# Matador Resources Co (MTDR) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Matador Resources Co's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1520006/000152000622000065/mtdr-20211231.htm
Accession: 0001520006-22-000065
Filing date: 2022-02-28
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/MTDR/
All MD&A years: /company/MTDR/mda/
Next year: /company/MTDR/mda/fy2022/ (FY 2022)

Item 7. 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 consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the impact of the worldwide spread of COVID-19 on oil and natural gas demand, oil and natural gas prices and our business, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

For a comparison of our results of operations for the years ended December 31, 2020 and December 31, 2019, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 26, 2021.

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.

2021 Operational Highlights

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 Lea and Eddy Counties, New Mexico and Loving County, Texas. In March 2021, we added a fourth rig to our operated drilling program, and in August 2021, we began operating a fifth drilling rig on behalf of San Mateo for the purpose of drilling an additional salt water disposal well in the southern part of the Arrowhead asset area in Eddy County, New Mexico (the “Greater Stebbins Area”). In October 2021, following the conclusion of drilling operations on the salt water disposal well, we moved this rig to the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area in Lea County, New Mexico. We operated five drilling rigs in the Delaware Basin during the remainder of 2021. Despite the addition of the fifth operated drilling rig and the acceleration of 11 Voni well completions forward into the fourth quarter of 2021, we were able to achieve D/C/E capital expenditures for 2021 of $513 million, which was below our original estimated range for 2021 D/C/E capital expenditures of $525 to $575 million as provided on February 23, 2021 and our revised estimated range for 2021 D/C/E capital expenditures of $535 to $565 million as provided on October 26, 2021.

During the year ended December 31, 2021, we completed and began producing oil and natural gas from 47 gross (44.2 net) operated and 50 gross (4.0 net) non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net) non-operated Haynesville shale wells that began producing in 2021.

The vast majority of our 2021 capital expenditures was directed to (i) the delineation and development of our leasehold position in the Delaware Basin, (ii) the development of certain midstream assets to support our operations there, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were primarily directed to the installation of pumping units and other

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facilities on certain of our Eagle Ford shale wells in South Texas and to our participation in several non-operated wells drilled and completed in the Haynesville shale in Northwest Louisiana throughout 2021.

Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%, as compared to 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, for the year ended December 31, 2020. Our average daily oil production in 2021 of 48,876 Bbl of oil per day increased 12% from 43,526 Bbl of oil per day in 2020. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production of 223.8 MMcf per day in 2021 increased 18% from 189.9 MMcf per day in 2020. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production in the Haynesville shale where we had significantly less non-operated activity in 2020 and 2021 as compared to 2019. Oil production comprised 57% of our total production for the year ended December 31, 2021, as compared to 58% in 2020.

For the year ended December 31, 2021, our oil and natural gas revenues were $1.70 billion, an increase of 128% from oil and natural gas revenues of $744.5 million for the year ended December 31, 2020. Our oil revenues increased 102% to $1.21 billion, as compared to $595.5 million for the year ended December 31, 2020. The increase in oil revenues resulted from a significantly higher weighted average realized oil price of $67.58 per Bbl in 2021, as compared to $37.38 per Bbl in 2020, as well as the 12% increase in oil production for the year ended December 31, 2021 noted above. Our natural gas revenues increased 232% to $494.9 million, as compared to $149.0 million for the year ended December 31, 2020. The increase in natural gas revenues resulted from an almost three-fold increase in our weighted average realized natural gas price of $6.06 per Mcf in 2021, as compared to $2.14 per Mcf in 2020, and the 18% increase in our natural gas production noted above.

We reported net income attributable to Matador shareholders of approximately $585.0 million, or $4.91 per diluted common share, on a GAAP basis for the year ended December 31, 2021, as compared to a net loss of $593.2 million, or ($5.11) per diluted common share, for the year ended December 31, 2020. Adjusted EBITDA for the year ended December 31, 2021 was $1.05 billion, as compared to Adjusted EBITDA of $519.3 million for the year ended December 31, 2020. 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 “Selected Financial Data—Non-GAAP Financial Measures.”

At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, with a Standardized Measure of $4.38 billion and a PV-10 of $5.35 billion. At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, with a Standardized Measure of $1.58 billion and a PV-10 of $1.66 billion. Our estimated total proved reserves of 323.4 million BOE at December 31, 2021 represented a 20% year-over-year increase, as compared to 270.3 million BOE at December 31, 2020. Our estimated proved oil reserves of 181.3 million Bbl at December 31, 2021 increased 13%, as compared to 159.9 million Bbl at December 31, 2020, and our estimated proved natural gas reserves of 852.5 Bcf at December 31, 2021 increased 29%, as compared to 662.3 Bcf at December 31, 2020. Proved oil reserves comprised 56% of our total proved reserves at December 31, 2021, as compared to 59% at December 31, 2020. At December 31, 2021, 60% of our total proved reserves were proved developed reserves, as compared to 46% at December 31, 2020.

