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F e b r u a r y 2 5 , 2 0 2 6 Q4’25 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, political and economic conditions and events in or affecting other producing regions or countries, 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 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 and EV / 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 ~480,000 net acres, >105,000 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 ~1,200 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 PR Acreage Delaware Basin New Mexico Texas Eddy Lea Culberson Loving Winkler Ward Reeves Low Leverage ~0.7x Net Debt to LQA EBITDAX at YE’261 Differentiated Growth >30% Two-Year CAGR (’23-’25) Strong Shareholder Returns Management Ownership Shareholder Alignment >6% Debt-Adjusted FCF per Share Growth $0.64 Sustainable and Growing Base Dividend Per Share (Annualized) Premier Delaware Basin Pure-Play Peer-Leading Cost Structure Proven Acquisition Strategy Top Tier Inventory Quality & Depth Leading FCF per Share Growth & Value Creation (1) Assumes strip pricing for remainder of year and no incremental acquisitions or shareholder returns above current base dividend
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3 (1) Non-GAAP financial measures; reconciliations are included in the Appendix (2) Associated production from acquired assets is immaterial for Q4’25 and expected to be ~400 Boe/d in Q1’26 Production Oil (MBbls/d) 188.6 181.8 NGLs (MBbls/d) 102.1 98.0 Natural Gas (MMcf/d) 664.3 676.8 Total (MBoe/d) 401.5 392.6 % Oil / % Liquids (% Total) 47% / 72% 46% / 71% Earnings & Cash Flow Adjusted EBITDAX1 ($MM) $950 $3,907 Adjusted Operating Cash Flow1 ($MM) $884 $3,609 Cash Capital Expenditures ($MM) $481 $1,966 Adjusted Free Cash Flow1 ($MM) $403 $1,644 Unit Costs Lease Operating Expense ($/Boe) $5.26 $5.26 GP&T ($/Boe) $1.18 $1.40 Cash G&A ($/Boe) $0.80 $0.83 Balance Sheet (As of 12/31/25) Cash and Cash Equivalents ($MM) $154 Total Debt ($MM) $3,575 Net Debt1 ($MM) $3,421 Net Debt-to-LQA EBITDAX1 (x) 0.9x Permian Resources Financial and Operational Highlights Q4’25 Highlights • Reported total average production of 401.5 MBoe/d, including 188.6 MBbls/d of oil, 102.1 MBbls/d of NGLs and 664.3 MMcf/d of natural gas • Announced cash capital expenditures of $481 MM, cash provided by operating activities of $904 MM and adjusted free cash flow1 of $403 MM • Reduced D&C costs to ~$700 per lateral foot • Added ~7,700 net acres and ~1,300 net royalty acres through ~140 transactions for ~$240 MM, demonstrating continued bolt-on and ground game success2 • Maintained strong balance sheet with leverage of ~0.9x FY’25 Highlights • Reported total average production of 392.6 MBoe/d, including 181.8 MBbls/d of oil, 98.0 MBbls/d of NGLs and 676.8 MMcf/d of natural gas • Generated cash provided by operating activities of $3.6 B and adjusted free cash flow1 of $1.6 B • Realized significant operational efficiency gains, resulting in reduced cycle times and lower well costs • Replaced 100% of developed inventory through accretive acquisitions for third consecutive year Q1’26 To-Date Highlights • Increasing quarterly base dividend 7% to $0.16 per share, representing a 3.6% yield Key Metrics FY’25Q4’25
