Matador Resources Co - Quarter Report: 2020 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

_________________________________________________________



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

For the quarterly period ended March 31, 2020



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

For the transition period from to

Commission File Number 001-35410

_________________________________________________________

Matador Resources Company

(Exact name of registrant as specified in its charter)

_________________________________________________________



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

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

(972) 371-5200

(Registrant’s telephone number, including area code)

_________________________________________________________

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



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

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

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

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



Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

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

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

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

Table of Contents

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2020

TABLE OF CONTENTS



	Page
PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements — Unaudited	3
Condensed Consolidated Balance Sheets at March 31, 2020 and December 31, 2019	3
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2020 and 2019	4
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2020 and 2019	5
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2020 and 2019	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3. Quantitative and Qualitative Disclosures About Market Risk	36
Item 4. Controls and Procedures	37
PART II — OTHER INFORMATION	38
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 6. Exhibits	40
SIGNATURES	41

Table of Contents

Part I — FINANCIAL INFORMATION

Item 1. Financial Statements — Unaudited

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS — UNAUDITED

(In thousands, except par value and share data)



	March 31, 2020			December 31, 2019
ASSETS
Current assets
Cash	$	27,063		$	40,024
Restricted cash	29,732			25,104
Accounts receivable
Oil and natural gas revenues	52,879			95,228
Joint interest billings	70,318			67,546
Other	30,592			26,639
Derivative instruments	121,179			—
Lease and well equipment inventory	11,638			10,744
Prepaid expenses and other current assets	13,234			13,207
Total current assets	356,635			278,492
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	4,724,293			4,557,265
Unproved and unevaluated	1,169,751			1,126,992
Midstream properties	711,863			643,903
Other property and equipment	27,640			27,021
Less accumulated depletion, depreciation and amortization	(2,746,314		)	(2,655,586		)
Net property and equipment	3,887,233			3,699,595
Other assets
Derivative instruments	11,371			—
Other long-term assets	78,432			91,589
Total other assets	89,803			91,589
Total assets	$	4,333,671		$	4,069,676
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	17,659		$	25,230
Accrued liabilities	197,305			200,695
Royalties payable	85,577			85,193
Amounts due to affiliates	234			19,606
Derivative instruments	—			1,897
Advances from joint interest owners	11,240			14,837
Amounts due to joint ventures	—			486
Other current liabilities	47,883			51,828
Total current liabilities	359,898			399,772
Long-term liabilities
Borrowings under Credit Agreement	315,000			255,000
Borrowings under San Mateo Credit Facility	307,500			288,000
Senior unsecured notes payable	1,039,811			1,039,416
Asset retirement obligations	37,118			35,592
Derivative instruments	—			1,984
Deferred income taxes	84,700			37,329
Other long-term liabilities	35,264			43,131
Total long-term liabilities	1,819,393			1,700,452
Commitments and contingencies (Note 9)
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 shares authorized; 116,671,325 and 116,644,246 shares issued; and 116,564,598 and 116,642,899 shares outstanding, respectively	1,167			1,166
Additional paid-in capital	2,014,246			1,981,014
Accumulated deficit	(22,771		)	(148,500		)
Treasury stock, at cost, 106,727 and 1,347 shares, respectively	(1,293		)	(26		)
Total Matador Resources Company shareholders’ equity	1,991,349			1,833,654
Non-controlling interest in subsidiaries	163,031			135,798
Total shareholders’ equity	2,154,380			1,969,452
Total liabilities and shareholders’ equity	$	4,333,671		$	4,069,676

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

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Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS — UNAUDITED

(In thousands, except per share data)



	Three Months Ended March 31,
	2020			2019
Revenues
Oil and natural gas revenues	$	197,914		$	193,269
Third-party midstream services revenues	15,830			11,838
Sales of purchased natural gas	10,544			11,231
Realized gain on derivatives	10,867			3,270
Unrealized gain (loss) on derivatives	136,430			(45,719		)
Total revenues	371,585			173,889
Expenses
Production taxes, transportation and processing	21,716			19,665
Lease operating	30,910			31,163
Plant and other midstream services operating	9,964			9,316
Purchased natural gas	8,058			10,634
Depletion, depreciation and amortization	90,707			76,866
Accretion of asset retirement obligations	476			414
General and administrative	16,222			18,290
Total expenses	178,053			166,348
Operating income	193,532			7,541
Other income (expense)
Interest expense	(19,812		)	(17,929		)
Other income (expense)	1,320			(110		)
Total other expense	(18,492		)	(18,039		)
Income (loss) before income taxes	175,040			(10,498		)
Income tax provision (benefit)
Deferred	39,957			(1,013		)
Total income tax provision (benefit)	39,957			(1,013		)
Net income (loss)	135,083			(9,485		)
Net income attributable to non-controlling interest in subsidiaries	(9,354		)	(7,462		)
Net income (loss) attributable to Matador Resources Company shareholders	$	125,729		$	(16,947	)
Earnings (loss) per common share
Basic	$	1.08		$	(0.15	)
Diluted	$	1.08		$	(0.15	)
Weighted average common shares outstanding
Basic	116,607			115,315
Diluted	116,684			115,315

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

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Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(In thousands)

For the Three Months Ended March 31, 2020



														Total shareholders’ equity attributable to Matador Resources Company


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

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

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Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED

(In thousands)

For the Three Months Ended March 31, 2019



														Total shareholders’ equity attributable to Matador Resources Company


																	Non-controlling interest in subsidiaries			Total shareholders’ equity
	Common Stock			Additional paid-in capital			Accumulated deficit			Treasury Stock
	Shares	Amount		Additional paid-in capital			Accumulated deficit			Shares	Amount
Balance at January 1, 2019	116,375	$	1,164	$	1,924,408		$	(236,277	)	21	$	(415	)	$	1,688,880		$	90,777		$	1,779,657
Issuance of common stock pursuant to employee stock compensation plan	6	—		—			—			—	—			—			—			—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	3	—		—			—			—	—			—			—			—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		5,802			—			—	—			5,802			—			5,802
Stock options exercised, net of options forfeited in net share settlements	210	2		3,109			—			—	—			3,111			—			3,111
Restricted stock forfeited	—	—		—			—			184	(3,170		)	(3,170		)	—			(3,170		)
Contribution related to formation of San Mateo I, net of tax of $3.1 million (see Note 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

