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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, 2021
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to            
Commission File Number 001-35410
 _________________________________________________________  
Matador Resources Company
(Exact name of registrant as specified in its charter)
  _________________________________________________________ 
Texas 27-4662601
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
5400 LBJ Freeway, Suite 1500
Dallas, Texas
75240
(Address of principal executive offices) (Zip Code)
(972) 371-5200
(Registrant’s telephone number, including area code)
 _________________________________________________________  
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading symbol(s) Name of each exchange on which registered
Common Stock, par value $0.01 per share MTDR New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.       Yes      No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).      Yes      No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer Accelerated filer
Non-accelerated filer Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).      Yes      No
As of April 28, 2021, there were 116,781,983 shares of the registrant’s common stock, par value $0.01 per share, outstanding.


MATADOR RESOURCES COMPANY
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2021
TABLE OF CONTENTS
  Page
3
3
3
4
5
7
8


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,
2021
December 31,
2020
ASSETS
Current assets
Cash $ 17,924  $ 57,916 
Restricted cash 30,333  33,467 
Accounts receivable
Oil and natural gas revenues 121,825  85,098 
Joint interest billings 43,331  34,823 
Other 11,658  17,212 
Derivative instruments 4,071  6,727 
Lease and well equipment inventory 11,045  10,584 
Prepaid expenses and other current assets 16,677  15,802 
Total current assets 256,864  261,629 
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated 5,407,305  5,295,931 
Unproved and unevaluated 925,259  902,133 
Midstream properties 851,412  841,695 
Other property and equipment 29,802  29,561 
Less accumulated depletion, depreciation and amortization (3,776,414) (3,701,551)
Net property and equipment 3,437,364  3,367,769 
Other assets
Derivative instruments 422  2,570 
Other long-term assets 44,231  55,312 
Total assets $ 3,738,881  $ 3,687,280 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable $ 30,198  $ 13,982 
Accrued liabilities 143,074  119,158 
Royalties payable 71,790  66,049 
Amounts due to affiliates 8,533  4,934 
Derivative instruments 83,805  45,186 
Advances from joint interest owners 7,000  4,191 
Other current liabilities 32,012  37,436 
Total current liabilities 376,412  290,936 
Long-term liabilities
Borrowings under Credit Agreement 340,000  440,000 
Borrowings under San Mateo Credit Facility 334,000  334,000 
Senior unsecured notes payable 1,041,393  1,040,998 
Asset retirement obligations 38,720  37,919 
Deferred income taxes 2,499  — 
Other long-term liabilities 25,324  30,402 
Total long-term liabilities 1,781,936  1,883,319 
Commitments and contingencies (Note 9)
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 shares authorized; 116,871,689 and 116,847,003 shares issued; and 116,779,751 and 116,844,768 shares outstanding, respectively
1,169  1,169 
Additional paid-in capital 2,043,703  2,027,069 
Accumulated deficit (683,973) (741,705)
Treasury stock, at cost, 91,938 and 2,235 shares, respectively
(1,504) (3)
Total Matador Resources Company shareholders’ equity 1,359,395  1,286,530 
Non-controlling interest in subsidiaries 221,138  226,495 
Total shareholders’ equity 1,580,533  1,513,025 
Total liabilities and shareholders’ equity $ 3,738,881  $ 3,687,280 




The accompanying notes are an integral part of these financial statements.
3


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS — UNAUDITED
(In thousands, except per share data)
  Three Months Ended
March 31,
  2021 2020
Revenues
Oil and natural gas revenues $ 316,233  $ 197,914 
Third-party midstream services revenues 15,438  15,830 
Sales of purchased natural gas 4,510  10,544 
Realized (loss) gain on derivatives (25,913) 10,867 
Unrealized (loss) gain on derivatives (43,423) 136,430 
Total revenues 266,845  371,585 
Expenses
Production taxes, transportation and processing 34,174  21,716 
Lease operating 25,939  30,910 
Plant and other midstream services operating 13,663  9,964 
Purchased natural gas 2,855  8,058 
Depletion, depreciation and amortization 74,863  90,707 
Accretion of asset retirement obligations 500  476 
General and administrative 22,188  16,222 
Total expenses 174,182  178,053 
Operating income 92,663  193,532 
Other income (expense)
Interest expense (19,650) (19,812)
Other (expense) income (675) 1,320 
Total other expense (20,325) (18,492)
Income before income taxes 72,338  175,040 
Income tax provision (benefit)
Deferred 2,840  39,957 
Income tax provision 2,840  39,957 
Net income 69,498  135,083 
Net income attributable to non-controlling interest in subsidiaries (8,853) (9,354)
Net income attributable to Matador Resources Company shareholders $ 60,645  $ 125,729 
Earnings per common share
Basic $ 0.52  $ 1.08 
Diluted $ 0.51  $ 1.08 
Weighted average common shares outstanding
Basic 116,807  116,607 
Diluted 118,669  116,684 
The accompanying notes are an integral part of these financial statements.
4

Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED
(In thousands)
For the Three Months Ended March 31, 2021
Total shareholders’ equity attributable to Matador Resources Company
Non-controlling interest in subsidiaries Total shareholders’ equity
  Common Stock Additional
paid-in capital
Accumulated deficit Treasury Stock
  Shares Amount Shares Amount
Balance at January 1, 2021 116,847  $ 1,169  $ 2,027,069  $ (741,705) $ (3) $ 1,286,530  $ 226,495  $ 1,513,025 
Dividends declared ($0.025 per share)
—  —  —  (2,913) —  —  (2,913) —  (2,913)
Issuance of common stock pursuant to employee stock compensation plan —  —  —  —  —  —  —  — 
Issuance of common stock pursuant to directors’ and advisors’
compensation plan
—  —  —  —  —  —  —  — 
Stock-based compensation expense related to equity-based awards including amounts capitalized —  —  1,477  —  —  —  1,477  —  1,477 
Stock options exercised, net of options forfeited in net share settlements 13  —  —  —  —  —  —  —  — 
Restricted stock forfeited —  —  (219) —  90  (1,501) (1,720) —  (1,720)
Contribution related to formation of San Mateo (see Note 6) —  —  15,376  —  —  —  15,376  —  15,376 
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries —  —  —  —  —  —  —  (14,210) (14,210)
Current period net income —  —  —  60,645  —  —  60,645  8,853  69,498 
Balance at March 31, 2021 116,872  $ 1,169  $ 2,043,703  $ (683,973) 92  $ (1,504) $ 1,359,395  $ 221,138  $ 1,580,533 





The accompanying notes are an integral part of these financial statements.
5

Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY — UNAUDITED
(In thousands)
For the Three 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 Shares Amount
Balance at January 1, 2020 116,644  $ 1,166  $ 1,981,014  $ (148,500) $ (26) $ 1,833,654  $ 135,798  $ 1,969,452 
Issuance of common stock pursuant to employee stock compensation plan —  —  —  —  —  —  —  — 
Issuance of common stock pursuant to directors’ and advisors’
compensation plan
—  —  —  —  —  —  —  — 
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  297  —  —  —  298  —  298 
Restricted stock forfeited —  —  —  —  106  (1,267) (1,267) —  (1,267)
Contribution related to formation of San Mateo, net of tax of $3.1 million (see Note 6)
—  —  11,613  —  —  —  11,613  —  11,613 
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $4.3 million (see Note 6)
—  —  16,280  —  —  —  16,280  29,394  45,674 
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries —  —  —  —  —  —  —  (11,515) (11,515)
Current period net income —  —  —  125,729  —  —  125,729  9,354  135,083 
Balance at March 31, 2020 116,671  $ 1,167  $ 2,014,246  $ (22,771) 107  $ (1,293) $ 1,991,349  $ 163,031  $ 2,154,380 




