Slides
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Chord Energy Aug 5 , 2026 Premier Williston Basin Operator Positioned to Thrive , Delivering Value
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Important Disclosures 2 Forward-Looking and Cautionary Statements Certain statements in this presentation, other than statements of historical facts, that address activities, events or developments that Chord expects, believes or anticipates will or may occur in the future, including any statements regarding future opportunities for Chord, future financial performance and condition, guidance and statements regarding Chord’s expectations, beliefs, plans, financial condition, objectives, assumptions or future events or performance are forward-looking statements based on assumptions currently believed to be valid. Forward-looking statements are all statements other than statements of historical facts. The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,” “may,” “might,” “likely,” “plan,” “positioned,” “strategy” and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. Specific forward-looking statements include statements regarding Chord’s plans and expectations with respect to the return of capital plan, advancement of its extended lateral program and production levels, anticipated financial and operating results and other guidance. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on certain assumptions made by Chord based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of Chord, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in crude oil, NGL and natural gas realized prices, uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas, the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with production levels, changes in trade policies and regulations, including increases or change in duties, current and potentially new tariffs or quotas and other similar measures, as well as the potential impact of retaliatory tariffs and other actions, war between Russia and Ukraine, military conflicts in the Red Sea Region, Iran, and the wider Middle East and their effect on commodity prices, changes or uncertainty in general economic and geopolitical conditions, inflation rates and the impact of associated monetary policy responses, including fluctuating interest rates, logistical challenges and supply chain disruptions, our business strategy, including the continued implementation of our 4-mile well program, the geographic concentration of our operations, uncertainties in estimating proved reserves and forecasting production results, drilling and completion of wells, operational factors affecting the commencement or maintenance of producing wells, the availability of infrastructure and midstream service providers, our ability to realize the anticipated benefits from acquisitions, the condition of the capital markets generally, as well as Chord’s ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting Chord’s business and other important factors that could cause actual results to differ materially from those projected as described in Chord’s reports filed with the U.S. Securities and Exchange Commission (the “SEC”). Any forward-looking statement speaks only as of the date on which such statement is made and Chord undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. Additional information concerning other risk factors is also contained in Chord’s most recently filed Annual Report on Form 10-K for the year ended December 31, 2025, subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other SEC filings. Non-GAAP Financial Measures This presentation includes supplemental financial metrics that are not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). These non-GAAP measures should not be considered in isolation or as a substitute for the nearest comparable measures prepared under GAAP. Because these non-GAAP measures exclude some but not all items that affect the comparable GAAP measure, such as net income (loss) or net cash provided by (used in) operating activities, and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies. Reconciliations of these non-GAAP financial measures to their most comparable GAAP measure can be found on Chord’s website at https://ir.chordenergy.com/non-gaap. From time to time, Chord provides forward-looking forecasts of these measures; however, Chord is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP measures because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measures. The reconciling items in future periods could be significant. Cautionary Statement Regarding Oil and Gas Quantities The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible— from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities of the exploration and development companies may justify revisions of estimates that were made previously. If significant, such revisions could impact Chord’s strategy and future prospects. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, Chord has not disclosed probable or possible reserves in its SEC filings. The production forecasts and expectations of the combined company for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