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

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Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS — UNAUDITED

(In thousands)



	Three Months Ended March 31,
	2020			2019
Operating activities
Net income (loss)	$	135,083		$	(9,485	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives	(136,430		)	45,719
Depletion, depreciation and amortization	90,707			76,866
Accretion of asset retirement obligations	476			414
Stock-based compensation expense	3,794			4,587
Deferred income tax provision (benefit)	39,957			(1,013		)
Amortization of debt issuance cost	684			643
Changes in operating assets and liabilities
Accounts receivable	36,342			(3,873		)
Lease and well equipment inventory	(1,296		)	(1,465		)
Prepaid expenses and other current assets	174			(936		)
Other long-term assets	1,749			9,809
Accounts payable, accrued liabilities and other current liabilities	(58,562		)	(41,621		)
Royalties payable	384			(7,500		)
Advances from joint interest owners	(3,598		)	(6,297		)
Other long-term liabilities	(92		)	(6,608		)
Net cash provided by operating activities	109,372			59,240
Investing activities
Oil and natural gas properties capital expenditures	(173,994		)	(182,288		)
Midstream capital expenditures	(73,439		)	(33,340		)
Expenditures for other property and equipment	(787		)	(807		)
Proceeds from sale of assets	—			1,555
Net cash used in investing activities	(248,220		)	(214,880		)
Financing activities
Borrowings under Credit Agreement	60,000			100,000
Borrowings under San Mateo Credit Facility	19,500			—
Cost to amend Credit Agreement	(660		)	—
Proceeds from stock options exercised	45			3,150
Contributions related to formation of San Mateo I	14,700			14,700
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	50,000			12,330
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(11,515		)	(8,330		)
Taxes paid related to net share settlement of stock-based compensation	(1,336		)	(3,208		)
Cash paid under financing lease obligations	(219		)	(274		)
Net cash provided by financing activities	130,515			118,368
Decrease in cash and restricted cash	(8,333		)	(37,272		)
Cash and restricted cash at beginning of period	65,128			83,984
Cash and restricted cash at end of period	$	56,795		$	46,712

Supplemental disclosures of cash flow information (Note 10)

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

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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 March 31, 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 months ended March 31, 2020 and 2019 (in thousands).



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

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Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued



	Three Months Ended March 31,
	2020		2019
Oil revenues	$	169,585	$	154,204
Natural gas revenues	28,329		39,065
Third-party midstream services revenues	15,830		11,838
Sales of purchased natural gas	10,544		11,231
Total revenues from contracts with customers	$	224,288	$	216,338

Property and Equipment

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

The Company capitalized approximately $8.2 million and $8.4 million of its general and administrative costs and approximately $1.4 million and $1.6 million of its interest expense for the three months ended March 31, 2020 and 2019, respectively.

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 months ended March 31, 2020 and 2019 (in thousands).



	Three Months Ended March 31,
	2020	2019
Weighted average common shares outstanding
Basic	116,607	115,315
Dilutive effect of options and restricted stock units	77	—
Diluted weighted average common shares outstanding	116,684	115,315

A total of 2.7 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the three months ended March 31, 2020 because their effects were anti-dilutive. A total of 2.8 million options to purchase shares of Matador’s common stock and 0.4 million restricted stock units were excluded from the diluted weighted average common shares outstanding for the three months ended March 31, 2019 because their effects were anti-dilutive. Additionally, 0.8 million restricted shares, which are participating securities, were excluded from the calculations above for the three months ended March 31, 2019, as the security holders do not have the obligation to share in the losses of the Company.

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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 three months ended March 31, 2020 (in thousands).



Beginning asset retirement obligations	$	36,211
Liabilities incurred during period	990
Liabilities settled during period	(44		)
Accretion expense	476
Ending asset retirement obligations	37,633
Less: current asset retirement obligations⁽¹⁾	(515		)
Long-term asset retirement obligations	$	37,118

_______________


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

NOTE 4 — DEBT

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

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

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. 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 March 31, 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 March 31, 2020, the lender commitments under the San Mateo Credit Facility were $375.0 million.

The San Mateo Credit Facility requires San Mateo I to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo I to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo I’s consolidated interest expense, of 2.50 or more. The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at March 31, 2020.

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Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 4 — DEBT — Continued

Senior Unsecured Notes

At March 31, 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 months ended March 31, 2020 and 2019 were 24% and 33%, respectively. The Company’s total income tax provision for the three months ended March 31, 2020 and 2019 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of permanent differences between book and tax income and state taxes, primarily in New Mexico.

NOTE 6 — EQUITY

Stock-based Compensation

In March 2020, the Company granted awards to certain of its employees of 601,210 service-based restricted stock units to be settled in cash, which are liability instruments, and 601,210 performance-based stock units, which are equity instruments. The performance-based stock units vest in an amount between zero and 200% of the target units granted based on the Company’s relative total shareholder return over the three-year period ending December 31, 2022, as compared to a designated peer group. The service-based restricted stock units vest ratably over three years, and the performance-based stock units are eligible to vest after completion of the three-year performance period. The fair value of these awards was approximately $2.5 million on the grant date.

