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3Q26 Results Conference Call NOVEMBER 4, 2026
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2 Disclaimers and Non-GAAP Definitions For convenience, references in this presentation to “Ovintiv”, “OVV”, the “Company”, “we”, “us” and “our” may, where applicable, refer only to or include any relevant direct and indirect subsidiary entities and partnerships (“Subsidiaries”) of Ovintiv Inc., and the assets, activities and initiatives of such Subsidiaries. The terms “include”, “includes”, “including” and “included” are to be construed as if they were immediately followed by the words “without limitation”, except where explicitly stated otherwise. The term “liquids” is used to represent oil, NGLs and condensate. The term “condensate” refers to plant condensate. The conversion of natural gas volumes to barrels of oil equivalent (“BOE”) is on the basis of six thousand cubic feet to one barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be misleading, particularly if used in isolation. There is no certainty that Ovintiv will drill all gross premium well inventory locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves or production. The locations on which Ovintiv will actually drill wells, including the number and timing thereof, is ultimately dependent upon the availability of capital, regulatory and partner approvals, seasonal restrictions, equipment and personnel, oil and natural gas prices, costs, actual drilling results, transportation constraints and other factors. All amounts presented throughout this presentation are on a Net Revenue Interest “NRI” basis and expressed in U.S. dollars, unless otherwise noted. Logan reports production on a Net Before Royalty “NBR” basis and uses Canadian dollars as its reporting currency. Certain measures in this presentation do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other companies and should not be viewed as a substitute for measures reported under U.S. GAAP. These measures are commonly used in the oil and gas industry and/or by Ovintiv to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. For additional information regarding non-GAAP measures, including reconciliations, see the Company’s website, www.ovintiv.com under Financial Document Library, and Ovintiv’s most recent Annual Report on Form 10-K and Quarterly Report on Form 10-Q as filed on EDGAR and SEDAR. This presentation contains references to non-GAAP measures as follows: • Non-GAAP Cash Flow, Non-GAAP Cash Flow Per Share (CFPS), Non-GAAP Free Cash Flow (FCF) and Non-GAAP Free Cash Flow Per Share (FCFPS) are non-GAAP measures. Non-GAAP Cash Flow is defined as cash from (used in) operating activities excluding net change in other assets and liabilities, and net change in non-cash working capital. Non-GAAP CFPS is Non-GAAP Cash Flow divided by the weighted average number of shares of common stock outstanding. Non-GAAP Free Cash Flow is defined as Non-GAAP Cash Flow in excess of capital expenditures, excluding net acquisitions and divestitures. Non-GAAP FCFPS is Non-GAAP Free Cash Flow divided by the weighted average number of shares of common stock outstanding. Forecasted Non-GAAP Cash Flow and Non-GAAP Free Cash Flow assume forecasted Non-GAAP Cash Flow based on price sensitivities of $88 WTI, $3.15 NYMEX and ($1.60) AECO differential. Due to their forward-looking nature, management cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as changes in operating assets and liabilities. Accordingly, Ovintiv is unable to present quantitative reconciliations of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Amounts excluded from these non-GAAP measures in future periods could be significant. • Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents. • Net Debt to Adjusted EBITDA is calculated as Net Debt, divided by Adjusted EBITDA. Adjusted EBITDA is defined as trailing 12-month net earnings (loss) before income taxes, depreciation, depletion and amortization, impairments, accretion of asset retirement obligation, interest, unrealized gains/losses on risk management, foreign exchange gains/losses, gains/losses on divestitures and other gains/losses. Management believes this measure is useful to the Company and its investors as a measure of financial leverage and the Company’s ability to service its debt and other obligations.