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58%24% 18% Premier Williston Operator • Size & scale with high quality assets • >1.3MM net acres • ~280 MBoepd • ~58% oil; >90% revenue1 • 10+ yrs of low-breakeven inventory2 3 Commodity Mix1 Disciplined, Oil-Focused Williston Operator Delivering Strong Returns Williston Basin Acreage Marcellus Non-Op Acreage Oil Gas NGL Production 6:1 (1) Reflects FY26 midpoint guidance; (2) Management estimate based on normalized activity pace; (3) CHRD net leverage as of 6/30/26 using LTM EBITDA Enhancing FCF • Lowered inventory breakeven >10% Y/Y • Capital discipline; maintenance program • Low base declines & reinvestment rate • Growing FCF/share Disciplined Return of Capital & Balance Sheet Management • Significant shareholder returns • Compelling base dividend ($5.20/share) • Share repurchases • Strong balance sheet; ~0.3x leverage3
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• Disciplined approach • Five Williston deals since ’21 • Enhanced scale o Oil volumes +300% from ’21 o >1.3MM acres • Significant synergy capture Chord’s Capital Allocation Approach 4 Opportunistic M&A • Financial strength essential • Maintained low leverage profile o ~0.3x at 2Q261 • Net debt of $0.9B at 2Q26 • No revolver borrowings, $2B of elected commitments at 2Q26 • Improving credit ratings Balance Sheet Management • Proven 3-mi/4-mi development o Conservative spacing • Basin leading rig/frac performance • Strong base performance with lower oil decline rate vs peers • Continued innovation driving down breakevens • Impressive shareholder returns track record • Attractive base dividend • Favor share buybacks currently • Avoiding pro-cyclical buying • Targeting 75%+ return of capital starting in 3Q26 Capital Allocation Focus Delivers Strong Returns Through Commodity Cycles (1) CHRD net leverage as of 6/30/26 using LTM EBITDA. Attractive E&P Investments Strong Return of Capital Program Allocation Options Capital Allocation Starts with Strong Cash Flow From Operations
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141.5 161.0 FY22 FY26 6.0 ~4.5 FY22 FY26 1.9 ~1.5 FY22 FY26 Highlights • Williston Basin largest acreage holder & producer • Scale drives operational efficiency • High oil cut provides upside to oil upcycle • Deep subsurface expertise • Significantly reducing costs Premier Williston Basin Operator, Driving Efficiencies 5(1) Source: Enverus as of 7/21/26. Reflects Jan-May 2026 gross operated oil production. Peers include CVX, COP, CLR, DVN, XOM, Kraken, Petro-Hunt, and Slawson; (2) FY22 reflects OAS, WLL and ERF pro-forma; (3) Net 10K’ equivalent operated locations. Long-Lateral Inventory Expansion3 • Chord’s long-lateral competitive advantage • Achieved ~80% long-lateral inventory faster than expected ~40% >50% YE23 Inventory YE24 Inventory YE25 Inventory ~80% 2-Mile 3-Mile Williston Basin Oil Production, MBopd1 4-Mile Operational Efficiency Enhancement2 • Increasing production w/ fewer rigs and crews Drilling Rigs Oil Production (MBopd) Completion Crews -25% Chord Peers -21% +14% 216 156 150 123 111 88 59 43 39
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Base Production Investment 6 Base Production Represents a Sizable Opportunity • Chord - largest producer in the Williston w/ most operated wells • Enhanced focus on base production • Base production investment: • Favorable risk/reward & attractive return potential • Capitalizing on higher oil pricing to trial new technologies • Accelerating volumes with potential EUR upside • Further lowers oil decline rate vs. peers Robust Opportunity Set • Initiatives driving production uplift Accelerating Workovers Reducing Cycle Times Chemical Jobs Surface Optimization Optimizing AL w/AI Lower Failure Rate High Pressure Gas Lift Pump Placement 24-Hour Workover Rigs BHA Design Change AI Driven Logistics Rod-less Pumping Jan-25 Jul-25 Jan-26 Jul-26 Bopd Volumes Original Outlook Investment Driving Incremental Volumes From Base1 • Outperforming original outlook Expanding Chemical Workover Program • Various treatments over hundreds of wells • Acidizing/Solvents – clean debris, enhance flow & recovery • Surfactants – reduce interfacial tension and improve mobility • Combo Treatments - removing scale, paraffins, polymers, biofilm • Potential upside largely not factored into latest volume outlook (1) .Subset of well population targeted for optimization
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65 61 56 YE23 YE24 2Q26 Share count (MM) Share Buyback Program Reducing Share Count 7(1) Reflects fully-diluted shares outstanding, including dilutive effect of outstanding warrants as applicable; YE23 & See slide 8 for details.FY24 pro-forma for Enerplus; (2) -14% FDSO Reduction since YE23 10% Oil Growth2 Per share CAGR since 2021 +26% Base Dividend CAGR since Feb-21 Delivering Strong Shareholder ReturnsTrack Record of Share Buybacks1 • Aggressive share count reduction • Buybacks preferred in current environment 14% Reduction (Since YE23) ~30% FCF Growth2 Per share since FY24