San Mateo II

On February 25, 2019, the Company announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) designed to expand the Company’s midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by the Company and 49% by Five Point. In addition, Five Point has committed to pay $125 million of the first $150 million of capital expenditures incurred by San Mateo II to develop facilities in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and the Stateline asset area. During the first quarter of 2019, the Company contributed $1.0 million of property and Five Point contributed $4.0 million of cash to San Mateo II. During the first quarter of 2020, the Company contributed $7.5 million and Five Point contributed $50.0 million of cash, of which $20.6 million was paid to carry Matador’s proportionate interest in San Mateo II and was therefore recorded in “Additional paid-in capital” in the Company’s interim unaudited condensed consolidated balance sheet, net of the $4.3 million deferred tax impact to Matador related to this equity contribution. In addition, the Company has the ability to earn up to $150.0 million in deferred performance incentives over the next several years, plus additional performance incentives for securing volumes from third-party customers.

Performance Incentives

In connection with the formation of San Mateo I in 2017, the Company has the ability to earn a total of $73.5 million in performance incentives to be paid by Five Point over a five-year period. The Company earned, and Five Point paid to the Company, $14.7 million in performance incentives during each of the three months ended March 31, 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 three months ended March 31, 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 March 31, 2020, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil 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 March 31, 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 or natural gas liquids (“NGL”) prices at March 31, 2020.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

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



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

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



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

At March 31, 2020, the Company had an aggregate asset value for open derivative financial instruments of $132.6 million.

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

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of March 31, 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
March 31, 2020
Current assets	$	321,607		$	(200,428	)	$	121,179
Other assets	296,261			(284,890		)	11,371
Current liabilities	(200,428		)	200,428			—
Long-term liabilities	(284,890		)	284,890			—
Total	$	132,550		$	—		$	132,550
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	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

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



		Three Months Ended March 31,
Type of Instrument	Location in Condensed Consolidated Statement of Operations	2020		2019
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	10,867	$	3,366
Natural Gas	Revenues: Realized loss on derivatives	—		(96		)
Realized gain on derivatives		10,867		3,270
Oil	Revenues: Unrealized gain (loss) on derivatives	136,430		(45,444		)
Natural Gas	Revenues: Unrealized loss on derivatives	—		(275		)
Unrealized gain (loss) on derivatives		136,430		(45,719		)
Total		$	147,297	$	(42,449	)

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

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

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



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

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



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

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



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

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



	Fair Value Measurements at March 31, 2020 using
Description	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
Oil derivatives and basis swaps	$	—	$	132,550	$	—	$	132,550
Total	$	—	$	132,550	$	—	$	132,550



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

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

Other Fair Value Measurements

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

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

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UNAUDITED — CONTINUED

NOTE 8 — FAIR VALUE MEASUREMENTS — Continued

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

NOTE 9 — COMMITMENTS AND CONTINGENCIES

Processing, Transportation and Salt Water Disposal Commitments

Firm Commitments

From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and salt water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and, in the case of salt water, disposal. The Company paid approximately $11.0 million and $6.8 million for deliveries under these agreements during the three months ended March 31, 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 March 31, 2020, the total deficiencies required to be paid by the Company under these agreements would be approximately $398.1 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 upon construction and completion of a pipeline extension and a fractionation facility by the counterparty, which is currently expected to be completed in 2020. The Company has no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the Company would not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company would have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven-year commitment period, it would be required to pay a deficiency fee per gallon of NGL below the Company’s commitment. Should the pipeline extension and fractionation facility be completed on or prior to February 28, 2021, the minimum contractual obligation during the seven-year period would be approximately $129.2 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 the third quarter 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 March 31, 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 March 31, 2020 was approximately $361.1 million.

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Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 9 — COMMITMENTS AND CONTINGENCIES — Continued

In June 2019, a subsidiary of San Mateo II entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed in service in 2020. San Mateo II’s total commitments under this agreement are $80.6 million. San Mateo II paid approximately $21.1 million under this agreement during the three months ended March 31, 2020. As of March 31, 2020, the remaining obligations of San Mateo II under this agreement were $19.4 million, which are expected to be paid within the next 12 months.

Legal Proceedings

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

NOTE 10 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

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



	March 31, 2020		December 31, 2019
Accrued evaluated and unproved and unevaluated property costs	$	107,173	$	72,376
Accrued midstream properties costs	40,781		46,402
Accrued lease operating expenses	20,849		18,223
Accrued interest on debt	2,861		18,569
Accrued asset retirement obligations	515		619
Accrued partners’ share of joint interest charges	18,202		14,322
Accrued payable related to purchased natural gas	1,770		17,806
Other	5,154		12,378
Total accrued liabilities	$	197,305	$	200,695

Supplemental Cash Flow Information

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



	Three Months Ended March 31,
	2020			2019
Cash paid for interest expense, net of amounts capitalized	$	35,461		$	35,326
Increase in asset retirement obligations related to mineral properties	$	738		$	445
Increase in asset retirement obligations related to midstream properties	$	213		$	—
Increase in liabilities for oil and natural gas properties capital expenditures	$	34,602		$	16,184
Decrease in liabilities for midstream properties capital expenditures	$	(5,579	)	$	(3,908	)
Stock-based compensation (benefit) expense recognized as liability	$	(1,411	)	$	605
Transfer of inventory from oil and natural gas properties	$	401		$	250

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Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 10 — SUPPLEMENTAL DISCLOSURES — Continued

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



	Three Months Ended March 31,
	2020		2019
Cash	$	27,063	$	20,758
Restricted cash	29,732		25,954
Total cash and restricted cash	$	56,795	$	46,712

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
	Exploration and Production		Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Three Months Ended March 31, 2020
Oil and natural gas revenues	$	196,795	$	1,119	$	—		$	—		$	197,914
Midstream services revenues	—		37,749		—			(21,919		)	15,830
Sales of purchased natural gas	3,595		6,949		—			—			10,544
Realized gain on derivatives	10,867		—		—			—			10,867
Unrealized gain on derivatives	136,430		—		—			—			136,430
Expenses⁽¹⁾	161,325		24,330		14,317			(21,919		)	178,053
Operating income (loss)⁽²⁾	$	186,362	$	21,487	$	(14,317	)	$	—		$	193,532
Total assets	$	3,571,257	$	715,413	$	47,001		$	—		$	4,333,671
Capital expenditures⁽³⁾	$	209,735	$	68,073	$	787		$	—		$	278,595

