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MACH NATURAL RESOURCES Q2 2026 Earnings Investor Presentation August 6 , 2026 NYSE : MNR machnr.com
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2 Disclaimer and Forward-Looking StatementsFORWARD-LOOKING STATEMENTSThis presentation contains statements that express the Company’s opinions, expectations, beliefs, plans, objectives, assumptions or projections regarding future events or future results, in contrast with statements that reflect historicalfacts. All statements, other than statements of historical fact included in this presentation regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives ofmanagement are forward-looking statements. When used in this presentation, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” andsimilar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Specific forward-looking statements include statements regarding the Company’s projectedresults of operating, financial position, growth opportunities and reserve estimates. These forward-looking statements are based on management’s current belief, based on currently available information as to the outcome and timing offuture events at the time such statement was made. Such statements are subject to a number of assumptions, risk and uncertainties, many of which are beyond the control of the Company. These include, but are not limited to, theCompany’s future financial condition, results of operations and ability to achieve the guidance provided, strategy and plans; the ability of the Company to realize anticipated synergies related to the closing of the Permian Basin and SanJuan Basin transactions in the timeframe expected or at all; changes in markets and the ability of the Company to finance operations in the manner expected; commodity price volatility; the impact of epidemics, outbreaks or other publichealth events, and the related effects on financial markets, worldwide economic activity and our operations; uncertainties about our estimated oil, natural gas and natural gas liquids (“NGLs”) reserves, including the impact of commodityprice declines on the economic producibility of such reserves, and in projecting future rates of production; difficult and adverse conditions in the domestic and global capital and credit markets; lack of transportation and storage capacityas a result of oversupply, government regulations or other factors; lack of availability of drilling and production equipment and services; potential financial losses or earnings reductions resulting from our commodity price riskmanagement program or any inability to manage our commodity risks; failure to realize expected value creation from property acquisitions and trades; access to capital and the timing of development expenditures; environmental,weather, drilling and other operating risks; regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas, the Oklahoma Corporation Commission and/or the KansasCorporation Commission; competition in the oil and natural gas industry; loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production; our ability to service ourindebtedness; any downgrades in our credit ratings that could negatively impact our cost of and ability to access capital; cost inflation; the potential for significant new tariffs and their impact on global oil, natural gas and NGL markets;political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the war in Ukraine and associatedeconomic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage; evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks,malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and risks related to our ability to expandour business, including through the recruitment and retention of qualified personnel. Please read the Company’s filings with the Securities and Exchange Commission (“SEC”), including “Risk Factors” in the Company’s Annual Report onForm 10-K, which is on file with the Securities and Exchange Commission (the “SEC”), for a discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements. As a result, theseforward-looking statements are not a guarantee of our performance, and you should not place undue reliance on such statements. Any forward-looking statement speaks only as of the date on which such statement is made, and theCompany undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.CAUTIONARY NOTEReferences to the Company’s estimated proved reserves are derived from the Company’s reserve reports prepared by Cawley Gillespie & Associates, Inc., the Company’s independent petroleum engineers. Reserve engineering is a processof estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and costassumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of anyfurther production and development drilling. Accordingly, our reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. You should not assume that the presentvalues referred to in this presentation represent the actual current market value of our oil, natural gas and NGL reserves. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors,which could cause our results to differ materially from those expressed in these third-party publications. This presentation contains trademarks, trade names and service marks of other companies, which are the property of theirrespective owners. We do not intend our use or display of other parties’ trademarks, trade names or service marks to imply, and such use or display should not be construed to imply, a relationship with, or endorsement or sponsorship ofus by, these other parties. Nothing herein should be construed as legal, financial, tax or other advice. You should consult your own advisers concerning any legal, financial, tax or other considerations concerning the opportunity describedherein. The general explanations included in this presentation cannot address, and are not intended to address, your specific investment objectives, financial situation or financial needs.NON-GAAP FINANCIAL INFORMATIONThis presentation includes certain financial measures that are not presented in accordance with U.S. generally accepted accounting principles (“GAAP”), including Adjusted EBITDA, Net Debt and PV-10. In the case of Pro forma non-GAAPfinancial measures or non-GAAP financial measures presented for future periods, the Company advises that it is unable to provide reconciliations of such measures without unreasonable effort. Accordingly, such measures should beconsidered in light of the fact that no GAAP measure of performance or liquidity is available as a point of comparison to such non-GAAP measures.Investor Relations Contact:405-252-8100 | ir@machnr.com This presentation is being provided by Mach Natural Resources LP (the “Company” or “Mach”) for informational purposes only. No persons have been authorized to make any representations regarding the information contained in thispresentation, and if given or made, such representations should not be considered as authorized. None of the Company, its respective affiliates or any of its or their respective employees, directors, officers, contractors, advisors,members, successors, representatives or agents makes any representation, warranty or undertaking, express or implied, and no reliance should be placed on, the fairness, accuracy, completeness or correctness of the information or theopinions contained herein. The information herein, including the forward-looking statements described below, has been prepared by the Company solely for use in this presentation, has not been independently verified and should beconsidered in the context of the circumstances prevailing at the time of its preparation. Management is under no obligation to update the information contained herein to reflect material developments which may occur after the date ofthe presentation. The Company may alter, modify or otherwise change in any manner the content of this presentation, without obligation to notify any person of such revision or changes.