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$17.10 $22.00 0.65 1.05 2021 2022 2023 2024 2025 2026 Delivering Per Share Growth Strong Capital Allocation • Maximizing efficient FCF generation • Counter-cyclical share repurchases • Disciplined M&A Operational Excellence • Reducing controllable costs • Improving efficiencies • Leveraging new technologies Significant Shareholder Returns • 14% share reduction since YE233 • $5.20/share base dividend annually Financial Strength • Maintained strong balance sheet Free Cash Flow Per Share2 8 Oil Production Per Share1 (1) Calculated as oil production / wtd. avg. diluted shares outstanding. 2025 production includes XTO on a pro-forma basis of 159 MBopd; (2) Reflects FY24 pricing ($75.70/$2.28), normalizes differentials & cash taxes for both periods. FY24 are actuals pro-forma for Enerplus. FY26 reflects midpoint guidance; (3) Pro-forma for Enerplus. 2024 2026 ~30% Growth ~10% CAGR vs ‘21
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(10%) (5%) 0% 5% 10% $0 $25 $50 $75 $100CapEx / Wedge Bopd Highlights • Wide spacing and long-laterals enhance economics • 4-mile laterals and alternate shape wells further improve returns • Continuing to drive operational efficiencies • Optimizing large production base Peer Leading Capital Efficiency 9(1) Peers based on consensus estimates in Feb. 2026. Chord based on Feb. 2026 midpoint FY26 guidance. Capital efficiency calculated as CapEx divided by wedge production. Decline rates from Enverus; Peers include APA, CRGY , DVN, EOG, FANG, MGY , MTDR, NOG, OVV, PR and SM; (2) 2024 reflects CHRD and Enerplus pro forma at announcement date. 2026 reflects midpoint of guidance. (3) Source: Enverus 2026 Capital Efficiency report 2/11/26. Peers include APA, CRGY , DVN, EOG, FANG, MGY , MTDR, NOG, OVV, PR and SM. 2026 Program Capital Efficiency vs Peers1 Top Quartile In 2026 Capital Efficiency Change 2025 vs 20263 Leading Rate of Change Y/Y Chord Peers Chord Peers 2024 (Enerplus Announcement) 2026 ~$1.5B 153 MBopd 161 MBopd $1.4B Oil Production Reducing Capital, Increasing Production2 • CapEx ~$100MM lower, oil production +8 MBopd higher CapEx
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Improving Capital Productivity 10 Flowing Capital Efficiency1 • Normalizing well productivity for relative capital cost • Increased long-laterals in ‘26 - better economics, lower CapEx per ft • 2026 reflects increase in 4-mile TIL activity to ~40%Bopd per ft / D&C per ft Cum. Bopd per ft / D&C per ft 2026 D&C/ft $566 ~80% long-laterals 2025 D&C/ft $680 ~45% long-laterals >10% Capital Efficiency Improvement (1) Flowing capital efficiency measured as Bopd per ft / capex per ft, reflects initial Feb 2026 outlook (2) Future F&D calculated as future development costs / PUD reserves. 2026 Program 2025 Program Future F&D2 • Future F&D trending -22% lower since 2023 • Longer laterals, wider spacing improving capital efficiency $16.75 $14.88 $13.04 2023 2024 2025 -22%
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0 5 10 15Lateral Length (000s)0 5 10 15 Chord Bakken Midland DJ Delaware Eagle Ford Lateral Length (000s) 901 830 703 680 566 10 12 14 16 18 400 500 600 700 800 900 1,000 2022 2023 2024 2025 2026 Avg. Lateral Length (000s) $/ft $/ft Avg. Lateral Length Bakken/Chord Uniquely Positioned for Long-Laterals 11 Industry Leader in Long-Lateral Development2 (1) Based on Feb 2026 guidance (2) Source: Enverus 2025 spuds. Chord 2026 plan reflects TILs. Peers include APA, COP, CVX, DVN, EOG, FANG, MTDR, OXY , PR, SM and XOM (Bakken, Delaware, DJ, Eagle Ford and Midland). Bakken Competitive Advantages • Supportive regulatory process • Favorable land layout – clearly established DSUs • Stress regime allows N/S & E/W lateral orientation • Generally targeting single zone (Middle Bakken) • Rock homogeneity, less faulting vs other basins • Consistent pressure regimes simplify mud-weight PeersChord Chord 2026 Plan Significant Improvement in Program D&C $/ft1 -37% Bakken / Chord Favorable Long-Lateral Positioning2 Chord Chord 2026 Plan
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4-Mile Lateral Program Progressing 12 3-Mile 4-Mile (Base Case) 4-Mile (Upside Case) Superior returns on long-lateral development 12 +90% - 100% EUR1 $8/Bbl - $12/Bbl Lower Breakeven1 of 2025 TIL activity ~5% +40% - 60% CapEx1 of 2026 TIL activity ~40% Cost of Supply Improvement1 $8-$10/Bbl $10-$12/Bbl 4-Mile Highlights • Organically improves inventory quality • Lowers breakevens, extends inventory life • >50 Drilled and 26 TIL’d2 • D&C execution and early performance meeting expectations • Cleanouts consistently reaching total depth • Pad drilling & trimulfrac supporting efficiencies • ~50% of long-term inventory3 $8-$10/Bbl (1) Compared to 2-mile analog; (2) As of early 3Q26; (3) Net 10K’ equivalent operated locations.