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Forward Looking Statements This presentation contains forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation, including Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, except for statements of historical fact, that relate to the anticipated future activities, plans, strategies, objectives or expectations of the Company, including the fourth quarter and fiscal year 2026 guidance and expected free cash flow, the presence and recoverability of estimated reserves, the expectation of delivering sustainable durable returns to shareholders in future years, plans regarding share buybacks and debt reduction, expected credit ratings, 2026 outlook, planned sustainability initiatives, the anticipated success of, and benefits from, technology and innovation, the ability of the Company to meet and maintain certain targets, including with respect to emissions-related and sustainability performance, timing and expectations regarding capital efficiencies and well completion and performance, are forward-looking statements. When used in this presentation, the use of words and phrases including “anticipates,” “believes,” “commit,” “continue,” “could,” “estimates,” “expects,” “focused on,” “forecast,” “framework,” “guidance,” “intends,” “maintain,” “may,” “opportunities,” “on track,” “outlook,” “plans,” “potential,” “strategy,” “targets,” “will,” “would” and other similar terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words or phrases. Readers are cautioned against unduly relying on forward-looking statements which are based on current expectations and by their nature involve numerous assumptions that are subject to both known and unknown risks and uncertainties (many of which are beyond our control) that may cause such statements not to occur, or actual results to differ materially and/or adversely from those expressed or implied. These assumptions include, without limitation: future commodity prices and basis differentials; the Company’s ability to consummate any pending acquisition or divestment transactions (including the acquisition described herein); the Company’s ability to integrate acquired assets and businesses and the timing thereof (including the acquisition described herein); the ability of the Company to access credit facilities, debt and equity markets and other sources of liquidity to fund operations or acquisitions and manage debt; the impact of changes in federal, state, provincial, local and tribal laws, rules and regulations, including the impact of changes in trade policies and tariffs; future foreign exchange rates; data contained in key modeling statistics; the availability of attractive commodity or financial hedges and the enforceability of risk management programs; the Company’s ability to capture and maintain gains in productivity and efficiency; the ability for the Company to generate cash returns and execute on its share buyback plan; expectations of plans, strategies and objectives of the Company, including anticipated production volumes and capital investment; benefits from technology and innovations; expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation and marketing agreements; access to adequate gathering, transportation, processing and storage facilities; assumed tax, royalty and regulatory regimes; the outlook of the oil and natural gas industry generally, including impacts from war and changes to the geopolitical environment; expectations and projections made in light of, and generally consistent with, the Company’s historical experience and its perception of historical industry trends, including with respect to the pace of technological development; and the other assumptions contained herein. Risks and uncertainties that may affect the Company’s financial or operating performance include: market and commodity price volatility, including widening price or basis differentials, and the associated impact to the Company’s stock price, credit rating, financial condition, oil and natural gas reserves and access to liquidity; uncertainties, costs and risks involved in our operations, including hazards and risks incidental to both the drilling and completion of wells and the production, transportation, marketing and sale of oil, condensate, NGL and natural gas; availability of equipment, services, resources and personnel required to perform the Company’s operating activities; service or material cost inflation; our ability to generate sufficient cash flow to meet our obligations and reduce debt; the impact of a pandemic, epidemic or other widespread outbreak of an infectious disease on commodity prices and the Company’s operations; our ability to secure adequate transportation and storage for oil, condensate, NGL and natural gas, as well as access to end markets or physical sales locations; interruptions to oil, condensate, NGL and natural gas production, including potential curtailments of gathering, transportation or refining operations; variability and discretion of the Company’s board of directors to declare and pay dividends, if any; the timing and costs associated with drilling and completing wells, and the construction of well facilities and gathering and transportation pipelines; business interruption, property and casualty losses (including weather related losses) or unexpected technical difficulties and the extent to which insurance covers any such losses; counterparty and credit risk; the actions of members of OPEC and other state-controlled oil companies with respect to oil, condensate, NGLs and natural gas production and the resulting impacts on oil, condensate, NGLs and natural gas prices; the impact of changes in our credit rating and access to liquidity, including costs thereof; changes in political