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PERMIAN RESOURCES August 5 , 2026 Q2'26 Earnings Presentation
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Important Information 1 Forward-Looking Statements The information in this presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 of management are forward-looking statements. When used in this presentation, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, political and economic conditions and events in or affecting other producing regions or countries, including international conflict, environmental risks, drilling and other operating risks, regulatory changes, including changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in our filings with the U.S. Securities and Exchange Commission. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation . Use of Non-GAAP Financial Measures This presentation includes non-GAAP financial measures, such as Adjusted EBITDAX, adjusted net income, adjusted net income - diluted and adjusted net income per adjusted diluted share, adjusted operating cash flow, adjusted free cash flow, net debt, net debt-to- LQA EBITDAX (or “leverage”), net debt-to-EBITDAX and adjusted basic and diluted weighted average shares outstanding (or “Adjusted Basic and Diluted Shares”). Please refer to the Appendix for a reconciliation of Adjusted EBITDAX to net income, the most comparable GAAP measure. We believe Adjusted EBITDAX is useful as it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to financing methods or capital structure. We exclude the items listed on the Appendix from net income (loss) in arriving at Adjusted EBITDAX 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 the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. Please refer to the Appendix for a reconciliation of adjusted operating cash flow and adjusted free cash flow to net cash provided by operating activities, the most comparable GAAP measure. We believe adjusted operating cash flow and adjusted free cash flow are useful indicators of the Company’s ability to internally fund its future exploration and development activities, to service its existing level of indebtedness or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities, other non-recurring costs or estimated tax distributions to noncontrolling interest owners after funding its capital expenditures paid for the period. The Company believes that these measures, as so adjusted, present meaningful indicators of the Company’s actual sources and uses of capital associated with its operations conducted during the applicable period. Our computation of adjusted operating cash flow and adjusted free cash flow may not be comparable to other similarly titled measures of other companies. Adjusted operating cash flow and adjusted free cash flow should not be considered as alternatives to, or more meaningful than, net cash provided by operating activities as determined in accordance with GAAP or as indicators of our operating performance or liquidity. Please refer to the Appendix for a reconciliation of adjusted net income (including Adjusted Net Income – Diluted and Adjusted Net Income per Adjusted Diluted Share) to net income attributable to Class A Common Stock, the most comparable GAAP measure. We believe adjusted net income is useful as it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers by excluding certain non-cash items that can vary significantly. Adjusted net income should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our presentation of adjusted net income should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of adjusted net income may not be comparable to other similarly titled measures of other companies. The Company defines net debt as the aggregate principal amount of the Company’s total debt, minus cash and cash equivalents. The Company presents this metric, as well as leverage, to help evaluate its capital structure and financial leverage and believes that it is widely used by professional research analysts, including credit analysts, and others in the evaluation of total leverage as well as in the valuation and comparison of companies in the oil and gas exploration and production industry. The Company presents this metric to show trends that investors may find useful in understanding the Company's ability to service its debt. Please refer to the Appendix for a reconciliation of adjusted basic and diluted weighted average shares outstanding to basic and diluted weighted average shares outstanding, the most comparable GAAP measures. Adjusted Basic and Diluted Shares provide a comparable per share measurement when presenting results such as adjusted free cash flow and adjusted net income that include the interests of both net income attributable to Class A Common Stock and the net income attributable to our noncontrolling interest. Use of Forecasted Non-GAAP Financial Measures The Company does not provide guidance on the items used to reconcile forecasted 2026E Net Debt / 2026E EBITDAX due to the uncertainty regarding timing and estimates of certain items. Therefore, we cannot reconcile forecasted 2026E Net Debt and 2026E EBITDAX without unreasonable effort. Due to the forward-looking nature of these non-GAAP financial measures, management cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures without unreasonable effort, due to the inherent difficulty in quantifying certain amounts due to a variety of factors, including the unpredictability of commodity price movements and future charges or reversals outside the normal course of business which may be significant . Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures.