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2025 Review – Another Year of Consistent Execution 4 Oil Production (MBbls/d) ~$750 ~$700 FY'25 Guidance Q4'25 Actual $7.75 $7.49 FY'25E Guidance FY'25 Actual Permian Resources delivered its third consecutive year of strong operational execution, continuing its track-record of driving value for shareholders in the field D&C Cost ($ per Lateral Foot) Controllable Cash Costs ($ / Boe) Other Initiatives Operating efficiencies and supply chain optimization drove per unit well costs lower Demonstrated strong cost control in 2025, while integrating multiple bolt-on acquisitions Maintained Fortress Balance Sheet Exceeded guidance primarily due to asset outperformance 6.0 3.3 172.5 181.8 FY'25 Guidance FY'25 Actual Acquisitions Standalone Improvement Enhanced Gas Marketing Portfolio Executed Accretive M&A Emphasized Technology Focus
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FY'24 FY'25 FY'24 FY'25 FY'24 FY'25 $7.49 $7.70 $7.95 $9.85 $10.30 $12.55 $13.50 $15.80 FANG MTDR EOG DVN OVV OXY APA Leading Execution and Relentless Focus on Costs Drive Peer-Leading Cost Structure Permian Pure-Plays Total Controllable Cash Costs ($ / Boe)1 5 (1) Total controllable cash costs include LOE, GP&T and cash G&A per Boe for the full-year 2025; APA represents first nine months of 2025 (latest data available); peer group includes Permian oil peers with >$6B market cap; peer data rounded to nearest $0.05 per Boe Drilled Feet / Day (Avg.) Completed Feet / Day (Avg.) D&C Cost ($ / Ft.) +6% +19% (10)% Operational efficiencies have driven sustainable reduction in D&C costs per ft. Leveraging Operational Expertise and Technical Acumen Removing plugging agents in older wells through chlorine dioxide (ClO2) Enhancing well stimulation through micro-seismic analysis Leveraging AI-driven subsurface insights to expand play boundaries Utilizing split string systems during coiled tubing operations Drilling • Realized significant supply chain optimization • Q4’25 represented lowest completion cost per foot in PR history Completions Production Operations Corporate • Fastest drilling year in company history • ~20% of 2025 drilling program consisted of extended reach laterals • Delivered longest lateral in company history at ~17,000’ in Q4’25 • Enhanced marketing portfolio to increase netbacks • Reduced cash G&A per Boe by 10% • Lowered interest expense with >$600 MM of debt reduction • Reduced LOE per Boe by 3% • Installed four microgrids in 2025, removing 30+ generators • Increased Q4’25 ESP runtime by ~40% compared to beginning of the year Trialing new frac isolation techniques during completion operations
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Continued Progress on Natural Gas Marketing Portfolio 6 FY’26E Residue Gas Price Exposure (% of Total)1 (1) Utilizes the mid-point of FY’26 total production guidance and assumes natural gas production as a % of total production is consistent with FY’25 Built-out PR’s midstream and marketing team Optimized existing agreements and entered into new long- haul transportation agreements First year where a majority of PR’s natural gas prices at Gulf Coast / DFW markets Additional protection through significant Waha hedges Achieve full impact of long-haul transportation agreements Exploring further optimization of volumes given flexibility of delivery points Last several years’ efforts are beginning to yield a material uplift to PR’s all-in natural gas netbacks and cash flow Unhedged Natural Gas Realization Guidance vs. Waha ($/Mcf) $(0.40) +$0.50 FY'25 Guidance FY'26 Guidance ~$1.00 per Mcf increase YoY in differential guidance vs. Waha 55%35% 10%Gulf Coast / DFW Markets Hedged Waha Unhedged Waha ~90% of PR’s 2026E natural gas production is either hedged or expected to price at Gulf Coast / DFW markets Firm Transport – Gulf Coast + DFW Markets (MMcf/d) ~150 ~240 ~400 ~700+ FY'24 FY'25 FY'26E FY'27E+ 2027+ 2025 2026
