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1 Acquiring NuVista Energy & 3Q25 Results November 4, 2025
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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. NuVista 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 and Non-GAAP Cash Flow per Share 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 Cash Flow per Share is Non-GAAP Cash Flow divided by the weighted average number of shares of common stock outstanding. • Non-GAAP Free Cash Flow and Non-GAAP Free Cash Flow per Share are non-GAAP measures. Non-GAAP Free Cash Flow is defined as Non-GAAP Cash Flow in excess of capital expenditures, excluding net acquisitions and divestitures. Non-GAAP Free Cash Flow per Share is defined as Non-GAAP Free Cash Flow divided by the weighted average number of shares of common stock outstanding. Forecasted Non-GAAP Free Cash Flow assumes forecasted Non-GAAP Cash Flow based on price sensitivity of $60 WTI, $4.00 NYMEX and ($1.70) AECO differential. The scenario utilizes the midpoint of the production and capital guidance. Due to its forward-looking nature, management cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measure, such as changes in operating assets and liabilities. Accordingly, Ovintiv is unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measure to its most directly comparable forward-looking GAAP financial measure. Amounts excluded from this non-GAAP measure in future periods could be significant. • Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents. • Return on Capital Employed (ROCE) is a non-GAAP measure. ROCE is defined as Adjusted Earnings divided by Capital Employed. Adjusted Earnings is defined as trailing 12-month Non-GAAP Adjusted Earnings plus after-tax interest expense. Non-GAAP Adjusted Earnings is defined as Net Earnings (Loss) excluding non-cash items that management believes reduces the comparability of the Company’s financial performance between periods. These items may include, but are not limited to, unrealized gains/losses on risk management, impairments, non-operating foreign exchange gains/losses, and gains/losses on divestitures. Income taxes, includes adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate. In addition, any valuation allowances are excluded in the calculation of income taxes. Capital Employed is defined as average debt plus average shareholders’ equity.
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3 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 third quarter and fiscal year 2025 guidance and expected free cash flow, timing and expected benefits and synergies of the acquisition, funding of the acquisition, pro forma ownership of the Company, expected closing date of the acquisition, plans to complete the Anadarko disposition, use of proceeds and the expected timing thereof, expected credit ratings, 2026 outlook, the resumption of the Company’s share buyback program, the presence of recoverability of estimated reserves, the expectation of delivering sustainable durable returns to shareholders, planned ESG 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 ESG 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,” “continue,” “could,” “estimates,” “expects,” “focused on,” “forecast,” “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 transactions described herein); the Company’s ability to integrate acquired assets and businesses and the timing thereof; the satisfaction of customary closing conditions and obtaining key regulatory, court and NuVista shareholder approvals; 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 (including to consummate the transactions described herein); the Company’s ability to successfully integrate the Montney assets; 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 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 with respect to the proposed transactions described herein include, among other things, the risk that the proposed transaction may not be completed in a timely basis or at all, which may adversely affect the Company’s and NuVista’s businesses and the price of their respective securities; the effect of the announcement, pendency or completion of the proposed transaction on the market price of Company and NuVista stock or the ability of each of the Company and NuVista to attract, motivate, retain and hire key personnel and maintain relationships with others whom they do business; that the proposed transaction may divert management’s attention from each of the Company’s and NuVista’s ongoing business operations; the risk of any legal proceedings related to the proposed transaction or otherwise, including resulting expense or delay; the occurrence of any event, change or other circumstance that could give rise to the termination of the definitive agreement for the transaction, including in circumstances which would require payment of a termination fee; the risk that restrictions during the pendency of the proposed transaction may impact the Company’s or NuVista’s ability to pursue certain business opportunities or strategic transactions; risks associated with third party contracts containing consent and/or other provisions that may be triggered by the proposed transaction; the risk that the anticipated benefits and synergies of the proposed transaction may not be fully realized or may take longer to realize than expected; risks relating to the value of Ovintiv securities to be issued in the proposed transaction; and the risk that the integration of NuVista’s business post-closing may not occur as anticipated. Forward Looking Statements
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4 Forward Looking Statements 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 Item 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.
