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N o ve m b e r 5 , 2 0 2 5 Q3’25 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, as a result of national supply chain disruptions due to trade policies and regulations or otherwise, 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 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 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 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 2025E Net Debt / 2025E EBITDAX and EV / 2026E EBITDAX due to the uncertainty regarding timing and estimates of certain items. Therefore, we cannot reconcile forecasted 2025E Net Debt, 2025E EBITDAX 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 Premier Delaware Basin Pure-Play E&P Company Top Tier Inventory Quality & Depth Commitment to Balance Sheet Strength Differentiated Shareholder Returns & Alignment Largest pure-play Delaware Basin E&P company with ~475,000 net acres, ~105,000 net royalty acres and ~400 MBoe/d of total production Scale and balance sheet strength provide flexibility to quickly respond to a range of market conditions Continuous Portfolio Optimization High quality asset base and operating expertise drive capital efficient development plan Inventory depth supports long-term free cash flow and sustainable shareholder returns Committed to financial discipline with strong balance sheet, hedge book and liquidity Low leverage profile maximizes flexibility Management team is highly aligned with shareholders, owning >6% of shares outstanding Leading & sustainable base dividend with 4.8% yield Focused on portfolio optimization to drive shareholder value Continued success in ground game increases high- return drilling inventory ~475,000 Net Acres ~$14 B Enterprise Value ~0.8x Q3’25 Leverage1 PR Key Statistics ~400 MBoe/d Total Production 15+ Years High-Quality Inventory PR Acreage Delaware Basin New Mexico Texas Eddy Lea Culberson Loving Winkler Ward Reeves (1) Non-GAAP financial measure; reconciliations are included in the Appendix
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3 (1) Non-GAAP financial measures; reconciliations are included in the Appendix (2) Acquired assets produced ~800 Boe/d in Q3’25 Production Oil (MBbls/d) 186.9 NGLs (MBbls/d) 105.8 Natural Gas (MMcf/d) 704.8 Total (MBoe/d) 410.2 % Oil / % Liquids (% Total) 46% / 71% Earnings & Cash Flow Adjusted EBITDAX1 ($MM) $1,019 Adjusted Operating Cash Flow1 ($MM) $949 Adjusted Free Cash Flow1 ($MM) $469 Unit Costs Lease Operating Expense ($/Boe) $5.07 GP&T ($/Boe) $1.43 Cash G&A ($/Boe) $0.86 Balance Sheet (As of 9/30/25) Cash and Cash Equivalents ($MM) $112 Total Debt ($MM) $3,575 Net Debt1 ($MM) $3,463 Net Debt-to-LQA EBITDAX1 (x) 0.8x Permian Resources Financial and Operational Highlights Q3’25 Highlights • Reported total average production of 410.2 MBoe/d, including 186.9 MBbls/d of oil, 105.8 MBbls/d of NGLs and 704.8 MMcf/d of natural gas • Announced cash capital expenditures of $480 MM, cash provided by operating activities of $766 MM and adjusted free cash flow1 of $469 MM ‒ Highest quarterly adjusted free cash flow in Company history • Declared base dividend of $0.15 per share, representing a 4.8% dividend yield • Increased mid-point of full year guidance for oil production by 3.0 MBbls/d to 181.5 MBbls/d and total production by 9.0 MBoe/d to 394.0 MBoe/d ‒ Updated FY’25 oil production guidance now 5% over initial full year guidance with capex below mid-point • Added ~5,500 net acres and ~2,400 net royalty acres through ~250 transactions for ~$180 MM, demonstrating continued bolt-on and ground game success2 • Maintained strong balance sheet with leverage1 of 0.8x ‒ Cash on hand of $112 MM, undrawn revolver and total liquidity