The accompanying notes are an integral part of these financial statements.
6

Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS — UNAUDITED
(In thousands)
  Three Months Ended
March 31,
  2021 2020
Operating activities
Net income $ 69,498  $ 135,083 
Adjustments to reconcile net income to net cash provided by operating activities
Unrealized loss (gain) on derivatives 43,423  (136,430)
Depletion, depreciation and amortization 74,863  90,707 
Accretion of asset retirement obligations 500  476 
Stock-based compensation expense 855  3,794 
Deferred income tax provision 2,840  39,957 
Amortization of debt issuance cost 724  684 
Changes in operating assets and liabilities
Accounts receivable (39,680) 36,342 
Lease and well equipment inventory 112  (1,296)
Prepaid expenses and other current assets (802) 174 
Other long-term assets 19  1,749 
Accounts payable, accrued liabilities and other current liabilities 8,560  (58,562)
Royalties payable 5,741  384 
Advances from joint interest owners 2,809  (3,598)
Other long-term liabilities (67) (92)
Net cash provided by operating activities 169,395  109,372 
Investing activities
Drilling, completion and equipping capital expenditures (85,986) (133,170)
Acquisition of oil and natural gas properties (6,676) (40,824)
Midstream capital expenditures (16,380) (73,439)
Expenditures for other property and equipment (133) (787)
Proceeds from sale of assets 280  — 
Net cash used in investing activities (108,895) (248,220)
Financing activities
Repayments of borrowings under Credit Agreement (100,000) — 
Borrowings under Credit Agreement —  60,000 
Repayments of borrowings under San Mateo Credit Facility (11,000) — 
Borrowings under San Mateo Credit Facility 11,000  19,500 
Cost to amend credit facilities —  (660)
Dividends paid (2,913) — 
Contributions related to formation of San Mateo 15,376  14,700 
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries —  50,000 
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries (14,210) (11,515)
Taxes paid related to net share settlement of stock-based compensation (1,721) (1,336)
Other (158) (174)
Net cash (used in) provided by financing activities (103,626) 130,515 
Decrease in cash and restricted cash (43,126) (8,333)
Cash and restricted cash at beginning of period 91,383  65,128 
Cash and restricted cash at end of period $ 48,257  $ 56,795 
Supplemental disclosures of cash flow information (Note 10)

The accompanying notes are an integral part of these financial statements.
7

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED

NOTE 1 — NATURE OF OPERATIONS
Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates
The interim unaudited condensed consolidated financial statements of the Company have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on February 26, 2021 (the “Annual Report”). The Company consolidates certain subsidiaries and joint ventures that are less than wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification, Consolidation (Topic 810). The Company proportionately consolidates certain joint ventures that are less than wholly-owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all normal, recurring adjustments that are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of March 31, 2021. Amounts as of December 31, 2020 are derived from the Company’s audited consolidated financial statements included in the Annual Report.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s interim unaudited condensed consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
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, 2021 and 2020 (in thousands).
Three Months Ended
March 31,
2021 2020
Revenues from contracts with customers $ 336,181  $ 224,288 
Realized (loss) gain on derivatives (25,913) 10,867 
Unrealized (loss) gain on derivatives (43,423) 136,430 
Total revenues $ 266,845  $ 371,585 
8

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
Three Months Ended
March 31,
2021 2020
Oil revenues $ 213,279  $ 169,585 
Natural gas revenues 102,954  28,329 
Third-party midstream services revenues 15,438  15,830 
Sales of purchased natural gas 4,510  10,544 
Total revenues from contracts with customers $ 336,181  $ 224,288 
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 each of the three months ended March 31, 2021 and 2020, 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 $9.5 million and $8.2 million of its general and administrative costs and approximately $0.6 million and $1.4 million of its interest expense for the three months ended March 31, 2021 and 2020, respectively.
Earnings Per Common Share
The Company reports basic earnings attributable to Matador shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador shareholders per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive.
The following table sets forth the computation of diluted weighted average common shares outstanding for the three months ended March 31, 2021 and 2020 (in thousands).
  Three Months Ended
March 31,
2021 2020
Weighted average common shares outstanding
Basic 116,807  116,607 
Dilutive effect of options and restricted stock units 1,862  77 
Diluted weighted average common shares outstanding 118,669  116,684 
A total of 1.5 million and 2.7 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the three months ended March 31, 2021 and 2020, respectively, because their effects were anti-dilutive.
9

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, 2021 (in thousands).
Beginning asset retirement obligations $ 38,542 
Liabilities incurred during period 166 
Liabilities settled during period (79)
Accretion expense 500 
Ending asset retirement obligations 39,129 
Less: current asset retirement obligations(1)
(409)
Long-term asset retirement obligations $ 38,720 
 _______________
(1)Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at March 31, 2021.
NOTE 4 — DEBT
At March 31, 2021, the Company had (i) $1.05 billion of outstanding senior notes due 2026 (the “Notes”), (ii) $340.0 million in borrowings outstanding under its reserves-based revolving credit facility (the “Credit Agreement”), (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration loan.
At March 31, 2021, San Mateo had $334.0 million in borrowings outstanding under its revolving credit facility (the “San Mateo Credit Facility”) and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between March 31, 2021 and April 28, 2021, San Mateo repaid $19.0 million of borrowings under the San Mateo Credit Facility.
Credit Agreements
MRC Energy Company
The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In April 2021, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. The Company elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and no material changes were made to the terms of the Credit Agreement. This April 2021 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment (subject to compliance with the covenant noted below). The Credit Agreement matures October 31, 2023.
The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 4.00 or less. The Company believes that it was in compliance with the terms of the Credit Agreement at March 31, 2021.
San Mateo Midstream, LLC
The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases to up to $400.0 million, and matures December 19, 2023. At March 31, 2021, the lender commitments under the San Mateo Credit Facility were $375.0 million (subject to San Mateo’s compliance with the covenants noted below).
The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s
10

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 4 — DEBT — Continued
consolidated interest expense, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at March 31, 2021.
Senior Unsecured Notes
At March 31, 2021, the Company had $1.05 billion of outstanding Notes, which have a 5.875% coupon rate. The Notes mature September 15, 2026, and interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company.
NOTE 5 — INCOME TAXES
The Company recorded an income tax provision of $2.8 million for the three months ended March 31, 2021, which resulted in an effective tax rate of 4%. The effective tax rate differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due primarily to recording a net deferred tax liability for state taxes, primarily in New Mexico, and continuing to recognize a valuation allowance against our U.S. federal net deferred tax assets. As a result of the full-cost ceiling impairments recorded in 2020, the Company recognized a valuation allowance against its net deferred tax assets for the year ended December 31, 2020. The valuation allowance will continue to be recognized until the future deferred tax benefits are more likely than not to become utilized.
The Company’s effective tax rate for the three months ended March 31, 2020 was 24%. The Company’s total income tax provision for the three months ended March 31, 2020 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due to the impact of permanent differences between book and tax income, as well as state taxes, primarily in New Mexico.
NOTE 6 — EQUITY
Common Stock Dividend
During the three months ended March 31, 2021, the Company’s Board of Directors (the “Board”) adopted a dividend policy and declared the Company’s first quarterly cash dividend of $0.025 per share of common stock. The dividend, which totaled $2.9 million, was paid on March 31, 2021. In April 2021, the Board declared the Company’s second quarterly cash dividend of $0.025 per share of common stock payable on June 3, 2021 to shareholders of record as of May 13, 2021.
San Mateo Distributions and Contributions
During the three months ended March 31, 2021 and 2020, San Mateo distributed $14.8 million and $12.0 million, respectively, to the Company and $14.2 million and $11.5 million, respectively, to a subsidiary of Five Point Energy LLC, the Company’s joint venture partner (“Five Point”). During the three months ended March 31, 2020, the Company contributed $7.5 million and Five Point contributed $50.0 million of cash to San Mateo, of which $20.6 million was paid to carry Matador’s proportionate interest in San Mateo 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. During the three months ended March 31, 2021, there were no contributions to San Mateo by either the Company or Five Point.
Performance Incentives
Five Point paid to the Company $15.4 million and $14.7 million in performance incentives during the three months ended March 31, 2021 and 2020, respectively. These performance incentives are recorded when received, net of the $3.1 million deferred tax impact to Matador during the three months ended March 31, 2020, in “Additional paid-in capital” in the Company’s interim unaudited condensed consolidated balance sheets. These performance incentives for the three months ended March 31, 2021 and 2020 are also denoted as “Contributions related to formation of San Mateo” under “Financing activities” in the Company’s interim unaudited condensed consolidated statements of cash flows and changes in shareholders’ equity.
NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS
At March 31, 2021, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling for the collars and fixed price for the swaps. At March 31, 2021, each contract was set to expire at
11