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5 Acquiring NuVista Energy Generates ~10% Free Cash Flow per shareŦ accretion1 Enhances Montney scale with ~25 Mbbls/d of oil production & ~930 net 10k locations for ~$1.3 MM/loc Reinforces position as leading Montney oil producer Strengthening the Balance Sheet Launching Anadarko divestiture process Two-quarter share buyback & bolt-on pause Permian Ground Game Adds ~170 Well Locations ~170 net 10k locations added YTD Oct ’25 in the core of the play for ~$1.5 MM/loc Strong 3Q25 Results & Updated FY25E Guidance Production beat and raise Ovintiv – The Permian & Montney Powerhouse 1 2 3 4 Note: throughout this presentation, “oil” when referring to Montney oil includes both oil & condensate given the near- parity pricing between Montney oil & condensate and WTI. Ŧ Non-GAAP measures defined in advisories . For additional information regarding non- GAAP measures see the Company’s website. 1) Pro-forma estimates and per share metric increases are for FY26E and assume the acquisition closes with a January 1, 2026, ef fective date and strip pricing as of October 31. 2025: ~$60/bbl WTI, ~$4.00 NYMEX & (~$1.70)/MMBtu AECO differential. Excludes one-time costs associated with the acquisition.
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6 Guide Actuals Oil & Condensate (Mbbls/d) 202 - 208 212 NGLs (C2-C4) (Mbbls/d) 94 - 98 98 Natural Gas (MMcf/d) 1,875 - 1,925 1,925 Total Production (MBOE/d) 610 - 630 630 Capital ($MM) $525 - $575 $544 3Q25 Continues Operational Momentum 3Q25 Operational Performance Montney Operational strength driving higher production Permian Continued strong performance supports expected LT oil & C5+ run-rate of ~120 Mbbls/d Anadarko Significant Free Cash FlowŦ generation with shallow production declines Resilient Cash Flow per ShareŦ $3.47 $55 $65 $75 $85 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 1Q24 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 Cash Flow per Share Avg WTI $/sh $/bblWTI Quarterly Avg. Range: ~$63-$80/bbl $351MM 3Q25 Free Cash FlowŦ Generating Substantial Free Cash FlowŦ Ŧ Non-GAAP measures defined in advisories . For additional information regarding non- GAAP measures see the Company’s website. $126MM Net DebtŦ Reduction in 3Q25 Ŧ
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7 Strong Execution & Improved FY25 Guidance Higher Production & Lower Capex in 2025E Delivering ~10 MBOE/d more for ~$50 MM less capex vs. original guidance1 Durable Multi-Year Cash Tax Savings Internal restructuring; anticipate ~50% decrease (~$75 MM) in 2025 cash taxes vs. original guidance1 Lower Operating Costs 3Q25 Upstream Opex ~7% lower vs. original guidance1 ~15% headcount reduction compared to YE23 AI-Driven Profit Performance Leveraging AI for real-time optimization to enhance returns and manage risks Profitability Catalysts2025 Production and Capital 4Q25E Original FY25E1 Prior FY25E2 Updated FY25E Total Production (MBOE/d) 610 – 630 595 - 615 600 - 620 610 - 620 Oil & Condensate (Mbbls/d) 203 – 209 202 - 208 205 - 209 208 - 210 Other NGLs (C2-C4) (Mbbls/d) 95 – 99 87 - 92 93 - 96 94 - 96 Natural Gas (MMcf/d) 1,875 – 1,925 1,825 – 1,875 1,825 – 1,875 1,850 – 1,870 Capital ($ MM) $440 - $490 $2,150 - $2,250 $2,125 - $2,175 $2,125 - $2,175 Note: Additional guidance is available in the Appendix. 1) Original FY25E guidance published in the 4Q24 release. 2) Prior FY25E guidance published in 2Q25 release.
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8 Added >3,200 Locations in the Permian & Montney April ’23 Nov. ’24 Today Acquiring NuVista Permian Montney Added Locations1 ~930 ~$1.3 MM/loc ~900 <$1.0 MM/loc A more focused, high-graded portfolio Paramount’s Alberta Montney Assets EnCap’s Midland Basin Assets ~1,050 ~$2.0 MM/loc ’23 – YTD’25 ~350 <$1.5 MM/loc Permian & Montney Ground Game ~85% Permian 1) Net 10k locations. Includes Premium locations, which reflect >35% IRR at $55/bbl WTI and $2.75/MMBtu NYMEX, and upside loc ations.