or economic conditions in the United States and Canada, including fluctuations in foreign exchange rates, tariffs, taxes, interest rates and inflation rates; failure to achieve or maintain our cost and efficiency initiatives; risks associated with technology, including electronic, cyber and physical security breaches; changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations thereof; our ability to timely obtain environmental or other necessary government permits or approvals; the Company’s ability to utilize U.S. net operating loss carryforwards and other tax attributes; risks associated with existing and potential lawsuits and regulatory actions made against the Company, including with respect to environmental liabilities and other liabilities that are not adequately covered by an effective indemnity or insurance; risks related to the purported causes and impact of climate change, and the costs therefrom; the impact of disputes arising with our partners, including suspension of certain obligations and inability to dispose of assets or interests in certain arrangements; the Company’s ability to acquire or find additional oil and natural gas reserves; imprecision of oil and natural gas reserves estimates and estimates of recoverable quantities, including the impact to future net revenue estimates; land, legal, regulatory and ownership complexities inherent in the U.S., Canada and other applicable jurisdictions; risks associated with past and future acquisitions or divestitures of oil and natural gas assets, including the receipt of any contingent amounts contemplated in the transaction agreements (such transactions may include third-party capital investments, farm-ins, farm-outs or partnerships); our ability to repurchase the Company’s outstanding shares of common stock, including risks associated with obtaining any necessary stock exchange approvals; the existence of alternative uses for the Company’s cash resources which may be superior to the payment of dividends or effecting repurchases of the Company’s outstanding shares of common stock; risks associated with decommissioning activities, including the timing and cost thereof; risks and uncertainties described in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections of the Company’s most recent Annual Report on Form 10-K and Quarterly Report on Form 10-Q; and other risks and uncertainties impacting the Company’s business as described from time to time in the Company’s filings with the SEC or Canadian securities regulators. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. Although the Company believes the expectations represented by its forward-looking statements are reasonable based on the information available to it as of the date such statements are made, forward-looking statements are only predictions and statements of our current beliefs and there can be no assurance that such expectations will prove to be correct. Unless otherwise stated herein, all statements, including forward-looking statements, contained in this presentation are made as of the date of this presentation and, except as required by law, the Company undertakes no obligation to update publicly, revise or keep current any such statements. The forward-looking statements contained or incorporated by reference in this presentation and all subsequent forward-looking statements attributable to the Company, whether written or oral, are expressly qualified by these cautionary statements. 3
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4 Permian-Montney Powerhouse MONTNEY PERMIAN Best-in-Class Assets Deep inventory in best rock in North America Industry Leading Execution Culture, expertise and data underpin stacked innovation Resilient Business Model Fortified balance sheet, stable portfolio and disciplined capital allocation Superior & Durable Returns
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Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures, see the Company’s website. 1) Net 10k locations. Includes Premium locations, which reflect >35% IRR at $55/ bbl WTI and $2.75/MMBtu NYMEX, and upside locations. 2) Compared against 2026 turn -in-lines normalized to net 10k. Value Creation Across the Business Logan Energy Corp. Acquisition Immediately accretive bolt-on enhances Montney scale, profitability and growth optionality Portfolio-Enhancing 2026 Inventory Additions Post-NuVista ~660 locations1 added for <$1.5 MM/location; replenishes ~2 years2 of drilling inventory Reaffirming Shareholder Returns Plan of 60%+ for 2026 ; 50-100% beyond 2026 69% of FCFŦ returned to shareholders in 3Q26; bought 13.9 MM shares since March 1 (~5% of shares outstanding) $3.4 B of Net DebtŦ at end of 3Q26 & expected <$4 B post Logan close in 1Q27 Balance sheet strength enables opportunistic value creation $680 MM of Free Cash FlowŦ in 3Q26 Best-in-class operations generating superior and durable returns 5
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6 Acquisition of Logan Energy Corp. (TSXV: LGN) Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website.. 1) Premium reflects >35% IRR at $55/ bbl WTI oil and $2.75/MMBtu NYMEX. Inventory depth described herein reflects estimated runway as of today. 2) Assumes ~$27.5K per flowing BOE/d PDP value and current production. 3) Pro-forma estimates and per share metric increases are for FY27E and assume the acquisition closes with a Jan. 1, 2027, effectiv e date and strip pricing as of Oct. 20, 2026: ~$88/ bbl WTI, ~$3.15/MMBtu NYMEX & ~($1.60)/MMBtu AECO basis. 4) Reflects total capacity. 5) Reflects estimated run rates as of 4Q26E, normalized for royalties at $60 -$90/bbl and assuming normal plant operations and run time. Pro Forma OVV Montney5 C$1.40/share | ~$890 MM (C$1.26 B) (including Net DebtŦ) Adds Liquids Rich Scale Unlocks Incremental Profitability Enhances Growth Optionality 420 base premium1 & upside locations ~$1.5 MM2 cost per premium1 location ~$0.8 MM 2 cost per total location 7 Mbbls/d Oil & Condensate realized prices at parity with WTI 5% accretive to CFPS 3 Ŧ 3% accretive to FCFPS 3 Ŧ ~$60 MM annual synergies (~$2 MM per well capex savings) Margin enhancement via infrastructure ownership Immediately competes in the portfolio Spare capacity to grow volumes via infrastructure ownership 50% of Simonette plant (90 MMcf/d 4) 65% of Pouce Coupe plant (57 MMcf/d4) 100% of two new oil batteries (24 Mbbls/d4) ~20 MMcf/d gas price diversification to Chicago starting in ‘29 OVV LGN Pro Forma Net Core Acres (000s) ~520 ~200 ~720 Oil & C5+ (Mbbls/d) ~80-85 ~7 ~90 Natural Gas (MMcf/d) ~1,700-1,800 ~70 ~1,820 Total (Mboe/d) ~400 ~20 ~420 Rigs 6 1 (Jan’27 start) 7