Our proved oil and natural gas reserves in the Delaware Basin increased 19% to 312.0 million BOE at December 31, 2021, as compared to 261.9 million BOE at December 31, 2020, primarily as a result of our ongoing delineation and development operations there. At December 31, 2021, approximately 96% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 13% to 177.1 million Bbl at December 31, 2021, as compared to 156.3 million Bbl at December 31, 2020, and our proved natural gas reserves in the Delaware Basin increased 28% to 809.3 Bcf, as compared to 633.5 Bcf at December 31, 2020. Proved oil reserves comprised 57% of our Delaware Basin total proved reserves at December 31, 2021, as compared to 60% at December 31, 2020.

At both December 31, 2021 and December 31, 2020, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.”

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2021 Midstream Highlights

San Mateo achieved strong operating results in 2021, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2020. Volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2021 and 2020. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.

During 2021, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021.

At December 31, 2021, San Mateo’s midstream system included:

•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;

•Oil Assets: Three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and

•Produced Water Assets: 14 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

2022 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2022. In the second half of 2021, we added a fifth operated drilling rig in the Delaware Basin to drill a salt water disposal well on behalf of San Mateo. In October 2021, following the conclusion of drilling operations on the salt water disposal well, we began drilling oil and natural gas wells with this rig, and we plan to operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22, 2022, we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the newly acquired acreage throughout the remainder of 2022. We have built significant optionality into our 2022 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2022 estimated capital expenditure budget consists of $640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially all of these 2022 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 2022 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 high percentage of longer horizontal wells in 2022, including 90% with anticipated completed lateral lengths of two miles or greater.

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At December 31, 2021, we had $48.1 million in cash (excluding restricted cash) and $554.2 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $700.0 million). Excluding any possible significant acquisitions, we expect to fund our 2022 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2022, 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.

We may divest portions of our non-core assets, particularly in the Haynesville shale and in our South Texas position (as we did in 2020, 2021 and early 2022), as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin, during 2022. 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 2022 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 acquisitions of producing properties, acreage and mineral interests and midstream assets for 2022. The aggregate amount of capital we 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.

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Revenues

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

[[GREPCENT_TABLE]]
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[[/GREPCENT_TABLE]]

________________

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

(2)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020

Oil and natural gas revenues. Our oil and natural gas revenues increased $956.1 million, or 128%, to $1.70 billion for the year ended December 31, 2021, as compared to $744.5 million for the year ended December 31, 2020. Our oil revenues increased $610.1 million, or 102%, to $1.21 billion for the year ended December 31, 2021, as compared to $595.5 million for the year ended December 31, 2020. This increase in oil revenues resulted from an 81% increase in the weighted average oil price realized for the year ended December 31, 2021 to $67.58 per Bbl, as compared to $37.38 per Bbl realized for the year ended December 31, 2020, and the 12% increase in our oil production to 17.8 million Bbl of oil for the year ended December 31, 2021, as compared to 15.9 million Bbl of oil for the year ended December 31, 2020. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $346.0 million, or 232%, to $494.9 million for the year ended December 31, 2021, as compared to $149.0 million for the year ended December 31, 2020. The increase in natural gas revenues was primarily attributable to the almost three-fold increase in the weighted average natural gas price realized for the year ended December 31, 2021 to $6.06 per Mcf, as compared to $2.14 per Mcf realized for the year ended December 31, 2020, and the 18% increase in our natural gas production to 81.7 Bcf for the year ended December 31, 2021, as compared to 69.5 Bcf for the year ended December 31, 2020. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production from our properties in the Haynesville shale.

Third-party midstream services revenues. Our third-party midstream services revenues increased $10.6 million, or 16%, to $75.5 million for the year ended December 31, 2021, as compared to $64.9 million for the year ended December 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 increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $37.6 million for the year ended December 31, 2021, as compared to $30.1 million for the year ended December 31, 2020, (ii) an increase in our third-party oil gathering and transportation revenues to $10.2 million for the year ended December 31, 2021, as compared to $9.4 million for the year ended December 31, 2020, and (iii) an increase in third-party produced water handling revenues to $27.6 million for the year ended December 31, 2021, as compared to $25.5 million for the year ended December 31, 2020.

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Sales of purchased natural gas. Our sales of purchased natural gas increased $44.3 million, or 106%, to $86.0 million for the year ended December 31, 2021, as compared to $41.7 million for the year ended December 31, 2020. This increase was primarily the result of the increase in realized natural gas prices and an increase in natural gas volumes sold during the year ended December 31, 2021. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at the Black River Processing Plant and subsequently sell the residue gas and NGLs 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 consolidated statements of operations.

