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 endedDecember 31, 2020 (the "Annual Report") filed with theSecurities and Exchange Commission (the "SEC") onFebruary 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 theSEC'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 toMatador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to "Matador" refer solely toMatador Resources Company and (iii) references to "San Mateo" refer toSan 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'sBlack 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 theSEC , all of which are difficult to predict. Forward-looking statements may include statements about: •our business strategy; •our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized; •our cash flows and liquidity; •the amount, timing and payment of dividends, if any; •our financial strategy, budget, projections and operating results; •the supply and demand of oil, natural gas and natural gas liquids; •oil, natural gas and natural gas liquids prices, including our realized prices thereof; •the timing and amount of future production of oil and natural gas; •the availability of drilling, completion and production equipment; •the availability of oil storage capacity; •the availability of oil field labor; •the amount, nature and timing of capital expenditures, including future exploration and development costs; •the availability and terms of capital; •our drilling of wells; 21 -------------------------------------------------------------------------------- Table of Conte nts •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 itsBlack River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells; •the ability of San Mateo to attract third-party volumes; •our costs and timing of exploiting and developing our properties and conducting other operations; •general economic conditions; •competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; •the effectiveness of our risk management and hedging activities; •our technology; •environmental liabilities; •counterparty credit risk; •regulatory risk; •developments in oil-producing and natural gas-producing countries; •the impact of COVID-19 on the oil and natural gas industry and our business; •our future operating results; and •our plans, objectives, expectations and intentions contained in this Quarterly Report or in our other filings with theSEC 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 ofthe United States and the rules and regulations of theSEC . Overview We are an independent energy company founded inJuly 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources inthe 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 theDelaware Basin inSoutheast New Mexico andWest Texas . We also operate in the Eagle Ford shale play inSouth Texas and theHaynesville shale andCotton Valley plays inNorthwest Louisiana . Additionally, we conduct midstream operations, primarily through San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Second Quarter Highlights For the three months endedJune 30, 2021 , our total oil equivalent production was 8.5 million BOE, and our average daily oil equivalent production was 93,200 BOE per day, of which 53,400 Bbl per day, or 57%, was oil and 239.1 MMcf per day, or 43%, was natural gas. Our average daily oil production of 53,400 Bbl per day for the three months endedJune 30, 2021 increased 24% year-over-year from 43,100 Bbl per day for the three months endedJune 30, 2020 . Our average daily natural gas production of 239.1 MMcf per day for the three months endedJune 30, 2021 increased 32% year-over-year from 181.4 MMcf per day for the three months endedJune 30, 2020 . For the second quarter of 2021, we reported net income attributable to Matador shareholders of$105.9 million , or$0.89 per diluted common share, on a generally accepted accounting principles inthe United States ("GAAP") basis, as compared to a net loss attributable to Matador shareholders of$353.4 million , or ($3.04 ) per diluted common share, for the second quarter of 2020. For the second quarter of 2021, our Adjusted EBITDA attributable to Matador shareholders ("Adjusted EBITDA"), a non-GAAP financial measure, was$261.0 million , as compared to Adjusted EBITDA of$107.6 million during the second 22 -------------------------------------------------------------------------------- Table of Conte nts quarter of 2020. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see "-Liquidity and Capital Resources-Non-GAAP Financial Measures." For more information regarding our financial results for the three months endedJune 30, 2021 , see "-Results of Operations" below. For the six months endedJune 30, 2021 , we reported net income attributable to Matador shareholders of$166.6 million , or$1.40 per diluted common share, on a GAAP basis, as compared to a net loss attributable to Matador shareholders of$227.7 million , or ($1.96 ) per diluted common share, for the six months endedJune 30, 2020 . For the six months endedJune 30, 2021 , our Adjusted EBITDA, a non-GAAP financial measure, was$459.1 million , as compared to Adjusted EBITDA of$248.2 million during the six months endedJune 30, 2020 . For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see "-Liquidity and Capital Resources-Non-GAAP Financial Measures." For more information regarding our financial results for the six months endedJune 30, 2021 , see "-Results of Operations" below. Operations Update We operated four drilling rigs in theDelaware Basin during the second quarter of 2021. AtJuly 27, 2021 , two of these rigs were drilling in the Stateline asset area inEddy County, New Mexico . These two rigs recently completed drilling 13 additional Boros wells in the eastern portion of the Stateline asset area and atJuly 27, 2021 were drilling 11 new Voni wells in the western portion of that asset area. The other two rigs have been drilling 13 wells in the southern portion of the Arrowhead asset area (the "GreaterStebbins Area "), nine of which were still in progress atJuly 27, 2021 . Four of these wells, all Second Bone Spring completions, were recently turned to sales. When we complete drilling the nine wells in progress in the GreaterStebbins Area , we plan to use these two rigs to drill two additional wells in the Ranger asset area inLea County, New Mexico and several additionalRodney Robinson wells in the western portion of theAntelope Ridge asset area inLea County . We turned to sales a total of 24 gross (15.6 