of >$2.6 B ‒ Repaid senior notes with cash on hand and redeemed convertible notes • PR’s low cost structure and strong well performance driving high returns despite low commodity prices ‒ Oil production outperformance driven by large scale Q3’25 developments ‒ D&C costs per lateral foot 3% below 2025 guidance • Entered into additional midstream and marketing contracts to further increase natural gas exposure to Gulf Coast and DFW markets ‒ Expect to have ~25% of natural gas production exposed to Waha prices in 2026, inclusive of hedges • Received inaugural investment grade credit rating by Fitch (BBB-) in July and a positive outlook from Moody’s (Ba1) in November Q3’25 Key Metrics
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$4.0 $3.6 1.0x 0.8x 1 1 1 1 1 2 Q2'25 Q3'25 Q3’25 Snapshot – Continued Execution for 12th Consecutive Quarter 4 176.5 186.9 161 169 Q2'25 Q3'25 Oil Production (MBbls/d) Increased production driven by recent well performance and APA acquisition $312 $469 $0.37 $0.55 Q2'25 Q3'25 Adj. Free Cash Flow ($ MM)3 $7.82 $7.36 Q2'25 Q3'25 Controllable Cash Costs ($ / Boe)2 Relentless focus on remaining the Delaware Basin low-cost leader Redeemed 2026 Senior Notes and 2028 Convertible Notes ~$750 ~$725 FY'25E Q3'25 D&C Cost ($ per Lateral Foot) Continued operational efficiencies and vendor optimization driving well costs per foot lower (1) Calculated as daily oil production (Bbls/d) divided by fully diluted, debt adjusted share count (in millions) (2) Total controllable cash costs consist of LOE, GP&T and Cash G&A (3) Non-GAAP financial measure; reconciliations are included in the Appendix Total Debt ($ B) Per Debt-Adjusted Diluted Share1 Per Diluted Share Net Debt / LQA EBITDAX3 Permian Resources Delivered Record Free Cash Flow in Q3’25
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0 25 50 75 0 30 60 90 Cume Oil; 10K Ft. Normalized (MBbls) Days on Production Leading Execution, Cutting Edge Technology Drive Robust Results 5 Haley Results vs. Offset Development1 Offset Peer Average Haley Actuals (1) Source for offset development: Enverus; includes analogous wells within a ~5 mile radius that were placed on production after January 1, 2020 Leveraging Operational Expertise and Technical Acumen Leveraging AI-driven subsurface insights and precision wellbore placement to expand play boundaries Removing plugging agents in older wells through chlorine dioxide (ClO2), significantly increasing base production Utilizing split string systems during coiled tubing operations, resulting in higher ROP on extended laterals Haley Locator Map New Mexico Texas Eddy Lea Loving Winkler Ward Reeves Headquarters in Midland, TX provides for seamless transfer of technological expertise to the field, leading to lower costs and superior execution Increased Capital Efficiency Lower per Unit Costs Higher Recoveries per Foot Enhanced FCF per Share Enhancing individual well stimulation through micro-seismic azimuth analysis Haley Overview • Q3’25 production outperformance driven by recent pad results, including Haley development in Winkler County, Texas • Haley pad placed on production during early Q3’25 ‒ Consisted of 17-well, three-mile development with high working interest • Haley wells delivered outstanding results, outperforming offset developments by ~45% ‒ Data driven spacing and targeting ‒ Tailored completions design by target interval