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Enhancing Economics With Long-Laterals 13 2-Mile 3-Mile 4-Mile 2-Mile vs 3-Mile 2-Mile vs 4-Mile CapEx Well Cost ($MM) $7.1 $8.5 $10.7 +20% +50% $ per ft $710 $568 $532 -20% -25% Expected Ultimate Recovery1 Oil EUR (000s) 450 675 855 +50% +90% Bo per ft 45 45 43 - -5% Economics F&D/bo $15.78 $12.62 $12.46 -20% -21% Capital and Recoveries (per ft)1Highlights • Williston Basin contiguous acreage advantaged for long-laterals • Organically improves inventory quality • Lowers breakevens and enhances economics • Reconfigured DSU spacing to 3 & 4-mile development Western Extension Case Study2 • Longer-laterals significantly improve economics in Western Extension (1) 4-mile EUR assumes 80% contribution from 4th mile; (2) Capital assumptions based on Feb 2026 disclosure $710 $568 $532 45 45 43 2-Mile 3-Mile 4-Mile Bo per ft Well cost per ft -2% -4% -9% 2-Mile 3-Mile 4-Mile Well Costs vs YE24 (% Change) • 4-mile well cost reduction – improving efficiencies
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Enhancing Inventory Quality and Duration Added 294 Net Operated 10K’ Inventory3 Low-Breakeven Locations Added in 2025 >10% Wtd. Avg. Breakeven Improvement YE25 vs YE24 operated inventory portfolio (125) 207 72 15 Net 10K' TILs Organic XTO Ground Game Operated Net 10K' -150 -100 -50 0 50 100 150 200 10K’ Net Operated Locations3 Low-Breakeven 2025 Activity Highlights • 10+ years low-breakeven inventory1 • Improving inventory quality and duration • Organically improving inventory – longer laterals, wider spacing • Long-lateral inventory increased to ~80% at YE252 o Ahead of schedule (1) Management estimate based on normalized activity pace; (2) Net 10K’ equivalent operated locations; (3) Reflects net 10K’ equivalent operated low-breakeven locations. >2X Inventory Replacement 14
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0.0x 0.5x 1.0x 1.5x - 30 60 90 120 150 180 2021 2026 Net Leverage Oil Production (MBopd) Oil Production Net Leverage Whiting Merger • Closed 3Q22 • ~23MM shares • ~$245MM cash Disciplined M&A Track Record 15 2021 20242022 2023 QEP Bolt-on • Closed 4Q21 • $745MM cash Enerplus Merger • Closed 2Q24 • ~21MM shares • ~$376MM cash XTO Bolt-on • Closed 2Q23 • $375MM cash Highlights • Williston Basin focus • Balanced approach - corporate mergers, bolt-ons and ground game • Significant synergy capture with enhanced scale and lower cost structure • Maintained strong balance sheet and shareholder returns focus Oasis Midstream Partners • Closed 1Q22 • ~21MM units / ~$160MM cash Non-Core Assets • Series of transactions • ~$40MM cash 2025 XTO Bolt-on • Closed 4Q25 • $550MM cash DJ Basin • Closed 4Q24 • $42.5MM cash Enhanced Scale, Strong Balance Sheet1,2 • Grown oil production >4x, maintained strong balance sheet (1) FY21 reflects OAS standalone and excludes Permian Basin production. FY26 reflects midpoint guidance; (2) CHRD net leverage as of 6/30/26 using LTM EBITDA. Permian Basin • Closed 2Q21 • $480MM cash AcquisitionsDivestitures