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7 Q4’25 Acquisitions Focused on High-Return Core Operating Areas Combined Acquisition Details Total Consideration ~$240 MM 8/8ths NRI ~77% Production (Boe/d)1 ~400 (~43% oil) Net Leasehold Acres ~7,700 Average Lateral Length ~11,400’ Net Royalty Acres2 ~1,300 Combined Acquisition Metrics3 Leasehold Acre Value ~$26,000 / Net Acre Net Royalty Acre Value2 ~$15,000 / NRA $ / Net 10,000’ Location ~$3 MM Q4’25 Acquisitions Overview • Closed ~140 transactions for total of ~$240 MM ‒ ~7,700 net acres and ~1,300 net royalty acres (“NRAs”) ‒ ~400 Boe/d (~43% oil) of production • Q4’25 activity focused on consolidating existing high-return Northern Delaware position ‒ ~99% of acquisition capital allocated to New Mexico ‒ Adds high-quality, long lateral locations that immediately compete for capital ‒ Additionally, acquired high-NRI inventory and net royalty acres in PR operated units • Continue to leverage cost structure and local relationships to drive deal flow Acquisition Summary Locator Map (1) Associated production from acquired assets is immaterial for Q4’25 and expected to be ~400 Boe/d in Q1’26 (2) 1/8th normalized (3) Production value assumed to be $30,000 per flowing Boe PR Acreage Q4’25 Acquisitions New Mexico Eddy Lea Northern Delaware Basin
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8 63 / 80 / 72 245 / 126 / 42 119 / 120 / 123 188 / 192 / 190 233 / 204 / 183 202 / 202 / 203 295 / 192 / 0 236 / 220 / 172 M&A Strategy Increases Inventory Life, Creates Long-Term Shareholder Value PR replaced >100% of inventory developed with high-return locations for the 3rd consecutive year 2025 Inventory Replacement 2025 M&A Overview • Continued execution on PR’s disciplined acquisition strategy, centered around making the business better and creating value for shareholders • During 2025, closed ~700 transactions for total of ~$1.1 B ‒ ~30,000 net acres and ~19,000 net royalty acres ‒ ~13,000 Boe/d (~40% oil) of production1 • Through acquisitions and organic expansion, PR added ~450 locations in 2025 ‒ Added ~250 high rate of return locations through accretive acquisitions ‒ Added ~200 locations through organic inventory expansion, predominantly in New Mexico • Acquisition pipeline remains robust, providing further confidence in PR’s ability to consummate attractive transactions Increase Shareholder Value Accretive to NAV and FCF per share Apply low-cost leadership & technical expertise Maintain and grow high-return inventory Leverage Midland-based team with long-term relationships ~(250) ~100 ~450 ~100 ~50 ~200 FY'25 TILs Bolt-Ons APA Acq. Ground Game Organic Additions Growing Inventory Depth PR’s M&A Strategy (1) Total production represents volume as of announcement date
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9 Total Production (MBoe/d) Oil Production (MBbls/d) Cash Capex (Includes non-D&C) D&C Costs (Per lateral foot) Avg. Lateral Length (Feet) 2026 Guidance Consistent Well Productivity Metric 2026 Guidance Highlights Change YoY 393 182 $1.97 B ~$730 ~10,500 2025 Results Higher Production Base, Reduced Capex and Consistent Capital Allocation Drive Increased Capital Efficiency ~415 ~189 ~$1.85 B ~$675 ~11,000 Benchmark Waha down ~(35)% +6% PR unhedged realizations up ~75% +4% (6)% (8)% +5% Enhanced Cost Structure Consistent Capital Allocation Longer Laterals Low Controllable Cash Costs and Taxes Key 2026 Guidance Drivers