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9 NuVista Acquisition Checks All the Boxes Immediately & Long- Term Accretive • ~10% higher Free Cash Flow per shareŦ1 • ~$100 MM expected durable annual synergies • ~3% higher Cash Flow per shareŦ1 Best Rock • ~10% uplift in average Montney oil type curve • Adjacent to existing Ovintiv acreage; ability to extend laterals • Locations immediately compete for capital Quality Inventory at the Right Price • ~930 locations (Premium2 + Upside); ~$1.3 MM/location3 • ~70% undeveloped • Market access to processing and downstream transport Enhances Montney Scale • ~85 Mbbls/d Pro Forma oil and condensate production1 • ~15-20 Years of Premium2 inventory • Oil growth optionality of >5% per year Strengthening the Balance Sheet • Neutral leverage when acquisition closes • Expect < $4.0 B Net DebtŦ post close of Anadarko disposition • Increased shareholder returns planned post disposition Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website. 1) Pro-forma estimates and per share metric increases are for FY26E and assume the acquisition closes with a January 1, 2026, ef fective date and strip pricing as of October 31. 2025: ~$60/bbl WTI, ~$4.00 NYMEX & (~$1.70)/MMBtu AECO differential. Excludes one-time costs associated with the acquisition. 2) Premium reflects >35% IRR at $55/bbl WTI oil and $2.75/MMBtu NYMEX. NuVista inventory depth described herein reflects Ovin tiv’s estimates with estimated runway for FY26E. 3) Assumes ~$20k per flowing BOE/d PDP value and current production.
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10 NuVista Energy Overview ~25Mbbls/d Oil & Condensate Production ~140k Net Core Acres ~95% Avg. W.I. ~930 Premium2 & Upside Locations ~100MBOE/d Total Production Deep Inventory Significant Production Scale3 1) As of October 31, 2025. 2) Premium reflects >35% IRR at $55/bbl WTI & $2.75/MMBtu NYMEX. 3) FY26E. 4) Reflects 2027E+. Montney firm transport values are calculated from AECO. All physical transport volumes represent Transpor t Receipt Volume and transport volumes are converted to Mcf at 1:1 ratio from MMBtu. Processing & Downstream Capacity Alberta Montney Acreage Pipestone Wapiti Karr ~70% Undeveloped ~400MMcf/d Natural Gas Production Company Details ~$2.7B Acquisition Enterprise Value 2 Rigs Operating in the Montney1 NVA TSX Ticker OVV NVA Alberta B.C. ~100% Gas Diversification Ex-AECO3 All amounts presented above and throughout this material are on a Net Revenue Interest (NRI) basis and expressed in U.S. dollars, unless otherwise noted NuVista reports production on a Net Before Royalty (NBR) basis and uses Canadian dollars as its reporting currency ~600MMcf/d Raw Inlet Processing Capacity
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11 Expanded Montney Footprint NuVista Inventory & Operational Details • ~140k net core acres directly adjacent to existing Alberta acreage • ~70% undeveloped • ~930 net 10k locations (~620 Premium1 & ~310 upside) • ~$1.3 MM per location assuming ~$20k/BOE/d PDP value 2 • ~100% operated, ~95% average WI • Acreage held indefinitely / no HBP3 requirements ~15-20 years of Pro Forma Premium1 Montney oil inventory • Transaction further expands our leading Montney scale Anticipate Pro Forma 2026E Montney activity of ~6 rigs & 1-2 frac crews Pro Forma OVV Montney4 OVV NVA Pro Forma Net Core Acres (000s) ~370 ~140 ~510 Oil & C5+ (Mbbls/d) ~60 ~25 ~85 Natural Gas (MMcf/d) ~1,350 ~400 ~1,750 Total (MBOE/d) ~300 ~100 ~400 1) Premium reflects >35% IRR at $55/bbl WTI & $2.75/MMBtu NYMEX.. 2) Reflects current production. 3) Held by production. 4) FY26E. ~620 Premium1 Locations 10-14 WPS ~310 Upside Locations Up to 16 WPS in most prolific areas and add’l infill opportunities NuVista Adds Depth to Premium1 Inventory ~930 Added Premium1 & Upside Locations Consistent with the development approach on the Legacy and Paramount Montney assets