Lease bonus - mineral acreage. We did not lease any of our mineral acreage to third parties during the year ended December 31, 2021. Our lease bonus - mineral acreage revenues were $4.1 million for the year ended December 31, 2020. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $220.1 million for the year ended December 31, 2021, as compared to a realized net gain of approximately $38.9 million for the year ended December 31, 2020. We realized a net loss of $197.5 million related to our oil costless collar and swap contracts for the year ended December 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 price of certain of our oil swap contracts. We also realized a net loss of approximately $26.1 million related to our natural gas costless collar contracts for the year ended December 31, 2021, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net gain of $3.5 million from our oil basis swap contracts for the year ended December 31, 2021, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized a net gain of $35.1 million related to our oil costless collar, put and swap contracts for the year ended December 31, 2020, resulting primarily from oil prices that were below the floor prices of certain of our oil costless collar contracts and below the strike price of certain of our oil put and swap contracts. We realized a net gain of $3.8 million from our oil basis swap contracts for the year ended December 31, 2020, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized an average loss on our oil derivatives of approximately $10.88 per Bbl of oil produced during the year ended December 31, 2021, as compared to an average gain of $2.45 per Bbl of oil produced during the year ended December 31, 2020. We realized an average loss on our natural gas derivatives of approximately $0.32 per Mcf of natural gas produced during the year ended December 31, 2021, as compared to no gain or loss on our natural gas derivatives during the year ended December 31, 2020. Our total oil volumes hedged for the year ended December 31, 2021 represented 61% of our total oil production, as compared to 77% of our total oil production for the year ended December 31, 2020. Our total natural gas volumes hedged for the year ended December 31, 2021 represented 62% of our total natural gas production, as compared to 10% of our total natural gas production for the year ended December 31, 2020.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $21.0 million for the year ended December 31, 2021, as compared to an unrealized loss of $32.0 million for the year ended December 31, 2020. During the year ended December 31, 2021, the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts increased from a net liability of approximately $35.9 million to a net liability of approximately $14.9 million, resulting in an unrealized gain on derivatives of approximately $21.0 million for the year ended December 31, 2021. During the year ended December 31, 2020, the aggregate net fair value of our open oil and natural gas derivative and oil basis swap contracts decreased from a net liability of approximately $3.9 million to a net liability of $35.9 million, resulting in an unrealized loss on derivatives of approximately $32.0 million for the year ended December 31, 2020.

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Expenses

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","2020","","2019"],["(In thousands, except expenses per BOE)"],["Expenses:"],["Production taxes, transportation and processing","","$","178,987","","","$","93,338","","","$","92,273"],["Lease operating","","108,964","","","104,953","","","117,305"],["Plant and other midstream services operating","","61,459","","","41,500","","","36,798"],["Purchased natural gas","","77,126","","","32,734","","","69,398"],["Depletion, depreciation and amortization","","344,905","","","361,831","","","350,540"],["Accretion of asset retirement obligations","","2,068","","","1,948","","","1,822"],["Full-cost ceiling impairment","","\u2014","","","684,743","","","\u2014"],["General and administrative","","96,396","","","62,578","","","80,054"],["Total expenses","","869,905","","","1,383,625","","","748,190"],["Operating income","","793,076","","","(521,499)","","","235,480"],["Other income (expense):"],["Net loss on asset sales and inventory impairment","","(331)","","","(2,832)","","","(967)"],["Interest expense","","(74,687)","","","(76,692)","","","(73,873)"],["Other (expense) income","","(2,712)","","","1,864","","","(2,126)"],["Total other (expense) income","","(77,730)","","","(77,660)","","","(76,966)"],["Income (loss) before income taxes","","715,346","","","(599,159)","","","158,514"],["Total income tax provision (benefit)","","74,710","","","(45,599)","","","35,532"],["Net income attributable to non-controlling interest in subsidiaries","","(55,668)","","","(39,645)","","","(35,205)"],["Net income (loss) attributable to Matador Resources Company shareholders","","$","584,968","","","$","(593,205)","","","$","87,777"],["Expenses per BOE:"],["Production taxes, transportation and processing","","$","5.69","","","$","3.39","","","$","3.82"],["Lease operating","","$","3.46","","","$","3.81","","","$","4.85"],["Plant and other midstream services operating","","$","1.95","","","$","1.51","","","$","1.52"],["Depletion, depreciation and amortization","","$","10.97","","","$","13.15","","","$","14.51"],["General and administrative","","$","3.06","","","$","2.27","","","$","3.31"]]
[[/GREPCENT_TABLE]]

Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $85.6 million, or 92%, to $179.0 million for the year ended December 31, 2021, as compared to $93.3 million for the year ended December 31, 2020. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 68% to $5.69 per BOE for the year ended December 31, 2021, as compared to $3.39 per BOE for the year ended December 31, 2020. These increases were primarily attributable to the $76.5 million increase in our production taxes to $129.8 million for the year ended December 31, 2021, as compared to $53.4 million for the year ended December 31, 2020, resulting from the $956.1 million increase in oil and natural gas revenues for the year ended December 31, 2021, as compared to the year ended December 31, 2020 and the $9.2 million increase in transportation and processing expenses to $49.2 million for the year ended December 31, 2021, as compared to $40.0 million for the year ended December 31, 2020, primarily resulting from the 14% increase in total oil equivalent production between the respective periods.