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued
varying times during 2021 and 2022. The Company had no open contracts associated with natural gas liquids (“NGL”) prices at March 31, 2021.
The following is a summary of the Company’s open costless collar contracts for oil and natural gas at March 31, 2021.
Commodity Calculation Period Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or $/MMBtu) Weighted Average Price Ceiling ($/Bbl or $/MMBtu) Fair Value of
Asset
(Liability)
(thousands)
Oil 04/01/2021 - 12/31/2021 7,110,000  $ 42.06  $ 55.15  (47,967)
Natural Gas 04/01/2021 - 12/31/2021 32,000,000  $ 2.45  $ 3.65  1,399 
Natural Gas 01/01/2022 - 03/31/2022 3,000,000  $ 2.60  $ 4.22  141 
Total open costless collar contracts $ (46,427)
The following is a summary of the Company’s open swap contracts for oil at March 31, 2021.
Commodity Calculation Period Notional Quantity (Bbl) Fixed Price
($/Bbl)
Fair Value of
Asset
(Liability)
(thousands)
Oil 04/01/2021 - 12/31/2021 1,530,000  $ 35.26  (34,697)
Total open swap contracts $ (34,697)
The following is a summary of the Company’s open basis swap contracts for oil at March 31, 2021.
Commodity Calculation Period Notional Quantity (Bbl) Fixed Price
($/Bbl)
Fair Value of
Asset
(Liability)
(thousands)
Oil Basis 04/01/2021 - 12/31/2021 6,300,000  $ 0.87  1,249 
Oil Basis 01/01/2022 - 12/31/2022 5,520,000  $ 0.95  563 
Total open basis swap contracts $ 1,812 
At March 31, 2021, the aggregate liability value for the Company’s open derivative financial instruments was $79.3 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.
12

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued
The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of March 31, 2021 and December 31, 2020 (in thousands).
Derivative Instruments Gross
amounts
recognized
Gross amounts
netted in the condensed
consolidated
balance sheets
Net amounts presented in the condensed
consolidated
balance sheets
March 31, 2021
Current assets $ 377,949  $ (373,878) $ 4,071 
Other assets 128,755  (128,333) 422 
Current liabilities (457,683) 373,878  (83,805)
Long-term liabilities (128,333) 128,333  — 
Total $ (79,312) $ —  $ (79,312)
December 31, 2020
Current assets $ 382,328  $ (375,601) $ 6,727 
Other assets 150,194  (147,624) 2,570 
Current liabilities (420,787) 375,601  (45,186)
Long-term liabilities (147,624) 147,624  — 
Total $ (35,889) $ —  $ (35,889)
The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the interim unaudited condensed consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.
  Three Months Ended
March 31,
Type of Instrument Location in Condensed Consolidated Statement of Operations 2021 2020
Derivative Instrument
Oil Revenues: Realized (loss) gain on derivatives $ (26,075) $ 10,867 
Natural Gas Revenues: Realized gain on derivatives 162  — 
Realized (loss) gain on derivatives (25,913) 10,867 
Oil Revenues: Unrealized (loss) gain on derivatives (39,269) 136,430 
Natural Gas Revenues: Unrealized loss on derivatives (4,154) — 
Unrealized (loss) gain on derivatives (43,423) 136,430 
Total $ (69,336) $ 147,297 
13

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 8 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.
Level 1    Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.
Level 2    Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3    Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions.
Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of March 31, 2021 and December 31, 2020 (in thousands).
  Fair Value Measurements at
 March 31, 2021 using
Description Level 1 Level 2 Level 3 Total
Assets (Liabilities)
Oil derivatives and basis swaps $ —  $ (80,852) $ —  $ (80,852)
Natural gas derivatives —  1,540  —  1,540 
Total $ —  $ (79,312) $ —  $ (79,312)
  Fair Value Measurements at
December 31, 2020 using
Description Level 1 Level 2 Level 3 Total
Assets (Liabilities)
Oil derivatives and basis swaps $ —  $ (41,584) $ —  $ (41,584)
Natural gas derivatives —  5,695  —  5,695 
Total $ —  $ (35,889) $ —  $ (35,889)
Additional disclosures related to derivative financial instruments are provided in Note 7.
Other Fair Value Measurements
At March 31, 2021 and December 31, 2020, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities.
At March 31, 2021 and December 31, 2020, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy.
14

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 8 — FAIR VALUE MEASUREMENTS — Continued
At March 31, 2021 and December 31, 2020, the fair value of the Notes was $1.02 billion and $1.03 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.
NOTE 9 — COMMITMENTS AND CONTINGENCIES
Processing, Transportation and Produced Water Disposal Commitments
Firm Commitments
From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for transportation, gathering, processing, fractionation, sales and disposal. The Company paid approximately $12.6 million and $11.0 million for deliveries under these agreements during the three months ended March 31, 2021 and 2020, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at March 31, 2021, the total deficiencies required to be paid by the Company under these agreements would be approximately $615.2 million.
San Mateo Commitments
The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at March 31, 2021 was approximately $470.1 million.
Legal Proceedings
The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact on the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

15

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 10 — SUPPLEMENTAL DISCLOSURES
Accrued Liabilities
The following table summarizes the Company’s current accrued liabilities at March 31, 2021 and December 31, 2020 (in thousands).
March 31,
2021
December 31,
2020
Accrued evaluated and unproved and unevaluated property costs $ 87,125  $ 44,012 
Accrued midstream properties costs 5,587  12,776 
Accrued lease operating expenses 23,192  24,276 
Accrued interest on debt 2,825  18,315 
Accrued asset retirement obligations 409  623 
Accrued partners’ share of joint interest charges 9,073  7,407 
Accrued payable related to purchased natural gas 199  418 
Other 14,664  11,331 
Total accrued liabilities $ 143,074  $ 119,158 
Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the three months ended March 31, 2021 and 2020 (in thousands).
  Three Months Ended
March 31,
  2021 2020
Cash paid for interest expense, net of amounts capitalized $ 35,085  $ 35,461 
Increase in asset retirement obligations related to mineral properties $ 105  $ 738 
Increase in asset retirement obligations related to midstream properties $ —  $ 213 
Increase in liabilities for drilling, completion and equipping capital expenditures $ 40,067  $ 35,714 
Increase (decrease) in liabilities for acquisition of oil and natural gas properties $ 2,031  $ (1,112)
Decrease in liabilities for midstream properties capital expenditures $ (6,691) $ (5,579)
Stock-based compensation expense (benefit) recognized as liability $ 7,249  $ (1,411)
Transfer of inventory (to) from oil and natural gas properties $ (574) $ 401 
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,
  2021 2020
Cash $ 17,924  $ 27,063 
Restricted cash 30,333  29,732 
Total cash and restricted cash $ 48,257  $ 56,795 
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
16