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Revised Guidance Summary 6 2025 Guidance Summary • Increasing full-year production ranges to 181 – 182 MBbls/d and 390 – 398 MBoe/d ‒ ~2% increase to both oil and total production ‒ Increase driven primarily by strong well results • No change to cash capital expenditure guidance • No change to total controllable cash cost guidance 2025 Revised Oil Guidance (MBbls/d)1 Note: For more detail, see Appendix slide (1) Represents the mid-point of FY’25 guidance YTD, Permian Resources has increased its original FY’25 oil guidance by ~5%, while lowering its capital budget by ~2% 3.0 2.7 3.0 0.3 172.5 178.5 181.5 February August November Standalone Improvement Q3’25 AcquisitionsAPA Bolt-On
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Acquisition Capital per Year3 ($ MM) $775 $880 $905 $980 $995 $1,015 $1,030 $1,065 $1,080 $7.35 $7.60 $8.25 $9.60 $10.35 $12.45 $13.85 $14.65 DC&E $ / Ft (Delaware Basin)1 (September 2025 Report) Total Controllable Cash Costs ($ / Boe)2 (Most Recent Filing) PR’s Low-Cost Leadership Drives Sustainable M&A Strategy 7 M&A Strategy • Disciplined acquisition strategy centered around making the business better and creating value for shareholders ‒ Drive both near and long-term accretion, while adding inventory that immediately competes for capital PR’s Competitive Advantages • Low-cost leadership in the Delaware Basin provides a sustainable advantage • Midland-based team leveraging long-term relationships to source accretive transactions • Decades of technical and operating experience within the Delaware Basin Proven Track-Record • Company has successfully executed value- driven approach to M&A since 2015 • Completed ~2,000 transactions over the past decade • Acquisition pipeline remains robust, providing continued confidence in PR’s ability to consummate attractive transactions that drive long-term value for shareholders Number of Transactions per Year3 (#) ~125 ~230 ~155 ~500 ~550 2021 2022 2023 2024 YTD'25 ~$1,100 ~$400 ~$250 ~$1,250 ~$830 ~$3,900 ~$4,500 2021 2022 2023 2024 YTD'25 PR’s Cost Leadership Provides a Material Advantage, Which Has Allowed it to Consistently Execute on Accretive M&A (1) Source for all companies: Enverus, “2Q25 Oil NAV Compass” published on September 22, 2025; peers include: APA, Civitas, Coterra, Devon, Diamondback, EOG, Matador and Occidental; data rounded to nearest $5 per foot (2) Total controllable cash costs include LOE, GP&T and cash G&A per Boe for the latest three-month period available, utilizing company filings; peers include: APA, Devon, Diamondback, EOG, Matador, Occidental and Ovintiv; data rounded to nearest $0.05 per Boe (3) Includes predecessor Colgate Energy’s 2021 and 2022 acquisitions prior to the merger with Centennial to create Permian Resources; reflects acquisition values before customary closing adjustments Asset Acquisitions Corporate Acquisitions
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8 Q3’25 Acquisitions Continue Track-Record of Improving the Business Through A&D New Mexico Texas Eddy Lea Reeves Q3’25 Acquisitions Combined Acquisition Details Total Consideration ~$180 MM 8/8ths NRI ~80% Number of Transactions ~250 Net Leasehold Acres ~5,500 Production (Boe/d) ~800 (~67% oil) Net Royalty Acres2 ~2,400 Average Lateral Length ~11,000’ Combined Acquisition Metrics1 Leasehold Acre Value ~$25,000 / Net Acre Net Royalty Acre Value2 ~$7,500 / NRA $ / Net 10,000’ Location ~$3 MM Q3’25 Acquisitions Overview • Closed ~250 transactions for total of ~$180 MM ‒ ~5,500 net acres and ~2,400 net royalty acres (“NRAs”) ‒ ~800 Boe/d (~67% oil) of production • ~95% of Q3 acquisition capital invested in New Mexico, further strengthening PR’s core Northern Delaware position • Consists of high-quality, extended lateral locations that immediately compete for capital within existing portfolio • Increases PR’s royalty portfolio to ~105,000 NRAs with 100% Permian-focus • Expect continued ground game momentum going forward Acquisition Summary (1) Production value assumed to be $30,000 per flowing Boe (2) 1/8th normalized New Mexico Locator Map Texas Locator Map Loving Winkler Ward