_____________________


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


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


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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —

UNAUDITED — CONTINUED

NOTE 11 — SEGMENT INFORMATION — Continued



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Three Months Ended March 31, 2019
Oil and natural gas revenues	$	191,663		$	1,606	$	—		$	—		$	193,269
Midstream services revenues	—			30,254		—			(18,416		)	11,838
Sales of purchased natural gas	—			11,231		—			—			11,231
Realized gain on derivatives	3,270			—		—			—			3,270
Unrealized loss on derivatives	(45,719		)	—		—			—			(45,719		)
Expenses⁽¹⁾	141,980			25,834		16,950			(18,416		)	166,348
Operating income (loss)⁽²⁾	$	7,234		$	17,257	$	(16,950	)	$	—		$	7,541
Total assets	$	3,043,375		$	477,836	$	62,087		$	—		$	3,583,298
Capital expenditures⁽³⁾	$	197,611		$	29,432	$	807		$	—		$	227,850

_____________________


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


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


(3)	Includes $23.1 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $13.7 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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 March 31, 2020, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes.

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



Condensed Consolidating Balance Sheet March 31, 2020
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	1,595,484	$	13,440	$	—	$	(1,608,924	)	$	—
Current assets	7,024		41,840		307,771		—			356,635
Net property and equipment	—		648,361		3,238,872		—			3,887,233
Investment in subsidiaries	1,516,219		—		170,552		(1,686,771		)	—
Long-term assets	—		2,855		97,278		(10,330		)	89,803
Total assets	$	3,118,727	$	706,496	$	3,814,473	$	(3,306,025	)	$	4,333,671
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	—	$	1,608,924	$	(1,608,924	)	$	—
Current liabilities	2,867		52,782		305,123		(874		)	359,898
Senior unsecured notes payable	1,039,811		—		—		—			1,039,811
Other long-term liabilities	84,700		320,131		384,207		(9,456		)	779,582
Total equity attributable to Matador Resources Company	1,991,349		170,552		1,516,219		(1,686,771		)	1,991,349
Non-controlling interest in subsidiaries	—		163,031		—		—			163,031
Total liabilities and equity	$	3,118,727	$	706,496	$	3,814,473	$	(3,306,025	)	$	4,333,671



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 March 31, 2020
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	45,319		$	347,687	$	(21,421	)	$	371,585
Total expenses	921			23,794			174,759		(21,421		)	178,053
Operating (loss) income	(921		)	21,525			172,928		—			193,532
Interest expense	(17,375		)	(2,437		)	—		—			(19,812		)
Other income	—			—			1,320		—			1,320
Earnings in subsidiaries	183,982			—			9,734		(193,716		)	—
Income before income taxes	165,686			19,088			183,982		(193,716		)	175,040
Total income tax provision	39,957			—			—		—			39,957
Net income attributable to non-controlling interest in subsidiaries	—			(9,354		)	—		—			(9,354		)
Net income attributable to Matador Resources Company shareholders	$	125,729		$	9,734		$	183,982	$	(193,716	)	$	125,729



Condensed Consolidating Statement of Operations For the Three Months Ended March 31, 2019
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	42,876		$	149,248		$	(18,235	)	$	173,889
Total expenses	1,035			25,505			158,043			(18,235		)	166,348
Operating (loss) income	(1,035		)	17,371			(8,795		)	—			7,541
Interest expense	(15,787		)	(2,142		)	—			—			(17,929		)
Other expense	—			—			(110		)	—			(110		)
(Loss) earnings in subsidiaries	(1,138		)	—			7,767			(6,629		)	—
(Loss) income before income taxes	(17,960		)	15,229			(1,138		)	(6,629		)	(10,498		)
Total income tax benefit	(1,013		)	—			—			—			(1,013		)
Net income attributable to non-controlling interest in subsidiaries	—			(7,462		)	—			—			(7,462		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(16,947	)	$	7,767		$	(1,138	)	$	(6,629	)	$	(16,947	)



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



Condensed Consolidating Statement of Cash Flows For the Three Months Ended March 31, 2019
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries		Consolidated
Net cash (used in) provided by operating activities	$	(109	)	$	32,616		$	26,733		$	—	$	59,240
Net cash used in investing activities	—			(29,988		)	(184,892		)	—		(214,880		)
Net cash provided by financing activities	—			3,968			114,400			—		118,368
(Decrease) Increase in cash and restricted cash	(109		)	6,596			(43,759		)	—		(37,272		)
Cash and restricted cash at beginning of period	456			18,840			64,688			—		83,984
Cash and restricted cash at end of period	$	347		$	25,436		$	20,929		$	—	$	46,712

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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” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

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

Cautionary Note Regarding Forward-Looking Statements

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

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; 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, increases in our borrowing base and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the impact of the novel coronavirus pandemic 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;


•	our drilling of wells;

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


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


•	our marketing of oil and natural gas;


•	our exploitation projects or property acquisitions;


•	the integration of acquisitions with our business;


•	our ability and the ability of San Mateo to construct and operate midstream facilities, including the operation 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 the novel coronavirus on the oil and natural gas industry and our business;


•	our future operating results; and


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

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

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

Overview

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

First Quarter Highlights

For the three months ended March 31, 2020, our total oil equivalent production was 6.5 million BOE, and our average daily oil equivalent production was 71,200 BOE per day, of which 40,600 Bbl per day, or 57%, was oil and 183.2 MMcf per day, or 43%, was natural gas. Our oil production of 3.7 million Bbl for the three months ended March 31, 2020 increased 19% year-over-year from 3.1 million Bbl for the three months ended March 31, 2019. Our natural gas production of 16.7 Bcf for the three months ended March 31, 2020 increased 22% year-over-year from 13.7 Bcf for the three months ended March 31, 2019.