net) wells in theDelaware Basin during the second quarter of 2021, including 15 gross (14.6 net) operated wells and nine gross (1.0 net) non-operated wells. During the second quarter of 2021, we turned to sales 13 gross (12.7 net) operated wells in the Stateline asset area; four were Wolfcamp A-Lower completions, four were Wolfcamp A-XY completions, four were Second Bone Spring completions and one was a First Bone Spring completion. In the Wolf asset area, we turned to sales two gross (1.9 net) operated wells, both of which were Second Bone Spring completions. We also participated in five gross (0.3 net) non-operated wells turned to sales in theAntelope Ridge asset area, two gross (0.7 net) non-operated wells in the Arrowhead asset area and two gross (less than 0.1 net) non-operated wells in the Rustler Breaks asset area. Our average daily oil equivalent production in theDelaware Basin for the second quarter of 2021 was 87,500 BOE per day, consisting of 51,700 Bbl of oil per day and 214.7 MMcf of natural gas per day, a 33% increase from 66,000 BOE per day, consisting of 41,500 Bbl of oil per day and 146.9 MMcf of natural gas per day, in the second quarter of 2020.The Delaware Basin contributed approximately 97% of our daily oil production and approximately 90% of our daily natural gas production in the second quarter of 2021, as compared to approximately 96% of our daily oil production and approximately 81% of our daily natural gas production in the second quarter of 2020. During the second quarter of 2021, we did not complete and turn to sales any operated wells on our leasehold properties in the Eagle Ford shale play inSouth Texas or in theHaynesville shale andCotton Valley plays inNorthwest Louisiana , but we did participate in four gross (less than 0.1 net) non-operated wells in theHaynesville shale. 2021 Capital Expenditure Budget AtJuly 27, 2021 , our 2021 estimated capital expenditures for drilling, completing and equipping wells ("D/C/E capital expenditures") remained$525 to$575 million , as originally estimated. As a result of savings on our operatedD/C/E capital expenditures in the first half of 2021, a faster drilling and completions pace and an anticipated decrease in non-operatedD/C/E capital expenditures in the second half of 2021, we intend to advance the next 11 Voni well completions in the Stateline asset area forward into the fourth quarter of 2021 and expect to be able to do so without increasing our estimates forD/C/E capital expenditures for full year 2021. AtJuly 27, 2021 , we increased our anticipated 2021 midstream capital expenditures from$20 to$30 million to$35 to$45 million , primarily to accommodate several new midstream opportunities forSan Mateo with producers inEddy County, New Mexico and to accelerate the installation of compression facilities and other infrastructure prior to the end of 2021 in order to be prepared for the additional volumes from the accelerated Voni completions noted above. Previously, these Voni-related capital expenditures were scheduled for early 2022. The anticipated total 2021 midstream capital expenditures of$35 to$45 million primarily reflect our proportionate share ofSan Mateo's estimated 2021 capital expenditures. 23 -------------------------------------------------------------------------------- Table of Conte nts Capital Resources Update Our Board of Directors (the "Board") declared a quarterly cash dividend of$0.025 per share of common stock in both the first and second quarters of 2021, which were paid onMarch 31, 2021 andJune 3, 2021 , respectively. InJuly 2021 , the Board declared a quarterly cash dividend of$0.025 per share of common stock payable onSeptember 3, 2021 to shareholders of record as ofAugust 12, 2021 . During each of the first and second quarters of 2021, we had net repayments of$100.0 million in borrowings under our third amended and restated credit agreement (the "Credit Agreement"). Our outstanding borrowings under our Credit Agreement atJune 30, 2021 were$240.0 million . InApril 2021 , the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at$900.0 million . The Company elected to keep the borrowing commitment at$700.0 million , the maximum facility amount remained$1.5 billion and no material changes were made to the terms of the Credit Agreement. ThisApril 2021 redetermination constituted the regularly scheduledMay 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. InJune 2021 ,San Mateo's revolving credit facility (the "San Mateo Credit Facility") was amended to increase the lender commitments under the revolving credit facility from$375.0 million to$450.0 million (subject toSan Mateo's compliance with certain covenants) and the borrowing rate for a base rate loan or Eurodollar loan under such facility was increased by 0.50%. TheSan Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to$700.0 million . Critical Accounting Policies There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report. Recent Accounting Pronouncements There are no recent accounting pronouncements that are expected to have a material impact on our financial statements. 24 -------------------------------------------------------------------------------- Table of Conte nts Results of Operations Revenues The following table summarizes our unaudited revenues and production data for the periods indicated: Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 Operating Data Revenues (in thousands)(1) Oil$ 315,114 $ 94,174 $ 528,393 $ 263,759 Natural gas 96,960 24,593 199,914 52,922 Total oil and natural gas revenues 412,074 118,767 728,307 316,681 Third-party midstream services revenues 19,850 14,668 35,288 30,498 Sales of purchased natural gas 10,918 13,981 15,428 24,525 Lease bonus - mineral acreage - 4,062 - 4,062 Realized (loss) gain on derivatives (42,611) 44,110 (68,524) 54,977 Unrealized (loss) gain on derivatives (42,804) (132,668) (86,227) 3,762 Total revenues$ 357,427 $ 62,920 $ 624,272 $ 434,505 Net Production Volumes(1) Oil (MBbl)(2) 4,855 3,920 8,594 7,617 Natural gas (Bcf)(3) 21.8 16.5 39.3 33.2 Total oil equivalent (MBOE)(4) 8,482 6,670 15,140 13,146 Average daily production (BOE/d)(5) 93,210 73,302 83,650 72,232 Average Sales Prices Oil, without realized derivatives (per Bbl)$ 64.90 $ 24.03 $ 61.49 $ 34.63 Oil, with realized derivatives (per Bbl)$ 56.13 $ 35.28 $ 53.49 $ 41.85 Natural gas, without realized derivatives (per Mcf)$ 4.46 $ 1.49 $ 5.09 $ 1.60 Natural gas, with realized derivatives (per Mcf)$ 4.46 $ 1.49 $ 5.09 $ 1.60