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 11 — SEGMENT INFORMATION — Continued
midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and Stateline asset areas and the Greater Stebbins Area in the Delaware Basin, which comprise most of the Company’s midstream operations, are conducted through San Mateo. San Mateo and its subsidiaries are not guarantors of the Notes.
The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.”
Exploration and Production Consolidations and Eliminations Consolidated Company
Midstream Corporate
Three Months Ended March 31, 2021
Oil and natural gas revenues $ 314,646  $ 1,587  $ —  $ —  $ 316,233 
Midstream services revenues —  43,909  —  (28,471) 15,438 
Sales of purchased natural gas 2,462  2,048  —  —  4,510 
Realized loss on derivatives (25,913) —  —  —  (25,913)
Unrealized loss on derivatives (43,423) —  —  —  (43,423)
Expenses(1)
156,444  26,247  19,962  (28,471) 174,182 
Operating income (loss)(2)
$ 91,328  $ 21,297  $ (19,962) $ —  $ 92,663 
Total assets $ 2,881,242  $ 831,239  $ 26,400  $ —  $ 3,738,881 
Capital expenditures(3)
$ 134,865  $ 9,773  $ 133  $ —  $ 144,771 
_____________________
(1)Includes depletion, depreciation and amortization expenses of $66.4 million and $7.8 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.7 million.
(2)Includes $8.9 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
(3)Includes $8.7 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $4.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
UNAUDITED — CONTINUED