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12 Established Integration Track Record Immediate Accretion1 Applying Proven Integration Playbook Paramount Montney │ EnCap Permian ~10% More FY26E Free Cash Flow per ShareŦ1 ~$100MM Expected Annual Free Cash FlowŦ Synergies ~3% More FY26E Cash Flow per ShareŦ1 Immediate Synergies ~$50 MM / yr in expected capital savings ~$1 MM / well from streamlined facility design & faster cycle times Additional non-well capital savings ~$50 MM / yr in expected cost savings Lower production cost from enhanced scale, AI & OCC Lower overhead Future Synergies Available processing capacity Optimizes pro forma liquids development & enhances flexibility Extended laterals from complementary land base Base optimization via integrated infrastructure and proprietary AI/automation Ŧ Non-GAAP measures defined in advisories. For additional information regarding non- GAAP measures see the Company’s website. Note: OCC is the Centralized Operations Control Center. 1) Pro-forma estimates and per share metric increases are for FY26E and assume the acquisition closes with a January 1, 2026, ef fective date and strip pricing as of October 31. 2025: ~$60/bbl WTI, ~$4.00 NYMEX & (~$1.70)/MMBtu AECO differential. Excludes one-time costs associated with the acquisition. ROCE Ŧ Higher Return on Capital EmployedŦ1
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13 0 2 4 6 8 10 12 14 16 18 0 1 2 3 4 5 6 7 8 9 10 11 12 Condensate-to-Gas Ratios (CGRs) Enhancing OVV’s Montney Oil Program Pro Forma Montney Oil & Condensate Type Curve Months Cume. Oil bbls/ft Higher CGR (Karr) Lower CGR (Cutbank Ridge) Note: The condensate-to-gas ratio (CGR) is a volumetric comparison used in condensate -rich fields to describe the amount of cond ensate produced, measured in bbls, per unit of natural gas produced, measured in MMcf. 1) Assumes strip pricing as of October 31, 2025: ~$60/bbl WTI, ~$4.00 NYMEX & (~$1.70)/MMBtu AECO differential. 2) Source: Enverus. Weighted average oil well productivity from 2023 -24. CGR: 20-150 CGR: 0-20 CGR: 150+ Ovintiv AB Acreage Previous Repeatable Montney Program NuVista Avg2 Pro Forma Repeatable Program NuVista Acreage Expected to Improve Montney Program oil productivity by ~10% New assets expected to generate >55% FY26E IRR1 at OVV cost structure Montney oil receives ~97% of WTI Economics do not require high NYMEX or AECO prices Low D&C costs (~$525/ft) Favorable royalty structure Retain upside to higher natural gas prices Montney Returns Driven By Oil
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14 Pro Forma Marketing Overview NuVista’s Gas Diversification1 Financial AECO Hedges JKM 162 231 231 21 21 207 140 120 2026 2027 2028 OVV 2026E ~30% AECO Exposure >50% Downstream FT Lower Pro Forma AECO Exposure3 Pro Forma 2026E ~25% AECO Exposure FT and financial hedges support strong AECO realizations • Inheriting ~250 MMcf/d of physical diversification in 2027+ • ~180% of AECO pre-hedge gas price realization (NuVista 1H25) • ~$120 MM mark-to-market value from financial hedges as of Oct. 31/25 MMcf/d Note: FT is firm transport. Montney firm transport values are calculated from AECO. All physical transport volumes represent Transport Receipt Volume and transport volumes are converted to Mcf at 1:1 ratio from MMBtu. 1) Excludes NYMEX hedges. Additional details provided in Appendix. 2) Reflects NuVista’s 2027 & 2028 FT. 3) Assumes 1.35 Bcf/d and 400 MMcf/d of Legacy and NuVista gas production, respectively, for illustrative purposes. MMcf/d 369 392 372 Downstream FT2 • Chicago: 83 MMcf/d • Dawn: 44 MMcf/d • Malin: 38 MMcf/d • Emerson: 46 MMcf/d • Ventura: 20 MMcf/d >50% Downstream FT Pro Forma AECO exposure estimated to decline by >5% • OVV continually pursuing opportunities to reduce AECO exposure • Added 50 MMcf/d of JKM exposure for 2026-27 in 3Q25 (100 MMcf/d total) Enhanced AECO (Only OVV)
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15 Pro Forma Processing Overview In Basin Processing Significant processing capacity provides additional growth optionality • NuVista adds ~0.6 Bcf/d of processing secured to 2035 • NuVista 37% owner & operator of Wembley plant; brings total OVV ownership to 63% at closing >5% Pro Forma Montney annual oil growth option with no major infrastructure spend required Leverages & builds on existing relationships • Proven track record of successful collaboration with third -party providers NVA Wembley ~600MMcf/d NVA Raw Inlet Processing Capacity >5% Pro Forma Montney Annual Oil Growth Production Option PGI Hythe CSV Albright Altagas Tidewater OVV Sexsmith Keyera PPF Keyera Wapiti CSV Karr PGI Wapiti Keyera Simonette & PGI Kaybob
