Slides
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Lengthening Laterals, Lowering Breakevens, Growing FCF Per Share November 4, 2026
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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, production levels, anticipated financial and operating results, other guidance, and the effects and anticipated benefits of the Marcellus divestiture. 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, the ability to complete or realize the anticipated benefits from the Marcellus divestiture, 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, including as a result of conflicts, 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 without unreasonable efforts. 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 Chord 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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3 Largest Williston Operator, Driving Strong Returns Williston Basin Acreage (1) Pro Forma for Marcellus divestiture; oil cut reflects latest guidance for peers (APA, CRGY , DVN, EOG, FANG, MTDR, MUR, NOG, OVV, OXY , PR, SM); (2) Management estimate based on normalized activity pace; (3) CHRD net leverage as of 9/30/26 using LTM EBITDA, excludes remaining Marcellus proceeds; (4) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap. (5) See slide 9 for details; (6) Fully-diluted shares outstanding, YE23 pro- forma for Enerplus >1.3MM net acres, basin's largest ~260 MBoepd FY26 production1 62% oil, industry leading1 10+ yrs low-breakeven inventory2 ~0.2x net leverage at 3Q263,4 $5.20 base dividend per share Growing free cash flow4 ~35% FCF4 per share growth, FY24 to FY265 • Inventory breakeven down >10% Y/Y • $225MM run-rate cost savings • Low base declines and reinvestment rate • Maintenance plus capital program Returning capital / Strong balance sheet 17% Share count reduction since YE236 • Target ROC 75%+ FCF4 at <0.5x leverage4 • Buybacks favored • $2.8B liquidity, undrawn revolver • Ba1 / BB, no near-term maturities
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Strong Cash Flow and Capital Discipline, Focused on Shareholder Returns 4(1) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap; (2) As of 10/30/26; (3) FY21 reflects OAS standalone and excludes Permian Basin production; (4) CHRD net leverage as of 9/30/26 using LTM EBITDA, excludes remaining Marcellus proceeds (5) RBL tenor extended to 2031 Attractive E&P Investments >10% lower inventory breakeven, YE25 vs YE24 • Proven 3-mile and 4-mile development / conservative spacing • Basin-leading rig and frac performance • Lower oil decline rate vs peers • Continued innovation Strong Return of Capital 75%+ return of capital targeted at net leverage 1 <0.5x • $5.20/share annual base dividend (3.3% yield2) • $205MM of buybacks in 3Q26 • Avoid pro-cyclical buying Opportunistic M&A +380% oil volume growth since 20213 • Disciplined approach • Five Williston deals since 2021 • >1.3MM net acres • Significant synergy capture Balance Sheet Management ~0.2x net leverage at 3Q261,4 • Net debt of $0.7B1,4 • No revolver borrowings; $2B elected commitments5 • Improving credit ratings Capital allocation focus delivers strong returns through cycles
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222 155 149 126 109 88 71 43 39 141.5 162.5 FY22 FY26E 6.0 ~4.5 FY22 FY26E 1.9 ~1.5 FY22 FY26E 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 10/28/26. Reflects Jan-Aug 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% +15%
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Run-Rate Savings More Than Doubled to $225MM in 15 Months 6 Annual run-rate savings from continuous improvement, $MM Operated D&C • 4-mile laterals • Refined spacing and well design • Faster D&C cycle times • Facility scale and efficiency Production Operations • Base optimization • AI-driven efficiency • Optimized production tax Marketing • Midstream renegotiations: oil, gas, water • Marketing optimization • Select midstream investments $225MM annual run-rate savings, ~14% of 2026E FCF1 $100MM $160MM $225MM Aug '25 YE25 Nov '26 +125% (1) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap.