For the first quarter of 2020, we reported net income attributable to Matador shareholders of approximately $125.7 million, or $1.08 per diluted common share, on a generally accepted accounting principles in the United States (“GAAP”) basis, as compared to a net loss attributable to Matador shareholders of $16.9 million, or $0.15 per diluted common share, for the first quarter of 2019. For the first quarter of 2020, our Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was $140.6 million, as compared to Adjusted EBITDA of $124.8 million during the first quarter of 2019. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and

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net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for the first quarter of 2020, see “— Results of Operations” below.

Operations Update

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

We began 2020 operating six drilling rigs in the Delaware Basin, as we continued 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 one operated drilling rig from our Wolf asset area in Loving County, Texas late in the first quarter of 2020, and we released 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. We anticipate releasing one additional drilling rig by the end of the second quarter of 2020. Thereafter, we expect to operate three drilling rigs in the Delaware Basin throughout the remainder of 2020. Two of these rigs are anticipated to operate in our Stateline asset area in Eddy County, New Mexico, and the third rig is expected to operate primarily in the Rustler Breaks and Antelope Ridge asset areas.

We completed and turned to sales a total of 36 gross (15.9 net) wells in the Delaware Basin during the first quarter of 2020, including 17 gross (15.6 net) operated horizontal wells and 19 gross (0.3 net) non-operated horizontal wells. During the first quarter of 2020, we completed and turned to sales a total of 17 gross (10.5 net) wells in the Antelope Ridge asset area, including 11 gross (10.4 net) operated wells and six gross (0.1 net) non-operated wells. The 11 gross operated wells turned to sales in the Antelope Ridge asset area included two Avalon completions, one First Bone Spring completion, four Second Bone Spring completions, one Third Bone Spring completion, two Wolfcamp A completions and one Wolfcamp B completion. These wells also included the first six gross (6.0 net) “Rodney Robinson” wells completed in the western portion of the Antelope Ridge asset area. The 1,200 gross and net acre Rodney Robinson tract is one of the key tracts we acquired in the BLM New Mexico Oil and Gas Lease Sale in September 2018 (the “BLM Acquisition”). These six Rodney Robinson wells, all two-mile laterals, were also the first wells drilled and completed on the 8,400 gross and net acres we acquired in the BLM Acquisition.

In the Rustler Breaks asset area, we began producing oil and natural gas from a total of 16 gross (2.8 net) wells, including three gross (2.6 net) operated wells and 13 gross (0.2 net) non-operated wells. Of the three gross operated wells completed and turned to sales in the Rustler Breaks asset area, two were Wolfcamp A completions and one was a Wolfcamp B completion. In the Wolf and Jackson Trust asset areas, we began producing oil and natural gas from three gross (2.6 net) operated wells during the first quarter of 2020, all of which were Wolfcamp A completions.

Our total Delaware Basin production for the first quarter of 2020 was 60,300 BOE per day, consisting of 38,500 Bbl of oil per day and 130.9 MMcf of natural gas per day, a 15% increase from production of 52,600 BOE per day, consisting of 32,000 Bbl of oil per day and 123.9 MMcf of natural gas per day, in the first quarter of 2019. The Delaware Basin contributed approximately 95% of our daily oil production and approximately 71% of our daily natural gas production in the first quarter of 2020, as compared to approximately 93% of our daily oil production and approximately 81% of our daily natural gas production in the first quarter of 2019.

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

Borrowing Base Increased

In February 2020, the lenders party to our reserves-based revolving credit facility (the “Credit Agreement”) 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. We also added two new banks to our lending group as part of this redetermination process. 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.

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2020 Capital Expenditure Budget

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, as we plan to reduce our operated drilling program from six rigs to three rigs by June 30, 2020, as noted above. At April 29, 2020, the range of our estimated 2020 midstream capital expenditures remained $85.0 to $105.0 million. See “— Liquidity and Capital Resources — 2020 Capital Expenditure Budget” for more information.

Restructuring of Derivative Financial Instruments

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 remain at currently depressed levels for the remainder of 2020 or should further market disruptions occur. As a result of these modifications, we almost doubled our oil volumes hedged for the period from April through December 2020. At April 29, 2020, we had approximately 10.3 million Bbl of oil hedged for the period from April through December 2020. These restructured derivative financial instruments include approximately 7.6 million Bbl of fixed-price oil swaps at a weighted average price of approximately $35 per Bbl and 2.3 million Bbl of oil collars with a weighted average floor price of approximately $48 per Bbl and a weighted average ceiling price of approximately $66 per Bbl. We also have approximately 0.4 million Bbl in oil put options, which represent options to sell at a specified exercise price, at a weighted average price of approximately $48 per Bbl for the period from April through June 2020.

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

Critical Accounting Policies

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

Recent Accounting Pronouncements

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

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Results of Operations

Revenues

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



	Three Months Ended March 31,
	2020		2019
Operating Data:
Revenues (in thousands):⁽¹⁾
Oil	$	169,585	$	154,204
Natural gas	28,329		39,065
Total oil and natural gas revenues	197,914		193,269
Third-party midstream services revenues	15,830		11,838
Sales of purchased natural gas	10,544		11,231
Realized gain on derivatives	10,867		3,270
Unrealized gain (loss) on derivatives	136,430		(45,719		)
Total revenues	$	371,585	$	173,889
Net Production Volumes:⁽¹⁾
Oil (MBbl)⁽²⁾	3,697		3,107
Natural gas (Bcf)⁽³⁾	16.7		13.7
Total oil equivalent (MBOE)⁽⁴⁾	6,476		5,395
Average daily production (BOE/d)⁽⁵⁾	71,161		59,941
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	45.87	$	49.64
Oil, with realized derivatives (per Bbl)	$	48.81	$	50.72
Natural gas, without realized derivatives (per Mcf)	$	1.70	$	2.85
Natural gas, with realized derivatives (per Mcf)	$	1.70	$	2.84