Lease operating expenses. Our lease operating expenses increased $4.0 million, or 4%, to $109.0 million for the year ended December 31, 2021, as compared to $105.0 million for the year ended December 31, 2020. This increase in our lease operating expenses for the year ended December 31, 2021 was attributable to an increase in workover expenses of $4.0 million, which resulted from additional well maintenance operations conducted during the year-ended December 31, 2021, as compared to 2020. On a unit-of-production basis, our lease operating expenses decreased 9% to $3.46 per BOE for the year ended December 31, 2021, as compared to $3.81 per BOE for the year ended December 31, 2020, primarily resulting from the 14% increase in total oil equivalent production between the respective periods.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $20.0 million, or 48%, to $61.5 million for the year ended December 31, 2021, as compared to $41.5 million for the year ended December 31, 2020. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of $30.8 million for the year ended December 31, 2021, as compared to $21.8 million for the year ended December 31, 2020, (ii) increased expenses associated with our expanded pipeline operations of

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$17.5 million for the year ended December 31, 2021, as compared to $10.0 million for the year ended December 31, 2020, and (iii) increased expenses associated with operating the Black River Processing Plant of $13.1 million for the year ended December 31, 2021, as compared to $9.7 million for the year ended December 31, 2020.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $16.9 million, or 5%, to $344.9 million for the year ended December 31, 2021, as compared to $361.8 million for the year ended December 31, 2020. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 17% to $10.97 per BOE for the year ended December 31, 2021, as compared to $13.15 per BOE for the year ended December 31, 2020. These decreases were primarily attributable to the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded during the year ended December 31, 2020. These decreases were partially offset by (i) the 14% increase in total oil equivalent production to 31.5 million BOE for the year ended December 31, 2021, as compared to 27.5 million BOE for the year ended December 31, 2020, and (ii) increased depreciation expenses attributable to our midstream segment of approximately $31.5 million for the year ended December 31, 2021, as compared to $23.3 million for the year ended December 31, 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 year ended December 31, 2021. Due to the sharp decline in oil and natural gas prices used to estimate proved oil and natural gas reserves in 2020, at June 30, 2020, September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded an impairment charge of $684.7 million, exclusive of tax effect, to our net capitalized costs. This full-cost ceiling impairment is reflected in our consolidated statement of operations for the year ended December 31, 2020, with the related deferred income tax credit recorded net of a valuation allowance.

General and administrative. Our general and administrative expenses increased $33.8 million, or 54%, to $96.4 million for the year ended December 31, 2021, as compared to $62.6 million for the year ended December 31, 2020. Our general and administrative expenses on a unit-of-production basis increased 35% to $3.06 per BOE for the year ended December 31, 2021, as compared to $2.27 per BOE for the year ended December 31, 2020. These increases were largely attributable to employee compensation costs, including a $16.1 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period based upon our share price at the end of each reporting period. The share price of our common stock increased from $12.06 at December 31, 2020 to $36.92 at December 31, 2021. The remainder of the increase for the year ended December 31, 2021, as compared to December 31, 2020, resulted primarily from the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time.

Interest expense. For the year ended December 31, 2021, we incurred total interest expense of approximately $79.5 million. We capitalized approximately $4.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2021 and expensed the remaining $74.7 million to operations. For the year ended December 31, 2020, we incurred total interest expense of approximately $82.2 million. We capitalized $5.5 million of our interest expense on certain qualifying projects for the year ended December 31, 2020 and expensed the remaining $76.7 million to operations.

Total income tax provision (benefit). At December 31, 2020, our deferred tax assets exceeded our deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, we established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. Due to a variety of factors, including our significant net income in 2021, our federal valuation allowance was reversed at September 30, 2021 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of our state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. We recorded a total income tax provision of $74.7 million for the year ended December 31, 2021. Our effective tax rate was 11.3% for the year ended December 31, 2021, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of reversing the valuation allowance, but also due to permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a total income tax benefit of $45.6 million for the year ended December 31, 2020. Our effective tax rate was 7.6% for the year ended December 31, 2020, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of the valuation allowance, but also due to permanent differences between book and taxable income and state taxes, primarily in New Mexico.