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Jan 2025 Jul 2025 Jan 2026 Jul 2026 Bopd Volumes Original Outlook Aug '26 Update Base Production Investment Outperforming Original Outlook 7 Base Production Represents a Sizable Opportunity • Largest producer in the Williston with the 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 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 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, improve mobility – Combo treatments: remove scale, paraffins, polymers, biofilm (1) .Subset of well population targeted for optimization Potential upside largely not factored into latest volume outlook Evaluation expected to complete in early 2027
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65MM 61MM 54MM YE23 YE24 3Q26 Buybacks Have Reduced Share Count 17% Since YE23 8(1) Reflects fully-diluted shares outstanding, including dilutive effect of outstanding warrants as applicable; YE23 & See slide 9 for details; (3) FY24 pro-forma for Enerplus; (2) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap; -17% Fully Diluted Shares1 Reduction since YE23 +10% Oil Growth per Share CAGR since 20212 +24% Base Dividend CAGR since Feb-21 Delivering Strong Shareholder ReturnsTrack Record of Share Buybacks1 • ~11MM shares retired since YE23 • Buybacks preferred in current environment ~35% FCF3 Growth per Share Since FY242 -17%
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0.65 0.79 0.84 0.92 1.00 1.05 2021 2022 2023 2024 2025 2026 Oil Per Share Up ~10% Annually, FCF1 Per Share Up ~35% Since 2024 Strong Capital Allocation • Maximizing efficient FCF1 generation • Counter-cyclical share repurchases • Disciplined M&A Operational Excellence • Reducing controllable costs • Improving efficiencies • Leveraging new technologies Shareholder Returns • 17% share reduction since YE234 • $5.20/share base dividend annually Financial Strength • Maintained strong balance sheet Adjusted Free Cash Flow1 Per Share3 9 Oil Production Per Share (Bo/sh)2 (1) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap; (2) Calculated as oil production / wtd. avg. diluted shares outstanding; (3) FY24 reflect actuals pro-forma for Enerplus and exclude Marcellus. FY26 reflects Nov. ’26 midpoint guidance and exclude Marcellus. Reflects flat pricing ($75/$3), oil differentials & cash taxes normalized in both periods; (4) Pro-forma for Enerplus, see slide 8 for details. ~10% CAGR $16.30 $22.00 2024 2026E ~35%
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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 Capital Efficiency Ranks Top 3 Among Peers 10(1) Peer capital efficiency calculated as consensus FY27E Capex / FY27E wedge production (27E consensus production less base production), based off 4Q26E consensus and Enverus published decline rates. Chord assumes latest guidance (FY26 162.5MBopd and $1.41B in E&P capital). 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. Program Capital Efficiency vs. Peers1 CapEx per Bopd of wedge production, 2027E Reducing Capital, Increasing Production2 • ~10 MBopd more oil on lower capital vs. 2024 ~$1.50B $1.41B 2024 2026E 153.0 162.5 2024 2026E +6% CapEx (ex Midstream) Oil Production, MBopd -6% Chord Peers
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2.9 5.5 2023 2026¹ Lateral Length per day (000s) Improving Capital Productivity 11 Operational efficiencies1 • Average lateral length +34% since 2023 • Frac completed lateral length per day up 90% since 2023 (1) Reflects CHRD 2026 data through 3Q26 (2) Future F&D calculated as future development costs / PUD reserves. 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% +90% 12.5 16.7 2023 2026¹ Lateral Length (000s) Average Lateral Length Frac Efficiency +34%
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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 Program D&C cost per foot Average lateral length Bakken/Chord Uniquely Positioned for Long-Laterals 12 Industry Leader in Long-Lateral Development2 (1) 2026 $/ft Based on Feb 2026 guidance; 2026 Lat Length based on average through 3Q26; (2) Source: Enverus 2026 Rig Releases through 3Q26; Peers include APA, CRGY , DVN, EOG, FANG, MGY , MTDR, MUR, OVV, PR, SM 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 Significant Improvement in Program D&C $/ft1 -37% Bakken / Chord Favorable Long-Lateral Positioning2 Chord 0 5 10 15 20Lateral Length (000s)0 5 10 15 20 Chord Bakken (excl CHRD) Midland Uinta DJ Eagle Ford Delaware Lateral Length (000s) Peers
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4-Mile Highlights • ~50% of long-term inventory2 • Improves inventory quality organically • Lowers breakevens, extends inventory life • 59 drilled, 47 TIL’d to date3 – D&C execution and early performance meeting expectations – Cleanouts consistently reaching total depth – Pad drilling & trimulfrac supporting efficiencies 4-Mile Laterals Scale to ~40% of 2026 TILs at Lower Breakevens 13 3-Mile 4-Mile (Base Case) 4-Mile (Upside Case) Superior returns on long-lateral development +90–100% EUR1 $8–$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 $8-$10/Bbl (1) Compared to 2-mile analog; (2) Net 10K’ equivalent operated locations; (3) As of 3Q26.