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16 Leading Permian Ground Game ~170 Added Premium1 & Upside Locations YTD Oct. 25 ~$1.5MM Cost per Net 10k Well Location ~90% Premium1 Locations 1) Premium reflects >35% IRR at $55/bbl WTI oil and $2.75/MMBtu NYMEX. 2) Transactions closed early October and are not reflected in 3Q25 financials. Low-cost high quality adds in the core of the play via swaps & bolt -ons >8k net acres and ~120 net 10k locations added in Oct. ’25 for ~$250 MM 2 No PDP; inventory accretive and competes for capital immediately ~170 added Permian locations are adjacent to existing OVV acreage in Midland and Martin Counties Boosted Permian Premium1 Oil Inventory in 2025
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17 Accelerating Debt Reduction & Unlocking Higher Shareholder Returns Anadarko Asset Sale Planned in 2026 Divestiture process to launch early 1Q26 Proceeds earmarked for accelerated debt reduction Expect to be below $4.0 B Net DebtŦ target post-sale Inflection point for increased shareholder returns NuVista acquisition not expected to impact the Company’s investment grade ratings • Leverage neutral at close • Balanced financing mix • Two-quarter share buyback pause starting 4Q25; buybacks expected to resume in 2Q26 • No additional bolt-on activity during buyback pause • No change to base dividend expected1 Significant debt reduction planned with Anadarko sale • Simplifies the portfolio and enhances durable returns Ŧ Non-GAAP measures defined in advisories . For additional information please see advisories contained within this document. 1) Subject to Board discretion.
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18 Builds on strong year-to-date company wide performance Leverages industry-leading innovation & execution in Montney oil Enhances Montney oil position Immediately & long-term accretive Expect credit ratings to be reaffirmed Stronger balance sheet & streamlined portfolio post-Anadarko sale Completing Portfolio Transformation ~715MBOE/d Total Production <$2.5B Capex ~230Mbbls/d Oil & Condensate Production 2026E Pro Forma Guidance Pre-Disposition
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Appendix A NuVista Acquisition
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21 Transaction Details Transaction Enterprise Value of ~$2.7B 1 • Blended acquisition cost of ~C$17.80/sh • C$18.00/sh for ~90.4% of NuVista shares outstanding2 • OVV ~9.6% ownership at C$16.00/sh cost basis, purchased Oct. 1/252 • ~$215 MM of net debt outstanding1 50% Equity / 50% Cash Financing Mix 3 • Fixed exchange ratio of ~0.172 shares of OVV for each share of NuVista • ~30 MM OVV shares to be issued; NuVista shareholders to own ~10.6% of the Pro Forma company2 • ~$1.1 B cash consideration funded through cash on hand, new term loan and/or credit facility borrowings2 • ~54% cash financing mix including previously acquired NuVista shares4 Anticipated Closing 1Q26 • Transaction unanimously approved by the OVV and NuVista Boards of Directors • Confirmed support for the transaction from NuVista’s directors and executive officers • Closing subject to NuVista shareholder vote, court and other customary approvals 1) Assumes a 0.7114 CAD to USD FX rate per Bank of Canada, as of November 3, 2025. ~C$300 MM net debt outstanding as of Oct. 31, 2025. 2) NuVista shareholder ownership figures exclude shares already owned by Ovintiv. Assumes all dilutive shares are settled in cash. 3) NuVista shareholders have the option to elect to receive C$18.00 in cash or 0.344 Ovintiv common shares per NVA share. On a fully pro-rated basis, total consideration represents C$9.00 in cash and 0.172 Ovintiv common shares per NVA share. 4) Percent consideration excludes outstanding debt.