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10 Consistent Well Productivity & Lower Cost Structure Drive Better Capital Efficiency Methodical development approach focused on primary Delaware zones delivers consistent well productivity Increased capital efficiency allows PR to deliver ~20% higher oil volumes with ~(10)% lower capex compared to 2024 Relentless focus on costs and higher operational efficiencies result in reduced well costs 2026 is the Most Capital Efficient Year Yet ~$815 ~$730 ~$675 FY'24 FY'25 FY'26E Avg. Cumulative Oil Production (MBbls per 1,000’ Lateral) D&C Costs ($ per Lateral Foot) Oil Production per $MM of Capex1 (1) 2026 estimates represent the mid-point of Full Year Guidance 0 75 150 225 300 Days 2024 2025 2026E (MBbls / $MM Capex) 28.3 33.8 37.3 FY'24 FY'25 FY'26E
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Continued Operational Excellence Drives Long-Term FCF per Share Growth 11 Capital Expenditures ($B)2 Net Debt and Leverage ($B) Oil Production (MBbls/d) $2.1 $2.1 $2.0 ~$1.85 2023 2024 2025 2026E Oil production growth driven by strong asset performance and accretive acquisitions Reducing capex profile despite significantly higher production base Reducing absolute debt and leverage despite decrease in commodity prices Free Cash Flow Per Share ($) Strong execution overcomes lower commodity prices, leading to consistent FCF per share growth $3.8 $3.7 $3.4 1.1x 1.0x 0.9x 0.7x 2023 2024 2025 2026E Net Debt / LQA EBITDAX (1) Calculated as daily oil production (Bbls/d) divided by fully diluted, debt adjusted share count (in millions) (2) 2023 capital expenditures pro forma for Earthstone Energy (3) Reflects Net Debt to LQA EBITDAX at YE’26 (4) 2026 represents NYMEX strip pricing as of February 18, 2026 97 159 182 ~189 111 149 168 181 2023 2024 2025 2026E ~95% Increase $1.13 $1.64 $1.94 2023 2024 2025 2026E ~70% Increase Per Debt- Adjusted Share1 ~10% Reduction WTI ($/Bbl)4 $78 $76 $65 $63 3
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12 Note: Peer group includes oil-weighted independents with >$5 B market cap (APA, CHRD, COP, DVN, EOG, FANG, MGY, MTDR, OVV, OXY and SM) Source: Market data and FactSet consensus estimates as of February 24, 2026; utilizes latest available company filings and pro forma for recent M&A PR’s Track Record of Free Cash Flow per Share Growth Drives Outsized Returns Permian Pure-Plays Free Cash Flow per Share Growth (2023 – 2025) Total Shareholder Return (1/1/23 to Today) Trading Multiples (EV / 2026E EBITDAX) PR is well-positioned to continue delivering leading FCF per share growth driven by its high-quality asset base, low-cost structure and disciplined acquisition strategy 107% 79% 41% 23% 7% 6% 3% (3)% (7)% (13)% (21)% (29)%(32)% 72% 44% 26% 23% 19% 14% 11% (2)% (9)% (20)% (24)% (25)% (30)% 15.0x 7.5x 6.8x 6.5x 5.9x 5.9x 5.2x 5.1x 4.6x 4.3x 3.7x 3.5x 2.8x
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Appendix