NOTE 11 — SEGMENT INFORMATION — Continued
Exploration and Production Consolidations and Eliminations Consolidated Company
Midstream Corporate
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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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our interim unaudited condensed consolidated financial statements and related notes thereto contained herein and the consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2020 (the “Annual Report”) filed with the Securities and Exchange Commission (the “SEC”) on February 26, 2021, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (this “Quarterly Report”), (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries. For certain oil and natural gas terms used in this Quarterly Report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.
Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the impact of the worldwide spread of the novel coronavirus (“COVID-19”) on oil and natural gas demand, oil and natural gas prices and our business; the operating results of San Mateo’s Black River cryogenic natural gas processing plant; the timing and operating results of the buildout by San Mateo of oil, natural gas and water gathering and transportation systems and the drilling of any additional salt water disposal wells; and the other factors discussed below and elsewhere in this Quarterly Report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:
our business strategy;
our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized;
our cash flows and liquidity;
the amount, timing and payment of dividends, if any;
our financial strategy, budget, projections and operating results;
the supply and demand of oil, natural gas and natural gas liquids;
oil, natural gas and natural gas liquids prices, including our realized prices thereof;
the timing and amount of future production of oil and natural gas;
the availability of drilling and production equipment;
the availability of oil storage capacity;
the availability of oil field labor;
the amount, nature and timing of capital expenditures, including future exploration and development costs;
the availability and terms of capital;
our drilling of wells;
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our ability to negotiate and consummate acquisition and divestiture opportunities;
government regulation and taxation of the oil and natural gas industry;
our marketing of oil and natural gas;
our exploitation projects or property acquisitions;
the integration of acquisitions with our business;
our ability and the ability of San Mateo to construct and operate midstream facilities, including the operation of its Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells;
the ability of San Mateo to attract third-party volumes;
our costs of exploiting and developing our properties and conducting other operations;
general economic conditions;
competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;
the effectiveness of our risk management and hedging activities;
our technology;
environmental liabilities;
counterparty credit risk;
developments in oil-producing and natural gas-producing countries;
the impact of COVID-19 on the oil and natural gas industry and our business;
our future operating results; and
our plans, objectives, expectations and intentions contained in this Quarterly Report or in our other filings with the SEC that are not historical.
Although we believe that the expectations conveyed by the forward-looking statements in this Quarterly Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition.
You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
Overview
We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
First Quarter Highlights
For the three months ended March 31, 2021, our total oil equivalent production was 6.7 million BOE, and our average daily oil equivalent production was 74,000 BOE per day, of which 41,500 Bbl per day, or 56%, was oil and 194.7 MMcf per day, or 44%, was natural gas. Our average daily oil production of 41,500 Bbl per day for the three months ended March 31, 2021 increased 2% year-over-year from 40,600 Bbl per day for the three months ended March 31, 2020. Our average daily natural gas production of 194.7 MMcf per day for the three months ended March 31, 2021 increased 6% year-over-year from 183.2 MMcf per day for the three months ended March 31, 2020.
For the first quarter of 2021, we reported net income attributable to Matador shareholders of $60.6 million, or $0.51 per diluted common share, on a generally accepted accounting principles in the United States (“GAAP”) basis, as compared to net income attributable to Matador shareholders of $125.7 million, or $1.08 per diluted common share, for the first quarter of 2020. For the first quarter of 2021, our Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was $198.1 million, as compared to Adjusted EBITDA of $140.6 million during the first quarter of 2020. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by
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operating activities, see “—Liquidity and Capital Resources—Non-GAAP Financial Measures.” For more information regarding our financial results for the three months ended March 31, 2021, see “—Results of Operations” below.
Operations Update
We began 2021 operating three 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. In March 2021, we added a fourth rig to our operated drilling program and currently plan to operate four rigs in the Delaware Basin throughout the remainder of 2021 but have the flexibility to reduce the number of rigs based upon market conditions or other factors. Two of these rigs are anticipated to operate in our Stateline asset area, and two of these rigs are expected to operate primarily in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and in the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area during the remainder of 2021.
We completed and turned to sales a total of 16 gross (6.0 net) wells in the Delaware Basin during the first quarter of 2021, including six gross (5.1 net) operated wells and 10 gross (0.9 net) non-operated wells. During the first quarter of 2021, we completed and turned to sales a total of eight gross (4.0 net) wells in the Antelope Ridge asset area, including four gross (3.8 net) operated wells and four gross (0.2 net) non-operated wells. Of the four gross operated wells completed and turned to sales in the Antelope Ridge asset area, all were on the Rodney Robinson leasehold; two were Wolfcamp A-XY completions and two were Third Bone Spring completions. In the Ranger asset area, we began producing oil and natural gas from two gross (1.3 net) operated wells during the first quarter of 2021, both of which were Second Bone Spring completions. In the Rustler Breaks asset area, we participated in six gross (0.7 net) non-operated wells turned to sales in the first quarter of 2021.
Our average daily oil equivalent production in the Delaware Basin for the first quarter of 2021 was 68,000 BOE per day, consisting of 39,900 Bbl of oil per day and 168.5 MMcf of natural gas per day, a 13% increase from 60,300 BOE per day, consisting of 38,500 Bbl of oil per day and 130.9 MMcf of natural gas per day, in the first quarter of 2020. The Delaware Basin contributed approximately 96% of our daily oil production and approximately 87% of our daily natural gas production in the first quarter of 2021, as compared to approximately 95% of our daily oil production and approximately 71% of our daily natural gas production in the first quarter of 2020.
During the first quarter of 2021, we did not complete and turn to sales any operated or non-operated wells on our leasehold properties in the Eagle Ford shale play in South Texas or in the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
Capital Resources Update
In February 2021, our Board of Directors (the “Board”) adopted a dividend policy and declared our first quarterly cash dividend of $0.025 per share of common stock, which was paid on March 31, 2021. In April 2021, the Board declared our second quarterly cash dividend of $0.025 per share of common stock payable on June 3, 2021 to shareholders of record as of May 13, 2021.
During the first quarter of 2021, we repaid $100.0 million of the borrowings under our third amended and restated credit agreement (the “Credit Agreement”). Our outstanding borrowings under our Credit Agreement at March 31, 2021 were $340.0 million.
In April 2021, the lenders under our Credit Agreement, led by Royal Bank of Canada, completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. The Company elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and no material changes were made to the terms of the Credit Agreement. This April 2021 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment.
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,
  2021 2020
Operating Data
Revenues (in thousands)(1)
Oil $ 213,279  $ 169,585 
Natural gas 102,954  28,329 
Total oil and natural gas revenues 316,233  197,914 
Third-party midstream services revenues 15,438  15,830 
Sales of purchased natural gas 4,510  10,544 
Realized (loss) gain on derivatives (25,913) 10,867 
Unrealized (loss) gain on derivatives (43,423) 136,430 
Total revenues $ 266,845  $ 371,585 
Net Production Volumes(1)
Oil (MBbl)(2)
3,738  3,697 
Natural gas (Bcf)(3)
17.5  16.7 
Total oil equivalent (MBOE)(4)
6,658  6,476 
Average daily production (BOE/d)(5)
73,983  71,161 
Average Sales Prices
Oil, without realized derivatives (per Bbl) $ 57.05  $ 45.87 
Oil, with realized derivatives (per Bbl) $ 50.08  $ 48.81 
Natural gas, without realized derivatives (per Mcf) $ 5.88  $ 1.70 
Natural gas, with realized derivatives (per Mcf) $ 5.89  $ 1.70 
_________________
(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, 2021 as Compared to Three Months Ended March 31, 2020