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Permian Resources – Company Overview 2 Largest pure-play Delaware Basin E&P company with ~535,000 net acres, ~125,000 net royalty acres and ~415 MBoe/d of FY’26E total production Acreage located in the core of the best U.S. oil shale basin, with stacked pay and low-cost supply Relentless focus on maintaining PR’s low-cost leadership position in the Delaware Basin Maintain optimized, lean organizational structure headquartered in Midland, Texas Disciplined acquisition strategy centered around making the business better and creating value for shareholders Successfully executed ~1,400 transactions since beginning of 2024 High-quality asset base and operating expertise drive capital efficient development 15+ years of inventory depth supports long-term FCF and sustainable shareholder returns Differentiated FCF per share growth has delivered peer-leading TSR since inception Committed to sustainable FCF per share growth through combination of lower costs and accretive growth Low Leverage ~0.5x Net Debt to LQA EBITDAX at YE’261 Differentiated Growth >30% Two-Year CAGR (’23-’25) Strong Shareholder Returns Employee Ownership Shareholder Alignment ~7% Debt-Adjusted FCF per Share Growth $0.64 Sustainable and Growing Base Dividend Per Share (Annualized) Premier Delaware Basin Pure-Play Peer-Leading Cost Structure Proven Acquisition Strategy Top Tier Inventory Quality & Depth Leading FCF per Share Growth & Value Creation (1) Assumes strip pricing for remainder of year and no incremental acquisitions or shareholder returns above current base dividend PR Acreage Delaware Basin New Mexico Texas Eddy Lea Culberson Loving Winkler Ward Reeves
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3 (1) Non-GAAP financial measures; reconciliations are included in the Appendix (2) Assets acquired in H1’26 included no existing production; Ward County bolt-on producing ~5 MBoe/d (~50% oil) at close on July 31, 2026 Production Oil (MBbls/d) 198.1 NGLs (MBbls/d) 86.2 Natural Gas (MMcf/d) 552.9 Total (MBoe/d) 376.4 % Oil / % Liquids (% Total) 53% / 76% Earnings & Cash Flow Adjusted EBITDAX1 ($MM) $1,344 Adjusted Operating Cash Flow1 ($MM) $1,272 Cash Capital Expenditures ($MM) $521 Adjusted Free Cash Flow1 ($MM) $751 Unit Costs Lease Operating Expense ($/Boe) $5.55 GP&T ($/Boe) $1.07 Cash G&A ($/Boe) $0.87 Balance Sheet (As of 6/30/26) Cash and Cash Equivalents ($MM) $132 Total Debt ($MM) $3,025 Net Debt1 ($MM) $2,893 Net Debt-to-LQA EBITDAX1 (x) 0.5x Permian Resources Financial and Operational Highlights Q2’26 Highlights • Reported total average production of 376.4 MBoe/d, including 198.1 MBbls/d of oil, 86.2 MBbls/d of NGLs and 552.9 MMcf/d of natural gas − Higher working interest and increased workovers drove oil production 3% higher QoQ − Curtailed high-GOR wells to maximize free cash flow • Announced cash capital expenditures of $521 MM, cash provided by operating activities of $1,506 MM and adjusted free cash flow1 of $751 MM − Generated record quarterly FCF per share • Delivered D&C per lateral foot costs consistent with full-year plan, as continued operational efficiencies largely offset impact of higher diesel costs YTD’26 Acquisition Highlights • Demonstrated continued bolt-on and ground game success through ~190 transactions year-to-date • Combined, PR acquiring ~54,000 net acres, ~20,000 NRAs and ~5,000 Boe/d in the core of the Delaware Basin for ~$1.05 B2 • Creative approach to dealmaking resulted in compelling value: − ~$13,000 per net acre, ~$8,000 per NRA and ~$2.5 MM per net 10,000’ location H2’26 Outlook • Oil production expected to be >200 MBbls/d • Capital expenditures expected to be <$1 B Key Metrics Q2’26
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Higher Working Interest and Increased Workovers Drive Higher Oil Production 4 192.3 198.1 $466 $521 Q1'26 Q2'26 Oil Production (MBbls/d) Generated 3% oil growth QoQ, exceeding high-end of prior FY guidance Capex ($MM) Incremental Capital Spent in Q2’26 Drives Immediate Production Impact that Generates Rapid Payback and Return ~75% ~82% Q2'26 Planned Q2'26 Actual Q1'26 Q2'26 Workovers (# of Projects) Working Interest (% Avg. of Completed Wells) Higher working interest in Q2’26 developments driven by successful ground game Increased workover program improved runtimes and added incremental barrels