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Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during 2022 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 2022 primarily through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2022, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.

At December 31, 2021, we had cash totaling $48.1 million and restricted cash totaling $38.8 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

At December 31, 2021, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $100.0 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 November 2021, the Company and lenders under our Credit Agreement entered into a Fourth Amended and Restated Credit Agreement, under which the borrowing base was increased to $1.35 billion. We elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and certain modifications were made to the terms of the Credit Agreement. These modifications include extending the maturity date to October 31, 2026, increasing the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50% and updating the key financial covenants under the Credit Agreement to require the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter, and (ii) a debt to EBITDA ratio, which is defined as total debt outstanding (net of up to $75.0 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less. This November 2021 update to the Credit Agreement took the place of the regularly scheduled November 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 covenants noted above). We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2021. Between December 31, 2021 and February 28, 2022, we repaid an additional $25.0 million of borrowings outstanding under the Credit Agreement.

At December 31, 2021, San Mateo had $385.0 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 matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under that facility from $375 million to $450 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility contains an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $700.0 million. The San Mateo Credit Facility 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 December 31, 2021. Between December 31, 2021 and February 22, 2022, we repaid an additional $30.0 million of borrowings outstanding under the San Mateo Credit Facility.

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On April 13, 2020, we executed a promissory note evidencing an unsecured loan in the amount of approximately $7.5 million as part of the Paycheck Protection Program. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act and is administered by the SBA. The loan was issued through Iberiabank, which is a lender under the Credit Agreement, matures on the second anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. We used the proceeds of the loan for payroll, including salaries, payroll taxes and employee medical benefits, as permitted by the program. The receipt of the loan allowed us to avoid further reductions to employee headcount and salaries above those taken in March 2020. The loan is eligible for forgiveness for the portion of the loan proceeds used for payroll costs and other designated operating expenses, provided at least 60% of the loan’s proceeds are used for payroll costs. During 2021, we applied to the SBA for forgiveness of the Paycheck Protection Program loan, as all proceeds were used for payroll costs.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2022. In the second half of 2021, we added a fifth contracted drilling rig in the Delaware Basin and plan to operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22, 2022, we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the newly acquired acreage throughout the remainder of 2022. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2022 estimated capital expenditure budget consists of $640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially all of these 2022 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, as well as 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 2022 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 high percentage of longer horizontal wells in 2022, including 90% with anticipated completed lateral lengths of two miles or greater.

We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale 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 producing properties, acreage and mineral interests, principally in the Delaware Basin, during 2022. 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 2022 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 acquiring producing properties, acreage and mineral interests for 2022.

Our 2022 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 2022 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 2022 and the hedges we currently have in place. For a 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 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2021. See “Risk

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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,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% 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.”

Our cash flows for the years ended December 31, 2021, 2020 and 2019 are presented below.

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","2020","","2019"],["(In thousands)"],["Net cash provided by operating activities","","$","1,053,355","","","$","477,582","","","$","552,042"],["Net cash used in investing activities","","(729,265)","","","(775,666)","","","(903,976)"],["Net cash (used in) provided by financing activities","","(328,553)","","","324,339","","","333,078"],["Net change in cash","","$","(4,463)","","","$","26,255","","","$","(18,856)"],["Adjusted EBITDA attributable to Matador Resources Company shareholders(1)","","$","1,051,973","","","$","519,277","","","$","610,756"]]
[[/GREPCENT_TABLE]]

__________________

(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 by $575.8 million to $1.05 billion for the year ended December 31, 2021, as compared to net cash provided by operating activities of $477.6 million for the year ended December 31, 2020. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $1.05 billion for the year ended December 31, 2021 from $500.7 million for the year ended December 31, 2020. This increase was primarily attributable to significantly higher realized oil and natural gas prices for the year ended December 31, 2021, as compared to the year ended December 31, 2020, as well as the 14% increase in total oil equivalent production during 2021, as compared to 2020. Changes in our operating assets and liabilities between December 31, 2020 and December 31, 2021 resulted in a net increase of approximately $22.1 million in net cash provided by operating activities for the year ended December 31, 2021, as compared to the year ended December 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. For example, 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 in 2020. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “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.”

Cash Flows Used in Investing Activities

Net cash used in investing activities decreased by $46.4 million to $729.3 million for the year ended December 31, 2021 from $775.7 million for the year ended December 31, 2020. This decrease in net cash used in investing activities was primarily attributable to a decrease of $40.0 million in D/C/E capital expenditures as compared to the year ended December 31, 2020, and a decrease of approximately $171.0 million in expenditures for midstream support equipment and facilities, resulting from completing the construction of the further expansion of the Black River Processing Plant and associated infrastructure, additional salt water disposal wells and additional pipeline infrastructure during 2020. These decreases were partially offset by an increase of $165.8 million in expenditures primarily related to our acquisition of oil and natural gas properties in the

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Delaware Basin during 2021. Cash used for D/C/E capital expenditures for the year ended December 31, 2021 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin.