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22 NuVista Gas Hedge Positions as of June 30, 2025 Natural Gas Hedge Positions1,2 Natural Gas 2026 2027 2028 2029 2030 2031 NYMEX Collars Volume MMcf/d Call Strike $/Mcf Put Strike $/Mcf 95 $5.27 $3.75 0 - - 0 - - 0 - - 0 - - 0 - - NYMEX Fixed Price Swaps Volume MMcf/d Price $/Mcf 20 $4.07 0 - 0 - 0 - 0 - 0 - AECO Fixed Price Basis Swaps Volume MMcf/d Price $/Mcf 187.5 ($0.92) 140 ($0.91) 120 ($1.04) 47.5 ($1.11) 70 ($1.08) 25 ($1.23) AECO Fixed Price Swaps Volume MMcf/d Price C$/GJ 19.5 $2.97 0 - 0 - 0 - 0 - 0 - 1) Excludes WTI hedges due to materiality. 2) Volumes are converted to Mcf at 1:1 ratio from MMBtu. 3) Undiscounted. As of October 31, 2025, strip pricing. ~$120 MM mark-to-market hedge value3
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23 Permian (Midland & Delaware) Montney Eagle Ford Bakken Uinta Anadarko Powder DJ Remaining Undrilled Resource (Ovintiv Internal North American Resource Assessment) Undeveloped Bbbls ~80% of remaining sub-$50/bbl breakeven oil locations in North America are in the Permian & Montney (Enverus, PV10 breakeven at 20:1 conversion) Focused in the Top North American Oil Basins The Permian & Montney are the two largest remaining oil resource basins in North America
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24 Condy Fundamentals Support Parity to WTI 0 300 600 900 1,200 2022 2023 2024 2025 2026 2027 2028 2029 2030 1) Canada Energy Regulator, December 2023 (Current Policies case). 2) Montney Condensate: ICE C5 1a + NYMEX Calendar Basis Swap. WTI: WTI Calendar Basis Swap. 3) Unhedged. Montney Condensate Competes with WTI ($/bbl)2 40 50 60 70 80 90 100 110 120 130 Jan 2021 Jul 2021 Jan 2022 Jul 2022 Jan 2023 Jul 2023 Jan 2024 Jul 2024 Jan 2025 Jul 2025 Captive Demand Growth (Mbbls/d)1 Canadian condensate demand expected to continue to be met with imports from the U.S. Even with domestic condensate production growth in Canada Required Condensate Imports to Meet Demand Domestic Condensate Production ~4% 5-yr Import Demand CAGR WTI Montney Condensate 97% OVV Montney Condensate Realizations vs. WTI, 2021-3Q253
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25Note: 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. 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 incentives programs exist to lower realized royalties • Upfront & early life royalty incentives derived from development costs $55/ $2.75 $85 / $5.00 $135 / $9.00 6 – 8% 13 – 15% Royalty Sensitivity1 U.S. Basin Average (20 – 25%) 24 – 26% WTI / Condensate $55 / $54 $70 / $69 $135 / $134 NYMEX / AECO $2.75 / $2.15 $5.00 / $4.00 $9.00 / $7.00 MAX Effective Royalties
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Appendix B 3Q25 Results
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27 Additional 2025 Guidance Operating Expenses Prior FY25 Guide1 3Q25A 4Q25 Guide PMOT (% of Upstream Product Revenue2) 3.75%-4.50% 4.18% 3.75%-4.50% Upstream T&P3 ($/BOE) $7.50-$8.00 $7.59 $7.50-$8.00 Upstream Opex3 ($/BOE) $3.75-$4.00 $3.71 $3.75-$4.00 Corporate Items (Quarterly Run Rate) Prior FY25 Guide1 3Q25A FY25 Guide Corporate G&A4 $70-$75 MM $67 MM $70-$75 MM Less Sublease Revenue ~$19 MM ~$20 MM ~$19 MM Corp. G&A Less Sublease Rev. $51-$56 MM $47 MM $51-$56 MM Interest Expense on Debt $85-$95 MM $88 MM $85-$95 MM Upstream DD&A ($/BOE) $9.50-$10.00 $9.31 $9.50-$10.00 Current Tax Expense Guidance Prior FY25 Guide1 Q3 YTD FY25 Guide Canada $80-$100 MM $78 MM $65-$75 MM U.S. $10-$30 MM $5 MM $5-$10 MM Total OVV $90-$130 MM $83 MM $70-$85 MM 1) Guidance as of 2Q25 release., which assumed $60/bbl WTI, $3.75/MMBtu NYMEX & 0.72 CAD/USD for 2H25.. 2) Excludes Gains (Losses) on Risk Management. 3) Excludes activity with no associated volume. 4) Excludes LTIs, restructuring and legal costs. Current guidance assumes $60/bbl WTI, $3.75/MMBtu NYMEX & 0.72 CAD/USD for 4Q25E Reduced FY25E current tax expense guidance to reflect the impact of internal restructuring and evolving U.S. tax guidelines