_________________


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


(2)	One thousand 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 March 31, 2020 as Compared to Three Months Ended March 31, 2019

Oil and natural gas revenues. Our oil and natural gas revenues increased $4.6 million, or 2%, to $197.9 million for the three months ended March 31, 2020, as compared to $193.3 million for the three months ended March 31, 2019. Our oil revenues increased $15.4 million, or 10%, to $169.6 million for the three months ended March 31, 2020, as compared to $154.2 million for the three months ended March 31, 2019. The increase in oil revenues resulted from the 19% increase in our oil production to 3.7 million Bbl of oil for the three months ended March 31, 2020, as compared to 3.1 million Bbl of oil for the three months ended March 31, 2019. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. This increase was partially offset by a lower weighted average oil price realized for the three months ended March 31, 2020 of $45.87 per Bbl, a decrease of 8% as compared to $49.64 per Bbl realized for the three months ended March 31, 2019. Our natural gas revenues decreased by $10.7 million, or 27%, to $28.3 million for the three months ended March 31, 2020, as compared to $39.1 million for the three months ended March 31, 2019. The decrease in natural gas revenues resulted from a 40% decrease in realized natural gas prices to $1.70 per Mcf for the three months ended March 31, 2020, as compared to $2.85 per Mcf realized for the three months ended March 31, 2019. This decrease was partially offset by the 22% increase in our natural gas production to 16.7 Bcf for the three months ended March 31, 2020, as compared to 13.7 Bcf for the three months ended March 31, 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.

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

Sales of purchased natural gas. Our sales of purchased natural gas decreased $0.7 million, or 6%, to $10.5 million for the three months ended March 31, 2020, as compared to $11.2 million for the three months ended March 31, 2019. The decrease was the result of a decrease in both the volume sold and the weighted average natural gas price realized for the three months ended March 31, 2020. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas, process the 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.

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

Unrealized gain (loss) on derivatives. Our unrealized net gain on derivatives was $136.4 million for the three months ended March 31, 2020, as compared to an unrealized net loss of $45.7 million for the three months ended March 31, 2019. During the three months ended March 31, 2020, the net fair value of our open oil and natural gas derivative contracts increased to a net asset of $132.6 million from a net liability of $3.9 million at December 31, 2019, resulting in an unrealized gain on derivatives of $136.4 million for the three months ended March 31, 2020. During the three months ended March 31, 2019, the net fair value of our open oil and natural gas derivative contracts decreased to a net asset of $4.1 million from a net asset of $49.8 million at December 31, 2018, resulting in an unrealized loss on derivatives of $45.7 million for the three months ended March 31, 2019.

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Expenses

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



	Three Months Ended March 31,
(In thousands, except expenses per BOE)	2020			2019
Expenses:
Production taxes, transportation and processing	$	21,716		$	19,665
Lease operating	30,910			31,163
Plant and other midstream services operating	9,964			9,316
Purchased natural gas	8,058			10,634
Depletion, depreciation and amortization	90,707			76,866
Accretion of asset retirement obligations	476			414
General and administrative	16,222			18,290
Total expenses	178,053			166,348
Operating income	193,532			7,541
Other income (expense):
Interest expense	(19,812		)	(17,929		)
Other income (expense)	1,320			(110		)
Total other expense	(18,492		)	(18,039		)
Income (loss) before income taxes	175,040			(10,498		)
Total income tax provision (benefit)	39,957			(1,013		)
Net income attributable to non-controlling interest in subsidiaries	(9,354		)	(7,462		)
Net income (loss) attributable to Matador Resources Company shareholders	$	125,729		$	(16,947	)
Expenses per BOE:
Production taxes, transportation and processing	$	3.35		$	3.65
Lease operating	$	4.77		$	5.78
Plant and other midstream services operating	$	1.54		$	1.73
Depletion, depreciation and amortization	$	14.01		$	14.25
General and administrative	$	2.51		$	3.39

Three Months Ended March 31, 2020 as Compared to Three Months Ended March 31, 2019

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

Lease operating. Our lease operating expenses decreased $0.3 million, or 1%, to $30.9 million for the three months ended March 31, 2020, as compared to $31.2 million for the three months ended March 31, 2019. This decrease was largely attributable to decreases in equipment rental and workover expenses of $1.7 million, as well as a decrease in saltwater disposal expenses of $4.3 million associated with connecting more wells to salt water disposal pipelines. These decreases were largely offset by increases in compression, repairs and other expenses of $5.7 million. On a unit-of-production basis, our lease operating expenses decreased 17% to $4.77 per BOE for the three months ended March 31, 2020, as compared to $5.78 per BOE for the three months ended March 31, 2019. This decrease was attributable to the 20% increase in our total oil equivalent production to 6.5 million BOE for the three months ended March 31, 2020, as compared to 5.4 million BOE for the three months ended March 31, 2019.

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Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $0.6 million, or 7%, to $10.0 million for the three months ended March 31, 2020, as compared to $9.3 million for the three months ended March 31, 2019. This increase was primarily attributable to increased expenses associated with our expanded commercial salt water disposal operations of $5.1 million for the three months ended March 31, 2020, as compared to $4.3 million for the three months ended March 31, 2019.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $13.8 million, or 18%, to $90.7 million for the three months ended March 31, 2020, as compared to $76.9 million for the three months ended March 31, 2019. This increase was primarily attributable to (i) the 20% increase in our total oil equivalent production to 6.5 million BOE for the three months ended March 31, 2020, as compared to 5.4 million BOE for the three months ended March 31, 2019, and (ii) increased depreciation expenses attributable to our midstream segment of $4.8 million for the three months ended March 31, 2020, as compared to $3.7 million for the three months ended March 31, 2019. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 2% to $14.01 per BOE for the three months ended March 31, 2020, as compared to $14.25 per BOE for the three months ended March 31, 2019. On a unit-of-production basis, the impact of the higher total proved oil and natural gas reserves at March 31, 2020, as compared to March 31, 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 March 31, 2020, as compared to the three months ended March 31, 2019.