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(1)We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues. (2)One thousand Bbl of oil. (3)One billion cubic feet of natural gas. (4)One thousand Bbl of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. (5)Barrels of oil equivalent per day, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Three Months EndedJune 30, 2021 as Compared to Three Months EndedJune 30, 2020 Oil and natural gas revenues. Our oil and natural gas revenues increased$293.3 million , or 247%, to$412.1 million for the three months endedJune 30, 2021 , as compared to$118.8 million for the three months endedJune 30, 2020 . Our oil revenues increased$220.9 million , or 235%, to$315.1 million for the three months endedJune 30, 2021 , as compared to$94.2 million for the three months endedJune 30, 2020 . This increase in oil revenues resulted from a 170% increase in the weighted average oil price realized for the three months endedJune 30, 2021 to$64.90 per Bbl, as compared to$24.03 per Bbl for the three months endedJune 30, 2020 , and from a 24% increase in our oil production to 4.9 million Bbl for the three months endedJune 30, 2021 , as compared to 3.9 million Bbl for the three months endedJune 30, 2020 . Our natural gas revenues increased$72.4 million , or 294%, to$97.0 million for the three months endedJune 30, 2021 , as compared to$24.6 million for the three months endedJune 30, 2020 . The increase in natural gas revenues resulted from an approximately three-fold increase in the weighted average natural gas price realized for the three months endedJune 30, 2021 to$4.46 per Mcf, as compared to a weighted average natural gas price of$1.49 per Mcf realized for the three months endedJune 30, 2020 , and from a 32% increase in our natural gas production to 21.8 Bcf for the three months endedJune 30, 2021 , as compared to 16.5 Bcf for the three months endedJune 30, 2020 . 25 -------------------------------------------------------------------------------- Table of Conte nts Third-party midstream services revenues. Our third-party midstream services revenues increased$5.2 million , or 35%, to$19.9 million for the three months endedJune 30, 2021 , as compared to$14.7 million for the three months endedJune 30, 2020 . Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to$10.3 million for the three months endedJune 30, 2021 , as compared to$6.3 million for the three months endedJune 30, 2020 , (ii) an increase in our third-party produced water gathering and disposal revenues to$7.0 million for the three months endedJune 30, 2021 , as compared to$6.2 million for the three months endedJune 30, 2020 , and (iii) an increase in our third-party oil gathering and transportation revenues to$2.6 million for the three months endedJune 30, 2021 , as compared to$2.1 million for the three months endedJune 30, 2020 . Sales of purchased natural gas. Our sales of purchased natural gas decreased$3.1 million , or 22%, to$10.9 million for the three months endedJune 30, 2021 , as compared to$14.0 million for the three months endedJune 30, 2020 . This decrease was primarily the result of a decrease in purchased natural gas volumes sold during the three months endedJune 30, 2021 . Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas atSan Mateo's cryogenic natural gas processing plant inEddy County, New Mexico (the "Black River Processing Plant") and subsequently sell the residue gas and natural gas liquids ("NGL") to other purchasers. These revenues, and the expenses related to these transactions included in "Purchased natural gas," are presented on a gross basis in our interim unaudited condensed consolidated statements of operations. Lease bonus - mineral acreage. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests. We did not lease any of our mineral acreage to third parties during the three months endedJune 30, 2021 . Our lease bonus - mineral acreage revenues were$4.1 million for the three months endedJune 30, 2020 . Realized (loss) gain on derivatives. Our realized net loss on derivatives was$42.6 million for the three months endedJune 30, 2021 , as compared to a realized net gain of$44.1 million for the three months endedJune 30, 2020 . We realized a net loss of$42.6 million related to our oil costless collar and oil and oil basis swap contracts for the three months endedJune 30, 2021 , resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike prices of certain of our oil and oil basis swap contracts. We realized an average loss on our oil derivatives of approximately$8.77 per Bbl produced during the three months endedJune 30, 2021 , as compared to an average gain of approximately$11.25 per Bbl produced during the three months endedJune 30, 2020 . Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives was$42.8 million for the three months endedJune 30, 2021 , as compared to an unrealized net loss of$132.7 million for the three months endedJune 30, 2020 . During the three months endedJune 30, 2021 , the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a net liability of$122.1 million from a net liability of$79.3 million atMarch 31, 2021 , resulting in an unrealized loss on derivatives of$42.8 million for the three months endedJune 30, 2021 . During the three months endedJune 30, 2020 , the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a net liability of$0.1 million atJune 30, 2020 from a net asset of$132.6 million atMarch 31, 2020 , resulting in an unrealized loss on derivatives of$132.7 million for the three months endedJune 30, 2020 . Six Months EndedJune 30, 2021 as Compared to Six Months EndedJune 30, 2020 Oil and natural gas revenues. Our oil and natural gas revenues increased$411.6 million , or 130%, to$728.3 million for the six months endedJune 30, 2021 , as compared to$316.7 million for the six months endedJune 30, 2020 . Our oil revenues increased$264.6 million , or 100%, to$528.4 million for the six months endedJune 30, 2021 , as compared to$263.8 million for the six months endedJune 30, 2020 . This increase in oil revenues resulted from a 78% increase in the weighted average oil price realized for the six months endedJune 30, 2021 to$61.49 per Bbl, as compared to$34.63 per Bbl for the six months endedJune 30, 2020 , and from a 13% increase in our oil production to 8.6 million Bbl for the six months endedJune 30, 2021 , as compared to 7.6 million Bbl for the six months endedJune 30, 2020 . Our natural gas revenues increased by$147.0 million , or 278%, to$199.9 million for the six months endedJune 30, 2021 , as compared to$52.9 million for the six months endedJune 30, 2020 . The increase in natural gas revenues resulted from a more than three-fold increase in the weighted average natural gas price realized for the six months endedJune 30, 2021 to$5.09 per Mcf, as compared to a weighted average natural gas price of$1.60 per Mcf for the six months endedJune 30, 2020 , and from an 18% increase in our natural gas production to 39.3 Bcf for the six months endedJune 30, 2021 , as compared to 33.2 Bcf for the six months endedJune 30, 2020 . 