Oil and natural gas revenues. Our oil and natural gas revenues increased $118.3 million, or 60%, to $316.2 million for the three months ended March 31, 2021, as compared to $197.9 million for the three months ended March 31, 2020. Our oil revenues increased $43.7 million, or 26%, to $213.3 million for the three months ended March 31, 2021, as compared to $169.6 million for the three months ended March 31, 2020. This increase in oil revenues primarily resulted from a 24% increase in the weighted average oil price realized for the three months ended March 31, 2021 to $57.05 per Bbl, as compared to $45.87 per Bbl for the three months ended March 31, 2020. Our natural gas revenues increased $74.6 million, or approximately 3.6-fold, to $103.0 million for the three months ended March 31, 2021, as compared to $28.3 million for the three months ended March 31, 2020. The increase in natural gas revenues primarily resulted from an approximately 3.5-fold increase in the weighted average natural gas price realized for the three months ended March 31, 2021 to $5.88 per Mcf, as compared to a weighted average natural gas price of $1.70 per Mcf realized for the three months ended March 31, 2020. The increase in natural gas revenues was also attributable to the 5% increase in our natural gas production to 17.5 Bcf for the three months ended March 31, 2021, as compared to 16.7 Bcf for the three months ended March 31, 2020.
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Third-party midstream services revenues. Our third-party midstream services revenues decreased $0.4 million, or 2%, to $15.4 million for the three months ended March 31, 2021, as compared to $15.8 million for the three months ended March 31, 2020. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This decrease was primarily attributable to (i) a decrease in our third-party natural gas gathering, transportation and processing revenues to $6.8 million for the three months ended March 31, 2021, as compared to $7.1 million for the three months ended March 31, 2020, and (ii) a decrease in our produced water gathering and disposal revenues to $6.5 million for the three months ended March 31, 2021, as compared to $6.7 million for the three months ended March 31, 2020. These decreases were partially offset by an increase in our third-party oil gathering and transportation revenues to $2.2 million for the three months ended March 31, 2021, as compared to $2.0 million for the three months ended March 31, 2020.
Sales of purchased natural gas. Our sales of purchased natural gas decreased $6.0 million, or 57%, to $4.5 million for the three months ended March 31, 2021, as compared to $10.5 million for the three months ended March 31, 2020. This decrease was primarily the result of a decrease in purchased natural gas volumes sold during the three months ended March 31, 2021. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and subsequently sell the residue gas and natural gas liquids (“NGL”) to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our interim unaudited condensed consolidated statements of operations.
Realized (loss) gain on derivatives. Our realized net loss on derivatives was $25.9 million for the three months ended March 31, 2021, as compared to a realized net gain of $10.9 million for the three months ended March 31, 2020. We realized a net loss of $26.1 million related to our oil costless collar and swap contracts for the three months ended March 31, 2021, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike prices of certain of our oil swap and oil basis swap contracts. We realized a net gain of $0.2 million related to our natural gas costless collar contracts for the three months ended March 31, 2021, resulting primarily from natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average loss on our oil derivatives of approximately $6.97 per Bbl produced during the three months ended March 31, 2021, as compared to an average gain of approximately $2.94 per Bbl produced during the three months ended March 31, 2020.
Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives was $43.4 million for the three months ended March 31, 2021, as compared to an unrealized net gain of $136.4 million for the three months ended March 31, 2020. During the three months ended March 31, 2021, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a net liability of $79.3 million from a net liability of $35.9 million at December 31, 2020, resulting in an unrealized loss on derivatives of $43.4 million for the three months ended March 31, 2021. 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.
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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) 2021 2020
Expenses
Production taxes, transportation and processing $ 34,174  $ 21,716 
Lease operating
25,939  30,910 
Plant and other midstream services operating 13,663  9,964 
Purchased natural gas 2,855  8,058 
Depletion, depreciation and amortization 74,863  90,707 
Accretion of asset retirement obligations 500  476 
General and administrative 22,188  16,222 
Total expenses 174,182  178,053 
Operating income 92,663  193,532 
Other income (expense)
Interest expense (19,650) (19,812)
Other (expense) income (675) 1,320 
Total other expense (20,325) (18,492)
Income before income taxes 72,338  175,040 
Income tax provision 2,840  39,957 
Net income attributable to non-controlling interest in subsidiaries (8,853) (9,354)
Net income attributable to Matador Resources Company shareholders $ 60,645  $ 125,729 
Expenses per BOE
Production taxes, transportation and processing $ 5.13  $ 3.35 
Lease operating $ 3.90  $ 4.77 
Plant and other midstream services operating $ 2.05  $ 1.54 
Depletion, depreciation and amortization $ 11.24  $ 14.01 
General and administrative $ 3.33  $ 2.51 
Three Months Ended March 31, 2021 as Compared to Three Months Ended March 31, 2020
Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $12.5 million, or 57%, to $34.2 million for the three months ended March 31, 2021, as compared to $21.7 million for the three months ended March 31, 2020. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 53% to $5.13 per BOE for the three months ended March 31, 2021, as compared to $3.35 per BOE for the three months ended March 31, 2020. These increases were primarily due to (i) the $9.6 million increase in production taxes to $23.7 million for the three months ended March 31, 2021, as compared to $14.1 million for the three months ended March 31, 2020, primarily due to the increase in the weighted average oil and natural gas prices realized between the two periods, and (ii) the $2.9 million increase in transportation and processing expenses to $10.5 million for the three months ended March 31, 2021, as compared to $7.6 million for the three months ended March 31, 2020.
Lease operating. Our lease operating expenses decreased $5.0 million, or 16%, to $25.9 million for the three months ended March 31, 2021, as compared to $30.9 million for the three months ended March 31, 2020. Our lease operating expenses on a unit-of-production basis decreased 18% to $3.90 per BOE for the three months ended March 31, 2021, as compared to $4.77 per BOE for the three months ended March 31, 2020. These decreases were largely attributable to (i) decreases in expenses associated with repairs and maintenance and equipment rentals of $3.0 million, (ii) a decrease in non-operated expenses of $1.0 million and (iii) a decrease in compression rental charges of $0.9 million for the three months ended March 31, 2021, as compared to the three months ended March 31, 2020.
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $3.7 million, or 37%, to $13.7 million for the three months ended March 31, 2021, as compared to $10.0 million for the three months ended March 31, 2020. This increase was primarily attributable to (i) increased expenses associated with our expanded
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commercial produced water disposal operations of $7.7 million for the three months ended March 31, 2021, as compared to $5.1 million for the three months ended March 31, 2020, and (ii) increased expenses associated with our expanded pipeline operations of $3.2 million for the three months ended March 31, 2021, as compared to $2.0 million for the three months ended March 31, 2020.
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $15.8 million, or 17%, to $74.9 million for the three months ended March 31, 2021, as compared to $90.7 million for the three months ended March 31, 2020. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 20% to $11.24 per BOE for the three months ended March 31, 2021, as compared to $14.01 per BOE for the three months ended March 31, 2020. These decreases were attributable to the increase in our estimated total proved oil and natural gas reserves, as well as the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2020. The decrease in our depletion, depreciation and amortization expenses was partially offset by a $3.0 million increase in depreciation expenses attributable to our midstream segment to $7.8 million for the three months ended March 31, 2021, as compared to $4.8 million for the three months ended March 31, 2020.
General and administrative. Our general and administrative expenses increased $6.0 million, or 37%, to $22.2 million for the three months ended March 31, 2021, as compared to $16.2 million for the three months ended March 31, 2020. Our general and administrative expenses increased 33% on a unit-of-production basis to $3.33 per BOE for the three months ended March 31, 2021, as compared to $2.51 per BOE for the three months ended March 31, 2020. These increases were largely attributable to the $5.7 million increase in stock-based compensation expense we recorded primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. The share price of our common stock increased by 94% from $12.06 at December 31, 2020 to $23.45 at March 31, 2021.
Interest expense. For the three months ended March 31, 2021, we incurred total interest expense of $20.2 million. We capitalized $0.6 million of our interest expense on certain qualifying projects for the three months ended March 31, 2021 and expensed the remaining $19.7 million to operations. 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.
Income tax provision. Our income tax provision was $2.8 million for the three months ended March 31, 2021. Our effective tax rate for the three months ended March 31, 2021 was 4%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to recording the net deferred tax liability for state taxes, primarily in New Mexico, and continuing to recognize a valuation allowance against our U.S. federal net deferred tax assets. As a result of the full-cost ceiling impairments recorded in 2020, we recognized a valuation allowance against our net deferred tax assets for the year ended December 31, 2020. The valuation allowance will continue to be recognized until the future deferred tax benefits are more likely than not to become utilized. Our effective tax rate for the three months ended March 31, 2020 was 24%, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to the impact of permanent differences between book and tax income, as well as state taxes, primarily in New Mexico.