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MONTNEY PERMIAN 7 Added Locations1 ~930 ~$1.3 MM/location ~240 NuVista Energy - Montney February ’26 Close Permian & Montney 50/50 split 2026 Ground Game = ~660 <$1.5 MM/location Core Permian & Montney Adds 2026 post NuVista 1) Net 10k locations. Includes Premium locations, which reflect >35% IRR at $55/ bbl WTI and $2.75/MMBtu NYMEX, and upside locations. 2) Premium reflects >35% IRR at $55/ bbl WTI oil and $2.75/MMBtu NYMEX. Inventory depth described herein reflects estimated runway as of today. 3) Compared against 2026 turn -in-lines normalized to net 10k. ~420 Logan Energy - Montney October ’26 Announced 2 Years3 of drilling inventory replaced post NuVista acquisition Sustaining a Position of Strength Oil 15-20 Years Gas Optionality 20+ Years Maintaining leading premium2 inventory depth Oil 12-15 Years
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8 Private Data Foundational for Stacked Innovation Cube Development Stacking & Spacing Surfactants Wet Sand & Proppant Intensity AI enabled production operations, D&C Private Data Culture Expertise Re-Occupation Strategy Simulfrac & Trimulfrac Stage Architecture Ovintiv’s Private Data Differentiation • High fidelity/private data on ~50% of the approximate 30,000 total horizontal wells drilled in the Midland basin • Built through a decade of strategic data trading, proprietary technology, and operating history • Unique scale and specificity improve innovation outcomes and operational efficiency • Enables differentiated AI applications through training on proprietary datasets • Powers stacked innovations that create a difficult to replicate return moat
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9 3Q26 – Strong Financial Performance Outstanding operational execution complemented by strong realized pricing Net DebtŦ at ~$3.4 B includes $457 MM worth of ground game acquisitions and shareholder returns of $467 MM Oil and Condensate production impacted by higher Canadian royalties from higher commodity prices and prolonged Albright plant outage Guide Actuals Total Production (MBOE/d) 615 – 640 631 Oil & Condensate (Mbbls/d) 205 – 210 204 NGLs (C2-C4) (Mbbls/d) 75 – 80 83 Natural Gas (MMcf/d) 2,000 – 2,100 2,062 Capital ($ MM) $550 - $600 $563 Buybacks (MM shares) 6.3 % Free Cash FlowŦ returned to shareholders 69% $680MM 3Q26 Free Cash FlowŦ $4.51 3Q26 Cash Flow per ShareŦ Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website. $1.99 3Q26 Earnings per Share
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$300 $850 $575 $589 $1,294 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037+ 10 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website. 1) Trailing Twelve Months for period ending September 30, 2026. Balance Sheet Strength Long-Term Debt Maturity Profile ~$3.4B Net DebtŦ at Sep. 30, 2026 ~0.7X Sep. 30, 2026 Net Debt to TTM1 Adjusted EBITDAŦ $3.6 B of Debt due 2030+ Repurchased $109 MM of debt in 3Q26, < 6-month payback No maturities until 2030 Long-term debt reduced $1.6 B (~30%) vs 3Q25 Positive rating outlook revision from S&P $MM <$4B Estimated Net DebtŦ post Logan close in 1Q27 Investment Grade balance sheet improves resiliency and optionality across commodity cycles Comfortable leverage following Permian and Montney ground game adds in 3Q26 Focused on maintaining balance sheet strength post Logan acquisition
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11 4Q26E & FY26E Guidance Generating Superior and Durable Returns • Best-in-class operational execution • Constructive macro storylines • Strong oil and sulfur pricing • Productivity Mega Deduction tax legislation in Canada • Bullish Canadian condensate backdrop • On track for record Free Cash FlowŦ in 2026 FY26E Production Guidance Reaffirmed • Generating ~6% oil & condensate production per share growth1 through 3Q26, on pace for 8-9% by YE26 • No additional activity • New wells continuing to meet or exceed expectations in both assets • Permian base production outperformance • Bought back ~5% of outstanding shares since March 1 FY26E Capital Guidance Reaffirmed • Reallocated $50 MM of capital to Permian from Montney to optimize oil production and cash flow while Albright gas plant is offline 4Q26E2 FY26E Total Production (MBOE/d) 615 – 640 630 – 645 Oil & Condensate (Mbbls/d) 203 – 207 210 – 212 NGLs (C2-C4) (Mbbls/d) 78 – 82 85 – 87 ( from 83 – 85) Natural Gas (MMcf/d) 2,000 – 2,100 2,025 – 2,075 Capital ($ MM) $550 - $600 $2,250 - $2,350 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website 1) Production per share growth compares midpoint of oil and condensate production guidance and shares outstanding as at March 1, 2026 versus midpoint of current oil and condensate production guidance and shares outstanding as at September 30, 2026. 2) Assumes Albright plant down all 4Q26, ~3 Mbbls/d of oil and condensate, and current strip pricing as of October 29, 2026.