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3 Mach Overview UNIT PRICE(1)(2)TICKER(EXCHANGE: NYSE) LIQUIDITY($MM)EV / 2026e ADJ. EBITDALOEPER BOECASH G&A PER BOE$13.64MNR Note: Adjusted EBITDA and Net Debt are non-GAAP financial measures. Refer to Appendix for additional detail. 1 As of close of trading July 31, 2026. 2 Based on common units outstanding of 166,948,094. $3114.6x$7.13$0.42 ENTERPRISE VALUE ($B)(1)(2)MARKET CAP ($B)(1)(2)PROVED RESERVES(MMBOE)NET ACRES(MM, APPROX.)Q2 2026 NET DAILY PRODUCTION(MBOED)NATURAL GAS AS % OF 2026e VOLUMES$3.4$2.37052.814970%As of 6/30/2026 and 99% HBP77% proved developed & 69% natural gas. $3.1B PV-10 at 12/31/2025Based on FY2026e guidance midpointBased on FY2026e guidance midpoint15% oil, 16% NGLs, and 69% natural gas~50% of gas volumes are unhedged. Systematic hedging insulates cash flow & allows for upside exposureIncludes Cash and Revolving Credit Facility Availability as of 6/30/2026Based on Consensus Adjusted EBITDA
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4 Mach At A Glance SAN JUAN BASINNet Acres: ~570,000 PERMIAN CENTRAL BASIN PLATFORMNet Acres: ~130,000 MID-CONTINENTNet Acres: ~2,100,000 GREEN RIVER BASINNet Acres: ~35,000 YE 2025 Proved Reserves Q2 2026 Production15%69%16%Natural Gas Oil NGLs705 MMBOE15%69%16%149 MBOEDCOMMITTED TODISCIPLINED REINVESTMENT~50%YTD2026 reinvestment rate aligns with target of reinvesting <50% of operating cash flow STABLE CASH –FLOWING ASSETS17%Low corporate PDP decline rate coupled with high-returning unconventional inventory drives cash flow stabilityDIVERSIFIED AND SCALEDASSET BASE55% &45%Balanced production portfolio with ~55% Mid-Con exposure and ~45% exposure to the Permian and San Juan Basins An INDEPENDENT UPSTREAM OIL AND GAS COMPANY with 2.8 MILLION NET ACRES focused on the acquisition, development and production of oil, natural gas, and NGL reserves in the ANADARKO BASINregion of Western Oklahoma, Southern Kansas and the panhandle of Texas; the SAN JUAN BASIN region of New Mexico and Colorado; and the PERMIAN BASIN region of West Texas. FOCUSED ONRETURN OF CAPITAL$244MMCash Distributed to Unitholders in FY202554%30%16%Q2 2026 % Revenue by Product$367 MM
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5 Our Four PillarsDISCIPLINED EXECUTION WITH ACCRETIVE ACQUISITIONS− Committed to executing ACQUISITIONS ACCRETIVE TO OUR DISTRIBUTIONS where the assets are purchased at a DISCOUNT TO PDP PV-10 − Continuous improvement mindset drives FOCUS ON COST REDUCTION and performance improvement DISCIPLINED REINVESTMENT RATE− Maintain REINVESTMENT RATE OF LESS THAN 50% OF OPERATING CASH FLOWto optimize distribution to unitholders− Assets provide for STABLE CASH FLOW with appropriate capexMAINTAIN FINANCIAL STRENGTH UNDERPINNED BY LOW LEVERAGE− Focused on SUSTAINING FINANCIAL STRENGTH through all commodity cycles by targeting a LOW NET DEBT TO ADJUSTED EBITDA RATIO of 1.0xMAXIMIZE CASH DISTRIBUTIONS TO EQUITY HOLDERS − Strategy designed to aim for all decisions companywide to result in accretion to our distributions− Target PEER-LEADING DISTRIBUTIONS to our equity holders Mach’s discipline in leverage, acquisitions, and reinvestment drives peer-leading cash distributions We built Mach around four strategic pillars designed to create a durable company across commoditycycles. These pillars guide our decisions companywide, including capital allocation, and ultimatelydrive industry-leading cash returns to our unitholders.“ ” Tom L. WardChief Executive Officer and Director
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6 History of Strong CROCI and Cash Distributions32%53%44%26%23%$67.92$94.23$77.62$75.72$64.81-$10$10$30$50$70$90$1100%10%20%30%40%50%60%2021 2022 2023 2024 2025Track Record of Strong CROCI(1)(2) Our low base decline allows for low capital intensity, allowing Mach to establish a strong free cash flow profileRealized Multiple on Invested Capital (“MOIC”)(3) of 2.0x through Q3 2026Commitment to Maximizing Cash ReturnsMach is committed to low leverage and a <50% reinvestment rate, supporting our ability to maximize adjusted free cash flow5-yr. Avg. 35% $90$71$86$62$59$93$45$46$89$60$0.95$0.75$0.90$0.60$0.50$0.79$0.38$0.27$0.53$0.64$0.36020406080100$0.00$0.20$0.40$0.60$0.80$1.00$1.20$1.40Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q32024 2025 2026Distributions ($MM) Distributions per Unit1 The Company defines CROCI as cash flow from operations plus interest expense, divided by the average of both the prior and current year’s total current assets less cash and cash equivalents less total current liabilities plus current portion of long-term debt plus proved oil and natural gas properties plus other property, plant and equipment plus other assets.2 CROCI for 2023 and 2025 includes Pro Forma adjustments for Paloma and Sabinal / IKAV acquisitions, respectively 3 The Company defines MOIC as the sum of distributions paid pre-IPO, distributions paid and to be paid to pre-IPO holders post-IPO, divided by total equity contributed by pre-IPO holders since inception. History of Mach’s Strong Variable Cash Distributions Across Commodity CyclesHistory of Mach’s Strong CROCI Across Commodity CyclesDistributions vary due to commodity price fluctuations, operational performance, and reinvestment timing.MNR Annual CROCI WTI MNR 5-Yr Avg. CROCI (2021 – 2025) $107paid to Mach unitholders in cash distributions since Company’s inception through Q3 2026$1.5 BILLION