26 -------------------------------------------------------------------------------- Table of Conte nts Third-party midstream services revenues. Our third-party midstream services revenues increased$4.8 million , or 16%, to$35.3 million for the six months endedJune 30, 2021 , as compared to$30.5 million for the six months endedJune 30, 2020 . This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to$17.1 million for the six months endedJune 30, 2021 , as compared to$13.4 million for the six months endedJune 30, 2020 , (ii) an increase in our third-party oil gathering and transportation revenues to$4.7 million for the six months endedJune 30, 2021 , as compared to$4.2 million for the six months endedJune 30, 2020 , and (iii) an increase in our third-party produced water gathering and disposal revenues to$13.5 million for the six months endedJune 30, 2021 , as compared to$12.9 million for the six months endedJune 30, 2020 . Sales of purchased natural gas. Our sales of purchased natural gas decreased$9.1 million , or 37%, to$15.4 million for the six months endedJune 30, 2021 , as compared to$24.5 million for the six months endedJune 30, 2020 . This decrease was primarily the result of a decrease in natural gas volumes sold during the six months endedJune 30, 2021 . Lease bonus - mineral acreage. We did not lease any of our mineral acreage to third parties during the six months endedJune 30, 2021 . Our lease bonus - mineral acreage revenues were$4.1 million for the six months endedJune 30, 2020 . Realized (loss) gain on derivatives. Our realized net loss on derivatives was$68.5 million for the six months endedJune 30, 2021 , as compared to a realized net gain of$55.0 million for the six months endedJune 30, 2020 . We realized a net loss of$68.7 million related to our oil costless collar and oil and oil basis swap contracts for the six months endedJune 30, 2021 , resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike prices of certain of our oil and oil basis swap contracts. We realized a net gain of$0.2 million related to our natural gas costless collar contracts for the six months endedJune 30, 2021 , resulting primarily from natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average loss on our oil derivatives of approximately$8.00 per Bbl produced during the six months endedJune 30, 2021 , as compared to an average gain of$7.22 per Bbl produced during the six months endedJune 30, 2020 . Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives was$86.2 million for the six months endedJune 30, 2021 , as compared to an unrealized net gain of$3.8 million for the six months endedJune 30, 2020 . During the period fromDecember 31, 2020 throughJune 30, 2021 , the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a net liability of$122.1 million from a net liability of$35.9 million , resulting in an unrealized loss on derivatives of$86.2 million for the six months endedJune 30, 2021 . During the period fromDecember 31, 2019 throughJune 30, 2020 , the aggregate net fair value of our open oil and natural gas derivative contracts increased to a net liability of$0.1 million from a net liability of$3.9 million , resulting in an unrealized gain on derivatives of$3.8 million for the six months endedJune 30, 2020 . 27 -------------------------------------------------------------------------------- Table of Conte nts Expenses The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated: Three Months Ended Six Months Ended June 30, June 30, (In thousands, except expenses per BOE) 2021 2020 2021 2020
Expenses
Production taxes, transportation and processing$ 43,843
28,752 26,162 54,691 57,072 Plant and other midstream services operating 13,746 9,780 27,409 19,744 Purchased natural gas 9,628 10,922 12,483 18,980 Depletion, depreciation and amortization 91,444 93,350 166,307 184,057 Accretion of asset retirement obligations 511 495 1,011 971 Full-cost ceiling impairment - 324,001 - 324,001 General and administrative 24,397 14,723 46,585 30,945 Total expenses 212,321 498,230 386,503 676,283 Operating income (loss) 145,106 (435,310) 237,769 (241,778) Other income (expense) Net loss on asset sales and impairment - (2,632) - (2,632) Interest expense (17,940) (18,297) (37,590) (38,109) Other income (expense) 14 473 (661) 1,793 Total other expense (17,926) (20,456) (38,251) (38,948) Income (loss) before income taxes 127,180 (455,766) 199,518 (280,726) Income tax provision (benefit) 5,349 (109,823) 8,189 (69,866)
Net income attributable to non-controlling interest in subsidiaries
(15,926) (7,473) (24,779) (16,827)
Net income (loss) attributable to
$ 105,905
$ 5.17
$ 3.39
$ 1.62
$ 10.78
$ 2.88
Three Months EndedJune 30, 2021 as Compared to Three Months EndedJune 30, 2020 Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased$25.0 million , or 133%, to$43.8 million for the three months endedJune 30, 2021 , as compared to$18.8 million for the three months endedJune 30, 2020 . On a unit-of-production basis, our production taxes and transportation and processing expenses increased 83% to$5.17 per BOE for the three months endedJune 30, 2021 , as compared to$2.82 per BOE for the three months endedJune 30, 2020 . These increases were primarily due to (i) a$22.5 million increase in production taxes to$31.1 million for the three months endedJune 30, 2021 , as compared to$8.6 million for the three months endedJune 30, 2020 , primarily due to the significant increase in the weighted average oil and natural gas prices realized between the two periods, and (ii) a$2.5 million increase in transportation and processing expenses to$12.7 million for the three months endedJune 30, 2021 , as compared to$10.2 million for the three months endedJune 30, 2020 , primarily due to the 32% increase in our natural gas production of 21.8 Bcf for the three months endedJune 30, 2021 , as compared to 16.5 