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0.3x 1.3x Peers 2027E Net Leverage 2026 2027 2028 2029 2030 2031 2032 2033 16(1) CHRD net leverage as of 6/30/26 using either LTM EBITDA or ‘27E EBITDA; (2) Based on NTM EBITDA at midpoint guidance run at $65 WTI/$3 HH, excluding hedges; (3) Reflects ’27E net leverage. Peer debt levels estimated from FactSet as of 7/28/26 with adjustments made for pending M&A. Peers include APA, MGY , MTDR, OVV, PR, SM. (4) Calculated as of 6/30/26, $2B elected commitment less $30.4MM letters of credit plus $612MM of cash; Robust Liquidity • $2.75B borrowing base/$2B ECA • Revolver maturity Nov. 2029 • No revolver borrowings at 2Q26 • Cash balance of $612MM at 2Q26 • $2.6B of liquidity4 at 2Q26 Strong Credit Profile • Moody’s Ba1 • S&P BB • No near-term debt maturities Low Leverage • ~0.3x leverage1 • Target sub-1x in normalized price environment2 • Financial strength supports org. resiliency • Provides optionality for strategic actions Debt Maturities and Balances • No near-term debt maturities Peer Leading Balance Sheet1,3 $750MM 6.75% $750MM 6.00% $2B ECA, undrawn Peer Leading Balance Sheet Supports Organization Resiliency
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3.0x 3.7x 4.4x Peers XOP Long-Term Outperformance, Attractive Valuation 17(1) Source: FactSet total return 12/31/20 – 7/27/26; peers include APA, MGY , MTDR, OVV, SM. (2) Source: FactSet as of 7/27/26; EBITDA reflects FY27 consensus estimates with adjustments made for pending M&A; peers include APA, MGY , MTDR, OVV, SM. (3) Management estimate based on normalized activity pace. Total Shareholder Return1 • Strong capital allocation / execution track record • Sustainable free cash flow generation EV / EBITDA Multiple2 • High-quality assets at attractive valuation vs peers • 10+ yrs of low-breakeven inventory3 High-quality oil-focused assets trading at an attractive valuation vs. peers 476% 322% 228% Peers XOP
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Durable, Low-Breakeven Inventory at Compelling Valuation • Strong inventory, discounted valuation vs peers • Improving inventory quality and duration • ~80% long-lateral inventory at YE251 Capital Efficiency Continues to Improve • Multi-year track record of strong execution, focus on innovation & efficiency • Basin leading cycle times and performance • 4-mile laterals further enhance economics Enhancing Generation of Free Cash Flow • Shallow base declines, low reinvestment rate • Delivering per share growth • Attractive FCF yield vs peers Strong Financial Position Supports Resiliency • Peer-leading balance sheet, strong liquidity • No near-term debt maturities • Enhancing FCF w/ continuous improvement Peer Leading Return of Capital Program • Significant track record of shareholder returns • Attractive base dividend, durable in low commodity prices • Disciplined M&A track record Top Tier Oil Assets in Williston Basin • Williston size and scale with high quality assets across >1.3MM net acres • Long-laterals and conservative spacing support deep, low-cost inventory and reduce asset variability • Attractive non-op asset in core of Marcellus • Strong oil leverage (>90% of revenue) 18 (1) Net 10K’ equivalent operated locations. Chord Energy = Premier Williston Basin Operator
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Supplementary Information