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0 2 4 6 8 10 12 14 16 18 0 1 2 3 4 5 6 7 8 9 10 11 12 Cume Oil bbls/ft Months FY25 Actuals (136 wells) 12 Proven Permian Leader 3Q26 Highlights 4Q26E Permian Quarterly Guidance Oil & Condensate (Mbbls/d) 125 - 130 Natural Gas (MMcf/d) 300 – 320 FY26E Permian Guidance Rigs ~5 Frac Crews 1 – 2 Capital ($ MM) $1,375 – $1,425 D&C ($/ft) < $600 Net TILs 130 – 140 Lateral Length (ft) ~13,000 2026A YTD 2026E OVV Type Curve Permian Well Performance 127 Mbbls/d of oil and condensate Strong base and new well performance continuing Drilled fastest 15k ft lateral ever; >2.5k ft/day pacesetter pad Costs controlled despite diesel pressures Surfactant Program Improving Productivity 3650 Avg Surfactant Well Avg Analog Well ~9% ~9% uplift in oil productivity compared to analog wells for only ~$100k/well Pumping surfactants on essentially all new wells in 2026 Cume. Oil bbls / ft Producing Days
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2026E Permian Oil & C5+ Base Production 2026 Latest Estimate Original Expectation 13 Permian Performance - Separating from the Pack Stacked Innovations Driving Productivity Gains Custom surfactant solutions Cube development Re-occupation strategy Stage architecture AI and machine learning Operations Control Center & remote-ops Defying Industry Trend of Well Degradation1 Strong incremental well performance continues Shallowing Base Declines 1) Source: Enverus/TXRRC (10/23/2026) ; vintage based on completion date 2) Midland peer companies include: APA, CVX, COP, CRGY, FANG, OXY, SM, XOM. ~3% outperformance 3Q26 record quarter for artificial lift uptime 0 2 4 6 8 10 12 14 16 18 1 2 3 4 5 6 7 8 9 10 11 12 2026 2025 2024 2023 Midland Peers (2026) Midland Peers (2025) OVV Months Cume. Oil bbls/ft 2 2
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14 Proven Montney Leader 3Q26 Highlights Outstanding execution and new well results Strong realized pricing further bolstered by incremental ~$75 MM earned from sulfur Higher condensate prices benefitting cash flow while pressuring net oil and condensate volumes Production optimization and Albright downtime mitigation efforts underway Annualized Net Long-Term Oil & C5+ Run-Rate Royalty Sensitivities 4Q26E2 Montney Guidance Oil & Condensate (Mbbls/d) 75 – 80 Natural Gas (MMcf/d) 1,700 – 1,800 FY26E Montney Guidance Rigs ~6 Frac Crews 1 – 2 Capital ($ MM) $825 – $875 D&C ($/ft) < $500 Net TILs 120 – 130 Lateral Length (ft) ~11,500 Montney Well Performance ~ 85 ~ 80 ~ 75 $1.0 $2.0 $3.0 $60 $90 $120 WTI Montney Oil & C5+ Volume (Mbbls/d) Montney Oil & C5+ Revenue1 ($B) Revenue1 Growth NRI Volume Decline ~40% ~75% ~6% ~12% 0 2 4 6 8 10 12 14 16 18 0 1 2 3 4 5 6 7 8 9 10 11 12 Higher CGR (Karr) Lower CGR (Cutbank Ridge) Months Cume. Oil bbls / ft 1) Assumes condensate realizations equal to 100% of WTI. 2) Assumes Albright plant down all 4Q26, ~3 Mbbls/d of oil and condensate, and current strip pricing as of October 29, 2026., 85 70 FY25 Actuals 96 wells 2026A YTD 2026E OVV Type Curve
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15 Montney Performance - Separating from the Pack First 100% Domestic Wet Sand Pad in Canada ~20% Sand cost savings versus imported dry 3,050 3,300 3,400 3,400 4,100 4,400 4,800 4,900 2023 2024 2025 2026 YTD Peers Ovintiv Montney Completions Performance (Feet/d) 1 Ramping domestic sand utilization Increasing wet sand capabilities Only operator implementing Simulfrac Basin leading well costs with top-tier well productivity Unique Montney Advantage from Permian Knowledge Transfer 1) Peer data sourced from Geoscout. Peers include ARX, CNQ, CR, HHRS, PIPE, SHEL, SDE, TOU, WCP.