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28 Hedge Positions as of September 30, 2025 Oil and Condensate Hedge Positions1 Oil and Condensate 4Q25 1Q26 2Q26 3Q26 4Q26 2027 2028 WTI 3-Way Options Volume Mbbls/d Call Strike $/bbl Put Strike $/bbl Sold Put Strike $/bbl 50 $76.57 $65.00 $50.00 45 $72.32 $62.01 $51.67 40 $70.62 $61.51 $51.25 30 $71.24 $60.00 $50.00 0 - - - 0 - - - 0 - - - Natural Gas Hedge Positions1,2 Natural Gas 4Q25 1Q26 2Q26 3Q26 4Q26 2027 2028 NYMEX 3-Way Options Volume MMcf/d Call Strike $/Mcf Put Strike $/Mcf Sold Put Strike $/Mcf 500 $4.47 $3.00 $2.25 500 $7.95 $3.33 $2.70 450 $5.92 $3.33 $2.58 450 $5.92 $3.33 $2.58 450 $5.92 $3.33 $2.58 0 - - - 0 - - - AECO Nominal Basis Swaps Volume MMcf/d Price $/Mcf 190 ($1.08) 0 - 0 - 0 - 0 - 20 ($1.38) 20 ($1.38) AECO % of NYMEX Swaps Volume MMcf/d Price % of NYMEX 100 72% 0 - 0 - 0 - 0 - 0 - 0 - AECO Fixed Price Swaps Volume MMcf/d Price $/Mcf 0 - 50 $2.35 50 $2.35 50 $2.35 50 $2.35 0 - 0 - 1) OVV also manages other key market basis differential risks for gas, oil and condensate. 2) Volume are converted to Mcf at 1:1 ratio from MMBtu. 3) Sensitivities do not include impact of other hedge contract positions and are reflected before -tax. Includes hedges executed t hrough September 30, 2025. 15 Mbbls/d of 2Q26 WTI three-ways with a soft floor of $60/bbl WTI Oil $40 $50 $60 $70 $80 $90 $100 4Q25 $69 $69 $23 - ($16) ($62) ($108) 1Q26 $42 $42 $8 - ($31) ($72) ($112) 2Q26 $37 $37 $6 - ($34) ($71) ($107) 3Q26 $28 $28 - - ($24) ($52) ($79) NYMEX Gas $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 4Q25 $35 $35 $23 - - - ($4) 1Q26 $28 $28 $28 $13 $2 - - 2Q26 $31 $31 $31 $13 $2 - - 3Q26 $31 $31 $31 $13 $2 - - 4Q26 $31 $31 $31 $13 $2 - - WTI & NYMEX Realized Gain / (Loss) Sensitivities ($ MM)3 Execution Since June 30, 2025 30 Mbbls/d of 3Q26 WTI three-ways with a soft floor of $60/bbl
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29 FY25E Asset-Level Guidance Permian Montney Anadarko Rigs 4-5 3-4 1-2 Frac Crews 1-2 ~1 0-1 Net TILs 130-140 75-85 37 Capital ($MM) $1,200-$1,250 $575-$625 $290-$310 D&C ($/ft) $600-$650 $500-$550 $525-$575 LL (ft) ~11,500 ~11,500 ~11,500 Trimulfrac ~75% - - Additional 2025 Guidance Asset-level capital guidance unchanged from prior FY25E guidance. Anadarko completions activity concluded in early 4Q25.
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30 Upstream T&P Sensitivities 4Q25E Sensitivity Upstream T&P F/X Rate (CAD/USD) ~0.72 +/- 0.01 CAD/USD $0.10/BOE WTI ($/bbl) ~$60 +/- $10/bbl $0.10/BOE NYMEX ($/MMBtu) ~$3.75 +/- $0.25/MMBtu $0.10/BOE 4Q25E Oil Price Free Cash FlowŦ Sensitivities1 WTI ($/bbl) Change vs. $60/bbl (assuming $3.75/MMBtu) $50 (~$140) MM $55 (~$75) MM $60 - $65 ~$75 MM $70 ~$150 MM 4Q25E Gas Price Free Cash FlowŦ Sensitivities1 NYMEX ($/MMBtu) Change vs. $3.75/MMBtu (assuming $60/bbl) $3.25 (~$40) MM $3.50 (~$20) MM $3.75 - $4.00 ~$20 MM $4.25 ~$40 MM 2025 Sensitivities 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, 2025, and taxes. 4Q25E CAD/USD Free Cash FlowŦ Sensitivity1 Sensitivity Change F/X Rate (CAD/USD) +/- 0.01 CAD/USD ~$10 MM T&P & Opex G&A Capital +/- 0.01 CAD/USD Free Cash FlowŦ Impacts Distribution of CAD/USD impacts