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Improved Midstream Portfolio Further Enhances All-In Gas Netbacks 9 Firm Transport and Sales Agreements (MMcf/d) Gulf Coast / DFW Markets Hedged Waha Spot Waha FY’26E Residue Gas Price Exposure (% of Total)1 Recent marketing agreements provide additional pricing exposure to Gulf Coast / DFW markets, increasing netbacks PR has significantly increased its exposure to Gulf Coast / DFW markets and added hedges, reducing exposure to Waha in 2026 Diversified Pricing Hedge ProtectionLong-Term Flexibility Higher Netbacks Flow Assurance PR Marketing & Midstream Goals (1) FY’26 estimated natural gas production volumes utilize consensus estimates ~25% ~50% ~15% ~25% ~60% ~25% As of 1/1/25 As of Today Marketing Update • Entered into additional natural gas firm transport and sales agreements, providing increased pricing exposure to Gulf Coast and DFW markets ‒ Secured firm transportation on Energy Transfer’s Hugh Brinson Pipeline and WhiteWater’s Matterhorn, Blackcomb and Eiger Pipelines ‒ These markets have historically realized meaningfully higher prices than Waha • As a result, 2026 exposure is diversified and netbacks are improved with ~330 MMcf/d realizing Gulf Coast and DFW pricing ‒ These volumes are expected to realize ~$1 per Mcf improved pricing relative to Waha ‒ Equates to >$100 MM uplift to FCF ‒ Combined with hedges, only 25% of volumes exposed to Waha pricing • Longer-term, these agreements position Permian Resources to benefit from growing natural gas demand and higher realized prices on a larger portion of its natural gas production 2026E Pricing ~240 ~330 ~650 ~700+ FY'25E FY'26E FY'27E FY'28E
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Strong Balance Sheet Supports “All of the Above” Capital Allocation Strategy 10 Investment Grade Quality Balance Sheet BBB- Fitch BB+ S&P Ba1 Moody’s $ ~0.8x Net Debt to LQA EBITDAX1 >$2.6 billion of total liquidity 0.5-1.0x leverage target (1) Non-GAAP financial measure; reconciliations are included in the Appendix (2) Assumes strip pricing for remainder of year; source (for peers): Pickering Energy Partners equity research; peer group includes Permian oil peers with >$4B market cap; PR based on internal estimates, assumes no incremental acquisitions or shareholder returns above current base dividend ~4.8% Current Dividend Yield • Dividend supported at ~$40 / Bbl WTI • Committed to sustainable dividend growth • Peer average yield of 3.4% Peer-Leading Base Dividend ~$830 MM of Acquisitions YTD • Added >20,000 net acres through ~550 transactions YTD • Conservative financing approach preserves balance sheet flexibility Accretive Acquisitions YE 2025E Net Debt / 2025E EBITDAX – Strip Pricing2 0.4x 0.7x 0.8x 0.9x 0.9x 0.9x 1.0x 1.2x 1.3x EOG COP DVN APA OXY MTDR OVV FANG ~$630 MM of Debt Reduction YTD • During Q3, called 2026 senior notes and redeemed legacy CDEV convert • Current weighted average debt maturity of >5 years Debt Repayment ~$75 MM of Share Buybacks YTD • Opportunistic strategy allows for PR to invest during downturns • ~$925 MM remaining under authorization Share Buybacks Credit Rating