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16 Oil Sands Growth Creates Durable Call on Diluent Supply Potential ~10-Year Call on Condensate Proposed Oil Pipeline Expansions ~1-3MMbbls/d Incremental WCSB Oil Export Capacity Diluent Intensity ~300bbls Approximate Diluent Required for Every 1,000 Barrels of Heavy Oil Shipped 0.3-0.9MMbbls/d Potential Incremental Condensate Required to Meet Oil Sands Expansion 0.5 – 1.5x Current Domestic Production Canadian Condensate Supply ~0.5-0.6 MMbbls/d Domestic Supply ~0.9 MMbbls/d Total Supply Today Southern Lights + Cochin Structurally Short Market Even pipeline expansion at the low end of the proposed range would further tighten an already import- dependent Canadian condensate market Source: Current Canadian market and proposed pipeline expansion data from Enverus. ~0.3–0.9 MMbbls/d Incremental Required Diluent Potential Future Supply Condensate historically prices near parity with WTI Expansions will require a call on condensate supply via premium condensate pricing ~0.3 MMbbls/d Imports
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17 Permian-Montney Powerhouse Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website. MONTNEY PERMIAN Delivering a Standout Year On track for record Free Cash FlowŦ generation Building on a Position of Strength Replenishing inventory at attractive entry points Momentum Continuing to Grow Leading execution performance continues to deliver strong profitability
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Appendix 3Q26 RESULTS
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19 Additional 2026 Guidance 3Q26 Guide 3Q26A 4Q26 Guide PMOT (% of Upstream Product Revenue1) 3.25%-3.75% 2.7% 3.25%-3.75% Upstream T&P2 ($/BOE) $8.75-$9.25 $8.12 $8.75-$9.25 Upstream Opex2 ($/BOE) $3.00-$3.50 $3.43 $3.00-$3.50 Operating Expenses (Quarterly Run-Rate) 3Q26 Guide 3Q26A 4Q26 Guide Corporate G&A3 $70-$75 MM $73 MM $70-$75 MM Less Sublease Revenue ~$19 MM $17 MM ~$17 MM Corp. G&A Less Sublease Rev. 3 $51-$56 MM $56 MM $53-$58 MM Interest Expense on Debt4 $60-$70 MM $62 MM $60-$70 MM Upstream DD&A ($/BOE) $9.25-$9.75 $9.41 $9.25-$9.75 Corporate Items (Quarterly Run-Rate) 3Q26A 2026 Guide Canada $76 MM $130-$150 MM* U.S. $9 MM $15-$25 MM Total OVV $85 MM $145-$175 MM Current Tax Expense (Annual) Current FY26 guidance assumes: • $85/bbl WTI • $3.50/MMBtu NYMEX • ($2.00)/MMBtu AECO basis • 0.72 CAD/USD for FY26E 1) Excludes Gains (Losses) on Risk Management. 2) Excludes activity with no associated volume. 3) Excludes LTIs, restructuring, transaction and legal costs. 4) 3Q26A excludes $3 MM of premiums on open market debt repurchases. *Includes ~$25 MM of estimated ’26 Productivity Mega Deduction tax benefit not yet enacted
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20 Hedge Positions as of September 30, 2026 Natural Gas Hedge Positions1 4Q26 1Q27 2Q27 3Q27 4Q27 NYMEX Fixed Price Swaps Volume MMcf/d Price $/Mcf 20 $4.07 0 - 0 - 0 - 0 - NYMEX 3-Way Options Volume MMcf/d Call Strike $/Mcf Put Strike $/Mcf Sold Put Strike $/Mcf 450 $5.92 $3.33 $2.58 300 $5.04 $3.50 $2.50 200 $4.49 $3.50 $2.50 200 $4.49 $3.50 $2.50 200 $4.49 $3.50 $2.50 NYMEX Collars Volume MMcf/d Call Strike $/Mcf Put Strike $/Mcf 95 $5.27 $3.75 15 $4.72 $3.50 15 $4.72 $3.50 15 $4.72 $3.50 15 $4.72 $3.50 AECO Nominal Basis Swaps Volume MMcf/d Price $/Mcf 338 ($1.25) 260 ($1.17) 260 ($1.17) 260 ($1.17) 260 ($1.17) AECO Fixed Price Swaps Volume MMcf/d Price $/Mcf 118 $2.30 100 $2.00 219 $1.78 219 $1.78 106 $2.00 AECO Collars Volume MMcf/d Call Strike $/Mcf Put Strike $/Mcf 3 $2.18 $1.72 0 - - 0 - - 13 $2.40 $1.79 20 $2.40 $1.79 Waha Nominal Basis Swaps Volume MMcf/d Price $/Mcf 50 ($1.98) 50 ($1.19) 50 ($1.41) 0 - 0 - Waha Fixed Price Swaps Volume MMcf/d Price $/Mcf 50 $1.77 0 - 0 - 0 - 0 - NuVista Cash Flow Deduction ($MM)2 $24 $16 $8 $12 $10 Oil & Condensate Hedge Positions1 4Q26 1Q27 2Q27 3Q27 4Q27 WTI Fixed Price Swaps Volume Mbbls/d Price $/bbl 4 $61.58 0 - 0 - 0 - 0 - WTI 3-Way Options Volume Mbbls/d Call Strike $/bbl Put Strike $/bbl Sold Put Strike $/bbl 41 $70.23 $57.25 $50.13 40 $85.56 $59.34 $50.00 30 $101.56 $61.67 $50.00 18 $101.03 $60.00 $50.00 0 - - - Note: Volumes are converted to Mcf at 1:1 ratio from MMBtu 1) OVV also manages other key market basis differential risks for gas, oil & condensate. The table excludes 1 Mbbls/d of WTI costless collars for 2026 with strike prices of $57.30 -$68.97/bbl. Includes certain WTI and AECO hedges executed in Canadian dollars and converted to US dollars at the period end exchange rate. 2) NuVista’s financial hedge position at close of the acquisition was valued at ~$199 MM. Those gains are booked as assets and realized into cash over time as they are settled but are not included in Non- GAAP Cash Flow.