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7 Industry-Leading CROCI versus Peers MGY CHRD PR PeerAverageMTDR CTRA DVN CRGY EOG FANG35%~2x THE PEER AVERAGE 1Mach Natural Resources’ data is as disclosed and pro forma for acquisitions. All calculations above use Gross O&G Properties as the main component of Capital Invested. No pro forma adjustments were made to peers. 18%Peer Averageexcl. MNR 5-Year Average CROCI (1)2021 - 2025 Proven Performance. Proven Returns. PEER-LEADINGANNUAL CROCI >20%Every year since inception, Mach has had a CROCI of >20%, demonstrating consistent capital discipline across varying price environments.INDUSTRY-LEADING5-YR AVERAGE CROCI35%Mach has averaged 35% CROCI over the last five years from 2021 through 2025, pro forma. This is among the strongest in the E&P sector. SUPERIOR 5-YEAR AVERAGE CROCI~2xSince 2021, Mach’s average CROCI is ~2x the peer average CROCI of 18%CROCI UNDERPINNED BYDISCIPLINED ACQUSITIONS 23All 23 acquisitions since 2018 have met our consistent underwriting criteria, allowing us to acquire cash-flowing assets at steep discounts to PDP PV-10 with a focus on accretion and balance sheet strength. Mach’s 5-year average CROCI is not only industry-leading, but we are also in the top 1% of all public companies in the U.S. MACH’S CROCI IN TOP 1%
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8 Industry-Leading Cash G&A per BOE GPOR NOG CHRD MUR HPK MTDR SM MGY CRGY TALOPeer Averageexcl. MNR $3.33$2.06$0.94$0.99$0.84$1.26$1.252018 2019 2020 2021 2022 2023 2024 2025 1H2026 MACH’S HISTORY OF STRUCTURAL EFFICIENCY IN CASH G&A PER BOE(1) OUR INDUSTRY-LEADING CASH G&A PER BOE VERSUS PEERS(1)$1.71$0.45TODAY , ~4x MORE EFFICIENT THAN PEERS $0.45 Best-In-Class G&A Efficiency. Mach has a history of lean growth. We have driven large reductions in G&A per BOE by leveraging fixed costs and minimizing corporate overhead. Today, we have a structural G&A advantage. Our cash G&A per BOE is more than 70% better than peers. This reflects our ability to grow while maintaining a low-cost structure. 86% REDUCTION SINCE 2018 1All figures shown above reflect total general and administrative expense excluding non-cash equity compensation expense, reflected on a per BOE basis. Mach’s cash G&A per BOE reflects 1H 2026 annualized. Peer data reflects full-year 2025 as reported.
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9 Scaled Platform Built Through Disciplined Acquisitions 0.00.51.01.52.02.53.0 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q22018 2019 2020 2021 2022 2023 2024 2025 20260255075100125150175 Net Acres (in millions) Driving ValueHard-to-Replicate PlatformDisciplined ExecutionWe have a scaled platform that delivers value. Durable cash flow, long-duration inventory, and embedded upside supportflexible capital allocationto the highest-return opportunities across cycles.Since 2018, we’ve spent >$3 billion across 23 acquisitionsaccumulating ~2.8 million acres across the Mid-Continent, Permian Basin, and San Juan Basin.Consistent underwriting criteria has guided every acquisition. This has allowed us to acquire cash-flowing assetsat discounts to PDP PV-10 with a focus on accretion and balance sheet strength. Disciplined Acquisitions Strategy. Hard-to-Replicate Platform.Since 2018, we have built a 2.8-million-acre platform producing 149 MBOED. Disciplined Acquisitions Strategy. Hard-to-Replicate Platform.Since 2018, we have built a 2.8-million-acre platform producing 149 MBOED. Net Production MBOED Net Production (MBOED) Net Acres (in millions)Acquisition
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10 TXODiversifiedVitesseSandRidgeEvolutionGranite RidgeEquinorTotalRepsolRileyVAALCOEpsilonPermian ResourcesNorthernChevronShellChordExxonDiamondbackBPCrescentExpandTourmalineEOGWhitecapMurphyAPACalifornia ResourcesConocoOvintivMagnoliaDevonSPDR S&P Oil & Gas E&P ETFSMMatadorBaytexTexas Pacific LandEQTOccidentalW&TRangeHighPeak Realized Distribution Yield, Annualized Since 2024Yield as of 8/1/2026 | Includes Cash Distributions paid through Q2 2026Generating Industry-Leading Distribution Yield 15% SPDR S&P Oil & Gas E&P ETFSource: Public filings.1Includes Mach’s most recent $0.36 cash distribution announced in conjunction with Q2 2026 earnings on August 6, 2026. PEER AVERAGE excluding Mach: 4%2%Paid and announced to Mach unitholders since 2024 through Q2 2026(1)~4x THE PEER AVERAGE $6.67 PER UNIT
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11 Our Free Cash Flow Breakeven Advantage $2.26 $2.40 $2.56 $2.84 $3.22 $3.69 $3.81 AR RRC EQT GPOR INR DEC BKV $1.72average excluding Mach: $2.97LTM Free Cash Flow Breakeven ComparisonsWhether compared to gas-weighted or liquids-weighted public E&Ps, Mach’s LTM free cash flow corporate breakevens are best-in-class among peers. $29.98 $35.10 $39.13 $48.13 $51.49 $54.97 $69.66 XOM FANG COP CRGY REPX TXO HPK $36.14average excluding Mach: $46.92 Source: Public filings. Note: Excludes impacts of hedges and income taxes. Data is based on YE 2025 financials; applies full-year 2025 average WTI and HH prices of $65.34/bbl and $3.39/mmbtu. 1$3.69 /mmbtu reflects DEC gas breakeven inclusive of ABS amortization.(1) Mach delivers best-in-class corporate breakevens. This reflects our focus on operational execution, as well as maintaining a balanced commodity mix and a low-cost structure. Even more compelling, we acquired these assets at steeply discounted prices, capturing peer-leading economics without paying for the upside. BEST-IN-CLASSamong gas-weighted peersGas-Weighted PeersLiquids-Weighted Peers BEST-IN-CLASSamong liquids-weighted peers