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

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

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

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

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of $19.6 million. We capitalized $1.6 million of our interest expense on certain qualifying projects for the three months ended March 31, 2019 and expensed the remaining $17.9 million to operations.

Total income tax provision. We recorded a total income tax expense of $40.0 million for the three months ended March 31, 2020, which 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 taxable income and state taxes, primarily in New Mexico. The effective tax rate for the three months ended March 31, 2020 was 24%. We recorded a total income tax benefit of $1.0 million for the three months ended March 31, 2019, and the effective tax rate was 33%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax loss due primarily to the impact of permanent differences between book and tax loss.

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 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). In addition, in 2020, we expect to receive the remaining portion of the $50.0 million capital carry Five Point agreed to provide to us in conjunction with the formation of San Mateo II. We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, 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.

In February 2020, the lenders under the 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. We also added two new banks to our lending group as part of this redetermination process. 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. 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 March 31, 2020.

At March 31, 2020, we had cash totaling approximately $27.1 million and restricted cash totaling approximately $29.7 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 March 31, 2020, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $315.0 million in borrowings outstanding under the Credit Agreement and (iii) approximately $46.0 million in outstanding letters of credit issued pursuant to the Credit Agreement. Between March 31 and April 29, 2020, we borrowed an additional $30.0 million under the Credit Agreement.

At March 31, 2020, San Mateo had $307.5 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the 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 March 31, 2020, the lender commitments under the San Mateo Credit Facility were $375.0 million. The San Mateo Credit Facility is guaranteed by San Mateo I’s subsidiaries, secured by substantially all of San Mateo I’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries. The San Mateo Credit Facility requires San Mateo I to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo I to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo I’s consolidated interest expense for such period, of 2.50 or more. The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at March 31, 2020.

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2020 Capital Expenditure Budget

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

We began 2020 operating six drilling rigs in the Delaware Basin, as we continued 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 one operated drilling rig from our Wolf asset area in Loving County, Texas late in the first quarter of 2020, and we released a second operated drilling rig from the Greater Stebbins Area in late April 2020. We anticipate releasing one additional drilling rig by the end of the second quarter of 2020. Thereafter, 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 in Eddy County, New Mexico, and the third rig is expected to operate primarily in the Rustler Breaks and Antelope Ridge asset areas.

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 million to $235.0 million and also accounts for the remaining portions of the $50.0 million capital carry that Five Point agreed to provide 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

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during the first quarter of 2020. As of April 29, 2020, WTI oil prices were below $20 per Bbl and were anticipated to remain below $30 per Bbl for the remainder of 2020. For further discussion of our expectations of such commodity prices, see “— General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 7 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments.

Our unaudited cash flows for the three months ended March 31, 2020 and 2019 are presented below:



	Three Months Ended March 31,
(In thousands)	2020			2019
Net cash provided by operating activities	$	109,372		$	59,240
Net cash used in investing activities	(248,220		)	(214,880		)
Net cash provided by financing activities	130,515			118,368
Net change in cash and restricted cash	$	(8,333	)	$	(37,272	)
Adjusted EBITDAattributable to Matador Resources Company shareholders⁽¹⁾	$	140,576		$	124,839

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(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 $50.1 million to $109.4 million for the three months ended March 31, 2020 from $59.2 million for the three months ended March 31, 2019. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $134.3 million for the three months ended March 31, 2020 from $117.7 million for the three months ended March 31, 2019, primarily attributable to higher oil and natural gas production, which was partially offset by lower realized oil and natural gas prices for the three months ended March 31, 2020, as compared to the three months ended March 31, 2019. Changes in our operating assets and liabilities between the two periods resulted in a net increase of approximately $33.6 million in net cash provided by operating activities for the three months ended March 31, 2020, as compared to the three months ended March 31, 2019.

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

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $33.3 million to $248.2 million for the three months ended March 31, 2020 from $214.9 million for the three months ended March 31, 2019. This increase in net cash used in investing activities is due to an increase in midstream capital expenditures of approximately $40.1 million, which was partially offset by a decrease of $8.3 million in oil and natural gas properties capital expenditures for the three months ended March 31, 2020, as compared to the three months ended March 31, 2019. Cash used for midstream capital expenditures for the three months ended March 31, 2020 was primarily attributable to the expansion of the Black River Processing Plant and midstream facilities in the Greater Stebbins Area and the Stateline asset area. Cash used for oil and natural gas properties capital expenditures for the three months ended March 31, 2020 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin.

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Cash Flows Provided by Financing Activities

Net cash provided by financing activities increased by $12.1 million to $130.5 million for the three months ended March 31, 2020 from $118.4 million for the three months ended March 31, 2019. During the three months ended March 31, 2020, our primary sources of cash from financing activities included borrowings under the Credit Agreement of $60.0 million, borrowings under the San Mateo Credit Facility of $19.5 million and net contributions related to the formation of San Mateo I and from non-controlling interest owners in less-than-wholly-owned subsidiaries of $53.2 million. During the three months ended March 31, 2019, we had borrowings under our Credit Agreement of $100.0 million, as well as net contributions related to the formation of San Mateo I and from non-controlling interest owners in less-than-wholly-owned subsidiaries of $18.7 million.

