OPEC+ (led by Saudi Arabia) reversed course and announced their intentions to reduce oil production significantly for the remainder of 2020 and into 2021 and 2022. It is uncertain, however, to what degree these production cuts may restore the balance between oil supply and demand, and most oil and natural gas industry observers remain skeptical that

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oil prices can improve substantially until oil demand improves, most likely as a result of the “re-opening” of the world economy as concerns surrounding COVID-19 begin to subside.

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

Further, if oil prices remain at their current depressed levels during the third quarter of 2020, we anticipate that we could realize another full-cost ceiling impairment to the net capitalized value of our oil and natural gas properties. In determining whether a full-cost ceiling impairment existed at June 30, 2020, we estimated the value, discounted at 10%, of our total proved oil and natural gas reserves using the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended June 30, 2020 as required under the guidelines established by the SEC, which were $43.60 per Bbl and $2.07 per MMBtu, respectively. We recorded an impairment charge of $324.0 million at June 30, 2020. If the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended June 30, 2020 had been $39.42 per Bbl and $1.91 per MMBtu, respectively, while all other factors remained constant, our full-cost ceiling would have been further impaired by approximately $300.0 million on a pro forma basis. The aforementioned pro forma prices, as estimated for the twelve month period October 2019 through September 2020, were calculated using a 12-month unweighted arithmetic average of oil and natural gas prices, which included the oil and natural gas prices on the first day of the month for the 10 months ended July 2020, with the price for July 2020 being held constant for August and September 2020. This pro forma excess of our net capitalized costs above the full-cost ceiling is attributable to a pro forma reduction of approximately $300.0 million in the estimated value, discounted at 10%, of our total proved oil and natural gas reserves, including a pro forma decrease in our estimated total proved reserves of approximately 5% from our estimated proved reserves at June 30, 2020, primarily attributable to certain proved undeveloped locations that would no longer be classified as proved undeveloped reserves using the pro forma prices. This calculation of the impact of lower commodity prices on our estimated total proved oil and natural gas reserves and our full-cost ceiling was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, this calculation strictly isolates the impact of commodity prices on our full-cost ceiling and proved reserves. Commodity prices are among several variables impacting the estimation of our proved reserves and full-cost ceiling, and other factors could have a significant effect on our future proved reserves and the present value of future cash flows, including, but not limited to, extensions and discoveries, acquisitions of proved reserves, changes in drilling and completion and operating costs, drilling results, revisions due to well performance and other factors, changes in development plans and production, among others. There are numerous uncertainties inherent in the estimation of proved oil and natural gas reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results. 

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

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

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At June 30, 2020, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and Truist Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. See Note 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, 2020 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (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, 2020 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 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. There have been no material changes to the risk factors we have disclosed in such reports.

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

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

Period	Total Number of Shares Purchased(1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs
April 1, 2020 to April 30, 2020	22,678	$	6.58	—	—
May 1, 2020 to May 31, 2020	664	$	6.40	—	—
June 1, 2020 to June 30, 2020	334	$	10.15	—	—
Total	23,676	$	6.62	—	—

_________________

(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.

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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).
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, 2020, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets - Unaudited, (ii) the Condensed Consolidated Statements of Operations - Unaudited, (iii) the Condensed Consolidated Statements of Changes in Shareholders’ Equity - Unaudited, (iv) the Condensed Consolidated Statements of Cash Flows - Unaudited and (v) the Notes to Condensed Consolidated Financial Statements - Unaudited (submitted electronically herewith).
104	Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101).

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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 31, 2020	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer

Date: July 31, 2020	By:	/s/ David E. Lancaster
		David E. Lancaster
		Executive Vice President and Chief Financial Officer

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