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NYSE: MNRmachnr.com Asset Portfolio
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13 Asset Portfolio Overview DIVERSIFIED, SCALED ASSET BASE55% &45%Balanced production portfolio with approx. 55% Mid-Continent exposure + approx. 45% Permian and San Juan Basin exposure. Scaled, Held-by-Production Portfolio with the Flexibility to Develop When and Where Returns are StrongDiversified AcrossOperating FromBuilt Through3~2.823Core Basins Million AcresAcquisitions MID-CONTINENT− Mach holds leading position in core of the play− World-class, multi-decade resource potential with commodity diversity and long-life production− This balanced asset base supports Mach’s approach to a diversified oil and gas portfolio and provides resilience across commodity cyclesNet Acres: ~2,100,000 80 MBOED2026e net productionSAN JUAN BASIN− Gaining attention as world-class natural gas asset− Mach is strategically positionedacross highest OGIP concentrationsin the play− Attractive cash flow profile with low decline− Asset is predominantly HBP with proven upside in the Mancos Shale and Fruitland Coal, providing Mach meaningful natural gas scale and long-term resource depth−Strong, early well performance from Mach’s initial wellsNet Acres: ~570,000 59 MBOED2026e net productionPERMIAN BASIN CENTRAL PLATFORM− Purchased this stable cash-flowing oil assetat ~$60 WTI− Acreage spans prolific reservoirs, with material horizontal development potentialNet Acres: ~130,00010 MBOED2026e net production
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14 Mach Differentiated with Top-Quartile Decline Rate EPMDECWTIBKVCRCPro Forma MachTXORRCREPXREPCRGYMUREQTAPACHRDWCPCIVIOXYCTRAOVVEXEMGYDVNCOPGPORFANGEOGPRNOGMTDRBTESMHPK17%PEER AVERAGE excluding Mach: 26%TOP-QUARTILE BOE CORPORATE DECLINE RATEprovides improved distributable cash flow durability Source: Public filings. Note: Peer data represents NTM PDP decline as of September 2025. Represents U.S. and Canadian assets.
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15 Prior Acquisitions + Agile Operations are Paving the Way.Our pivot toward oil-centric drilling is underway, with this year’s inventory supplied by multiple, disciplined Mid-Continent acquisitions dating back to 2020. Purchasing discounted assets is a core pillar of our strategy, allowing us to build 2.1 million acres of high-quality inventory in the Mid-Continentsince 2018. By redirecting capital to a targeted subset, we are unlocking value from locations acquired at zero incremental cost through our PDP-focused acquisition strategy. Commodity Diversity. Best-In-Class Oil and Natural Gas Reinvestment Inventory. Value From Prior Acquisitions is Being Unlocked with Mach’s 2026 Drilling Program−Four pillars guide all company decisions (including capital allocation) to maximize unitholder returns across commodity cycles−Five acquisitions dating back six years to 2020 fuel the inventory of Mach’s 2026 drilling program− Currently operating three oil rigs in Oklahoma− Targeting high-return Oswego, Red Fork and Ardmore intervals, with locations acquired at zero incremental cost to the original acquisition Mid-Continent: Unlocking Free Oil Upside MID-CONTINENT NET ACRES: ~2,100,000 MachAcreageMach Acreage from five acquisitions supplying 2026 drilling program 2026e Oil-Focus AreasOKTXKS
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16 Expecting Top-Tier Oswego IRRs in 2026Oswego Oil Program. Repeatable. Low-Risk with Top Tier Returns. At the core of our shift to oil is a scaled, well-understood Oswego program built on years of repeatable results. The combination of consistent results and strong WTI prices allows our 2026 Oswego drilling program to target outsized returns. $57 WTI $65 WTI $75 WTI $85 WTI Modest WTI Improvements Drive Meaningful IRR Expansion to 2025 Oswego Drilling ProgramMach’s 16-well 2025 Oswego Drilling Program generated an attractive IRR of 39% at $57 WTI. When applying higher WTI price assumptions to those same 16 wells in Mach’s 2025 Oswego Drilling Program, the IRRs increase significantly, from 39% up to 145%.56%87%145% Improved WTI Price Scenarios to better reflect a more positive oil environment Last Year, our 16-well 2025 Oswego drilling program, generated a normalized IRR of 39%$57 WTIz39% IRRToday, when you apply more favorable WTI prices to last year’s Oswego program, the IRRs are enhanced from 39% up to ~150%$65 - $85 WTI DELIVERING STRONG ANNUAL IRRs~50%Since 2018, we have averaged ~50% IRRs on our annual drilling program.OSWEGO = REPEATABLE + LOW RISK~250With ~250 wells drilled, the Oswego represents a high-confidence, high-return oil development opportunity.ATTRACTIVE 39% IRR in 202539%Our 2025 16-well Oswego Drilling Program delivered an attractive overall IRR of 39% at a flat price of $57.42 WTI. OSWEGO IRR SENSITIVITY TO WTI>50% - 145%Applying modest increases in WTI (ranging from $65 - $85) to our 2025 Oswego Program drives materially enhanced returns. Note: The 39% IRR uses Bloomberg Fair Value flat prices of $57.42 WTI and $4.42 HH. The WTI Price sensitivities of $65, $75, and $85 use $3.50 HH.