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21 2026 Sensitivities 4Q26E Sensitivity Upstream T&P F/X Rate (CAD/USD) ~0.72 +/- 0.01 CAD/USD $0.10/BOE WTI ($/bbl) ~$85 +/- $10/bbl $0.10/BOE NYMEX ($/MMBtu) ~$3.50 +/- $0.25/MMBtu $0.10/BOE Upstream T&P Sensitivities 4Q26E Oil Price Free Cash FlowŦ Sensitivities1 WTI ($/bbl) Change vs. $85/bbl (assuming $3.50/MMBtu) $65 (~$300) MM $75 (~$140) MM $85 - $95 ~$140 MM $105 ~$280 MM 4Q26E Gas Price Free Cash FlowŦ Sensitivities1 NYMEX ($/MMBtu) Change vs. $3.50/MMBtu (assuming $85/bbl) $3.00 (~$25) MM $3.25 (~$15) MM $3.50 - $3.75 ~$15 MM $4.00 ~$30 MM Sensitivity Change F/X Rate (CAD/USD) +/- 0.01 CAD/USD ~$10 MM 4Q26E CAD/USD Free Cash FlowŦ Sensitivity1 WTI Oil $60 $70 $80 $90 $100 $110 4Q26 4 (1) (42) (83) (124) (166) 1Q27 - - (20) (43) (67) (93) 2Q27 5 - - - (8) (25) 3Q27 - - - - (3) (15) 4Q27 - - - - - - WTI & NYMEX Realized Gain / (Loss) Sensitivities ($ MM)2 NYMEX Gas $2.25 $2.75 $3.25 $3.75 $4.25 $4.75 4Q26 48 33 9 2 - (1) 1Q27 29 21 7 - - (5) 2Q27 20 15 5 - - (5) 3Q27 20 15 5 - - (5) 4Q27 20 15 5 - - (5) Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website. 1) Includes the impact of hedges through September 30, 2026, and taxes. 2) Sensitivities do not include impact of other hedge contract positions and are reflected before -tax. Includes hedges executed through Sep. 30, 2026.
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22 Diversification Enhances Montney Gas Prices MMcf/d 4Q26 2027 2028 2029+ Dawn 390 400 400 400 Chicago 325 330 330 330 Malin 150 150 150 150 Sumas 20 20 20 20 Emerson 15 20 20 20 Cedar LNG1 0 0 10 70 OVV AECO Price Mitigation Total Firm Transport 900 920 930 990 JKM Linked2 100 120 90 90 Chicago Linked2 0 20 100 100 Ventura 10 20 20 20 Enhanced AECO 75 75 0 0 Total Ex-AECO Physical Sales 185 235 210 210 Total AECO Hedges3 460 430 450 250 Total AECO Mitigation 1,545 1,585 1,590 1,450 ~20% Percentage of JKM received on 100 MMcf/d for 2026-20274 ~$170MM Estimated hedge gain on JKM contracts thru 2027, includes ~$40 MM in 4Q26 <20% 2026E Montney Gas Production Exposed to AECO OVV AECO Price Mitigation 0% 50% 100% 150% 200% 250% 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 3Q26 100% of AECO 231 % Of AECO in 3Q26 $1.44/Mcf Premium to AECO in 3Q26 Note: Montney firm transport values are calculated from AECO. Transport volumes represent Transport Receipt Volume and are conve rted to Mcf at 1:1 ratio from MMBtu and rounded to the nearest 5 MMcf/d for presentation purposes. 1) Assumes Nov. 2028 start up date. 2) Derivative contracts and do not impact pre -hedge realized pricing. 3) Hedges as of Sep. 30, 2026. 4) Difference from AECO recorded as hedge gain/loss; expected hedge gain based on strip pricing as of October 29, 2026. 5) Less deduction for transportation, liquefaction, fuel, and indicative AECO basis to NYMEX. Downstream markets consistently outperform AECO and trade above NYMEX seasonally ~93% ~Percentage of JKM received on 20 MMcf/d for 20275
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23 Reaffirming Shareholder Returns Active 2026 buyback program continues • Meaningful gap to intrinsic value remains, even with strong YTD performance • Returned 69% of FCFŦ to shareholders in 3Q26 Framework designed to enable flexibility through the commodity cycle • With significant FCFŦ, undervalued shares and resilient balance sheet, keeping returns 60%+ for ’26, consistent with prior quarter • Continue to direct some incremental FCFŦ to opportunistic ground game inventory additions Framework enhances investor returns while avoiding pro-cyclical behavior Annual Free Cash FlowŦ to shareholders via base dividend & share buybacks 50% 100% 75%+ 75%+ Original Plan / ~$60WTI Current Macro Environment Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures, see the Company’s website. Targeting 60%+ of annualized ’26 FCFŦ
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24 Focused in the Top North American Oil Basins Permian (Midland & Delaware) Montney Eagle Ford Bakken Uinta Anadarko Powder DJ Undeveloped bbls Remaining Undrilled Resource (Ovintiv Internal North American Resource Assessment) 80% of remaining sub-$50/bbl breakeven oil locations in North America are in the Permian & Montney (Enverus, PV10 breakeven at 20:1 conversion) The Permian & Montney are the two largest remaining oil resource basins in North America