Liquidity and Capital Resources
Our primary use of capital has been, and we expect will continue to be during the remainder of 2021 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditures for the remainder of 2021 primarily through a combination of cash on hand, operating cash flows and performance incentives paid to us by a subsidiary of Five Point Energy LLC, our joint venture partner, in connection with San Mateo. If capital expenditures were to exceed our operating cash flows during the remainder of 2021, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our
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future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.
At March 31, 2021, we had cash totaling $17.9 million and restricted cash totaling $30.3 million, which was associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. During the first quarter of 2021, we repaid $100.0 million of the borrowings under the Credit Agreement. In addition, in February 2021, the Board adopted a dividend policy and declared our first quarterly cash dividend of $0.025 per share of common stock, which was paid on March 31, 2021. In April 2021, the Board declared our second quarterly cash dividend of $0.025 per share of common stock payable on June 3, 2021 to shareholders of record as of May 13, 2021.
At March 31, 2021, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $340.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration (“SBA”) loan. In April 2021, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. We elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and no material changes were made to the terms of the Credit Agreement. This April 2021 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment (subject to compliance with the covenant noted below). The Credit Agreement matures in October 2023. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 4.00 or less. We believe that we were in compliance with the terms of the Credit Agreement at March 31, 2021.
At December 31, 2020 and March 31, 2021, San Mateo had $334.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases to up to $400.0 million, and matures in December 2023. At March 31, 2021, the lender commitments under the San Mateo Credit Facility were $375.0 million (subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility is guaranteed by San Mateo’s subsidiaries, secured by substantially all of San Mateo’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at March 31, 2021. Between March 31, 2021 and April 28, 2021, San Mateo repaid $19.0 million of borrowings under the San Mateo Credit Facility.
On April 13, 2020, we executed a promissory note evidencing an unsecured loan in the amount of approximately $7.5 million as part of the Paycheck Protection Program. For a discussion of such loan, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in the Annual Report.
During the first quarter and through April 2021, the oil and natural gas industry has experienced continued improvement in commodity prices as compared to the same period in 2020, primarily resulting from (i) improvements in oil demand as the impact from COVID-19 has begun to abate and (ii) actions taken by the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) to reduce the worldwide supply of oil through coordinated production cuts. As a result, West Texas Intermediate (“WTI”) oil prices have increased from $48.52 per barrel at December 31, 2020 to as high as $66.09 per barrel in early March 2021. Prices for natural gas and NGLs were also much higher during the first quarter and through April 2021 than they were for the same period in 2020. While oil prices have continued to improve in 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains uncertain, and we can provide no assurances as to when or to what extent economic disruptions resulting from COVID-19 and the corresponding decreases in oil demand may improve further. These economic disruptions have also reduced our ability to access the capital markets on reasonably similar terms as were available prior to 2020.
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 2021. We began 2021 operating three contracted drilling rigs in the Delaware Basin and, in March 2021, we added a fourth drilling rig. We currently plan to operate four drilling rigs in the Delaware Basin throughout the remainder of 2021. Our 2021 estimated capital expenditure budget consists of $525.0 to $575.0 million for drilling, completing and equipping wells (“D/C/E capital expenditures”) and $20.0 to $30.0 million for midstream capital expenditures, which
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reflects our proportionate share of San Mateo’s estimated 2021 capital expenditures. Substantially all of these 2021 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2021 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a higher percentage of longer horizontal wells in 2021, including 98% with anticipated completed lateral lengths of two miles or greater. We have built significant optionality into our drilling program, which should generally allow us to increase or decrease the number of rigs we operate as necessary based on changing commodity prices and other factors.
We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana, as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during the remainder of 2021. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2021 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for 2021.
Our 2021 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control.
Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for the remainder of 2021 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for the remainder of 2021 and the hedges we currently have in place. For further discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 7 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments.
Our unaudited cash flows for the three months ended March 31, 2021 and 2020 are presented below:
  Three Months Ended
March 31,
(In thousands) 2021 2020
Net cash provided by operating activities $ 169,395  $ 109,372 
Net cash used in investing activities (108,895) (248,220)
Net cash (used in) provided by financing activities (103,626) 130,515 
Net change in cash and restricted cash $ (43,126) $ (8,333)
Adjusted EBITDA attributable to Matador Resources Company shareholders(1)
$ 198,115  $ 140,576 
__________________
(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 and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below.
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Cash Flows Provided by Operating Activities
Net cash provided by operating activities increased $60.0 million to $169.4 million for the three months ended March 31, 2021 from $109.4 million for the three months ended March 31, 2020. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased $58.4 million to $192.7 million for the three months ended March 31, 2021 from $134.3 million for the three months ended March 31, 2020, primarily attributable to significantly higher realized oil and natural gas prices for the three months ended March 31, 2021, as compared to the three months ended March 31, 2020. Changes in our operating assets and liabilities between the two periods resulted in a net increase of approximately $1.6 million in net cash provided by operating activities for the three months ended March 31, 2021, as compared to the three months ended March 31, 2020.
Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. Furthermore, the effects of COVID-19 and the corresponding decline in oil demand significantly impacted the prices we received for our oil production in recent periods. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices.
Cash Flows Used in Investing Activities
Net cash used in investing activities decreased $139.3 million to $108.9 million for the three months ended March 31, 2021 from $248.2 million for the three months ended March 31, 2020. This decrease in net cash used in investing activities was primarily due to (i) a decrease of $57.1 million in midstream capital expenditures, (ii) a decrease of $47.2 million in D/C/E capital expenditures and (iii) a decrease of $34.1 million in expenditures related to acquisition of oil and natural gas properties for the three months ended March 31, 2021, as compared to the three months ended March 31, 2020. Cash used for D/C/E capital expenditures for the three months ended March 31, 2021 and 2020 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin. Cash used for midstream capital expenditures for the 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, which were completed in 2020.
Cash Flows (Used in) Provided by Financing Activities
Net cash used in financing activities was $103.6 million for the three months ended March 31, 2021, a significant change from net cash provided by financing activities of $130.5 million for the three months ended March 31, 2020. During the three months ended March 31, 2021, our primary use of cash related to financing activities was for the repayment of $100.0 million in borrowings under our Credit Agreement and the payment of our quarterly dividend on March 31, 2021. During the three months ended March 31, 2020, our primary sources of cash from financing activities included borrowings under our 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 and from non-controlling interest owners in less-than-wholly-owned subsidiaries of $53.2 million.
See Note 4 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes.
Guarantor Financial Information
The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At March 31, 2021, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries are not guarantors of the Notes.
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The following tables present summarized financial information of Matador (as issuer of the Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities.