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20 Category Continuous Improvement Initiatives 2025 Run-Rate Results Operated D&C Production and LOE Marketing Corporate • Active marketing team improving netbacks • Evaluate midstream opportunities • Proactive contract renegotiation • Consolidating agreements • Resource utilization • Opportunity discovery • Rapid AI adoption • Lowering cost of capital • Lower failure rates and improved uptime • Rod-less pumping • AI-driven machine learning on rod lift wells • 24-hr workover rigs • 4-mile well adoption • Continuous pumping • Dual fuel utilization • Faster cycle times • Modular facility designs $30-$50MM Annual Run- Rate Savings • Renegotiated several contracts o oil, gas and water ~$25MM Annual Run- Rate Savings • Scaled corporate AI adoption • Optimized production tax • Attractive debt cost of capital ~$50MM Annual Run- Rate Savings • >50% ESP cycle time reduction • 25% failure rate improvement • Scaled AI to 99% of rod lift wells ~$45MM Annual Run- Rate Savings • TIL’d seven 4-mile wells • Leader in lateral footage drilled • Continuous pumping $160MM Annual Run-Rate Savings (~12% of 2026 FCF)1 Continuous Improvement Initiatives Achieved in 2025 Continuous Improvement Initiatives Delivering FCF Enhancement (1) FCF reflects FY26 midpoint guidance (1H26A & $75 WTI/$3.00 Henry Hub 2H26)
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21 Williston Basin Gas Takeaway Bison Xpress • ~0.3 Bcf/d • In-service 2026 AECO Hub LNG Canada • ~2 Bcf/d • Phase I cargoes began shipping June 2025 Ventura Hub WBI Energy Bakken East • ~1.0 Bcf/d • In-service 2029/2030 Northern Border • ~2.2 Bcf/d • Midwest market access Marketing Overview Delivering $30-$50MM FCF savings 2026+ Williston Basin Oil Takeaway1 (1) Source: Enverus. - 500 1,000 1,500 2,000 2020 2021 2022 2023 2024 2025 2026 MBopd Local Refining Pipeline Rail Production Marketing Highlights • Marketing team maximizes netbacks and flow assurance • Optimize diffs with pricing diversification and flexibility • Ample oil takeaway capacity has improved basin diffs • Expanding gas takeaway anticipated to support stronger realizations • Stable gas-oil ratios • Improving gas capture / flow assurance Marketing Optimization • $30-$50MM annual FCF savings 2026+ • Numerous agreements executed in 2025 o Crude, gas, water • Opportunity to drive further optimization
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115 124 124 - 20 40 60 80 100 120 140 FY24 FY25 1H26 MMCfpd High Quality Non-Operated Marcellus Position 22 Highlights • Dry gas window in core of the Marcellus • Strong operator with top-tier well productivity • Large PDP base with low declines • Deep inventory with attractive economics Marcellus Realized Prices / Production • $3.15/Mcf in FY25 • $6.40/Mcf in 1Q26, $2.10/Mcf in 2Q26 Marcellus Acreage – NE Pennsylvania
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Return of Capital 23 Return of capital framework: • Target return of capital (RoC) determined at quarter-end based on: — Estimated forward leverage — Percentage of Adjusted FCF less Acquisition / Leasehold Below 0.5x leverage: 75%+ Below 1.0x leverage: 50%+ >1.0x leverage: Base dividend+ ($5.20/share annual) Calculation: • Base dividend subtracted from Target RoC • Remainder of Target RoC focused on share repurchases — May taper repurchases cadence at higher oil prices to avoid pro-cyclical buybacks • Do not expect to pay variable dividends in current environment; balance of FCF goes to balance sheet • Dividends are declared with earnings results; expected cash distribution in following qtr (e.g. 2Q26 base dividend paid in 3Q26) • Leverage Calculation: — Net Debt: Debt less cash measured at quarter-end — EBITDA: Estimate for next twelve months run at $65 WTI and $3 HH, excluding the impact of hedges 2Q26 Return of Capital ($MM) 1 $414 Adjusted Free Cash Flow2 - $4 Acquisition / Leasehold x 54% Target 50%+ at Current Leverage3 = $220 Actual Return of Capital - $73 Base Quarterly Dividend of $1.30/share = $147 Return of Capital After Base Dividend - $147 Share Repurchases = $- No Variable Dividend (1) Amounts rounded to nearest million; (2) Excludes $0.7MM of reimbursable non-op CapEx. (3) Net debt to NTM EBITDA at $65/$3 on 3/31/26 was >0.5x. Expect target of 75%+ based on leverage on 6/30/26 Base Dividend $1.30/share Share Buybacks $147MM 2Q26 Return of Capital