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25 Inventory Depth Supports Durable Returns Ovintiv’s Permian Assets Ovintiv’s Montney Assets ~205 k Net Permian Acres ~12-15 years of Premium1 oil inventory ~720 k Net Core Montney Acres ~15-20 years of Premium1 oil inventory >20 years of Premium1 Natural Gas inventory1) Premium reflects >35% IRR at $55/ bbl WTI oil and $2.75/MMBtu NYMEX. Inventory depth described herein reflects estimated runway as of today. Martin Midland Andrews Ector Crane Upton Reagan Glasscock Howard Gaines Dawson Borden British Columbia Alberta Dawson Creek Grande Prairie Cutbank Ridge Pipestone Wapiti Karr Simonette Pouce Coupe Flatrock OVV Montney Logan Montney Logan Duvernay Ft St John
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0% 20% 40% 60% 80% 10 0% 120% 14 0% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 0% 20% 40% 60% 80% 10 0% 120% 14 0% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 Ovintiv’s Approach Alternative Approach Risk that future child wells are no longer economic 26 Cube Development Supports Inventory Duration Cube Development Ovintiv established cube development in 2015 – simultaneous co- development of multiple stacked zones in a single development window Reoccupation Strategy • Drill adjacent cube in ~18-24 months • Optimizes spacing and timing between development windows • Dominant driver of Ovintiv development planning Sampling IRR Creaming Curve • Drilling wells across full rate-of-return creaming curve vs. cherry-picking highest short-term return locations Drives Durable Returns Preserves inventory quality and longevity Improves resource recovery Maximizes NPV and capital efficiency Consistent and repeatable programs >10% Improvement in OVV Permian Oil Productivity per Foot 2022-25A -2%/yr Avg. Permian Oil Productivity per Foot Decline 2022-24A vs. Industry Average1Ovintiv Drilled wells within a cube (illustrative) 1) Source: Enverus
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27 Canadian Royalty Sensitivity Royalty rates vary based on commodity prices • OVV Reports “NRI” volumes after royalties across its U.S. and Canadian assets • Changes in royalty rates seen in changes to reported net production Observed Montney rates at or below U.S. basins • U.S. royalties are traditionally a “fixed” percentage • Even in a “high” scenario Montney royalties screen in-line with U.S. basins Government incentive programs exist to lower realized royalties • Upfront & early life royalty incentives derived from development costs 6 – 8% 13 – 15% U.S. Basin Average (20 – 25%) 24 – 26% WTI / Condensate $55 / $54 $70 / $69 $90 / $89 $135 / $134 NYMEX / AECO $2.75 / $2.15 $5.00 / $4.00 $6.25 / $5.00 $9.00 / $7.00 MAX Effective Royalties 19 – 21% Royalty Sensitivity1 Note: Royalty calculations assume AECO benchmark prices of approximately 80% of NYMEX. Royalties reflect “Net Effective Roya lties to OVV” after incentives. 1) Total BOE Production.
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28 Track Record of Responsible Operations DJ BIC TCFD SASB >20 Years Top Quartile Added to Dow Jones Best in Class North American Index for sustainability Reporting aligned with Task Force on Climate-related Financial Disclosure (TCFD) Utilizing Sustainability Accounting Standards Board (SASB) guidance Of transparent sustainability reporting Safety performance among peers2 Scope 1&2 GHG intensity reduction target Committed ~$13 MM to children’s hospitals to make a positive difference in our communities Donated ~$11.6 MM over five years to ~1,000 charities through matched giving by Ovintiv and its employees Dedicated to our communities Achieved >85% of our 2030 goal as of YE25 Tied to compensation for all employees 50% Intensity Reduction1 (from ’19 – ’30) Note: the data utilized in calculating reduction metrics is subject to certain reporting rules, regulatory reviews, definitio ns, calculation methodologies, adjustments and other factors. Such factors may change over time, which could result in significant revisions to our reduction metrics, targets, goals, reported progress in achieving such targets or goals, or ability to achieve such targets or goals in the future. 1) Measured in Tons CO2e / MBOE. 2) Based on AXPC membership. OVV has been in the top quartile every year since 2021.