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Q2’26 Natural Gas Production (MMcf/d) Optimizing FCF By Limiting Dry Gas Volumes During Low Price Environments 5 Unhedged Natural Gas Revenue ($ MM) ~$40 2026E 2027E ~750 ~550 Plan Actual Generated incremental FCF by proactively curtailing high-GOR wells Firm transportation portfolio and higher future prices expected to drive meaningful natural gas revenue in 2027+ >$75 MM in Q2 Natural Gas Revenue Uplift Q2’26 Going Forward • Benchmark Waha prices averaged $(3.14) per Mcf in Q2’26 • PR proactively curtailed production on high-GOR wells to maximize FCF rather than selling natural gas at negative prices • Reduced natural gas production by ~20% QoQ, particularly at locations receiving Waha pricing ‒ Curtailed volumes allowed PR to sell higher percentage of overall volumes at advantaged hubs • Resulted in achieving Q2’26 unhedged realized price of $(1.74) per Mcf, a $1.40 per Mcf premium to Waha • >700 MMcf/d of firm transport to Gulf Coast / DFW markets in 2027 ‒ Expect significant increase to PR’s natural gas revenue in 2027 based on higher strip pricing and improved realizations at Gulf Coast / DFW • PR is well positioned to benefit from long-term US gas demand growth ‒ 1+ Bcf/d gross production and long-dated inventory ‒ Attractive long-haul transportation portfolio provides additional optionality for ultimate end markets Firm Transportation – Gulf + DFW (MMcf/d) ~400 >700 2026E 2027E+
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6 Adj. Free Cash Flow ($ MM)2 (1) Assets acquired in H1’26 included no existing production (2) Non-GAAP financial measure; reconciliations are included in the Appendix Permian Resources delivered record free cash flow in Q2’26 $513 $751 $0.60 $0.88 Q1'26 Q2'26 Per Diluted Share• Responded quickly to accelerate oil production • Increased high-return workovers, driving improved runtime • Accelerated POP dates to deliver incremental barrels • Higher working interest from successful H1’26 ground game 1 • Continue to maintain peer leading D&C unit costs through longer lateral lengths, wellbore design improvements and efficiency gains • Continued optimization of power supply and compression fleet, improving runtime • Increased prefabrication of facilities and remote field oversight • Curtailed high-GOR wells to maximize cash flow in negative Waha environment • As a result, PR produced ~200 MMcf/d less in Q2’26 • Combination of curtailments, firm transport and hedging resulted in realized gas price of $0.38 per Mcf Successfully Managed Waha Volatility Maintained Cost Control Maximized Oil Production and Revenue 1 2 3 Proactive Response and Leading Cost Structure Maximize Free Cash Flow
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7 (1) All acquisition statistics pro forma for Texas acreage trade (2) 1/8th Normalized (3) Assets acquired in H1’26 included no existing production; Ward County bolt-on producing ~5 MBoe/d (~50% oil) at close on July 31, 2026 Combined Acquisition Details (YTD’26)1 Net Leasehold Acres ~54,000 Net Underwritten Locations (10,000’) ~330 Net Royalty Acres2 ~20,000 Avg. Lateral Length ~12,500’ Leasehold Acre Value ~$13,000 / Acre 8/8ths NRI ~80% Net Royalty Acre Value2 ~$8,000 / NRA $ / Net 10,000’ Location ~$2.5 MM Net Total Production3 ~5 MBoe/d (50% Oil) Add’l Potential Upside Locations >200 YTD’26 Acquisitions Overview • Acquired ~54,000 net acres in the core of the Delaware Basin for total consideration of ~$1.05 B through ~190 transactions − Acquired acreage offset to existing operating areas primarily in Ward and Eddy Counties − Bolt-on acquisitions focused on high-NRI, long lateral inventory − Grassroots acquisitions increase working interest in near-term developments • Adds ~330 high-confidence net 10,000’ locations that immediately compete for capital − Provides exposure to additional future inventory additions with >200 upside locations • Acquisitions included ~20,000 net royalty acres, increasing PR’s royalty portfolio