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77% 70% 21% 1% (9%) (23%) (31%) (35%) (40%) (43%) SPY FANG EOG COP OVV MTDR APA OXY DVN 15.5x 6.4x 5.3x 5.1x 4.8x 3.8x 3.7x 3.5x 3.3x 3.0x S&P 500 FANG COP OXY EOG DVN MTDR OVV APA 11 Note: Peer group includes Permian oil peers with >$4 B market cap Source: Market data and FactSet consensus estimates as of November 4, 2025; utilizes latest available company filings and pro forma for recent A&D (1) For NA producers, Permian and total production data reflects Enverus gross daily production for August 2025 (latest available data); for producers with international operations, Permian and total production volumes from most recent public filings Compelling Value Proposition Continues with Premier Assets and Increased Scale PR shareholder return has exceeded Permian oil peers since its formation… …And still provides significant upside to its valuation versus peers Low Leverage ~0.8x Net Debt to LQA EBITDAX Differentiated Growth ~15% FY’25E over FY’24 Strong Shareholder Returns Management Ownership Shareholder Alignment >6% FCF per Share Growth2 Total Shareholder Return Since Inception (8/31/22 – 11/4/25) EV / 2026E EBITDAX Permian % total production1 100% ~35% ~55% ~65% ~60% 100% ~100% ~35% ~75% Permian Pure-Plays (2) Based on equity reserach estimates $0.60 Sustainable and Growing Base Dividend Per Share (Annualized)
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Appendix
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Permian Resources Q3’25 Operational and Financial Overview 13 Market Statistics (Data in MM, except per share data) Diluted Shares Outstanding1 843.0 Share Price (11/4/25) $12.41 Market Capitalization $10,462 Total Debt $3,575 Cash & Cash Equivalents $112 Enterprise Value $13,925 Key Statistics ($’s in MM, except per share data) Total Per Share (Diluted) Total Oil and Gas Revenue $1,321.8 Adjusted EBITDAX3 $1,018.8 Less: Interest Expense (Cash) $67.4 Less: Exploration and Other (Cash) $4.1 Less: Current Taxes ($1.2) Adjusted Operating Cash Flow3 $948.5 Less: Cash Capital Expenditures $479.7 Adjusted Free Cash Flow3 $468.8 Adjusted Net Income – Diluted3 $315.1 $0.374 Net Income Attributable to Class A Common Stock $59.2 $0.08 Adjusted Diluted Weighted Average Shares3 846.2 Costs ($ / Boe) Lease Operating Expense $5.07 Gathering, Processing & Transportation $1.43 Severance & Ad Valorem Taxes $2.69 Cash G&A $0.86 Depreciation, Depletion & Amortization $13.96 Realizations Oil (per Bbl) $64.77 NGL (per Bbl) $17.50 Natural Gas (per Mcf)2 $0.58 (1) Represents Class A and Class C Common Stock outstanding as of October 31, 2025 and unvested restricted stock and performance stock units as of September 30, 2025 (2) Includes effect of purchased gas sales (3) Non-GAAP financial measures; reconciliations are included in the Appendix (4) Calculated using Q3’25 adjusted diluted weighted average shares outstanding of 846.2 MM
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Commentary Revised 2025 Guidance Detail 14 Revised FY’25 Guidance Production Net Average Daily Production (Boe/d) 390,000 - 398,000 Net Average Daily Oil Production (Bbls/d) 181,000 - 182,000 Production Costs ($ / Boe) Total Controllable Cash Costs $7.25 - $8.25 Lease Operating Expense ~$5.55 Gathering, Processing & Transportation ~$1.30 Cash General and Administrative1 ~$0.90 Severance and Ad Valorem Taxes (% of revenue) 6.5% - 8.5% Cash Capital Expenditure Program ($ MM) Total Cash Capital Expenditures $1,920 - $2,020 Drilling & Completions ~80% Facilities, Infrastructure, Capital Workover & NonOp ~20% Operated Drilling Program TILs (Gross) ~275 Average Working Interest ~75% Average Lateral Length (Feet) ~10,000’ (1) Excludes stock-based compensation • Oil and total production increased by ~2% due to strong well results • No change • No change • No change Additional Commentary Expect <$5 MM in current income tax for FY’25 at current strip prices Average realized revenue (unhedged): ‒ Oil per Bbl: 98% – 100% of WTI ‒ Natural gas per Mcf: $0.30 – $0.50 less than Waha Hub pricing ‒ NGLs per Bbl: 27% – 30% of WTI