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Guidance Highlights • Oil volumes unchanged at 161.0 MBopd • 3Q26 163.0 MBopd at midpoint, with a decline into 4Q26 • CapEx unchanged, $1.4B at midpoint • 3Q26 $375MM at midpoint, decreasing further in 4Q • Includes ~$30MM midstream CapEx 2026 Outlook Development Highlights • 4 – 5 rigs, 1 – 2 frac crews • 140 – 160 gross operated TILs, ~75% WI • ~80% long-lateral 2026 Guidance Ranges FY26 24 3Q26 2026 Development Activity Wild Woods FBIR Little Knife Red Bank Painted Woods Indian Butte 2026 Development Area Murphy Creek Wild Tarpon Wheelock SanishMontana (1) Non-GAAP financial measure. See https://ir.chordenergy.com/non-gaap for more information; (2) 3Q26, 4Q26, and FY26 reflect $70/Bbl - $100/Bbl WTI. 4Q26 Oil volumes (MBopd) 161.5 - 164.5 156.0 - 159.0 160.2 - 161.8 NGL volumes (MBblpd) 50.0 - 52.0 49.0 - 51.0 50.2 - 51.4 Natural gas volumes (MMcfpd) 397.0 - 405.0 410.0 - 418.0 406.6 - 410.6 Total volumes (MBoepd) 277.7 - 284.0 273.3 - 279.7 278.2 - 281.8 CapEx ($MM) $360 - $390 $242 - $292 $1,360 - $1,440 Oil Premium/(Discount) to WTI ($/Bbl) $(0.70) - $0.30 $(1.50) - $0.50 $(0.80) - $(0.00) NGL realization (% of WTI) 4% - 10% 4% - 14% 7% - 11% Natural gas realization (% of Henry Hub) 20% - 30% 35% - 45% 38% - 44% LOE ($/Boe) $10.00 - $11.00 $10.00 - $11.00 $10.05 - $10.55 Cash GPT ($/Boe)1 $2.75 - $3.15 $2.80 - $3.20 $2.80 - $3.00 Cash G&A ($MM)1 $25 - $27 $25 - $27 $98 - $103 Production taxes (% of oil, NGL and gas sales) 8.0% - 8.4% 8.0% - 8.4% 8.0% - 8.2% Cash Interest ($MM) 1 $25 - $27 $25 - $27 $102 - $106 Cash taxes (% of Adjusted EBITDA) 2 3% - 9% 4% - 12% 5% - 8%
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0% 5% 10% 15% 20% 25% $0 $500 $1,000 $1,500 $2,000 $60 $80 $100 FCF Yield Free Cash Flow ($MM) Free Cash Flow Free Cash Flow Yield Strong Free Cash Flow Generation 25 2026 Free Cash Flow Yield2 (1) EBITDA and FCF reflect FY26 midpoint guidance (1H26A & $75 WTI/$3.00 Henry Hub 2H26). (2) FCF Yield calculated as FCF / market cap. Market cap as of 8/3/26; assumes $3.00 NYMEX gas; Reflects hedge book as of 8/3/26 Sources & Uses1 • Flat+ organic growth • Delivering strong returns • Low reinvestment rate • ROC framework • Preference for buybacks, while avoiding pro-cyclical buying ~$1.4B CapEx Investment in Business ~90% Op/Non-Op D&C ~$1.3B Adjusted FCF Return of Capital (“ROC”) Cash to Balance Sheet Acquisition / Leasehold Significant Cash Generation ~$3.0B EBITDA 14% FCF Yield 18% FCF Yield 22% FCF Yield