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Enhancing Economics With Long-Laterals 14 2-Mile 3-Mile 4-Mile 2-Mile vs 3-Mile 2-Mile vs 4-Mile CapEx Well Cost ($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 15
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Oasis / Whiting • Closed 3Q22 • ~23MM shares • ~$245MM cash Disciplined M&A Track Record 16 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 pure-play • 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 ~5x, maintained strong balance sheet (1) FY21 reflects OAS standalone and excludes Permian Basin production. FY26 reflects midpoint of November guidance; (2) CHRD net leverage as of 9/30/26 using LTM EBITDA, excludes remaining Marcellus proceeds (3) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap. Permian Basin • Closed 2Q21 • $480MM cash AcquisitionsDivestitures 2026 Marcellus Non-Op • Expected close 4Q26 • $550MM cash 34.1 MBopd 162.5 MBopd 0.4x 0.2x 2021 2026 Oil Production Net Leverage³
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2027 2028 2029 2030 2031 2032 2033 17(1) CHRD net leverage as of 9/30/26 using LTM EBITDA or ‘27E EBITDA, excludes remaining Marcellus proceeds; (2) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap; (3) Based on NTM EBITDA at midpoint guidance at $65 WTI/$3 HH, ex-hedges; (4) Calculated as of 9/30/26, $2B elected commitment less $30.3MM letters of credit plus $805MM of cash. Excludes remaining Marcellus proceeds; (5) Reflects ’27E net leverage. Peer debt levels estimated from FactSet as of 10/28/26 with adjustments made for pending M&A. Peers include APA, CRGY , MGY , MTDR, OVV, PR, SM. Robust Liquidity • $2.75B borrowing base/$2B ECA • Revolver maturity Oct. 2031 • No revolver borrowings at 3Q26 • Cash balance of $805MM at 3Q26 • $2.8B of liquidity at 3Q264 Strong Credit Profile • Moody’s Ba1 • S&P BB • No near-term debt maturities Low Leverage • ~0.2x leverage1,2 • Target sub-1x in normalized price environment3 • Financial strength supports org. resiliency • Provides optionality for strategic actions Debt Maturities and Balances • No near-term debt maturities Peer Leading Balance Sheet1,5 Net leverage2 $750MM 6.75% $750MM 6.00% $2B ECA, undrawn Peer Leading Balance Sheet Supports Organization Resiliency 0.2x 0.9x Peers
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3.1x 3.7x 4.5x Peers XOP Long-Term Outperformance, Attractive Valuation 18(1) Source: FactSet total return 12/31/20 – 10/27/26; peers include APA, MGY , MTDR, OVV, SM. (2) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap. (3) Source: FactSet as of 10/27/26; EBITDA reflects FY27 consensus estimates with adjustments made for pending M&A; peers include APA, MGY , MTDR, OVV, SM. (4) Management estimate based on normalized activity pace. Total Shareholder Return1 • Strong capital allocation / execution track record • Sustainable free cash flow2 generation EV / EBITDA2 Multiple3 • High-quality assets at attractive valuation vs peers • 10+ yrs of low-breakeven inventory4 High-quality oil-focused assets trading at an attractive valuation vs. peers 576% 429% 290% 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 with 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 • Strong oil leverage (>90% of revenue) 19 (1) Net 10K’ equivalent operated locations. Chord Energy: The Premier Williston Basin Operator
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Supplementary Information
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21 Williston Basin Gas Takeaway Bison Xpress • ~0.3 Bcf/d • In-service 2027 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 $65-$105MM Adj. FCF1 savings 2026+ Williston Basin Oil Takeaway2 (1) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap; (2) 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 • Expected $65-$105MM annual Adj. FCF1 savings 2026+ o Ramps up over next several years • Numerous agreements executed in 2025 & 2026 o Crude, gas, water • Opportunity to drive further optimization