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17 Premier Operator Driving Efficiencies in the Oswego Oswego Capital Efficiency | D&C Capital per Lateral Feet ($ / ft.)Oswego Drilling Efficiency | Lateral Feet Drilled per Day (Ft. / day)Oswego Well Productivity | EUR per Lateral Feet(BO / ft.) $570$422$3832023 2024 2025 4635936552023 2024 2025 181821202320242025 Mach is driving continued D&C capital efficiencies in our Oswego program.33% REDUCTION Mach is delivering consistent well results, and productivity is in-line with type curve.CONSISTENT and IN-LINE ~250 Oswego Wells Drilled in Mach’s History.Ongoing Efficiency Gains.Across our scaled, well-understood Oswego position, Mach continues to deliver robust, repeatable results. Our solid operational execution and consistent results will drive top-tier IRRs in our 2026 Oswego drilling program. Strong 87% IRRs at $75 WTI. Our strong operational execution is driving significant efficiencies to our drilling times.41% IMPROVEMENT Note: From 2023 through 2025, Mach drilled 132 wells.type curve
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18 Mid-Continent: Multiple Paths to Value Capture DRY GAS WINDOWWET GAS WINDOW Long-Term Strategic Optionality.Today, the Mid-Continent is the anchor of Mach’s balanced portfolio. The commodity diversity of the basin affords the Company flexibility and optionality, allowing Mach to allocate capital to its highest return opportunities based on market prices. OIL WINDOW Commodity Diversity. Resilient Returns.Our Mid-Continent position provides commodity optionality across various oil, liquids-rich, and natural gas targets. The inherent diversity of this world-class resources allows for dynamic value capture, driving resilient unitholder returns through cycles.Mid-Continent Supports Dynamic Value Capture and Provides Mach Four Strategic Advantages−Commodity Diversity: Broad exposure to oil, condensate, NGL and natural gas opportunities helps reduce single-commodity dependence and supports resilience across market cycles−Multi-Pay Exposure: Multiple proven horizons across the Anadarko Basin create diverse development pathways, provide attractive capital allocation options and allow Mach to aim capital toward most attractive returns−Inventory Flexibility: Large-scale operated acreage position and deep inventory allows activity to be paced by returns, timing and commodity outlook−Value Maximization: Nimble operating structure (short-cycle planning and flexible rig commitments) enable rapid pivots toward highest-return opportunities to enhance value creation OKTXKS ~2,100,000 NET ACRES
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19 San Juan Basin: Strong Mancos Performance ~570,000 NET ACRES Early Results In-Line and Strategically Positioned.Results from Mach’s 2025 drilling program are in line with type curve expectations. In Mach’s 2026 drilling program, we continue to optimize drilling techniques and reduce overall drilling days. With its acreage position overlaying the core of the play, Mach is capturing the highest OGIP concentrations. UTNMCOAZ2025 Drilling Program (5 wells)2026 Drilling Program (7 wells)Increasing OGIPMach AcreagePositive Early Results: Well performance from Mach’s 2025 drilling program is right in-line with type curve of 1.7 Bcf / 1,000’.Strategic Positioning: Mach is strategically positioned in the highest OGIP areas.Momentum: Renewed operator focus with modern horizontal development helping unlock additional value in a mature basin.Long-Term Value Creation: Long-duration optionality to convert resource in place into future production, cash flow and strong returns. 1 Individual well production normalized to 3-mile lateral length. - 2,000 4,000 6,0001 2 3 4 5 6 7 8 9 10 11 12Months of Production 2025 Drilling ProgramWell Productivity | 2025 Drilling Program vs. Type Curve1Cumulative Gas Production, MMCF1 Individual well production normalized to 3-mile lateral length.Initial five wells of 2025 drilling program areCONSISTENT and POSITIVE
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20 San Juan Basin: Driving Long-Term Value 2026 2033 2040 Gas Optionality. Bullish San Juan Pricing Environment.Natural gas remains a critical energy source and will continue to play a major role in energy markets. In the San Juan Basin, our shallow decline and low maintenance capital will allow Mach to be a long-term supplier to improving Western gas fundamentals. With the flexibility to develop our top-tier inventory in a disciplined, price-responsive manner, Mach will benefit from the long-term bullish outlook for San Juan pricing. Net Gas Production (Mcf/d)2030NOTE: Base and Development wedge illustrate a potential production profile using Mach’s internal data. This chart does not serve as a forecast, as Mach has not provided guidance beyond 2026e. Once the marketing agreement rolls off, Mach has meaningful gas volumes that are fully exposed to market pricing. At that point, Mach can fully realize the mostfavorable market pathways, such as San Juan basis and new demand markets (incl. LNG, data centers, and new takeaway optionality)volumes above linereceive variable El Paso San Juan pricing volumes below linereceive fixed pricingCurrent residue marketing agreement includes fixed and variable components, and expires in 2030 Development WedgeProduction BaseResidue Marketing Agreement Near-Term Limited Pricing Optionality
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21 Permian Central Basin PlatformASSET OVERVIEWAcreage across prolific reservoirs in the Permian Basin, including heart of the Central Basin Platform and Eastern Shelf Stable cash flows from predictable production profile, with declines as low as 5% in some areas and proven field optimization strategiesOil-heavy and mature PDP base with material horizontal development potentialWell-understood, high OOIP legacy fields previously owned by major operatorsLegacy lease agreements carry a high base 8/8thNRIPermian Central Basin Platform8%Base Decline Rate(1): 10 MBOED (94%)FY2026e Production (% Oil):~90%Avg. Operated W.I.:~130,000Net Acres: Mach Permian Central Basin Platform Position ~130,000 NET ACRESTXNMNew MexicoTexasAndrewsGainesCochranHockleyTerryDawsonBordenScurryMartinHowardMitchellEctorMidlandYoakumLubbockCrosbyLynnGarzaLea In September 2025, we purchased ~10 MBOED of stable crude production at In Q2 2026,we benefited from significantly higher prices with a quarterly realized price of~$60 WTI >$90 per barrel KEY STATS1 Based on NTM PDP volumes as of 12/31/2025.