to ~125,000 net royalty acres • Consistent execution of PR’s disciplined acquisition strategy − Relationships, proprietary data and creative deal structures generate unique opportunities − Peer leading cost structure drives higher returns − Focus on making the business better and driving long-term FCF per share accretion • Financed with cash on hand and revolving credit facility Acquired Acreage Locator Map 2026 Acquisitions Demonstrate Continued Momentum For PR’s Ground Game and A&D Efforts May Fed Sale ~6,400 Net Acres Ward County ~23,300 Net Acres Ground Game ~9,300 Net Acres Parkway Bolt-Ons ~15,200 Net Acres PR Parkway Bolt-Ons May Fed Sale Ground Game / WI Additions Ward County Bolt-On New Mexico Eddy Delaware Basin Lea Texas Ward Culberson Reeves Winkler Loving
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Bolt-On Overview • On July 31st, PR closed the acquisition of largely non-operated acreage located in the Texas Delaware Basin for total consideration of ~$520 MM • ~20,500 net acres and ~950 NRAs concentrated in the core of the Texas Delaware Basin – 35% operated; 100% held by production – ~5 MBoe/d (~50% oil) of low decline production • Bolt-on directly offset to PR’s existing asset base – Proximity to PR acreage enables seamless integration, resulting in meaningful operational synergies – Extends lateral lengths and increases working interest in existing PR units • Includes high-quality inventory in proven zones, primarily in Bone Spring and Wolfcamp intervals • Acquisition financed with cash on hand and revolving credit facility Ward County Bolt-On Acreage Map Key Statistics Total Net Leasehold Acres ~20,500 Leasehold Acre Value ~$15,000 / Acre Total Net Royalty Acres ~950 Net Royalty Acre Value ~$9,000 / NRA Net Total Production (MBoe/d)1 ~5 Net Oil Production (MBbls/d)1 ~2.5 8 Offset to existing core position Scattered position Extended laterals Non-operated High-return inventory Low working interest Advantages Challenges Bolt-On Summary Ward County Bolt-On – Growing Core Texas Position (1) Ward County bolt-on producing ~5 MBoe/d (~50% oil) at close on July 31, 2026 PR Operated Non-Op Additional WI in PR Operated Units Loving Winkler WardReeves Texas
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9 Trade Overview • On August 3rd, PR entered into an agreement for an acreage trade with an offset operator utilizing a combination of recently acquired bolt-on acreage and legacy PR acreage – Traded out of ~8,300 primarily low working interest, non-operated net acres – Traded into ~11,100 contiguous, operated net acres – No change in production • Expected closing during Q3’26 Strategic Rationale • Existing acreage was high-return with potential for long lateral development but was low working interest and generally non-operated • Leveraged PR’s relationships and ability to structure complex transactions for a “win-win” trade • Pro forma position is high working interest with long lateral development of highly attractive Bone Spring and Wolfcamp targets • Significant value uplift converting non-op locations to operated locations ~35% ~95% Before After % Operated Acreage Net Operated 10k’ Locations Trade Highlights ~50 ~120 Before After Acreage Trade Highlights Offset to existing core position Ready to develop Extended laterals Blocky operated position High-return inventory High working interest Pro Forma Acreage Map ~10,600 ~12,600 Before After Average Lateral Length (Ft.) Recently Signed Significant Acreage Trade, Further Optimizing Texas Position Trade In Trade Out PR Ward Reeves TX Winkler Loving NM
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10 Option Executed Proprietary Test Well January Fed Sale Test Well Test Well Oct. 2025 Eddy Eddy Eddy Eddy January BLM Sale Jan. 20261 2 Tascosa Option Aug. 2026 Current Position Today3 4 Identified the Opportunity Offset to existing core position Potential for further growth ~15,000’ average lateral length Stacked pay Contiguous position ~82% 8/8ths NRI Parkway Bolt- Ons Highlights Tascosa Energy Partners, a local operator with a longstanding PR relationship, proposed partnering on a test well offset PR’s existing Parkway asset in Eddy County Structured “Win-Win” Agreed for PR to operate and fund test well in exchange for option to acquire majority of acreage in Tascosa’s position Two months from the initial discussion, PR placed online a test well, which resulted in one of the best 3rd Bone Spring wells in the area With its proprietary data, PR acquired ~9,600 offsetting net acres in the January BLM sale at attractive prices with high NRIs PR executed option to acquire 5,600 net acres from Tascosa Energy Partners Parkway Bolt-Ons – Utilizing Proprietary Data and Midland Relationships to Add High-Quality Inventory