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

Non-GAAP Financial Measures

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

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

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

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



	Three Months Ended March 31,
(In thousands)	2020			2019
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
Net income (loss) attributable to Matador Resources Company shareholders	$	125,729		$	(16,947	)
Net income attributable to non-controlling interest in subsidiaries	9,354			7,462
Net income (loss)	135,083			(9,485		)
Interest expense	19,812			17,929
Total income tax provision (benefit)	39,957			(1,013		)
Depletion, depreciation and amortization	90,707			76,866
Accretion of asset retirement obligations	476			414
Unrealized (gain) loss on derivatives	(136,430		)	45,719
Stock-based compensation expense	3,794			4,587
Consolidated Adjusted EBITDA	153,399			135,017
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(12,823		)	(10,178		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	140,576		$	124,839



	Three Months Ended March 31,
(In thousands)	2020			2019
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	109,372		$	59,240
Net change in operating assets and liabilities	24,899			58,491
Interest expense, net of non-cash portion	19,128			17,286
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(12,823		)	(10,178		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	140,576		$	124,839

Net income attributable to Matador shareholders increased by $142.7 million to $125.7 million for the three months ended March 31, 2020, as compared to a net loss of $16.9 million for the three months ended March 31, 2019. This increase in net income attributable to Matador shareholders is primarily attributable to an increase of $182.1 million in unrealized gain on derivatives, from an unrealized loss of $45.7 million for the three months ended March 31, 2019 to an unrealized gain of $136.4 million for the three months ended March 31, 2020. This increase was partially offset by a $41.0 million increase in the deferred income tax provision. In addition, net income was positively impacted by higher oil and natural gas production, which was partially offset by lower realized oil and natural gas prices for the three months ended March 31, 2020, as compared to the three months ended March 31, 2019.

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

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of March 31, 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.

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Obligations and Commitments

We had the following material contractual obligations and commitments at March 31, 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⁾	$	677,528	$	—	$	—	$	677,528	$	—
Senior unsecured notes⁽²⁾	1,050,000		—		—		—		1,050,000
Office leases	25,382		3,997		8,080		8,564		4,741
Non-operated drilling and other capital commitments⁽³⁾	64,449		30,746		20,000		13,703		—
Drilling rig contracts⁽⁴⁾	37,444		28,845		8,599		—		—
Asset retirement obligations⁽⁵⁾	37,633		515		3,379		1,995		31,744
Natural gas transportation, gathering and processing agreements with non-affiliates⁽⁶⁾	634,239		54,977		133,912		134,070		311,280
Gathering, processing and disposal agreements with San Mateo⁽⁷⁾	511,796		—		60,418		163,614		287,764
Natural gas engineering, construction and installation contract⁽⁸⁾	19,416		19,416		—		—		—
Total contractual cash obligations	$	3,057,887	$	138,496	$	234,388	$	999,474	$	1,685,529

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(1)

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


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


(3)	At March 31, 2020, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells.


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


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

(6)

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

(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)

Beginning in June 2019, a subsidiary of San Mateo II entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. See Note 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. For the three months ended March 31, 2020, oil prices averaged $45.78 per Bbl, ranging from a high of $63.27 per Bbl in early January to a low of $20.09 per Bbl in late March, 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: (1) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (2) a sudden, unexpected increase in global oil supply resulting

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

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

We realized a weighted average oil price of $45.87 per Bbl ($48.81 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended March 31, 2020, as compared to $49.64 per Bbl ($50.72 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended March 31, 2019. At April 29, 2020, the NYMEX WTI oil futures contract for the earliest delivery date had decreased significantly from the average price for the first quarter of 2020, settling at $15.06 per Bbl, which was also a significant decrease as compared to $63.50 at April 29, 2019.

Natural gas prices were significantly lower in the first quarter of 2020, as compared to the first quarter of 2019. For the three months ended March 31, 2020, natural gas prices averaged $1.87 per MMBtu, ranging from a high of $2.20 per MMBtu in early January to a low of $1.60 per MMBtu in late March, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $1.70 per Mcf (with no realized gains or losses from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended March 31, 2020, as compared to $2.85 per Mcf ($2.84 with realized losses from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended March 31, 2019. At April 29, 2020, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased from the end of the first quarter of 2020, settling at $1.87 per MMBtu, which was a decrease as compared to $2.59 per MMBtu at April 29, 2019.

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

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

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

The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX 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 March 31, 2020, most of our oil production from the Delaware Basin was

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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. At April 29, 2020, this oil price differential was approximately $2.50 per Bbl, despite being approximately ($6.00) per Bbl earlier in April. It is possible that the differential could turn negative again at certain times during the remainder of 2020. At April 29, 2020, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated oil production for the remainder of 2020 and throughout 2021 and 2022.

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

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

Beginning in late September 2019, as the GCX Pipeline became operational, we began selling a majority of our produced Delaware Basin natural gas at Houston Ship Channel pricing, and we have realized an improvement in the natural gas pricing received despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. Further, approximately 29% of our reported natural gas production in the first quarter 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.

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

We anticipate that the volatility in these oil and natural gas price differentials could persist throughout 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 did during the second quarter of 2019, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. In addition, we have no derivative contracts in place to mitigate our exposure to these natural gas price differentials during 2020.

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

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

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

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

Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, in 2019 and 2020, separate bills were introduced in the New Mexico Senate proposing to add a surtax on natural gas processors and proposing to place a moratorium on hydraulic fracturing. In 2019, New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Although such bills have not passed, 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.

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Except as set forth below, there have been no material changes to the sources and effects of our market risk since December 31, 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 March 31, 2020, The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) were the counterparties for all of our derivative instruments. At April 29, 2020, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and 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 March 31, 2020 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (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 March 31, 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.

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

Item 1A. Risk Factors

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

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

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

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


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


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


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


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


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


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


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


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


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


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


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


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


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


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

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

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

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



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

_________________


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

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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).

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

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

10.3		Fourteenth Amendment to Third Amended and Restated Credit Agreement, dated as of February 27, 2020, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2019).

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

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

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

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

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

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

†		Indicates a management contract or compensatory plan or arrangement.

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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: May 1, 2020	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer



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