Cash Flows (Used in) Provided by Financing Activities

Net cash used in financing activities was $328.6 million for the year ended December 31, 2021, as compared to net cash provided by financing activities of $324.3 million for the year ended December 31, 2020. The net cash used in financing activities for the year ended December 31, 2021 was primarily attributable to (i) net repayments under our Credit Agreement of $340.0 million, (ii) net borrowings under the San Mateo Credit Facility of $51.0 million, (iii) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $13.4 million and (iv) dividends paid of $14.6 million.

See Note 7 to the consolidated financial statements in this Annual 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 December 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.

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.

[[GREPCENT_TABLE]]
[["(in thousands)"],["Summarized Balance Sheet","","December 31, 2021"],["Assets"],["Current assets","","$","305,712"],["Net property and equipment","","$","3,060,233"],["Other long-term assets","","$","48,890"],["Liabilities"],["Current liabilities","","$","461,013"],["Long-term debt","","$","1,142,580"],["Other long-term liabilities","","$","138,010"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(in thousands)","","Year Ended"],["Summarized Statement of Operations","","December 31, 2021"],["Revenues","","$","1,543,420"],["Expenses","","873,037"],["Operating income","","$","670,383"],["Other expense","","(67,823)"],["Tax provision","","(74,710)"],["Net income","","$","527,850"]]
[[/GREPCENT_TABLE]]

Non-GAAP Financial Measures

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

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

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by 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.

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","2020","","2019"],["(In thousands)"],["Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):"],["Net income (loss) attributable to Matador Resources Company shareholders","","$","584,968","","","$","(593,205)","","","$","87,777"],["Net income attributable to non-controlling interest in subsidiaries","","55,668","","","39,645","","","35,205"],["Net income (loss)","","640,636","","","(553,560)","","","122,982"],["Interest expense","","74,687","","","76,692","","","73,873"],["Total income tax provision (benefit)","","74,710","","","(45,599)","","","35,532"],["Depletion, depreciation and amortization","","344,905","","","361,831","","","350,540"],["Accretion of asset retirement obligations","","2,068","","","1,948","","","1,822"],["Full-cost ceiling impairment","","\u2014","","","684,743","","","\u2014"],["Unrealized (gain) loss on derivatives","","(21,011)","","","32,008","","","53,727"],["Non-cash stock-based compensation expense","","9,039","","","13,625","","","18,505"],["Net loss on asset sales and impairment","","331","","","2,832","","","967"],["Expense related to contingent consideration","","1,485","","","\u2014","","","\u2014"],["Consolidated Adjusted EBITDA","","1,126,850","","","574,520","","","657,948"],["Adjusted EBITDA attributable to non-controlling interest in subsidiaries","","(74,877)","","","(55,243)","","","(47,192)"],["Adjusted EBITDA attributable to Matador Resources Company shareholders","","$","1,051,973","","","$","519,277","","","$","610,756"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","2020","","2019"],["(In thousands)"],["Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:"],["Net cash provided by operating activities","","$","1,053,355","","","$","477,582","","","$","552,042"],["Net change in operating assets and liabilities","","982","","","23,078","","","34,517"],["Interest expense, net of non-cash portion","","71,028","","","73,860","","","71,389"],["Expense related to contingent consideration","","1,485","","","\u2014","","","\u2014"],["Adjusted EBITDA attributable to non-controlling interest in subsidiaries","","(74,877)","","","(55,243)","","","(47,192)"],["Adjusted EBITDA attributable to Matador Resources Company shareholders","","$","1,051,973","","","$","519,277","","","$","610,756"]]
[[/GREPCENT_TABLE]]

For the year ended December 31, 2021, we reported net income attributable to Matador shareholders of $585.0 million, as compared to a net loss attributable to Matador shareholders of $593.2 million for the year ended December 31, 2020. This increase primarily resulted from (i) significantly higher realized oil and natural gas prices and higher oil and natural gas production, for the year ended December 31, 2021, as compared to the year ended December 31, 2020, and (ii) no full-cost ceiling impairment recorded for the year ended December 31, 2021, as compared to $684.7 million recorded for the year ended December 31, 2020. These increases were partially offset by a realized loss on derivatives of $220.1 million for the year ended December 31, 2021, as compared to a realized gain on derivatives of $38.9 million for the year ended December 31, 2020, and an income tax provision of $74.7 million for the year ended December 31, 2021, as compared to an income tax benefit of $45.6 million for the year ended December 31, 2020.