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Return of Capital 22 3Q26 Return of Capital ($MM) 3 (1) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap; (2) Net debt to NTM EBITDA at $65/$3 on 9/30/26 was <0.5x; (3) Amounts rounded to nearest million; (4) excludes $4.5MM of reimbursable non-op CapEx and $6MM of reimbursable Marcellus CapEx that exceeded expectations; (5) As of 10/30/2026 Return of capital framework Target return of capital (RoC) is set at quarter-end from forward leverage, as a share of adjusted FCF1 less acquisition / leasehold CapEx Forward leverage1,2 Target RoC Below 0.5x (current) 75%+ Below 1.0x 50%+ Above 1.0x Base dividend+ ($5.20/share annual) Calculation • Base dividend is subtracted from target RoC; the remainder goes to share repurchases • Repurchase cadence may taper at higher oil prices to avoid pro-cyclical buybacks • No variable dividend expected in the current environment; balance of FCF goes to the balance sheet • Dividends are declared with earnings and paid the following quarter (3Q26 base dividend paid 4Q26) • Leverage = quarter-end net debt (debt less cash) ÷ next-twelve-month EBITDA at $65 WTI / $3 HH, excluding hedges Base dividend $71MM $1.30/share quarterly Share repurchases $205MM Additional $78MM in 4Q26 to date5 Variable dividend $0 None this quarter Dividend $71MM Buybacks $205MM $442MM -$4MM -$276MM $162MM -$78MM Adjusted FCF¹,⁴ Acquisitions CapEx Return of capital Balance Sheet 4Q26 buybacks to date⁵
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Guidance Highlights • FY26 oil volumes increased to 162.5 MBopd (~1%) • 4Q26 oil volumes increased to 161.0 MBopd at midpoint (~2%) • FY26 CapEx $1.46B at midpoint • FY26 includes ~$50MM of midstream (up from $30MM from Feb) • 4Q26 $330MM at midpoint 2026 Outlook Updated in November Development Highlights • 4 – 5 rigs, 1 – 2 frac crews • 149 – 155 gross operated TILs, ~75% WI • ~80% long-lateral 2026 Guidance Ranges FY26 23 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) 4Q26 & FY26 reflects $70/Bbl - $100/Bbl WTI. 4Q26 Oil volumes (MBopd) 159.5 - 162.5 162.0 - 163.0 NGL volumes (MBblpd) 53.0 - 55.0 52.5 - 53.0 Natural gas volumes (MMcfpd) 351.0 - 359.0 398.0 - 400.0 Total volumes (MBoepd) 271.0 - 277.3 280.9 - 282.7 CapEx ($MM) $305 - $355 $1,435 - $1,485 Oil Premium/(Discount) to WTI ($/Bbl) $0.50 - $1.50 $(0.09) - $0.16 NGL realization (% of WTI) 15% - 25% 13% - 15% Natural gas realization (% of Henry Hub) 30% - 40% 41% - 43% LOE ($/Boe) $10.50 - $11.50 $10.31 - $10.55 Cash GPT ($/Boe)1 $2.40 - $2.80 $2.70 - $2.80 Cash G&A ($MM)1 $25 - $29 $99 - $103 Production taxes (% of oil, NGL and gas sales) 8.0% - 8.4% 8.1% - 8.2% Cash Interest ($MM) 1 $25 - $27 $103 - $105 Cash taxes (% of Adjusted EBITDA) 2 5% - 11% 5% - 6%
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Strong FCF1 Generation 24(1) Non-GAAP financial measure. A reconciliation to the most comparable GAAP measure can be found at https://ir.chordenergy.com/non-gaap. (2) EBITDA and FCF reflect FY26 midpoint guidance (1Q26 – 3Q26 actuals & 4Q26 pricing of $90 WTI/$3.00 Henry Hub) Sources & Uses, FY26E2 ~$3.4B EBITDA1: cash generation ~$1.46B CapEx: Investment in Business ~90% to Op / Non-Op D&C • Flat+ organic growth • Delivering strong returns • Low reinvestment rate ~$1.6B Adjusted FCF1 Return of capital, cash to balance sheet, acquisitions / leasehold • ROC framework governs distributions • Preference for buybacks, while avoiding pro-cyclical buying