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11 Differentiated Acquisition Strategy Creates Long-Term Shareholder Value • Continue to execute PR’s differentiated acquisition strategy, leveraging Midland-based Business Development and Land teams ‒ ~85% of YTD’26 transactions represent proprietary / off-market deals ‒ Decade plus track record positions PR as the preferred counterparty in the Delaware Basin • Leverage proprietary technical data and peer leading cost structure to drive returns • Consistent and conservative underwriting during periods of high oil prices and increased volatility ‒ YTD’26 transactions signed at a weighted average front month WTI price of ~$72.50 per Bbl • Financial discipline and free cash flow generation allow PR to execute strategy while retaining fortress balance sheet ‒ Q2’26 leverage of ~0.5x and expected YE’26 leverage of ~0.5x Permian Resources’ “Secret Sauce” PR’s Prudent & Disciplined Acquisition Strategy Enhances Long-Term Equity Value Creation Target off-market opportunities where PR’s proprietary information provides real advantage Apply peer-leading cost structure to generate outsized returns Deploy creative deal structures, such as trades, exchanges, farm-ins, options, etc. Leverage longstanding relationships with local counterparties
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Balance Sheet Supports “All of the Above” Capital Allocation Strategy 12 BBB- Fitch BBB- S&P Baa3 Moody’s ~0.5x Net Debt to LQA EBITDAX1 at YE’26 >$3.0 billion of total liquidity 0.5-1.0x leverage target Investment Grade Credit Ratings (1) Non-GAAP financial measure; reconciliations are included in the Appendix. Assumes strip pricing for remainder of year and no incremental acquisitions or shareholder returns above current base dividend (2) Peers and PR assume $70 / Bbl WTI for remainder of the year; source (for peers): Pickering Energy Partners equity research; peer group includes Permian oil peers with >$6B market cap (APA, COP, DVN, EOG, FANG, MTDR, OVV and OXY); PR based on internal estimates, assumes no incremental acquisitions or shareholder returns above current base dividend ~3.1% Current Dividend Yield • Dividend supported at ~$40 / Bbl WTI • Track-record of consistent dividend growth • Advantaged yield versus peer average of ~2.6% Peer-Leading Base Dividend ~$1.05 B of Acquisitions YTD’26 • Added ~54,000 net acres through ~190 transactions YTD • Acquired at attractive valuations that support long-term free cash flow accretion Accretive Acquisitions ~$875 MM of Senior Notes Redemption YTD’26 • Redeemed ESTE 8.00% Sr. Notes due 2027 ($550 MM) and 9.875% Sr. Notes due 2031 ($325 MM) • Current weighted average debt maturity of >5 years Debt Repayment ~$925 MM Buyback Authorization • Opportunistic strategy allows for PR to invest during downturns • Able to respond to market dislocations in scale Share Buybacks Investment Grade Balance Sheet $ 0.2x 0.4x 0.5x 0.5x 0.5x 0.6x 0.6x 0.7x 1.8x Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 YE 2026E Net Debt / 2026E EBITDAX – $70 / Bbl Oil2
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182 ~199 FY'25 FY'26 (Updated Guidance) Improved 2026 Plan Oil Production (MBbls/d) Cash Capex ($ MM) $1,966 ~$1,950 FY'25 FY'26 (Updated Guidance) (1) Closed July 31, 2026 ~10% Higher oil production ~1% Lower capital expenditures FY’26 Commentary • Oil production guidance increased to ~199 MBbls/d ‒ Production driven by higher working interest and increased workover activity ‒ Ward County bolt-on produced ~2.5 MBbls/d at closing1 • Cash capital expenditures guidance updated to ~$1.95 B ‒ ~$25 MM of capex associated with Ward County bolt-on ‒ Remainder of incremental capex primarily associated with successful ground game acquisitions which increased working interest in 2026 TILs • No changes to total controllable cash costs or current income tax guidance H2’26 Commentary • Oil production >200 MBbls/d • Cash capex <$1 B 13