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Adjusted EBITDA, a non-GAAP financial measure, increased $532.7 million to $1.05 billion for the year ended December 31, 2021, as compared to $519.3 million for the year ended December 31, 2020. This increase was primarily attributable to the significantly higher realized oil and natural gas prices and higher oil and natural gas production noted above for the year ended December 31, 2021, as compared to the year ended December 31, 2020.

Off-Balance Sheet Arrangements

 From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 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 14 to the consolidated financial statements in this Annual 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 December 31, 2021.

[[GREPCENT_TABLE]]
[["","","Payments Due by Period"],["","","Total","","Less Than 1 Year","","1-3 Years","","3-5 Years","","More Than 5 Years"],["(In thousands)"],["Contractual Obligations:"],["Borrowings, including letters of credit(1)","","$","547,273","","","$","\u2014","","","$","401,470","","","$","145,803","","","$","\u2014"],["Senior unsecured notes(2)","","1,050,000","","","\u2014","","","\u2014","","","1,050,000","","","\u2014"],["Office leases","","18,483","","","4,123","","","8,529","","","5,831","","","\u2014"],["Non-operated drilling and other capital commitments(3)","","65,414","","","45,614","","","19,800","","","\u2014","","","\u2014"],["Drilling rig contracts(4)","","10,835","","","10,835","","","\u2014","","","\u2014","","","\u2014"],["Asset retirement obligations(5)","","41,959","","","270","","","5,074","","","1,518","","","35,097"],["Transportation, gathering, processing and disposal agreements with non-affiliates(6)","","597,334","","","70,014","","","143,424","","","142,185","","","241,711"],["Transportation, gathering, processing and disposal agreements with San Mateo(7)","","390,307","","","\u2014","","","100,101","","","182,740","","","107,466"],["Total contractual cash obligations","","$","2,721,605","","","$","130,856","","","$","678,398","","","$","1,528,077","","","$","384,274"]]
[[/GREPCENT_TABLE]]

__________________

(1)The amounts included in the table above represent principal maturities only. At December 31, 2021, we had $100.0 million of 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 under the SBA loan. The Credit Agreement matures in October 2026. At December 31, 2021 San Mateo had $385.0 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 1.85% and 2.11%, for the Credit Agreement and the San Mateo Credit Facility, respectively, at December 31, 2021, the interest expense for such facilities is expected to be approximately $1.9 million and $8.2 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 December 31, 2021 is expected to be approximately $61.7 million each year until maturity.

(3)At December 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. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 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 14 to the consolidated financial statements in this Annual 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

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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 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

General Outlook and Trends

Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, political instability in Russia, Ukraine, China and the Middle East, the actions of OPEC+, the worldwide spread of COVID-19, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors.

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. 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.”

During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) the increase in global oil supply resulting from the actions of OPEC+. The sudden decline in oil prices began to improve later in the second quarter of 2020 and generally continued throughout the remainder of 2020.

During the year ended December 31, 2021 and through February 22, 2022, the oil and natural gas industry experienced continued improvement in commodity prices, as compared to 2020, primarily resulting from (x) improvements in oil demand as the impact from COVID-19 has begun to abate, (y) actions taken by OPEC+ to reduce the worldwide supply of oil through coordinated production cuts and (z) changes in supply and demand dynamics, particularly with respect to natural gas markets generally and, more recently, instability in Russia and Ukraine. While oil and natural gas prices improved significantly in 2021 and early 2022, the general outlook for the oil and natural gas industry for the remainder of 2022 remains unclear, and we can provide no assurances that commodity prices will remain at current levels or increase further. In fact, commodity prices may decline from their current levels, particularly in response to the spread of new variants, if any, of COVID-19, the actions of OPEC+ and other governmental authorities to increase the global oil supply and milder weather conditions, among other factors. 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 this Annual Report. The economic disruptions associated with COVID-19 and the volatility in oil and natural gas prices have also impacted our ability to access the capital markets on reasonably similar terms as were available prior to 2020.

For the year ended December 31, 2021, oil prices averaged $68.11 per Bbl, as compared to $39.34 per Bbl in 2020, ranging from a low of $47.62 per Bbl in early January to a high of $84.65 per Bbl in late October, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $67.58 per Bbl ($56.70 per Bbl including realized losses from oil derivatives) for our oil production for the year ended December 31, 2021, as compared to $37.38 per Bbl ($39.83 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2020. At February 22, 2022, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2021, closing at $92.35 per Bbl, and was higher compared to $61.49 per Bbl on February 22, 2021. We are uncertain that oil prices will remain at these levels as noted above.