Bcf for the three months endedJune 30, 2020 . Lease operating. Our lease operating expenses increased$2.6 million , or 10%, to$28.8 million for the three months endedJune 30, 2021 , as compared to$26.2 million for the three months endedJune 30, 2020 . This increase was primarily attributable to increases in expenses associated with workovers, chemicals and other expenses of$3.4 million , which were attributable to servicing an increased number of operated wells atJune 30, 2021 , as compared toJune 30, 2020 . This increase 28 -------------------------------------------------------------------------------- Table of Conte nts was partially offset by a decrease in produced water trucking and disposal expenses of$1.1 million as more of our operated wells have been connected to produced water pipelines during three months endedJune 30, 2021 , as compared to the three months endedJune 30, 2020 . Our lease operating expenses on a unit-of-production basis decreased 14% to$3.39 per BOE for the three months endedJune 30, 2021 , as compared to$3.92 per BOE for the three months endedJune 30, 2020 , primarily due to the 27% increase in our total oil equivalent production for the three months endedJune 30, 2021 , as compared to the three months endedJune 30, 2020 . Plant and other midstream services operating. Our plant and other midstream services operating expenses increased$4.0 million , or 41%, to$13.7 million for the three months endedJune 30, 2021 , as compared to$9.8 million for the three months endedJune 30, 2020 . This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of$6.6 million for the three months endedJune 30, 2021 , as compared to$5.4 million for the three months endedJune 30, 2020 , (ii) increased expenses associated with our expanded pipeline operations of$3.7 million for the three months endedJune 30, 2021 , as compared to$2.0 million for the three months endedJune 30, 2020 , and (iii) increased expenses associated with operating the expanded Black River Processing Plant of$3.5 million for the three months endedJune 30, 2021 , as compared to$2.5 million for the three months endedJune 30, 2020 . Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased$1.9 million , or 2%, to$91.4 million for the three months endedJune 30, 2021 , as compared to$93.4 million for the three months endedJune 30, 2020 . On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 23% to$10.78 per BOE for the three months endedJune 30, 2021 , as compared to$14.00 per BOE for the three months endedJune 30, 2020 . These decreases were attributable to the increase in our estimated total proved oil and natural gas reserves, as well as the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2020. The decrease in our depletion, depreciation and amortization expenses was partially offset by a$2.8 million increase in depreciation expenses attributable to our midstream segment to$7.8 million for the three months endedJune 30, 2021 , as compared to$5.0 million for the three months endedJune 30, 2020 . Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment were recorded for the three months endedJune 30, 2021 . AtJune 30, 2020 , the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by$243.9 million . As a result, we recorded an impairment charge of$324.0 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax benefit of$80.1 million . This full-cost ceiling impairment of$324.0 million is reflected in our interim unaudited condensed consolidated statement of operations for the three months endedJune 30, 2020 . General and administrative. Our general and administrative expenses increased$9.7 million , or 66%, to$24.4 million for the three months endedJune 30, 2021 , as compared to$14.7 million for the three months endedJune 30, 2020 . Our general and administrative expenses increased 30% on a unit-of-production basis to$2.88 per BOE for the three months endedJune 30, 2021 , as compared to$2.21 per BOE for the three months endedJune 30, 2020 . These increases were largely attributable to employee compensation costs, including a$5.2 million increase in stock-based compensation expense we recorded primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. The share price of our common stock increased by 54% from$23.45 atMarch 31, 2021 to$36.01 atJune 30, 2021 . The remainder of the increase for the three months endedJune 30, 2021 , as compared to the three months endedJune 30, 2020 , resulted primarily from the reinstatement of employee compensation beginning inMarch 2021 , which had been previously reduced beginning inMarch 2020 in response to the significantly lower oil and natural gas price environment at that time. Interest expense. For the three months endedJune 30, 2021 , we incurred total interest expense of$19.8 million . We capitalized$1.9 million of our interest expense on certain qualifying projects for the three months endedJune 30, 2021 and expensed the remaining$17.9 million to operations. For the three months endedJune 30, 2020 , we incurred total interest expense of$20.1 million . We capitalized$1.8 million of our interest expense on certain qualifying projects for the three months endedJune 30, 2020 and expensed the remaining$18.3 million to operations. Income tax provision (benefit). Our income tax provision was$5.3 million for the three months endedJune 30, 2021 . Our effective tax rate for the three months endedJune 30, 2021 was 5%, which differed from amounts computed by applying theU.S. federal statutory rate to the pre-tax income due to recording the net deferred tax liability for state taxes, primarily inNew Mexico , and continuing to recognize a valuation allowance against ourU.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 endedDecember 31, 2020 . The valuation allowance will continue to be recognized until the future deferred tax benefits are more likely than not to become utilized. We recorded an income tax benefit of$109.8 million for the three months endedJune 30, 2020 , and our effective tax rate for the three months endedJune 30, 2020 was 24%, which differed from amounts computed by applying theU.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 inNew Mexico . 