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Chord Financial and Operational Results 25 Numbers in the table may not add due to rounding. (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) 4Q25, 1Q26, and 2Q26 exclude $8.0MM, $3.0MM, and $0.7MM of reimbursable non-op CapEx, respectively. 3Q26 excludes $4.5MM of reimbursable non-op CapEx and $6MM of reimbursable Marcellus CapEx that exceeded expectations. Financial Highlights ($MM) Q4 2025 Q1 2026 Q2 2026 Q3 2026 Key Operating Statistics Q4 2025 Q1 2026 Q2 2026 Q3 2026 Oil revenues 801 996 1,415 1,307 Oil production (MBopd) 153.0 158.0 165.4 165.5 NGL revenues 24 38 45 61 NGL production (MBpd) 52.4 49.0 53.0 55.1 Gas revenues 52 116 35 41 Gas production (MMcfpd) 404.2 411.4 408.0 420.6 Total revenues $877 $1,150 $1,494 $1,408 Total production (MBoepd) 272.8 275.6 286.4 290.8 Operating Costs Operating Costs (per boe) LOE 244 245 268 282 LOE $9.72 $9.87 $10.28 $10.56 Cash GP&T1 71 69 74 74 Cash GP&T1 $2.82 $2.79 $2.83 $2.77 Cash G&A1 27 27 21 26 Cash G&A1 $1.07 $1.09 $0.81 $0.95 Production tax 69 87 126 116 Production tax $2.74 $3.50 $4.83 $4.33 Total operating costs $411 $427 $489 $498 Total operating costs $16.35 $17.25 $18.75 $18.62 Realized hedges 30 (18) (93) (49) Distributions from investment in equity securities 2 2 2 2 Other 8 6 9 7 Adjusted EBITDA1 $506 $713 $923 $871 Adjusted EBITDA1 per boe $20.18 $28.76 $35.42 $32.57 CapEx2 305 342 416 371 Other Operating Statistics Cash Interest1 26 26 26 26 Gross operated TILs 30 37 66 28 Cash tax paid - 21 67 32 Net operated TILs 27 30 47 21 Adjusted Free Cash Flow1 $175 $324 $414 $442 NYMEX WTI ($/Bbl) $59.14 $72.40 $92.72 $85.69 Return of Capital NYMEX Henry Hub ($/MMBtu) 3.57 4.93 2.90 2.96 Base dividend 74 74 73 71 Realized oil price 56.90 70.05 93.99 85.80 Share repurchases 10 71 147 205 Realized NGL price 4.88 8.66 9.25 11.92 Variable dividend - - - - Realized gas price $1.40 $3.14 $0.94 $1.07 Total Return of Capital $84 $145 $220 $276 Balance Sheet ($MM) Borrowing base $2,750 Elected commitments 2,000 Revolver borrowings - Senior notes 1,500 Total debt 1,500 Cash 805 Liquidity 2,774 Net debt to LTM Adjusted EBITDA1 0.2x Letters of credit $30
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Hedge Book Overview1 (1) Hedge book as of 10/30/26. Percentage hedged for all periods based on midpoint FY26 guidance, pro forma for Marcellus div estiture, and excludes WTI-Brent basis swaps. 26 4Q26 1Q27 2Q27 3Q27 4Q27 1Q28 2Q28 3Q28 4Q28 4Q26 FY27 FY28 WTI Collars Volume (Bbl/d) 48,750 38,000 28,000 18,000 7,000 - - - - 48,750 22,652 - Floor ($/Bbl) $75.61 $78.55 $76.51 $72.38 $75.95 - - - - $75.61 $76.48 - Cap ($/Bbl) $83.88 $85.75 $84.23 $79.68 $83.53 - - - - $83.88 $83.90 - WTI 3-Way Collars Volume (Bbl/d) 18,500 27,000 26,500 22,000 24,000 20,000 13,000 6,000 1,000 18,500 24,859 9,964 Sub-floor ($/Bbl) 54.05$ 50.00$ 50.00$ 49.55$ 51.04$ 52.25$ 53.08$ 54.17$ 55.00$ $54.05 $50.15 $52.88 Floor ($/Bbl) 70.54$ 65.19$ 64.91$ 65.27$ 66.88$ 68.37$ 69.47$ 71.19$ 76.25$ $70.54 $65.54 $69.35 Cap ($/Bbl) 82.67$ 78.29$ 78.57$ 78.38$ 78.07$ 78.60$ 79.76$ 80.24$ 83.90$ $82.67 $78.33 $79.36 WTI Fixed Price Swaps Volume (Bbl/d) 11,000 6,000 2,000 1,000 1,000 - - - - 11,000 2,482 - Strike ($/Bbl) 64.94$ 67.58$ 73.82$ 72.45$ 72.45$ - - - - $64.94 $69.82 - WTI-Brent Basis Swaps Volume (Bbl/d) 14,000 - - - - - - - - 14,000 - - Strike ($/Bbl) (5.58)$ - - - - - - - - ($5.58) - - Henry Hub Collars Volume (MMBtu/d) 35,000 25,000 25,000 - - - - - - 35,000 12,397 - Floor ($/MMBtu) 3.82$ 3.75$ 3.75$ - - - - - - $3.82 $3.75 - Cap ($/MMBtu) 4.33$ 4.18$ 4.18$ - - - - - - $4.33 $4.18 - Henry Hub Fixed Price Swaps Volume (MMBtu/d) 80,000 40,000 40,000 25,000 25,000 10,000 10,000 - - 80,000 32,438 4,973 Strike ($/MMBtu) 3.93$ 4.01$ 4.01$ 3.83$ 3.83$ 3.56$ 3.56$ - - $3.93 $3.94 $3.56 Crude % Volume Hedged 48% 44% 35% 25% 20% 12% 8% 4% 1% 48% 31% 6% Gas % Volume Hedged 40% 22% 22% 9% 9% 3% 3% - - 40% 15% 2%