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Hedge Book Overview 15 Hedging Philosophy • Protect the balance sheet, cash flow and shareholder returns • Ensure business is in a position to be opportunistic during downcycles • Balance downside protection with appropriate upside commodity price exposure Position Highlights • For remainder of 2025, crude oil hedges cover ~30% of anticipated production at a weighted average WTI price of ~$70.99 / Bbl1 • For remainder of 2025, natural gas hedges cover ~36% of expected production at a weighted average price of ~$2.20 / MMBtu net to Waha2 (1) Utilizes the mid-point of FY’25 oil production guidance (2) Utilizes the mid-point of FY’25 total production guidance and assumes natural gas production as a % of total production is consistent with FY’24 Crude Oil Hedge Position (Bbls/d) Natural Gas Hedge Position (MMBtu/d) 57,000 29,500 29,500 WTI Swaps Q4’25 H1’26 H2’26 Total Oil Hedged (Excl Basis) Hedged Volume (Bbls/d) 57,000 29,500 29,500 Wtd. Avg. Fixed Price ($/Bbl) $70.99 $69.28 $67.85 246,848 156,000 190,810 182,265 140,000 0 100,000 200,000 300,000 Waha Fixed Swaps HH Swaps Q4’25 H1’26 H2’26 H1’27 H2’27 Waha Fixed Swaps Hedged Volume (MMBtu/d) 81,848 65,000 99,810 42,265 -- Wtd. Avg. Price ($/MMBtu) $1.41 $1.52 $2.35 $3.57 -- Waha Differential Basis Swaps Hedged Volume (MMBtu/d) 207,000 137,000 137,000 161,000 161,000 Wtd. Avg. Price ($/MMBtu) ($1.43) ($1.83) ($1.31) ($0.79) ($0.78) Henry Hub Fixed Price Swaps Hedged Volume (MMBtu/d) 165,000 91,000 91,000 140,000 140,000 Weighted Average Price ($/MMBtu) $4.02 $3.74 $3.83 $3.78 $3.76
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Hedge Book Overview (as of October 31, 2025) 16 Bal 2025 FY 2026 FY 2027 Q4 2025 Q1 Q2 Q3 Q4 2026 Q1 Q2 Q3 Q4 2027 WTI Fixed Price Swaps Total Volume (Bbl) 5,244,000 5,244,000 2,655,000 2,684,500 2,714,000 2,714,000 10,767,500 -- -- -- -- -- Daily Volume (Bbl/d) 57,000 57,000 29,500 29,500 29,500 29,500 29,500 -- -- -- -- -- Weighted Average Price ($ / Bbl) $70.99 $70.99 $69.71 $68.85 $68.13 $67.57 $68.56 -- -- -- -- -- Mid-Cush Basis Swaps Total Volume (Bbl) 4,140,000 4,140,000 2,655,000 2,684,500 2,714,000 2,714,000 10,767,500 -- -- -- -- -- Daily Volume (Bbl/d) 45,000 45,000 29,500 29,500 29,500 29,500 29,500 -- -- -- -- -- Weighted Average Price ($ / Bbl) $1.10 $1.10 $1.07 $1.07 $1.07 $1.07 $1.07 -- -- -- -- -- WTI Roll Fixed Price Swaps Total Volume (Bbl) 5,244,000 5,244,000 1,575,000 1,592,500 1,610,000 1,610,000 6,387,500 -- -- -- -- -- Daily Volume (Bbl/d) 57,000 57,000 17,500 17,500 17,500 17,500 17,500 -- -- -- -- -- Weighted Average Price ($ / Bbl) $0.55 $0.55 $0.28 $0.28 $0.28 $0.28 $0.28 -- -- -- -- -- Henry Hub Fixed Price Swaps Total Volume (MMBtu) 15,180,000 15,180,000 8,190,000 8,281,000 8,372,000 8,372,000 33,215,000 12,600,000 12,740,000 12,880,000 12,880,000 51,100,000 Daily Volume (MMBtu/d) 165,000 165,000 91,000 91,000 91,000 91,000 91,000 140,000 140,000 140,000 140,000 140,000 Weighted Average Price ($ / MMBtu) $4.02 $4.02 $4.08 $3.40 $3.65 $4.01 $3.79 $4.24 $3.32 $3.58 $3.94 $3.77 Waha Daily Fixed Price Swaps Total Volume (MMBtu) 7,530,000 7,530,000 5,850,000 5,915,000 5,980,000 12,385,000 30,130,000 7,650,000 -- -- -- 7,650,000 Daily Volume (MMBtu/d) 81,848 81,848 65,000 65,000 65,000 134,620 82,548 85,000 -- -- -- 20,959 Weighted Average Price ($ / MMBtu) $1.41 $1.41 $2.78 $0.27 $1.68 $2.68 $2.03 $3.57 -- -- -- $3.57 Waha Differential Basis Swaps Total Volume (MMBtu) 19,044,000 19,044,000 12,330,000 12,467,000 12,604,000 12,604,000 50,005,000 14,490,000 14,651,000 14,812,000 14,812,000 58,765,000 Daily Volume (MMBtu/d) 207,000 207,000 137,000 137,000 137,000 137,000 137,000 161,000 161,000 161,000 161,000 161,000 Weighted Average Price ($ / MMBtu) ($1.43) ($1.43) ($1.34) ($2.31) ($1.42) ($1.21) ($1.57) ($0.47) ($1.11) ($0.65) ($0.91) ($0.78)