29 -------------------------------------------------------------------------------- Table of Conte nts Six Months EndedJune 30, 2021 as Compared to Six Months EndedJune 30, 2020 Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased$37.5 million , or 93%, to$78.0 million for the six months endedJune 30, 2021 , as compared to$40.5 million for the six months endedJune 30, 2020 . On a unit-of-production basis, our production taxes and transportation and processing expenses increased 67% to$5.15 per BOE for the six months endedJune 30, 2021 , as compared to$3.08 per BOE for the six months endedJune 30, 2020 . These increases were primarily due to (i) a$32.1 million increase in production taxes to$54.8 million for the six months endedJune 30, 2021 , as compared to$22.7 million for the six months endedJune 30, 2020 , primarily due to the significant increase in the weighted average oil and natural gas prices realized between the two periods, and (ii) a$5.4 million increase in transportation and processing expenses to$23.2 million for the six months endedJune 30, 2021 , as compared to$17.8 million for the six months endedJune 30, 2020 , primarily due to the 18% increase in our natural gas production to 39.3 Bcf for the six months endedJune 30, 2021 , as compared to 33.2 Bcf for the six months endedJune 30, 2020 . Lease operating. Our lease operating expenses decreased$2.4 million , or 4%, to$54.7 million for the six months endedJune 30, 2021 , as compared to$57.1 million for the six months endedJune 30, 2020 . Our lease operating expenses on a unit-of-production basis decreased 17% to$3.61 per BOE for the six months endedJune 30, 2021 , as compared to$4.34 per BOE for the six months endedJune 30, 2020 . These decreases were largely attributable to (i) a decrease in produced water trucking and disposal expenses of$1.7 million as more of our operated wells have been connected to produced water pipelines, (ii) a decrease in repairs and maintenance and equipment rentals of$3.1 million and (iii) a decrease in compressor rental charges of$1.1 million . These decreases were partially offset by increases associated with workovers and chemical expenses of$3.3 million , which were attributable to servicing an increased number of operated wells atJune 30, 2021 , as compared toJune 30, 2020 . Plant and other midstream services operating. Our plant and other midstream services operating expenses increased$7.7 million , or 39%, to$27.4 million for the six months endedJune 30, 2021 , as compared to$19.7 million for the six months endedJune 30, 2020 . This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of$14.2 million for the six months endedJune 30, 2021 , as compared to$10.5 million for the six months endedJune 30, 2020 , (ii) increased expenses associated with our expanded pipeline operations of$7.0 million for the six months endedJune 30, 2021 , as compared to$4.0 million for the six months endedJune 30, 2020 , and (iii) increased expenses associated with operating the expanded Black River Processing Plant of$6.2 million for the six months endedJune 30, 2021 , as compared to$5.2 million for the six months endedJune 30, 2020 . Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased$17.8 million , or 10%, to$166.3 million for the six months endedJune 30, 2021 , as compared to$184.1 million for the six months endedJune 30, 2020 . On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 22% to$10.98 per BOE for the six months endedJune 30, 2021 , as compared to$14.00 per BOE for the six months endedJune 30, 2020 . These decreases were attributable to the increase in our estimated total proved oil and natural gas reserves, as well as the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2020. The decrease in our depletion, depreciation and amortization expenses was partially offset by a$5.8 million increase in depreciation expenses attributable to our midstream segment to$15.6 million for the six months endedJune 30, 2021 as compared to$9.8 million for the six months endedJune 30, 2020 . Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment were recorded for the six months endedJune 30, 2021 . AtJune 30, 2020 , the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by$243.9 million . As a result, we recorded an impairment charge of$324.0 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax benefit of$80.1 million . This full-cost ceiling impairment of$324.0 million is reflected in our interim unaudited condensed consolidated statement of operations for the six months endedJune 30, 2020 . General and administrative. Our general and administrative expenses increased$15.6 million , or 51%, to$46.6 million for the six months endedJune 30, 2021 , as compared to$30.9 million for the six months endedJune 30, 2020 . Our general and administrative expenses increased 31% on a unit-of-production basis to$3.08 per BOE for the six months endedJune 30, 2021 , as compared to$2.35 per BOE for the six months endedJune 30, 2020 . These increases were largely attributable to employee compensation costs, including an$11.0 million increase in stock-based compensation expense we recorded primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. The share price of our common stock increased approximately three-fold from$12.06 atDecember 31, 2020 to$36.01 atJune 30, 2021 . The remainder of the increase for the six months endedJune 30, 2021 , as compared to the six months endedJune 30, 2020 , resulted primarily from the reinstatement of employee compensation beginning inMarch 2021 , which had been previously reduced beginning inMarch 2020 in response to the significantly lower oil and natural gas price environment at that time. 30 -------------------------------------------------------------------------------- Table of Conte nts Interest expense. For the six months endedJune 30, 2021 , we incurred total interest expense of$40.1 million . We capitalized$2.5 million of our interest expense on certain qualifying projects for the six months endedJune 30, 2021 and expensed the remaining$37.6 million to operations. For the six months endedJune 30, 2020 , we incurred total interest expense of$41.3 million . We capitalized$3.2 million of our interest expense on certain qualifying projects for the six months endedJune 30, 2020 and expensed the remaining$38.1 million to operations. Income tax provision (benefit). Our income tax provision was$8.2 million for the six months endedJune 30, 2021 . Our effective tax rate for the six months endedJune 30, 2021 was 5%, which differed from amounts computed by applying theU.S. federal statutory rate to the pre-tax income due to recording the net deferred tax liability for state taxes, primarily inNew Mexico , and continuing to recognize a valuation allowance against ourU.