Natural gas prices also improved significantly during 2021. For the year ended December 31, 2021, natural gas prices averaged $3.71 per MMBtu, as compared to $2.13 per MMBtu in 2020, ranging from a low of $2.45 per MMBtu in late January to a high of $6.31 per MMBtu in early October. As a result of milder-than-expected winter weather, natural gas prices declined over the course of the fourth quarter of 2021, finishing the year at $3.73 per MMBtu. We realized a weighted average natural gas price of $6.06 per Mcf ($5.74 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2021, as compared to $2.14 per Mcf (with no realized gains or losses from natural gas derivatives) for the year ended December 31, 2020. As a two-stream reporter, the revenues associated with our NGL production are included in the weighted average natural gas price. At February 22, 2022, the NYMEX Henry Hub natural gas futures

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contract price for the earliest delivery date had increased from year-end 2021, closing at $4.50 per MMBtu, and was higher as compared to $2.95 per MMBtu at February 22, 2021. We are uncertain that natural gas prices will remain at these levels, particularly as we exit the winter heating season.

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During year ended December 31, 2021, we incurred realized losses on our oil and natural derivative contracts of approximately $220.1 million, primarily as a result of oil and natural prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts and above the strike price of certain of our oil swap and oil basis swap contracts. At February 22, 2022, almost all of the derivative contracts we had in place that contributed to these realized losses on derivatives in 2021 had expired. At February 22, 2022, given current oil and natural gas prices and the oil and natural gas derivative contracts we have in place, we do not anticipate losses of such magnitude from our derivative contracts in 2022, although there may be periods where we realize losses from derivatives. At December 31, 2021, adjusted for derivative contracts entered into between January 1, 2022 and February 22, 2022, we had derivative contracts in place for approximately 5.1 million Bbl of our anticipated full year 2022 oil production and approximately 54.7 Bcf of our anticipated full year 2022 natural gas production.

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 December 31, 2021, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years but began 2020 slightly positive to the WTI oil price and remained positive through much of the first quarter. With the abrupt decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020, reaching ($6.00) per Bbl before becoming positive later in the second quarter and improving throughout the rest of 2020 and 2021 and into early 2022. At February 22, 2022, this oil price differential was approximately +$1.00 per Bbl. At February 22, 2022, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated full year 2022 oil production.

Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years, including times in April 2019 when natural gas was being sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu. 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 again 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 2021. In early 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin, particularly beginning in the latter half of 2022, began to increase. As a result, the Waha basis differential began to widen, and, at February 22, 2022, this natural gas price differential was approximately ($0.60) per MMBtu.

A significant portion of our Delaware Basin natural gas production is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2021, we typically realized a premium to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 11% of our reported natural gas production for the year ended December 31, 2021 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing.

Although the natural gas price differentials have recently at times been positive or close to zero, 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 in 2022.

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At February 22, 2022, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain periods over the last few years, 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.

As a result of the recent increases in oil and natural gas prices, we have begun to experience inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, personnel and completion costs, among others. Should oil and natural gas prices remain at their current levels or increase further, we expect to be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. We budgeted a 10 to 15% increase in oilfield service costs, as compared to the fourth quarter of 2021, in preparing our full-year D/C/E and midstream capital expenditures for 2022. Should we experience service cost inflation above 10 to 15% during 2022, we may be required to increase our 2022 estimated capital expenditure budget. Further, in early 2022, supply chain disruptions being experienced throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely fashion, which could result in delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows.

In addition, should oil and natural gas prices remain at their current levels throughout 2022, we may exhaust our federal or state net operating loss carryforwards and become subject to federal and state income taxes in future periods. At February 22, 2022, given our current projections, we do not expect to pay significant federal income taxes, if any, in 2022, but may pay federal income taxes in 2023. We may pay state income taxes in 2022 and 2023, however, in New Mexico and Texas.

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, various 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 signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require 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. The NMED has proposed similar rules and regulations. 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 the Biden Administration Federal Lease Orders. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our 2022 and future 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 31% 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.”

We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to

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impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well. See “Risk Factors—Risks Related to Laws and Regulations—The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.”

Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Equity returns in the sector prior to 2021 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 significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the 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.”

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.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2021.

Oil and Natural Gas Properties

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the

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amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.

Ceiling Test

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

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

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

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

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

Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time.

Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.”

Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with

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guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues.

Derivative Financial Instruments

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. Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently as an unrealized gain or loss on derivatives in our consolidated statements of operations. Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using 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.

Stock-Based Compensation

We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan then in effect to members of our Board of Directors and certain employees, contractors and advisors. We use the fair value method to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. We use our own historical volatility to estimate the future volatility of our stock.

We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the closing price of our common stock on the date of the grant for awards issued under the 2012 Incentive Plan and on the trading day prior to the date of grant for awards issued under the 2019 Incentive Plan. See Note 9 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2021.

Income Taxes

We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.