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Chord Financial and Operational Results 26(1) Non-GAAP financial measure. A reconciliation of this non-GAAP financial measure to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap; (2) 3Q25, 4Q25, 1Q26 and 2Q26 exclude $11.7MM, $8.0MM, $3.0MM, and $0.7MM of reimbursable non-op CapEx, respectively. Financial Highlights ($MM) Q3 2025 Q4 2025 Q1 2026 Q2 2026 Key Operating Statistics Q3 2025 Q4 2025 Q1 2026 Q2 2026 Oil revenues 911 801 996 1,415 Oil production (MBopd) 155.7 153.0 158.0 165.4 NGL revenues 25 24 38 45 NGL production (MBpd) 55.1 52.4 49.0 53.0 Gas revenues 31 52 116 35 Gas production (MMcfpd) 420.1 404.2 411.4 408.0 Total revenues $967 $877 $1,150 $1,494 Total production (MBoepd) 280.9 272.8 275.6 286.4 Operating Costs Operating Costs (per boe) LOE 249 244 245 268 LOE $9.62 $9.72 $9.87 $10.28 Cash GP&T1 74 71 69 74 Cash GP&T1 2.86 2.82 2.79 2.83 Cash G&A1 17 27 27 21 Cash G&A1 0.64 1.07 1.09 0.81 Production tax 80 69 87 126 Production tax 3.08 2.74 3.50 4.83 Total operating costs $418 $411 $427 $489 Total operating costs $16.19 $16.35 $17.25 $18.75 Realized hedges 20 30 (18) (93) Distributions from investment in affiliate 2 2 2 2 Other 7 8 6 9 Adjusted EBITDA1 $578 $506 $713 $923 Adjusted EBITDA1 per boe $22.35 $20.18 $28.76 $35.42 CapEx2 322 305 342 416 Other Operating Statistics Cash Interest1 18 26 26 26 Gross operated TILs 25 30 37 66 Cash tax paid 7 - 21 67 Net operated TILs 17 27 30 47 Adjusted Free Cash Flow1 $230 $175 $324 $414 NYMEX WTI ($/Bbl) $65.00 $59.14 $72.40 $92.72 Return of Capital NYMEX Henry Hub ($/MMBtu) 3.12 3.57 4.93 2.90 Base dividend 75 74 74 73 Realized oil price 63.59 56.90 70.05 93.99 Share repurchases 83 10 71 147 Realized NGL price 4.89 4.88 8.66 9.25 Total Return of Capital $158 $84 $145 $220 Realized gas price $0.81 $1.40 $3.14 $0.94 Balance Sheet ($MM) Borrowing base $2,750 Elected commitments 2,000 Revolver borrowings - Senior notes 1,500 Total debt 1,500 Cash 612 Liquidity 2,581 Net debt to LTM Adjusted EBITDA 0.3x Letters of credit $30
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Hedge Book Overview1 (1) Hedge book as of 8/3/26. Percentage hedged for all periods based on midpoint FY26 guidance and excludes WTI -Brent basis swaps. 3Q26 4Q26 1Q27 2Q27 3Q27 4Q27 1Q28 2Q28 3Q28 2H26 FY27 FY28 WTI Collars Volume (Bbl/d) 20,000 24,750 9,000 4,000 4,000 - - - - 22,375 4,225 - Floor ($/Bbl) 68.00$ 67.54$ 64.94$ 62.50$ 63.75$ -$ -$ -$ -$ 67.74$ 64.08$ -$ Cap ($/Bbl) 78.35$ 76.09$ 71.49$ 72.18$ 70.10$ -$ -$ -$ -$ 77.10$ 71.32$ -$ WTI 3-Way Collars Volume (Bbl/d) 28,000 18,500 27,000 26,500 21,000 16,000 10,000 5,000 1,000 23,250 22,590 3,981 Sub-floor ($/Bbl) 58.21$ 54.05$ 50.00$ 50.00$ 49.29$ 49.06$ 49.50$ 50.00$ 50.00$ 56.56$ 49.67$ 49.69$ Floor ($/Bbl) 75.18$ 70.54$ 65.19$ 64.91$ 65.00$ 64.30$ 64.93$ 66.00$ 65.00$ 73.33$ 64.90$ 65.27$ Cap ($/Bbl) 89.89$ 82.67$ 78.29$ 78.57$ 78.35$ 77.03$ 77.40$ 80.16$ 79.15$ 87.02$ 78.16$ 78.37$ WTI Fixed Price Swaps Volume (Bbl/d) 20,000 11,000 6,000 2,000 1,000 1,000 - - - 15,500 2,482 - Strike ($/Bbl) 67.85$ 64.94$ 67.58$ 73.82$ 72.45$ 72.45$ -$ -$ -$ 66.82$ 69.82$ -$ WTI-Brent Basis Swaps Volume (Bbl/d) 14,000 14,000 - - - - - - - 14,000 - - Strike ($/Bbl) (5.30)$ (5.58)$ -$ -$ -$ -$ -$ -$ -$ (5.44)$ -$ -$ Henry Hub Collars Volume (MMBtu/d) 35,000 35,000 25,000 25,000 - - - - - 35,000 12,397 - Floor ($/MMBtu) 3.82$ 3.82$ 3.75$ 3.75$ -$ -$ -$ -$ -$ 3.82$ 3.75$ -$ Cap ($/MMBtu) 4.33$ 4.33$ 4.18$ 4.18$ -$ -$ -$ -$ -$ 4.33$ 4.18$ -$ Henry Hub Fixed Price Swaps Volume (MMBtu/d) 80,000 80,000 40,000 40,000 25,000 25,000 10,000 10,000 - 80,000 32,438 4,973 Strike ($/MMBtu) 3.93$ 3.93$ 4.01$ 4.01$ 3.83$ 3.83$ 3.56$ 3.56$ -$ 3.93$ 3.94$ 3.56$ Crude % Volume Hedged 42% 34% 26% 20% 16% 11% 6% 3% 1% 38% 18% 2% Gas % Volume Hedged 28% 28% 16% 16% 6% 6% 2% 2% 0% 28% 11% 1% 27