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22 2025 Drilling Program 100%150%IRR %39% IRR44% IRRMancos Deep Anadarko Oswego Red Fork 43% IRR50% OVERALL, STRONG TOTAL IRR FROM MACH’S 2025 DRILLING PROGRAM42% IRR Note: Program data set includes wells with first sales in 2025. Pricing uses Bloomberg Fair Value flat prices of $57.42 WTI and $4.42 HH.
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23 Commitment to Our Four PillarsDISCIPLINED EXECUTION WITH ACCRETIVE ACQUISITIONS− Committed to executing ACQUISITIONS ACCRETIVE TO OUR DISTRIBUTIONS where the assets are purchased at a DISCOUNT TO PDP PV-10 − Continuous improvement mindset drives FOCUS ON COST REDUCTION and performance improvement DISCIPLINED REINVESTMENTRATE− Maintain REINVESTMENT RATE OF LESS THAN 50% OF OPERATING CASH FLOWto optimize distribution to unitholders− Assets provide for STABLE CASH FLOW with appropriate capexMAINTAIN FINANCIAL STRENGTH UNDERPINNED BY LOW LEVERAGE− Focused on SUSTAINING FINANCIAL STRENGTH through all commodity cycles by targeting a LOW NET DEBT TO ADJUSTED EBITDA RATIO of 1.0xMAXIMIZE CASH DISTRIBUTIONS TO EQUITY HOLDERS − Strategy designed to aim for all decisions companywide to result in accretion to our distributions− Target PEER-LEADING DISTRIBUTIONS to our equity holders Mach’s discipline in leverage, acquisitions, and reinvestment drives peer-leading cash distributions
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24 Mach Resources. All Rights Reserved. Appendix
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25 Guidance | as of August 6, 2026FY 2026eUpdatedPreviousNet Production Guidance23 – 2522 – 24Oil (MBbls/d)20 – 2220 – 22NGLs (MBbls/d)610 – 630645 – 665Natural Gas (MMcf/d)145 – 152150 – 157Total (MBoe/d)Price Realizations Guidance (excluding derivatives)($1.50 - $0.00)($1.50) - $0.00Oil (differential to NYMEX WTI) ($/Bbl)31% - 35%31% - 35%NGLs (% of WTI)($1.25) – ($1.05)($1.25) - ($1.05)Natural Gas (differential to NYMEX HH) ($/Mcf)Other Guidance Items$6.75 - $7.50$6.50 - $7.25Lease Operating Expense ($/Boe)$3.30 - $3.80$3.15 - $3.60Gathering and Processing ($/Boe)4.0% - 6.0%4.0% - 6.0%Prod. Taxes (% of Oil, natural gas, and NGL sales)$15 - $20$15 - $20Midstream Operating Profit ($MM)$20 - $25$20 - $25G&A, excluding equity-based compensation ($MM)$85 - $90$85 - $90Interest Expense ($MM)Development Cost Guidance ($MM)$270 - $290$275 - $300Upstream (D&C and Workovers)$40 - $50$40 - $60Other (Midstream and Land)$310 - $340$315 - $360Total
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26 Debt Summary | as of June 30, 2026Debt Summary$725MM drawn on $1.0B Revolving Credit Facility (“RCF”)$450MM Term Loan Interest rate: SOFR (+) 300bps – 400bpsBank group includes 16 lenders, led by Truist and Wells FargoLoan maturity: 2/27/2029Systematic Approach to HedgingCommodity price exposure has the most impact each quarter on quarterly distributionsModest hedging program in place to help mitigate price-risk exposure ~1.5x$311MM~$1.1BNET DEBT / P.F. LTM ADJ. EBITDA(3)LIQUIDITY (2)NET DEBT(1) Note: Adjusted EBITDA and Net Debt are non-GAAP financial measures. Refer to Appendix for additional detail. 1As of June 30, 2026. 2Liquidity consists of cash and cash equivalents of $41MM and undrawn RCF of $275MM reduced by $5MM of letters of credit as of June 30, 2026. 3Represents Net Debt to Pro forma LTM Adjusted EBITDA as of June 30, 2026. Term Loan$450Drawn RCF$725Undrawn RCF$275Borrowing Base($MM) $1,450MM
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27 Q2 2026 Financial Info. and Non-GAAP Reconciliations(1,2,3) 1)Adjusted EBITDA is a non-GAAP financial performance measure. We define Adjusted EBITDA as net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) impairment of oil and gas assets, (5) equity-based compensation expense and (6) (gain) loss on sale of assets, net.2)Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial performance measure used by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as net income adjusted for (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) loss on debt extinguishment, (5) equity-based compensation expense, (6) (gain) loss on sale of assets, net, (7) cash interest expense, net, (8) development costs and (9) change in accrued realized derivative settlements. Development costs include all of our capital expenditures, other than acquisitions. 