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14 Source: Market data as of August 4, 2026; utilizes latest available company filings; peer group includes Permian oil peers with >$6 B market cap (APA, COP, DVN, EOG, FANG, MTDR, OVV and OXY) PR Is Well Positioned For Continued Outsized Value Creation Permian Pure-Plays ✓ Robust free cash flow per share generation ✓ Premier asset quality and inventory depth in the best U.S. shale basin ✓ Proven track-record of operational execution and thoughtful M&A ✓ Lowest cost structure in the Delaware Basin ✓ Fortress balance sheet and maximum liquidity ✓ Leading base dividend yield, sustainable through downcycles ✓ Highly aligned management team with significant ownership Free Cash Flow per Share Growth (2023 – 2025) PR is well-positioned to continue delivering leading FCF per share growth through its high-quality asset base, low-cost structure and disciplined acquisition strategy Total Shareholder Return (1/1/23 to Today) Focus on Per Share Value Creation Drives Leading TSR 139% 101% 57% 28% 24% 10% (8)% (9)% (15)% (19)% 72% 55% 25% 20% 11% (2)% (9)% (10)% (25)% (30)%
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Appendix
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Permian Resources Q2’26 Operational and Financial Overview 16 Market Statistics (Data in MM, except per share data) Diluted Shares Outstanding1 850.0 Share Price (8/4/26) $20.50 Market Capitalization $17,425 Total Debt $3,025 Cash & Cash Equivalents $132 Enterprise Value $20,318 Key Statistics ($’s in MM, except per share data) Q2’26 Total Oil and Gas Revenue $1,858.0 Adjusted EBITDAX3 $1,343.5 Less: Interest Expense (Cash) $56.9 Less: Exploration and Other (Cash) $8.6 Less: Current Taxes $5.8 Adjusted Operating Cash Flow3 $1,272.2 Less: Cash Capital Expenditures $521.4 Adjusted Free Cash Flow3 $750.8 Adjusted Net Income3 $590.9 Per Diluted Share3 $0.69 Net Income $792.5 Per Diluted Share $0.93 Diluted Weighted Average Shares 855.2 Costs ($ / Boe) Q2’26 Lease Operating Expense $5.55 Gathering, Processing & Transportation $1.07 Severance & Ad Valorem Taxes $4.20 Cash G&A $0.87 Depreciation, Depletion & Amortization $14.60 Realizations Q2’26 Oil (per Bbl) $97.81 NGL (per Bbl) $23.28 Natural Gas (per Mcf)2 $(1.74) (1) Represents Class A common Stock outstanding as of July 31, 2026 and unvested restricted stock and performance stock units as of June 30, 2026 (2) Includes effect of purchased gas sales (3) Non-GAAP financial measures; reconciliations are included in the Appendix
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Revised FY’26 Guidance Production Net Average Daily Production (Boe/d) 400,000 - 430,000 Net Average Daily Oil Production (Bbls/d) 197,000 - 201,000 Production Costs ($ / Boe) Total Controllable Cash Costs $7.15 - $8.15 Lease Operating Expense ~$5.45 Gathering, Processing & Transportation ~$1.40 Cash General and Administrative1 ~$0.80 Severance and Ad Valorem Taxes (% of revenue) 6.5% - 8.5% Cash Capital Expenditure Program ($ B) Total Cash Capital Expenditures $1.9 - $2.0 Drilling & Completions ~$1.525 Facilities, Infrastructure, Capital Workover & NonOp ~$0.425 Operated Drilling Program TILs (Gross) ~250 Average Working Interest >80% Average Lateral Length (Feet) ~11,000’ Commentary • Expect average working interest of >80% due to YTD ground game success • No change • Reflects higher working interest and Ward County bolt-on • Total production unchanged due to Q2’26 curtailment of high-GOR wells • Oil production guidance increased by 10 MBbls/d since Feb. 2026 (1) Excludes stock-based compensation 2026 Revised Guidance Detail FY’26 Summary Increased full year oil production range by 10 MBbls/d compared to initial guidance in February Adjusted mid-point of capex guidance to ~$1.95 B ‒ ~$25 MM of capex associated with Ward County bolt-on ‒ Remainder of incremental capex primarily associated with successful ground game acquisitions which increased working interest in 2026 TILs No change to anticipated current income tax of ~$20 MM in 2026, assuming current strip prices H2’26 Summary Expect oil production to be >200,000 Bbls/d Anticipate <$1 B of total capex Other FY’26 Details Average realized revenue (unhedged): ‒ Oil per Bbl: 97% – 100% of WTI ‒ Natural gas per Mcf: $0.25 – $0.75 premium to Waha Hub pricing ‒ NGLs per Bbl: 23% – 25% of WTI 17