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Permian Resources Q4’25 & FY’25 Operational and Financial Overview 14 Market Statistics (Data in MM, except per share data) Diluted Shares Outstanding1 847.6 Share Price (2/24/26) $17.79 Market Capitalization $15,079 Total Debt $3,575 Cash & Cash Equivalents $154 Enterprise Value $18,500 Key Statistics ($’s in MM, except per share data)` Q4’25 FY’25 Total Oil and Gas Revenue $1,169.4 $5,065.2 Adjusted EBITDAX3 $949.6 $3,907.3 Less: Interest Expense (Cash) $65.4 $275.0 Less: Exploration and Other (Cash) $5.8 $23.9 Less: Current Taxes ($5.2) ($1.1) Adjusted Operating Cash Flow3 $883.6 $3,609.5 Less: Cash Capital Expenditures $480.5 $1,965.9 Adjusted Free Cash Flow3 $403.1 $1,643.6 Adjusted Net Income – Diluted3 $311.0 $1,214.1 Per Adjusted Diluted Share3 $0.37 $1.43 Net Income Attributable to Class A Common Stock $339.5 $935.2 Per Diluted Share $0.45 $1.28 Adjusted Diluted Weighted Average Shares3 845.7 846.5 Costs ($ / Boe) Q4’25 FY’25 Lease Operating Expense $5.26 $5.26 Gathering, Processing & Transportation $1.18 $1.40 Severance & Ad Valorem Taxes $2.32 $2.72 Cash G&A $0.80 $0.83 Depreciation, Depletion & Amortization $14.21 $14.18 Realizations Q4’25 FY’25 Oil (per Bbl) $58.78 $64.06 NGL (per Bbl) $15.44 $18.41 Natural Gas (per Mcf)2 $0.07 $0.63 (1) Represents Class A and Class C Common Stock outstanding as of February 20, 2026 and unvested restricted stock and performance stock units as of December 31, 2025 (2) Includes effect of purchased gas sales (3) Non-GAAP financial measures; reconciliations are included in the Appendix
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Commentary 2026 Guidance Detail 15 FY’26 Guidance Production Net Average Daily Production (Boe/d) 400,000 - 430,000 Net Average Daily Oil Production (Bbls/d) 186,000 - 192,000 Production Costs ($ / 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 $1.75 - $1.95 Drilling & Completions ~$1.45 Facilities, Infrastructure, Capital Workover & NonOp ~$0.4 Operated Drilling Program TILs (Gross) ~250 Average Working Interest 75% - 80% Average Lateral Length (Feet) ~11,000’ (1) Excludes stock-based compensation • Decreased per well unit costs due to higher efficiencies • Lower YoY cash capex despite significantly higher production base Additional Commentary Activity to be allocated ~65% NM, ~30% TX Delaware and ~5% Midland Capital program of ~$1.85 B, representing 6% reduction YoY despite significantly higher production base Expect <$5 MM in current income tax for 2026 at current strip prices Average lateral length of ~11,000 ft. and average working interest of 75% – 80% (average 8/8ths NRI of ~79%) 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 • Delivers ~4% YoY oil growth • Consistent well productivity YoY • Capital allocation weighted to high-return Delaware Basin wells • Strong operating efficiencies and successful integration of acquired assets deliver best-in-class total controllable cash costs • Continued low-cost G&A by maintaining optimized, lean organizational structure headquartered in Midland, Texas • Further optimizing acreage position with increased lateral lengths
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Strong Balance Sheet Supports “All of the Above” Capital Allocation Strategy 16 YE 2026E Net Debt / 2026E EBITDAX – $60 / Bbl Oil2 0.3x 0.7x 0.7x 0.7x 0.8x 0.8x 0.9x 1.0x 1.2x EOG OXY OVV COP DVN APA MTDR FANG (1) Non-GAAP financial measure; reconciliations are included in the Appendix (2) Peers and PR assume $60 / 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; PR based on internal estimates, assumes no incremental acquisitions or shareholder returns above current base dividend ~3.6% Current Dividend Yield • Dividend supported at ~$40 / Bbl WTI • Track-record of consistent dividend growth • Advantaged yield versus peer average of 2.8% Peer-Leading Base Dividend ~$1.1 B of