3)Net debt is a non-GAAP financial measure. We define Net Debt as the aggregate principal of all outstanding current and long-term debt, including unamortized issuance costs, less cash and cash equivalents. We use net debt as a measure of financial position and believe this measure provides useful additional information to investors to evaluate our capital structure and financial leverage. Income StatementQ2 2026Operational StatisticsQ2 2026Non-GA AP ReconciliationsQ2 2026Net Total Production Net Daily Production Net Income (Loss) to Adjusted EBITDAOil (MBbl) 2,065 Oil (Bbl/d) 22,692 Net Income (Loss) $98,213NGLs (MBbl) 2,123 NGLs (Bbl/d) 23,330 Interest expense, net 24,250Natural Gas (MMcf) 56,168 Natural Gas (Mcf/d) 617,231 DD&A 98,229 Total (MBoe) 13,549 Total (Boe/d) 148,890 Unrealized (Gain) Loss on Derivative Instruments (41,691)Equity-Based Compensation Expense 3,413Revenues Realized Pricing(Gain) Loss on Sale of Assets (183)Oil $196,996 Weighted Avg. NYMEX - WTI ($/bbl) $92.90 Adjusted EBITDA $182,231NGLs 61,551 Oil Differential ($/bbl) $2.50Natural Gas 108,305 Realized Oil ($/bbl) $95.40 Total Oil & Gas Revenues $366,852Net Income (Loss) to Cash Available for DistributionGain (Loss) on Derivative Contracts 23,485 Weighted Avg. NYMEX - HH ($/mcf) $2.90 Net Income (Loss) $98,213Midstream Revenue 9,384 Natural Gas Differential ($/mcf) ($0.97) Interest expense, net 24,250Product Sales 6,234 Realized Natural Gas ($/mcf) $1.93 DD&A 98,229 Total Revenues $405,955 Unrealized (Gain) Loss on Derivative Instruments (41,691)Realized NGLs ($/bbl) $28.99 Equity-Based Compensation Expense 3,413Expenses% of WTI 31% (Gain) Loss on Sale of Assets (183)Gathering & Processing Expense $47,968 Cash Interest Expense, net (22,554)Lease Operating Expense 97,724Operating Cash CostsDevelopment Costs (96,637)Production Taxes 18,538 Gathering & Processing Expense ($/Boe) $3.54 Change in Accrued Realized Derivative Settlements (2,943)Midstream Operating Expense 4,954 Lease Operating Expense ($/Boe) $7.21 Cash Available for Distribution ("CAD") $60,097Cost of Product Sales 5,402 Production Taxes (% of O&G Rev.) 5.1%DD&A - Oil & Gas 93,887 Cash G&A Expense ($/Boe) $0.54Total Debt to Net DebtDD&A - Other 4,342 Total Debt $1,175,000General & Administrative 10,671Development CostsLess: Cash and Cash Equivalents(41,187) Total Expenses $283,486 Gross Wells Spud 9 Net Debt $1,133,813Net Wells Spud 5.0Other Income (Expense)Gross Wells TIL 6Production MixInterest Expense ($24,515) Net Wells TIL 4.2 Oil 15%Other Income (Expense) 259 NGLs 16%Total Other Income (Expense)(24,256) Upstream (D&C and Workovers) $79,893 Natural Gas 69%Net Income (Loss) $98,213 Other (Midstream and Land) 16,744Total Development Costs $96,637Revenue MixOil 54%Note: Some totals and changes throughout the section may not sum or recalculate due to roundingNGLs 16%Natural Gas 30%
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28 1H 2026 Financial Info. and Non-GAAP Reconciliations(1,2,3) 1)Adjusted EBITDA is a non-GAAP financial performance measure. We define Adjusted EBITDA as net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) impairment of oil and gas assets, (5) equity-based compensation expense and (6) (gain) loss on sale of assets, net.2)Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial performance measure used by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as net income adjusted for (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) loss on debt extinguishment, (5) equity-based compensation expense, (6) (gain) loss on sale of assets, net, (7) cash interest expense, net, (8) development costs and (9) change in accrued realized derivative settlements. Development costs include all of our capital expenditures, other than acquisitions. 3)Net debt is a non-GAAP financial measure. We define Net Debt as the aggregate principal of all outstanding current and long-term debt, including unamortized issuance costs, less cash and cash equivalents. We use net debt as a measure of financial position and believe this measure provides useful additional information to investors to evaluate our capital structure and financial leverage. Income Statement1H 2026Operational Statistics1H 2026Non-GAA P Reconciliations1H 2026Net Total Production Net Daily Production Net Income (Loss) to Adjusted EBITDAOil (MBbl) 4,286 Oil (Bbl/d) 23,680 Net Income (Loss) $63,175NGLs (MBbl) 4,067 NGLs (Bbl/d) 22,470 Interest expense, net 48,413Natural Gas (MMcf) 116,247 Natural Gas (Mcf/d) 642,249 DD&A 196,402 Total (MBoe) 27,728 Total (Boe/d) 153,193 Unrealized (Gain) Loss on Derivative Instruments 62,078Equity-Based Compensation Expense 6,962Revenues Realized Pricing(Gain) Loss on Sale of Assets (175)Oil $351,880 Weighted Avg. NYMEX - WTI ($/bbl) $82.25 Adjusted EBITDA $376,855NGLs 107,720 Oil Differential ($/bbl) ($0.15)Natural Gas 272,798 Realized Oil ($/bbl) $82.10 Total Oil & Gas Revenues $732,398Net Income (Loss) to Cash Available for DistributionGain (Loss) on Derivative Contracts (73,414) Weighted Avg. NYMEX - HH ($/mcf) $3.97 Net Income (Loss) $63,175Midstream Revenue 18,993 Natural Gas Differential ($/mcf) ($1.62) Interest expense, net 48,413Product Sales 13,903 Realized Natural Gas ($/mcf) $2.35 DD&A 