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 endedDecember 31, 2020 . The valuation allowance will continue to be recognized until the future deferred tax benefits are more likely than not to become utilized. We recorded an income tax benefit of$69.9 million for the six months endedJune 30, 2020 , and our effective tax rate for the six months endedJune 30, 2020 was 23%, which differed from amounts computed by applying theU.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 inNew 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 ofFive Point Energy LLC , our joint venture partner, in connection withSan Mateo . If capital expenditures were to exceed our operating cash flows during the remainder of 2021, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. AtJune 30, 2021 , we had cash totaling$44.6 million and restricted cash totaling$34.6 million , which was associated withSan Mateo . By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. During each of the first and second quarters of 2021, we had net repayments of$100.0 million in borrowings under the Credit Agreement. In addition, the Board declared our first two quarterly cash dividends of$0.025 per share of common stock, which were paid onMarch 31, 2021 andJune 3, 2021 . InJuly 2021 , the Board declared a quarterly cash dividend of$0.025 per share of common stock payable onSeptember 3, 2021 to shareholders of record as ofAugust 12, 2021 . AtJune 30, 2021 , we had (i)$1.05 billion of outstanding 5.875% senior notes dueSeptember 2026 (the "Notes"), (ii)$240.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately$45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv)$7.5 million outstanding under an unsecuredU.S. Small Business Administration ("SBA") loan. InApril 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. ThisApril 2021 redetermination constituted the regularly scheduledMay 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 inOctober 2023 . The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to$50.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 4.0 or less. We believe that we were in compliance with the terms of the Credit Agreement atJune 30, 2021 . AtJune 30, 2021 ,San Mateo had$352.5 million in borrowings outstanding under the San Mateo Credit Facility and approximately$9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. BetweenJune 30, 2021 andJuly 27, 2021 ,San Mateo repaid$25.0 million of borrowings under the San Mateo Credit Facility. The San Mateo Credit Facility maturesDecember 19, 2023 and was amended inJune 2021 to increase the lender commitments under that facility from$375 million to$450 million (subject toSan Mateo's compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender 31 -------------------------------------------------------------------------------- Table of Conte nts commitments to up to$700.0 million . The San Mateo Credit Facility is guaranteed bySan Mateo's subsidiaries, secured by substantially all ofSan Mateo's assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries. The San Mateo Credit Facility requiresSan Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.0 or less, subject to certain exceptions. The San Mateo Credit Facility also requiresSan Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided bySan Mateo's consolidated interest expense for such period, of 2.5 or more. The San Mateo Credit Facility also restricts the ability ofSan Mateo to distribute cash to its members ifSan Mateo's liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe thatSan Mateo was in compliance with the terms of the San Mateo Credit Facility atJune 30, 2021 . OnApril 13, 2020 , we executed a promissory note evidencing an unsecured loan in the amount of approximately$7.5 million as part of the Paycheck Protection Program. For a discussion of such loan, see "Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources" in the Annual Report. During the six months endedJune 30 and throughJuly 2021 , the oil and natural gas industry has experienced continued improvement in commodity prices as compared to 2020, primarily resulting from (i) improvements in oil demand as the impact from COVID-19 has begun to abate and (ii) actions taken by theOrganization 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 atDecember 31, 2020 to as high as$74.05 per barrel in lateJune 2021 . While oil prices have improved in 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains uncertain, and we can provide no assurances as to when or to what extent economic disruptions resulting from COVID-19 and the corresponding decreases in oil demand may improve further. These economic disruptions have also impacted our ability to access the capital markets on reasonably similar terms as were available prior to 2020. Prices for natural gas and NGLs were also much higher during the six months endedJune 30 and throughJuly 2021 as compared to 2020. We expect that development of ourDelaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 2021. We operated four drilling rigs in theDelaware Basin during the second quarter of 2021. AtJuly 27, 2021 , two of these rigs were drilling in the Stateline asset area inEddy County, New Mexico . These two rigs recently completed drilling 13 additional Boros wells in the eastern portion of the Stateline asset area and atJuly 27, 2021 were drilling 11 new Voni wells in the western portion of that asset area. The other two rigs have been drilling 13 wells in the GreaterStebbins Area , nine of which were still in progress atJuly 27, 2021 . Four of these wells, all Second Bone Spring completions, were recently turned to sales. When we complete drilling the nine wells in progress in the GreaterStebbins Area , we plan to use these two rigs to drill two additional wells in the Ranger asset area inLea County, New Mexico and several additionalRodney Robinson wells in the western portion of theAntelope Ridge asset area inLea County . AtJuly 27, 2021 , our 2021 estimated capital expenditures forD/C/E capital expenditures remained$525 to$575 million , as originally estimated. As a result of savings on our operatedD/C/E capital expenditures in the first half of 2021, a faster drilling and completions pace and an anticipated decrease in non-operatedD/C/E capital expenditures in the second half of 2021, we intend to advance the next 11 Voni well completions in the Stateline asset area forward into the fourth quarter of 2021 and expect to be able to do so without