Acquisitions in 2025 • Added ~30,000 net acres through ~700 transactions in FY’25 • Conservative financing approach preserves balance sheet flexibility Accretive Acquisitions ~$635 MM of Debt Reduction in 2025 • Redeemed ESTE 9.875% Sr. Notes, called 2026 Sr. Notes and redeemed legacy CDEV convert in 2025 • Current weighted average debt maturity of ~5 years Debt Repayment ~$75 MM of Share Buybacks in 2025 • Opportunistic strategy allows for PR to invest during downturns • ~$925 MM remaining under authorization Share Buybacks Investment Grade Quality Balance Sheet BBB- Fitch BB+ S&P Ba1 Moody’s $ ~0.7x Net Debt to LQA EBITDAX1 at YE’26 ~$2.7 billion of total liquidity 0.5-1.0x leverage target Credit Rating
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Year-End 2025 Reserves Summary 17 Reserves Category Total Proved Reserves (Net MMBoe)Reserves Overview Proved Reserves increased 9% YoY Proved Developed Reserves increased 6% YoY 582 925 1,027 1,116 YE'22 YE'23 YE'24 YE'25 Commodity Category 43% 26% 31% Oil NGLs Gas 71% 29% Proved Developed Proved Undeveloped Total Proved Developed Reserves (Net MMBoe) 341 704 746 794 YE'22 YE'23 YE'24 YE'25
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Hedge Book Overview 18 (1) Utilizes the mid-point of FY’26 oil production guidance (2) Utilizes the mid-point of FY’26 total production guidance and assumes natural gas production as a % of total production is consistent with FY’25 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 2026, crude oil hedges cover ~30% of anticipated production1 at a weighted average WTI price of ~$64.72 / Bbl • For 2026, natural gas hedges cover ~48% of expected production2 at a weighted average price of ~$2.75 / MMBtu Crude Oil Hedge Position (Bbls/d) Natural Gas Hedge Position (MMBtu/d) Q1’26 Q2’26 Q3’26 Q4’26 Total Oil Hedged (Excl Basis) Hedged Volume (Bbls/d) 59,500 69,500 49,500 49,500 Wtd. Avg. Fixed Price ($/Bbl) $64.62 $63.70 $65.79 $65.16 Mid-Cush Basis Swaps Daily Volume (Bbl/d) 49,833 69,500 39,500 39,500 Weighted Average Price ($ / Bbl) $0.94 $0.91 $1.02 $1.02 WTI Roll Fixed Price Swaps Daily Volume (Bbl/d) 37,833 57,500 27,500 27,500 Weighted Average Price ($ / Bbl) $0.26 $0.31 $0.33 $0.33 59,500 69,500 49,500 49,500 WTI Swaps 332,000 366,810 182,265 140,000 0 200,000 400,000 HSC Fixed Swaps Waha Fixed Swaps HH + Waha Basis Swaps H1’26 H2’26 H1’27 H2’27 Henry Hub Fixed Price Swaps Hedged Volume (MMBtu/d) 137,000 137,000 140,000 140,000 Wtd. Avg. Price ($/MMBtu) $3.90 $4.00 $3.78 $3.76 Waha Fixed Swaps Hedged Volume (MMBtu/d) 95,000 129,810 42,265 -- Wtd. Avg. Price ($/MMBtu) $1.54 $2.39 $3.57 -- HSC Fixed Swaps Hedged Volume (MMBtu/d) 100,000 100,000 -- -- Wtd. Avg. Price ($/MMBtu) $4.02 $4.10 -- -- Waha Differential Basis Swaps Hedged Volume (MMBtu/d) 137,000 137,000 161,000 161,000 Wtd. Avg. Price ($/MMBtu) ($1.83) ($1.31) ($0.79) ($0.78)
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Hedge Book Overview (as of February 20, 2026) 19 FY 2026 FY 2027 Q1 Q2 Q3 Q4 2026 Q1 Q2 Q3 Q4 2027 WTI Fixed Price Swaps Total Volume (Bbl) 5,355,000 6,324,500 4,554,000 4,554,000 20,787,500 -- -- -- -- -- Daily Volume (Bbl/d) 59,500 69,500 49,500 49,500 56,952 -- -- -- -- -- Weighted Average Price ($ / Bbl) $64.62 $63.70 $65.79 $65.16 $64.72 -- -- -- -- -- Mid-Cush Basis Swaps Total Volume (Bbl) 4,485,000 6,324,500 3,634,000 3,634,000 18,077,500 -- -- -- -- -- Daily Volume (Bbl/d) 49,833 69,500 39,500 39,500 49,527 -- -- -- -- -- Weighted Average Price ($ / Bbl) $0.94 $0.91 $1.02 $1.02 $0.96 -- -- -- -- -- WTI Roll Fixed Price Swaps Total Volume (Bbl) 3,405,000 5,232,500 2,530,000 2,530,000 13,697,500 -- -- -- -- -- Daily Volume (Bbl/d) 37,833 57,500 27,500 27,500 37,527 -- -- -- -- -- Weighted Average Price ($ / Bbl) $0.26 $0.31 $0.33 $0.33 $0.31 -- -- -- -- -- Henry Hub Fixed Price Swaps Total Volume (MMBtu) 12,330,000 12,467,000 12,604,000 12,604,000 50,005,000 12,600,000 12,740,000 12,880,000 12,880,000 51,100,000 Daily Volume (MMBtu/d) 137,000 137,000 137,000 137,000 137,000 140,000 140,000 140,000 140,000 140,000 Weighted Average Price ($ / MMBtu) $4.23 $3.57 $3.83 $4.16 $3.95 $4.24 $3.32 $3.58 $3.94 $3.77 Waha Daily Fixed Price Swaps Total Volume (MMBtu) 8,550,000 8,645,000 8,740,000 15,145,000 41,080,000 7,650,000 -- -- -- 7,650,000 Daily Volume (MMBtu/d) 95,000 95,000 95,000 164,620 112,548 85,000 -- -- -- 20,959 Weighted Average Price ($ / MMBtu) $2.66 $0.43 $1.80 $2.73 $2.03 $3.57 -- -- -- $3.57 HSC Daily Fixed Price Swaps Total Volume (MMBtu) 9,000,000 9,100,000 9,200,000 9,200,000 36,500,000 -- -- -- -- -- Daily Volume (MMBtu/d) 100,000 100,000 100,000 100,000 100,000 -- -- -- -- -- Weighted Average Price ($ / MMBtu) $4.40 $3.63 $3.95 $4.24 $4.06 -- -- -- -- -- Waha Differential Basis Swaps Total Volume (MMBtu) 12,330,000 12,467,000 12,604,000 12,604,000 50,005,000 14,490,000 14,651,000 14,812,000 14,812,000 58,765,000 Daily Volume (MMBtu/d) 137,000 137,000 137,000 137,000 137,000 161,000 161,000 161,000 161,000 161,000 Weighted Average Price ($ / MMBtu) ($1.34) ($2.31) ($1.42) ($1.21) ($1.57) ($0.47) ($1.11) ($0.65) ($0.91) ($0.78)
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Reconciliation of Adjusted EBITDAX to Net Income 20 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) 12/31/2025 9/30/2025 6/30/2025 3/31/2025 12/31/2024 Net income attributable to Class A Common Stock $339,505 $59,234 $207,137 $329,298 $216,650 Net income attributable to noncontrolling interest 42,386 22,227 37,884 61,265 38,829 Interest expense 67,067 69,386 72,770 73,839 76,783 Income tax expense 33,965 87,394 62,486 100,334 62,645 Depreciation, depletion and amortization 524,979 526,915 506,410 474,203 486,463 Impairment and abandonment expense 379 2,251 146 5,209 2,128 Loss on extinguishment of debt — 264,294 — 5,826 — Non-cash derivative (gain) loss (79,493) (35,307) (17,256) (36,423) 73,579 Stock-based compensation expense2 14,031 17,435 19,293 16,199 13,149 Exploration and other expenses 6,799 4,933 5,060 15,250 6,363 (Gain) loss on sale of long-lived assets — — — — 66 Adjusted EBITDAX $949,618 $1,018,762 $893,930 $1,045,000 $976,655
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Reconciliation of Adjusted Operating Cash Flow and Adjusted Free Cash Flow 21 (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 December 31, 2025 Adjusted Operating Cash Flow and Adjusted Free Cash Flow Reconciliation1 Based on Cash Capital Expenditures Three Months Ended December 31, Year Ended December 31, (in thousands) 2025 2024 2025 2024 Net cash provided by operating activities $904,327 $871,578 $3,607,541 $3,411,968 Changes in working capital: Accounts receivable 281,226 103,963 321,456 51,396 Prepaid and other assets 20,313 1,663 23,288 8,491 Accounts payable and other liabilities (322,321) (73,735) (347,422) (78,353) Merger and integration expense & other — — 4,749 25,659 Estimated tax distribution to noncontrolling interest owners 2 63 582 (125) — Adjusted operating cash flow 883,608 904,051 3,609,487 3,419,161 Less: total cash capital expenditures (480,518) (504,459) (1,965,926) (2,060,667) Adjusted free cash flow $403,090 $399,592 $1,643,561 $1,358,494 Adjusted diluted weighted average shares outstanding 845,742 847,094 846,529 829,058