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Hedge Book Overview (as of July 31, 2026) 18 Remaining 2026 FY 2027 FY 2028 Q3 Q4 2026 Q1 Q2 Q3 Q4 2027 Q1 Q2 Q3 Q4 2028 WTI Fixed Price Swaps Total Volume (Bbl) 6,440,000 6,440,000 12,880,000 900,000 910,000 920,000 920,000 3,650,000 -- -- -- -- -- Daily Volume (Bbl/d) 70,000 70,000 70,000 10,000 10,000 10,000 10,000 10,000 -- -- -- -- -- Weighted Average Price ($ / Bbl) $68.68 $67.10 $67.89 $74.25 $72.94 $72.06 $71.29 $72.62 -- -- -- -- -- Mid-Cush Basis Swaps Total Volume (Bbl) 6,440,000 6,440,000 12,880,000 900,000 910,000 920,000 920,000 3,650,000 -- -- -- -- -- Daily Volume (Bbl/d) 70,000 70,000 70,000 10,000 10,000 10,000 10,000 10,000 -- -- -- -- -- Weighted Average Price ($ / Bbl) $1.03 $1.03 $1.03 $1.10 $1.10 $1.10 $1.10 $1.10 -- -- -- -- -- WTI Roll Fixed Price Swaps Total Volume (Bbl) 6,578,000 6,578,000 13,156,000 -- -- -- -- -- -- -- -- -- -- Daily Volume (Bbl/d) 71,500 71,500 71,500 -- -- -- -- -- -- -- -- -- -- Weighted Average Price ($ / Bbl) $1.24 $1.13 $1.18 -- -- -- -- -- -- -- -- -- -- Henry Hub Fixed Price Swaps Total Volume (MMBtu) 12,604,000 12,604,000 25,208,000 12,600,000 12,740,000 12,880,000 12,880,000 51,100,000 -- -- -- -- -- Daily Volume (MMBtu/d) 137,000 137,000 137,000 140,000 140,000 140,000 140,000 140,000 -- -- -- -- -- Weighted Average Price ($ / MMBtu) $3.83 $4.16 $4.00 $4.24 $3.32 $3.58 $3.94 $3.77 -- -- -- -- -- Waha Daily Fixed Price Swaps Total Volume (MMBtu) 8,740,000 15,145,000 23,885,000 7,650,000 -- -- -- 7,650,000 -- -- -- -- -- Daily Volume (MMBtu/d) 95,000 164,620 129,810 85,000 -- -- -- 20,959 -- -- -- -- -- Weighted Average Price ($ / MMBtu) $1.80 $2.73 $2.39 $3.57 -- -- -- $3.57 -- -- -- -- -- HSC Daily Fixed Price Swaps Total Volume (MMBtu) 9,200,000 9,200,000 18,400,000 -- -- -- -- -- -- -- -- -- -- Daily Volume (MMBtu/d) 100,000 100,000 100,000 -- -- -- -- -- -- -- -- -- -- Weighted Average Price ($ / MMBtu) $3.95 $4.24 $4.10 -- -- -- -- -- -- -- -- -- -- Waha Differential Basis Swaps Total Volume (MMBtu) 12,604,000 12,604,000 25,208,000 14,490,000 14,651,000 14,812,000 14,812,000 58,765,000 -- -- -- -- -- Daily Volume (MMBtu/d) 137,000 137,000 137,000 161,000 161,000 161,000 161,000 161,000 -- -- -- -- -- Weighted Average Price ($ / MMBtu) ($1.42) ($1.21) ($1.31) ($0.47) ($1.11) ($0.65) ($0.91) ($0.78) -- -- -- -- -- HSC Differential Basis Swaps Total Volume (MMBtu) -- -- -- 9,000,000 9,100,000 9,200,000 9,200,000 36,500,000 9,100,000 9,100,000 9,200,000 9,200,000 36,600,000 Daily Volume (MMBtu/d) -- -- -- 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 Weighted Average Price ($ / MMBtu) -- -- -- ($0.48) ($0.48) ($0.48) ($0.48) ($0.48) ($0.36) ($0.36) ($0.36) ($0.36) ($0.36)
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Reconciliation of Adjusted EBITDAX to Net Income 19 Adjusted EBITDAX Reconciliation1 (1) Adjusted EBITDAX is a non-GAAP financial measure (2) Includes stock-based compensation expense for equity awards related to general and administrative employees only. Stock-based compensation amounts for geographical and geophysical personnel are included within the Exploration and other expenses line ite m For the Three Months Ended, (in thousands) 6/30/2026 3/31/2026 12/31/2025 9/30/2025 6/30/2025 Net income attributable to Class A Common Stock $792,464 $43,620 $339,505 $59,234 $207,137 Net income attributable to noncontrolling interest — 6,774 42,386 22,227 37,884 Interest expense 59,648 67,020 67,067 69,386 72,770 Income tax expense 223,388 13,486 33,965 87,394 62,486 Depreciation, depletion and amortization 500,160 526,288 524,979 526,915 506,410 Impairment and abandonment expense 1,740 2,011 379 2,251 146 (Gain) loss on extinguishment of debt (5,289) — — 264,294 — Non-cash derivative (gain) loss (256,558) 369,297 (79,493) (35,307) (17,256) Stock-based compensation expense2 18,199 15,163 14,031 17,435 19,293 Exploration and other expenses 9,769 3,997 6,799 4,933 5,060 Adjusted EBITDAX $1,343,521 $1,047,656 $949,618 $1,018,762 $893,930