(In thousands) March 31, 2021
Summarized Balance Sheet
Assets
Current assets $ 214,610 
Net property and equipment $ 2,670,985 
Other long-term assets $ 55,727 
Liabilities
Current liabilities $ 370,735 
Long-term debt $ 1,381,393 
Other long-term liabilities $ 62,649 

Three Months Ended
(In thousands) March 31, 2021
Summarized Statement of Operations
Revenues $ 247,793 
Expenses 175,123 
Operating income $ 72,670 
Other expense (18,399)
Tax provision (2,840)
Net income $ 51,431 

Non-GAAP Financial Measures
We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
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The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively.
  Three Months Ended
March 31,
(In thousands) 2021 2020
Unaudited Adjusted EBITDA Reconciliation to Net Income
Net income attributable to Matador Resources Company shareholders $ 60,645  $ 125,729 
Net income attributable to non-controlling interest in subsidiaries 8,853  9,354 
Net income 69,498  135,083 
Interest expense 19,650  19,812 
Total income tax provision 2,840  39,957 
Depletion, depreciation and amortization 74,863  90,707 
Accretion of asset retirement obligations 500  476 
Unrealized loss (gain) on derivatives 43,423  (136,430)
Non-cash stock-based compensation expense 855  3,794 
Consolidated Adjusted EBITDA 211,629  153,399 
Adjusted EBITDA attributable to non-controlling interest in subsidiaries (13,514) (12,823)
Adjusted EBITDA attributable to Matador Resources Company shareholders $ 198,115  $ 140,576 
  Three Months Ended
March 31,
(In thousands) 2021 2020
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities
Net cash provided by operating activities $ 169,395  $ 109,372 
Net change in operating assets and liabilities 23,308  24,899 
Interest expense, net of non-cash portion 18,926  19,128 
Adjusted EBITDA attributable to non-controlling interest in subsidiaries (13,514) (12,823)
Adjusted EBITDA attributable to Matador Resources Company shareholders $ 198,115  $ 140,576 
For the three months ended March 31, 2021, we reported net income attributable to Matador shareholders of $60.6 million, as compared to net income attributable to Matador shareholders of $125.7 million for the three months ended March 31, 2020. This $65.1 million decrease in net income attributable to Matador shareholders primarily resulted from an unrealized loss on derivatives of $43.4 million for the three months ended March 31, 2021, as compared to an unrealized gain on derivatives of $136.4 million for the three months ended March 31, 2020. This change was partially offset by higher oil and natural gas production and higher realized oil and natural gas prices for the three months ended March 31, 2021, as compared to the three months ended March 31, 2020.
Adjusted EBITDA, a non-GAAP financial measure, increased $57.5 million to $198.1 million for the three months ended March 31, 2021, as compared to $140.6 million for the three months ended March 31, 2020. This increase is primarily attributable to higher oil and natural gas production and higher realized oil and natural gas prices for the three months ended March 31, 2021, as compared to the three months ended March 31, 2020.
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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, 2021, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.
Obligations and Commitments
We had the following material contractual obligations and commitments at March 31, 2021.
  Payments Due by Period
(In thousands) Total Less
Than
1 Year
1 - 3
Years
3 - 5
Years
More
Than
5 Years
Contractual Obligations
Borrowings, including letters of credit(1)
$ 736,273  $ —  $ 736,273  $ —  $ — 
Senior unsecured notes(2)
1,050,000  —  —  —  1,050,000 
Office leases 21,540  4,045  8,424  8,706  365 
Non-operated drilling and other capital commitments(3)
42,656  23,126  19,530  —  — 
Drilling rig contracts(4)
16,757  15,954  803  —  — 
Asset retirement obligations(5)
39,129  409  5,099  1,482  32,139 
Transportation, gathering, processing and disposal agreements with non-affiliates(6)
615,235  66,837  143,141  143,433  261,824 
Transportation, gathering, processing and disposal agreements with San Mateo(7)
470,108  27,562  152,340  182,740  107,466 
Total contractual cash obligations $ 2,991,698  $ 137,933  $ 1,065,610  $ 336,361  $ 1,451,794 
__________________
(1)The amounts included in the table above represent principal maturities only. At March 31, 2021, we had $340.0 million in borrowings outstanding under the Credit Agreement, approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and $7.5 million in borrowings outstanding under the SBA loan. The Credit Agreement matures in October 2023. At March 31, 2021, San Mateo had $334.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. Assuming the amounts outstanding and interest rates of 1.61% and 1.86%, for the Credit Agreement and the San Mateo Credit Facility, respectively, at March 31, 2021, the interest expense for such facilities is expected to be approximately $5.5 million and $6.3 million each year until maturity.
(2)The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding as of March 31, 2021 is expected to be approximately $61.7 million each year until maturity.
(3)At March 31, 2021, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells.
(4)We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs.
(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at March 31, 2021.
(6)From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.
(7)We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.
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General Outlook and Trends
During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices resulting from two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) the increase in global oil supply resulting from actions of OPEC+. The sudden decline in oil prices began to improve later in the second quarter of 2020 and throughout the remainder of 2020 and the first quarter of 2021. For the three months ended March 31, 2021, oil prices averaged $58.14 per Bbl, ranging from a low of $47.62 per Bbl in early January to a high of $66.09 per Bbl in early March, based upon the WTI oil futures contract price for the earliest delivery date.
We realized a weighted average oil price of $57.05 per Bbl ($50.08 per Bbl including realized losses from oil derivatives) for our oil production for the three months ended March 31, 2021, as compared to $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. At April 28, 2021, the WTI oil futures contract for the earliest delivery date had increased from the average price for the first quarter of 2021 of $58.14 per Bbl, settling at $63.86 per Bbl, which was a significant increase as compared to $12.34 per Bbl at April 28, 2020.
Natural gas prices were also higher in the first quarter of 2021, as compared to the first quarter of 2020. For the three months ended March 31, 2021, natural gas prices averaged $2.72 per MMBtu, ranging from a low of $2.45 per MMBtu in mid-January to a high of $3.22 per MMBtu in mid-February, 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 $5.88 per Mcf ($5.89 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended March 31, 2021, as compared to $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. While most of our natural gas production is typically sold at prices established at the beginning of each month by the various markets where we sell our natural gas production, certain volumes of our natural gas production are sold at daily market prices. During the first quarter of 2021, and particularly during the historically prolonged cold weather conditions in New Mexico and Texas in February due to Winter Storm Uri, these daily market prices for natural gas were often well above the monthly market prices, resulting in an associated increase in our weighted average realized natural gas price for the first quarter of 2021. NGL prices were also strong in the first quarter of 2021, which further contributed to our first quarter weighted average realized natural gas price. At April 28, 2021, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased from the average price for the first quarter of 2021 of $2.72 per MMBtu, settling at $2.93 per MMBtu, which was also an increase as compared to $1.79 per MMBtu at April 28, 2020.
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 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—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” in the Annual Report.
From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets.
The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At March 31, 2021, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and most of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.
The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years, but began 2020 slightly positive to the WTI oil price and remained positive through much of the first quarter. With the abrupt decline in oil prices
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during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020, reaching ($6.00) per Bbl before becoming positive in the second quarter and improving through the rest of 2020 and into 2021. At April 28, 2021, this oil price differential was approximately $0.29 per Bbl. At April 28, 2021, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated oil production for the remainder of 2021 and 2022.
A portion of our Delaware Basin natural gas production is exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years, including in April 2019 when natural gas was sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu. In early 2020, the Waha basis differential remained significant at about ($1.20) per MMBtu and continued to deteriorate. Natural gas prices at the Waha hub were negative on certain days in April 2020. The Waha basis differential narrowed during the remainder of the second quarter of 2020. During the third quarter of 2020 and, in particular, at the beginning of October 2020, the Waha basis differential widened significantly again, including several days when natural gas was being sold at the Waha hub for negative prices, due to seasonal pipeline maintenance and other factors that reduced capacity out of the Waha hub. These capacity issues have been largely resolved and the Waha basis differential improved during the remainder of 2020 and throughout the first quarter of 2021.
The majority of our Delaware Basin natural gas production, however, is typically sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2020 and most of the first quarter of 2021, we typically realized a premium to natural gas sold at the Waha hub despite higher transportation changes incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production to other markets, e.g., Southern California, to improve our realized natural gas pricing.
Although the natural gas price differentials have recently remained positive, these price differentials could deteriorate in future periods. Should we experience future periods of negative pricing for natural gas as we have in previous periods, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. In addition, we have no derivative contracts in place to mitigate our exposure to these natural gas price differentials during 2021 or for future periods.
In addition to concerns regarding oil and natural gas prices and basis differentials, the destruction of global oil demand resulting from the decline in economic activity associated with COVID-19, in conjunction with the actions initiated by Saudi Arabia in March 2020 to increase its oil production to world markets, led to a significant oversupply of oil worldwide. OPEC+ (led by Saudi Arabia) reversed course in April 2020 and reduced oil production significantly for the remainder of 2020 and through the first quarter of 2021, which has contributed to improving oil prices. The members of OPEC+ have generally adhered to these production cuts, which have contributed to improving oil prices, although OPEC+ has begun to restore production levels as oil prices have improved. It is uncertain to what degree these production cuts may restore the balance between oil supply and demand, and most oil and natural gas industry observers remain skeptical that oil prices can improve further until oil demand improves, most likely as a result of the “re-opening” of the world economy as concerns surrounding COVID-19 begin to subside.
During times of low oil prices, we may elect to shut in or curtail certain volumes of our oil production temporarily rather than sell the oil at depressed prices. As most of our natural gas production in the Delaware Basin is associated with oil production, portions of our natural gas production may also be curtailed or shut in. Furthermore, portions of our Delaware Basin production in the first quarter of 2021 were impacted by the historically prolonged cold weather conditions in New Mexico and Texas in February due to Winter Storm Uri, although we were able to produce and sell the majority of our oil and natural gas during this period. We experienced minimal impact to our production volumes due to insufficient storage capacity or damage to refineries downstream of our operations as a result of Winter Storm Uri.
At April 28, 2021, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected.
Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, separate bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Following that executive order, the
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governing New Mexico regulatory bodies and New Mexico legislature have proposed various rules, regulations and bills regarding the reduction of natural gas waste and the control of emissions. In 2021, New Mexico adopted a rule that requires upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. In January 2021, the Biden administration issued (i) an order signed by the acting Secretary of the Interior dated January 20, 2021 providing for a 60-day pause limiting the authority of local offices of the Bureau of Land Management to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Federal Lease Orders”). While certain of the Biden Federal Lease Orders were allowed to expire in March 2021, others were extended. The pause relating to federal oil and natural gas leases in these orders did not restrict our activities on existing valid leases. As such, we have continued our operations on federal properties. However, we can provide no assurances that federal regulations will not be adopted that limit our ability to develop our federal properties. Should such actions be taken, they would almost certainly impact our drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” in our Annual Report.
In addition, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry, recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.
Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.” in the Annual Report.
We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Except as set forth below, there have been no material changes to the sources and effects of our market risk since December 31, 2020, which are disclosed in Part II, Item 7A of the Annual Report and incorporated herein by reference.
Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production.
We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option have different fixed price
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components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection.
We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At March 31, 2021, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), Truist Bank (or affiliates thereof), PNC Bank and the Royal Bank of Canada were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. See Note 7 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments. Such information is incorporated herein by reference.
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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Quarterly Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2021 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There were no changes in our internal controls during the three months ended March 31, 2021 that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting.
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Part II — OTHER INFORMATION
Item 1. Legal Proceedings
We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows.
For information on our legal proceeding with the Environmental Protection Agency and the New Mexico Environment Department, see “Item 3. Legal Proceedings” in the Annual Report. There have been no material changes regarding such legal proceeding.
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. For a discussion of such risks and uncertainties, please see “Item 1A. Risk Factors” in the Annual Report. There have been no material changes to the risk factors we have disclosed in the Annual Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
During the quarter ended March 31, 2021, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.
Period
Total Number of Shares Purchased(1)
Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs
January 1, 2021 to January 31, 2021 8,142  $ 15.56  —  — 
February 1, 2021 to February 28, 2021 67,445  $ 20.06  —  — 
March 1, 2021 to March 31, 2021 917  $ 24.99  —  — 
Total 76,504  $ 19.64  —  — 
_________________
(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
3.2
3.3
3.4
10.1†
10.2
31.1
31.2
32.1
32.2
   101
The following financial information from Matador Resources Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets - Unaudited, (ii) the Condensed Consolidated Statements of Operations - Unaudited, (iii) the Condensed Consolidated Statements of Changes in Shareholders’ Equity - Unaudited, (iv) the Condensed Consolidated Statements of Cash Flows - Unaudited and (v) the Notes to Condensed Consolidated Financial Statements - Unaudited (submitted electronically herewith).
   104 Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101).
   † Indicates a management contract or compensatory plan or arrangement.

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