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22 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) There is no tax benefit calculated for the loss on extinguishment of debt associated with the Convertible Senior Notes incurred during the year ended December 31, 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 Three Months Ended December 31, Year Ended December 31, (in thousands, except per share data) 2025 2024 2025 2024 Net income attributable to Class A Common Stock $339,505 $216,650 $935,174 $984,701 Net income attributable to noncontrolling interest 42,386 38,829 163,762 265,808 Loss on extinguishment of debt2 — — 270,120 8,585 Non-cash derivative (gain) loss (79,493) 73,579 (168,479) (17,783) Merger and integration expense & other — — 4,749 25,659 Impairment and abandonment expense 379 2,128 7,985 9,912 (Gain) loss on sale of long-lived assets — 66 — (375) Adjusted net income excluding above items 302,777 331,252 1,213,311 1,276,507 Income tax (expense) benefit attributable to the above items 3 8,264 (25,785) (1,804) (65,656) Adjusted Net Income $311,041 $305,467 $1,211,507 $1,210,851 Interest on Convertible Senior Notes, net of tax — 1,294 2,570 5,182 Adjusted Net Income – Diluted $311,041 $306,761 $1,214,077 $1,216,033 Adjusted diluted weighted average shares outstanding (non-GAAP)4 845,742 847,094 846,529 829,058 Adjusted net income per adjusted diluted share $0.37 $0.36 $1.43 $1.47
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Reconciliation of Net Debt-to-LQA EBITDAX 23 Net Debt-to-LQA EBITDAX Reconciliation1 (1) Net debt-to-LQA EBITDAX, also referred to as “leverage" in this presentation, is a non-GAAP financial measure (2) Represents adjusted EBITDAX (reconciled in the Appendix) for the three months ended December 31, 2025, on an annualized basis ($ in thousands) December 31, 2025 Total debt, net $3,545,598 Unamortized debt discount, premium and issuance costs on senior notes 29,402 Total debt 3,575,000 Less: cash and cash equivalents (153,690) Net debt (non-GAAP) 3,421,310 LQA EBITDAX2 $3,798,472 Net debt-to-LQA EBITDAX 0.9x
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Reconciliation of Adjusted Basic and Diluted Shares 24 Adjusted Shares Reconciliation1 (1) Adjusted basic and diluted weighted average shares outstanding are non-GAAP financial measures Three Months Ended December 31, Year Ended December 31, (in thousands) 2025 2024 2025 2024 Basic weighted average shares of Class A Common Stock outstanding 745,004 702,968 715,772 640,662 Weighted average shares of Class C Common Stock 84,378 100,401 94,632 144,566 Adjusted basic weighted average shares outstanding 829,382 803,369 810,404 785,228 Basic weighted average shares of Class A Common Stock outstanding 745,004 702,968 715,772 640,662 Add: Dilutive effects of Convertible Senior Notes — 29,408 — 29,408 Add: Dilutive effects of equity awards 16,360 14,317 15,203 14,422 Diluted weighted average shares of Class A Common Stock outstanding 761,364 746,693 730,975 684,492 Weighted average shares of Class C Common Stock 84,378 100,401 94,632 144,566 Effect of conversion of Convertible Senior Notes on weighted average shares — — 20,922 — Adjusted diluted weighted average shares outstanding 845,742 847,094 846,529 829,058