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2.0% 1.0% 2023 2024 Flare Percentage (%) 2024 Sustainability Report Highlights 17 25% 60% 2023 2024 Continuous Emissions Monitoring (% of Oil Prod.) 2024 Highlights • Plan to publish 3rd Annual Permian Resources Corporate Sustainability Report in November 2025 • Reduced flaring to 1.0% of natural gas volumes, compared to 2.0% in the prior year • Deployed continuous emissions monitoring across 60% of our oil production, a significant increase versus 2023 • Conducted aerial flyovers, inspecting >2,000 sites to ensure high-quality emission monitoring • Limited oil spills to 0.002% and produced water spills to 0.002% of volumes produced • Eliminated the use of fresh water in our completion operations • Utilized recycled water in 47% of our water used for completion operations • Increased our 2024 charitable giving budget to $3 million and provided volunteer or financial support to >60 unique charitable initiatives across the Permian Basin • Structured 100% of our Co-CEOs’ compensation as performance stock units with no cash salary or bonus • Highly aligned management team with shareholders, owning >6% of shares outstanding ~0.5% ~4.5% Peer Avg. CEO Ownership (%)1 1% 0% 2023 2024 Fresh Water Usage (%) (1) Source: PR data and S&P Global; includes Permian oil peers with >$4 B market cap (Apache, ConocoPhillips, Devon, Diamondback, EOG, Matador, Ovintiv and Oxy)
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Reconciliation of Adjusted EBITDAX to Net Income 18 Adjusted EBITDAX Reconciliation1 (1) Adjusted EBITDAX is a non-GAAP financial measure (2) Includes stock-based compensation expense for equity awards related to general and administrative employees only. Stock-based compensation amounts for geographical and geophysical personnel are included within the Exploration and other expenses line ite m. For the Three Months Ended, ($ in thousands, unless specified) 9/30/24 12/31/24 3/31/25 6/30/25 9/30/25 Net income attributable to Class A Common Stock $386,376 $216,650 $329,298 $207,137 $59,234 Net income attributable to noncontrolling interest 70,151 38,829 61,265 37,884 22,227 Interest expense 74,824 76,783 73,839 72,770 69,386 Income tax expense 106,468 62,645 100,334 62,486 87,394 Depreciation, depletion and amortization 453,603 486,463 474,203 506,410 526,915 Impairment and abandonment expense 1,380 2,128 5,209 146 2,251 Loss on extinguishment of debt 5,110 -- 5,826 -- 264,294 Non-cash derivative (gain) loss (213,102) 73,579 (36,423) (17,256) (35,307) Stock-based compensation expense2 13,537 13,149 16,199 19,293 17,435 Exploration and other expenses 6,962 6,363 15,250 5,060 4,933 (Gain) loss on sale of long-lived assets (329) 66 -- -- -- Adjusted EBITDAX $904,980 $976,655 $1,045,000 $893,930 $1,018,762
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Reconciliation of Adjusted Operating Cash Flow and Adjusted Free Cash Flow 19 (1) Adjusted operating cash flow and adjusted free cash flow are non-GAAP financial measures (2) Reflects estimated future distributions to noncontrolling interest owners based upon current federal and state income tax expense recognized during the period and expected to be paid by the partnership. Such estimates are based upon the noncontrolling interest ownership percentage as of the three months ended September 30, 2025 Adjusted Operating Cash Flow and Adjusted Free Cash Flow Reconciliation1 Based on Cash Capital Expenditures Three Months Ended September 30, (in thousands, except per share data) 2025 2024 Net cash provided by operating activities $766,486 $954,358 Changes in working capital: Accounts receivable 63,690 (78,413) Prepaid and other assets (239) 2,431 Accounts payable and other liabilities 118,356 (56,437) Other non-recurring charges -- 1,106 Estimated tax distribution to noncontrolling interest owners 2 224 (181) Adjusted operating cash flow 948,517 822,864 Less: Total cash capital expenditures (479,680) (520,173) Adjusted free cash flow $468,837 $302,691 Adjusted diluted weighted average shares outstanding 846,217 836,909