increasing our estimates forD/C/E capital expenditures for full year 2021. AtJuly 27, 2021 , we increased our anticipated 2021 midstream capital expenditures from$20 to$30 million to$35 to$45 million , primarily to accommodate several new midstream opportunities forSan Mateo with producers inEddy County, New Mexico and to accelerate the installation of compression facilities and other infrastructure prior to the end of 2021 in order to be prepared for the additional volumes from the accelerated Voni completions noted above. Previously, these Voni-related capital expenditures were scheduled for early 2022. The anticipated total 2021 midstream capital expenditures of$35 to$45 million primarily reflect our proportionate share ofSan 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 theDelaware Basin , with the exception of amounts allocated to limited operations in ourSouth Texas andHaynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2021Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout theDelaware 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. 32 -------------------------------------------------------------------------------- Table of Conte nts We may divest portions of our non-core assets, particularly in the Eagle Ford shale inSouth Texas and theHaynesville shale andCotton Valley plays inNorthwest 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 theDelaware 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 theDelaware Basin , the Eagle Ford shale inSouth Texas and theHaynesville shale inNorthwest Louisiana . Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for the remainder of 2021 and the hedges we currently have in place. For further discussion of our expectations of such commodity prices, see "-General Outlook and Trends" below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 7 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments. Our unaudited cash flows for the six months endedJune 30, 2021 and 2020 are presented below: Six Months Ended June 30, (In thousands) 2021 2020 Net cash provided by operating activities$ 427,595 $ 210,385 Net cash used in investing activities (251,122) (458,761) Net cash (used in) provided by financing activities (188,648) 226,756 Net change in cash and restricted cash$ (12,175) $ (21,620) Adjusted EBITDA attributable toMatador Resources Company shareholders(1)$ 459,081 $ 248,170 __________________ (1)Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see "-Non-GAAP Financial Measures" below. Cash Flows Provided by Operating Activities Net cash provided by operating activities increased$217.2 million to$427.6 million for the six months endedJune 30, 2021 from$210.4 million for the six months endedJune 30, 2020 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased$221.7 million to$457.4 million for the six months endedJune 30, 2021 from$235.7 million for the six months endedJune 30, 2020 , primarily attributable to significantly higher realized oil and natural gas prices and higher oil and natural gas production for the six months endedJune 30, 2021 , as compared to the six months endedJune 30, 2020 . Changes in our operating assets and liabilities between the two periods resulted in a net decrease of approximately$4.5 million in net cash provided by operating activities for the six months endedJune 30, 2021 , as compared to the six months endedJune 30, 2020 . 33 -------------------------------------------------------------------------------- Table of Conte nts Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. Furthermore, the effects of COVID-19 and the corresponding decline in oil demand significantly impacted the prices we received for our oil production in recent periods, particularly during 2020. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. Cash Flows Used in Investing Activities Net cash used in investing activities decreased$207.6 million to$251.1 million for the six months endedJune 30, 2021 from$458.8 million for the six months endedJune 30, 2020 . This decrease in net cash used in investing activities was primarily due to (i) a decrease of$98.2 million in midstream capital expenditures, (ii) a decrease of$72.6 million inD/C/E capital expenditures and (iii) a decrease of$36.4 million in expenditures related to acquisition of oil and natural gas properties for the six months endedJune 30, 2021 , as compared to the six months endedJune 30, 2020 . Cash used forD/C/E capital expenditures for the six months endedJune 30, 2021 and 2020 was primarily attributable to our operated and non-operated drilling and completion activities in theDelaware Basin . Cash used for midstream capital expenditures for the six months endedJune 30, 2020 was primarily attributable to the expansion of theBlack River Processing Plant and midstream facilities in the GreaterStebbins Area and the Stateline asset area, which were completed in 2020. Cash Flows (Used in) Provided by Financing Activities Net cash used in financing activities was$188.6 million for the six months endedJune 30, 2021 , a significant change from net cash provided by financing activities of$226.8 million for the six months endedJune 30, 2020 . During the six months endedJune 30, 2021 , our primary uses of cash related to financing activities were for the net repayment of$200.0 million in borrowings under our Credit Agreement and the payment of our first two quarterly dividends. These payments were partially offset by net borrowings under the San Mateo Credit Facility of$18.5 million . During the six months endedJune 30, 2020 , our primary sources of cash from financing activities included borrowings under our Credit Agreement of$130.0 million , borrowings under the San Mateo Credit Facility of$32.0 million and net contributions related to the formation ofSan Mateo and from non-controlling interest owners in less-than-wholly-owned subsidiaries of$59.8 million . See Note 4 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes. Guarantor Financial Information The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the "Guarantor Subsidiaries") on a full and unconditional basis (except for customary release provisions). AtJune 30, 2021 , the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan.San Mateo and its subsidiaries are not guarantors of the Notes. 34
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Table of Conte nts 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.
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