196,402 Total Revenues $691,880 Unrealized (Gain) Loss on Derivative Instruments 62,078Realized NGLs ($/bbl) $26.48 Equity-Based Compensation Expense 6,962Expenses% of WTI 32% (Gain) Loss on Sale of Assets (175)Gathering & Processing Expense $107,239 Cash Interest Expense, net (45,039)Lease Operating Expense 198,656Operating Cash CostsDevelopment Costs (171,793)Production Taxes 35,105 Gathering & Processing Expense ($/Boe) $3.87 Change in Accrued Realized Derivative Settlements 7,424Midstream Operating Expense 10,110 Lease Operating Expense ($/Boe) $7.16 Cash Available for Distribution ("CAD") $167,447Cost of Product Sales 12,186 Production Taxes (% of O&G Rev.) 4.8%DD&A - Oil & Gas 187,891 Cash G&A Expense ($/Boe) $0.45Total Debt to Net DebtDD&A - Other 8,511 Total Debt $1,175,000General & Administrative 19,422Development CostsLess: Cash and Cash Equivalents(41,187) Total Expenses $579,120 Gross Wells Spud 14 Net Debt $1,133,813Net Wells Spud 8.7Other Income (Expense)Gross Wells TIL 10Production MixInterest Expense ($48,932) Net Wells TIL 7.7 Oil 15%Other Income (Expense) (653) NGLs 15%Total Other Income (Expense)(49,585) Upstream (D&C and Workovers) $146,666 Natural Gas 70%Net Income (Loss) $63,175 Other (Midstream and Land) 25,127Total Development Costs $171,793Revenue MixOil 48%Note: Some totals and changes throughout the section may not sum or recalculate due to roundingNGLs 15%Natural Gas 37%
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29 Hedge Summary | as of August 1, 2026 Note: Basis swaps represent Argus WTI Midland underlying contracts. 2026 2026 2027 2028 2029Q3 Q4 FY FY FYNatural GasSwaps (HH) Hedged Volume (Bbtu) 10,666 8,025 15,278 3,480 4,544 Weighted Average Swap Price $3.39 $3.68 $3.50 $3.69 $3.43Crude OilSwaps (CS) Hedged Volume (MBbl) 797 752 2,415 773 - Weighted Average Swap Price $65.41 $63.54 $63.94 $65.58 -Basis Swaps Hedged Volume (MBbl) 138 138 - - - Weighted Average Swap Price $1.25 $1.25 - - -Collars (CS) Hedged Volume (MBbl) 184 184 181 - - Weighted Average Floor Price $60.00 $60.00 $62.50 - - Weighted Average Ceiling Price $78.52 $78.52 $71.25 - -
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30 Our Midstream Infrastructure TexasOklahoma San JuanArchuletaRio ArribaLa PlataNew MexicoColoradoMid-Continent Midstream InfrastructureSan Juan Basin Midstream InfrastructureGas plantMach acreageGas pipelineSan JuanMid-ContinentMach owns and operates multiple gas gathering and gas processing assets along with an extensive network of water infrastructure in the Mid-Continent and the San Juan BasinThese systems enable significant cost savings, operational control, flow assurance, additional 3rdparty revenue and flexibility to have scalable, accretive developmentVERTICALLY INTEGRATED ASSETSMach’s Florida River Plant: MNR Operated, 100% Ownership; ~400 MMcf / dSan Juan Plant: Hilcorp Operated, 50% Ownership; ~550 MMcf / d~350 MMcf / d of cryogenic processing capacity across four owned processing facilities including ~260 MMcf / d at our state-of-the-art Lincoln plant processing complex GAS PROCESSING~1,425 miles of gas gathering pipeline across all systems~965 miles of owned water gathering pipeline~1,500 miles of gas gathering pipeline across all systems~900 miles of owned water gathering pipeline across our two systems with excess capacity availableGAS GATHERING AND WATER INFRASTRUCTURE
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31 Takeaway | Gas Markets Major Downstream Pipelines in Mid-ContinentMajor Downstream Pipelines in San Juan Basin Ample Existing Capacity with Multiple OptionsCurrent San Juan gas production: ~1.6 Bcf /d is below historical peak production of ~3.4 Bcf /d, so the region has capacity beyond current production, enabling near-term production stability without takeaway bottlenecks(2)Market AccessSan Juan Basin is well-positioned geographically to Southwest, Pacific Northwest, and intrastate Colorado markets given existing pipelines MidshipEOITSouthern StarOGTPanhandle EasternNGPLMEPEGT NGPL El PasoNorthwestTransColorado Transwestern U.S. LNG Capacity Growth (Bcf / d) (1)Ample Existing Capacity with Multiple OptionsCurrent Anadarko gas production: ~8 Bcf / d gross is below historical highs of > 10 Bcf /d, with ~12 Bcf/d of takeaway capacity, so the region is long on capacity and includes ample storage(1)Market Access Mid-Continent sits at a crossroads; flows can move into the Midwest or south into Gulf Coast, LNG, or Southwest markets1 Source: NextEra Energy 2 BP 010203040Jan 2016 Jan 2017 Jan 2018 Jan 2019 Jan 2020 Jan 2021 Jan 2022 Jan 2023 Jan 2024 Jan 2025 Jan 2026 Jan 2027 Jan 2028 Jan 2029 Jan 2030 Jan 2031 Jan 2032Existing CapacityUnder Construction Capacity Under Development Mid-Continent San Juan Basin
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