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20 Reconciliation of Adjusted Net Income Adjusted Net Income Reconciliation1 Three Months Ended September 30, ($ in thousands, except per share data) 2025 2024 Net income attributable to Class A Common Stock $59,234 $386,376 Net income attributable to noncontrolling interest 22,227 70,151 Loss on extinguishment of debt2 264,294 5,110 Non-cash derivative (gain) loss (35,307) (213,102) Other non-recurring charges -- 1,106 Impairment and abandonment expense 2,251 1,380 (Gain) loss on sale of long-lived assets -- (329) Adjusted net income excluding above items $312,699 250,692 Income tax benefit (expense) attributable to the above items 2,3 2,437 30,529 Adjusted Net Income $315,136 $281,221 Interest on Convertible Senior Notes, net of tax -- 1,305 Adjusted Net Income – Diluted $315,136 $282,526 Adjusted diluted weighted average shares outstanding (Non-GAAP)4 846,217 836,909 Adjusted Net Income per Adjusted Diluted Share $0.37 $0.34 (1) Adjusted Net Income, Adjusted Net Income – Diluted and Adjusted Net Income per Adjusted Diluted Share are non-GAAP financial measures (2) There is no tax benefit calculated for the loss on extinguishment of debt associated with the Convertible Senior Notes incurred during the three months ended September 30, 2025 (3) Income tax benefit (expense) for adjustments made to adjusted net income is calculated using PR’s federal and state-apportioned statutory tax rate that was approximately 22.5% (4) Adjusted diluted weighed average shares outstanding is a Non-GAAP measure that has been computed and reconciled to the nearest GAAP metric in the Appendix of this presentation
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Reconciliation of Net Debt-to-LQA EBITDAX 21 Net Debt-to-LQA EBITDAX Reconciliation1 (1) Net debt-to-LQA EBITDAX, also referred to as “leverage" in this presentation, is a non-GAAP financial measure (2) Represents adjusted EBITDAX (reconciled in the Appendix) for the three months ended September 30, 2025, on an annualized basi s ($ in thousands) September 30, 2025 Total debt, net $3,544,836 Unamortized debt discount, premium and issuance costs on senior notes 30,164 Total debt 3,575,000 Less: cash and cash equivalents (111,805) Net debt (Non-GAAP) 3,463,195 LQA EBITDAX2 $4,075,048 Net debt-to-LQA EBITDAX 0.8x
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Reconciliation of Adjusted Basic and Diluted Shares 22 Adjusted Shares Reconciliation1 (1) Adjusted basic and diluted weighted average shares outstanding are non-GAAP financial measures Three Months Ended September 30, (in thousands) 2025 2024 Basic weighted average shares of Class A Common Stock outstanding 712,282 693,692 Weighted average shares of Class C Common Stock 95,660 100,670 Adjusted basic weighted average shares outstanding 807,942 794,362 Basic weighted average shares of Class A Common Stock outstanding 712,282 693,692 Add: Dilutive effects of Convertible Senior Notes -- 29,117 Add: Dilutive effects of equity awards 15,411 13,430 Diluted weighted average shares of Class A Common Stock outstanding 727,693 736,239 Weighted average shares of Class C Common Stock 95,660 100,670 Effect of conversion of Convertible Senior Notes on weighted average shares 22,864 -- Adjusted diluted weighted average shares outstanding 846,217 836,909