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Reconciliation of Adjusted Operating Cash Flow and Adjusted Free Cash Flow 20 (1) Adjusted operating cash flow and adjusted free cash flow are non-GAAP financial measures Adjusted Operating Cash Flow and Adjusted Free Cash Flow Reconciliation1 Three Months Ended June 30, (in thousands) 2026 2025 Net cash provided by operating activities $1,505,688 $1,038,696 Changes in working capital: Accounts receivable (1,067) (9,283) Prepaid and other assets 31,155 (5,639) Accounts payable and other liabilities (263,587) (206,789) Estimated tax distribution to noncontrolling interest owners — (160) Adjusted operating cash flow 1,272,189 816,825 Less: total cash capital expenditures (521,434) (504,996) Adjusted free cash flow $750,755 $311,829 Adjusted diluted weighted average shares outstanding 855,243 845,075
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21 Reconciliation of Adjusted Net Income Adjusted Net Income Reconciliation1 (1) Adjusted Net Income, Adjusted Net Income – Diluted and Adjusted Net Income per Adjusted Diluted Share are non-GAAP financial measures (2) Income tax benefit (expense) for adjustments made to adjusted net income is calculated using PR’s federal and state-apportioned statutory tax rate that was approximately 22.5% (3) Adjusted diluted weighed average shares outstanding is a non-GAAP measure that has been computed and reconciled to the nearest GAAP metric in the Appendix of this presentation Three Months Ended June 30, (in thousands, except per share data) 2026 2025 Net income attributable to Class A Common Stock $792,464 $207,137 Net income attributable to noncontrolling interest — 37,884 (Gain) loss on extinguishment of debt (5,289) — Non-cash derivative (gain) loss (256,558) (17,256) Impairment and abandonment expense 1,740 146 Adjusted net income excluding above items 532,357 227,911 Income tax benefit (expense) attributable to the above items 2 58,524 (4,674) Adjusted Net Income $590,881 $223,237 Interest on Convertible Senior Notes, net of tax — 1,287 Adjusted Net Income – Diluted $590,881 $224,524 Adjusted diluted weighted average shares outstanding (non-GAAP)3 855,243 845,075 Adjusted net income per adjusted diluted share $0.69 $0.27
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Reconciliation of Net Debt-to-LQA EBITDAX 22 Net Debt-to-LQA EBITDAX Reconciliation1 (1) Net debt-to-LQA EBITDAX, also referred to as “leverage" in this presentation, is a non-GAAP financial measure (2) Represents adjusted EBITDAX (reconciled in the Appendix) for the three months ended June 30, 2026, on an annualized basis ($ in thousands) June 30, 2026 Total debt, net $2,993,050 Unamortized debt discount, premium and issuance costs on senior notes 31,950 Total debt 3,025,000 Less: cash and cash equivalents (131,722) Net debt (non-GAAP) 2,893,278 LQA EBITDAX2 $5,374,084 Net debt-to-LQA EBITDAX 0.5x
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Reconciliation of Adjusted Basic and Diluted Shares 23 Adjusted Shares Reconciliation1 (1) Adjusted basic and diluted weighted average shares outstanding are non-GAAP financial measures Three Months Ended June 30, (in thousands) 2026 2025 Basic weighted average shares of Class A Common Stock outstanding 837,369 701,353 Weighted average shares of Class C Common Stock outstanding — 99,051 Adjusted basic weighted average shares outstanding 837,369 800,404 Basic weighted average shares of Class A Common Stock outstanding 837,369 701,353 Add: Dilutive effects of Convertible Senior Notes — 30,037 Add: Dilutive effects of equity awards 17,874 14,634 Diluted weighted average shares of Class A Common Stock outstanding 855,243 746,024 Weighted average shares of Class C Common Stock — 99,051 Adjusted diluted weighted average shares outstanding 855,243 845,075