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31 Montney Outperformance in 3Q25 ~8% QoQ improvement in Gold Creek base decline from implementation of proprietary AI in the Operations Control Center Strong performance driven by ongoing collaboration with field operations and third-party partners Activity cadence; ~50% of FY25E 1 TILs came online in 2Q25 Results in higher expected oil run-rate from ~55 to ~60 Mbbls/d Application of OVV Design & Testing Upside Inventory on Acquired Acreage 4Q25 Updates Expected to be Provided with 4Q25 Results in February 2026 10-02 Pad in eastern Wapiti: first end-to-end OVV wells (8 WPS) 15-16 Pad in western Karr: first high density pilot (3 stack, 14 WPS) Key Drivers Behind Outperformance Gold Creek Completions Performance Prior Owner Design OVV Design ~3,900 Ft/d 1) FY25E is the midpoint of current guidance. • Real-time frac optimization • 30% reduced fluid volume • 10% increased stage spacing
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32 Leading Permian Ops 0 2 4 6 8 10 12 14 16 0 1 2 3 4 5 6 7 8 9 10 11 12 Re-Affirming 2025 Permian Type Curve Months Cume. Oil bbls / ft FY24A (145 wells) FY25E Type Curve 2022 2023 2024 YTD25 2022 2023 2024 YTD25 Drilling ~2,000 Ft/d 3Q25: ~4,600 Ft/d 3Q25: >2,000 Ft/d Completions ~4,200 Ft/d
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33 Proactive AECO & Waha Risk Management 2026E Legacy Montney Natural Gas Exposures1 Percent of Legacy Montney Gas Production Note: FT is firm transport. Montney firm transport values are calculated from AECO. All physical transport volumes represent Transport Receipt Volume and transport volumes are converted to Mcf at 1:1 ratio from MMBtu. 1) Assumes 1.35 Bcf/d and 250 MMcf/d of Montney and Permian gas production, respectively, for illustrative purposes. Financia l hedges as of Sept. 30, 2025. 710 MMcf/d Existing Downstream FT │2025+ (FT to Dawn, Malin, Sumas & Chicago) 100 MMcf/d JKM │2026-27 ~420 MMcf/d AECO Exposed ~30% AECO Exposure 2026-28 50 MMcf/d Fixed AECO Hedges │2026 70 MMcf/d Enhanced AECO │2025-27 2026E Permian Natural Gas Exposures1 Percent of Permian Gas Production 100 MMcf/d Existing Downstream FT │2025+ (FT to Houston Ship Channel) ~100 MMcf/d Waha Exposed ~40% Waha Exposure 4Q25+ • Additional 50 MMcf/d of JKM exposure for total of 100 MMcf/d, beginning Jan ’26 • Largest supplier option in Rockies LNG, the producer consortium supporting Ksi Lisims off of Western Canada • ~50 MMcf/d of capacity on Matterhorn pipeline to commence in 4Q25 • Total of ~150 MMcf/d of downstream firm transport to Houston Ship Channel 187% % of AECO 3Q25 YTD Montney Gas Realizations Pre-Hedge 153% % of Waha 3Q25 YTD Permian Gas Realizations Pre-Hedge 50 MMcf/d New Downstream FT │4Q25+ (FT to Houston Ship Channel)
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34 Diversified Legacy Montney Gas Pricing Stn 2 Malin Sumas Emerson Chicago Dawn Empress Montney / WCSB Gas Export Infrastructure NGTL System Northern Border Alliance GTN BC (Westcoast) Canadian Mainline Ksi Lisims (~2030) Cedar (~2028) LNG Canada (2025 & ~2030) Woodfibre (~2027) CGL PRGT Note: PRGT is Prince Rupert Gas Transmission and CGL is Coastal GasLink. 1) MMcf/d. Montney firm transport values are calculated from AECO. All physical transport volumes represent Transport Receipt Volume and transport volumes are converted to Mcf at 1:1 ratio from MMBtu. Significantly priced outside of AECO today with an option to participate in LNG Coastal Gas Link connected to OVV- operated Sunrise plant BC Montney partner (Mitsubishi) is an owner of LNG Canada Largest supplier to Rockies LNG (supplier to Ksi Lisims) OVV is Well-Positioned for LNG Firm Transport (2026+) Dawn ~330 Sumas ~20 Malin ~115 Chicago ~245 Total Firm Transport ~710 AECO Hedges (2026) 50 Enhanced AECO (2026-27) 70 JKM (2026-27) 100 AECO Price Mitigation1 >0.9Bcf/d FY26E Montney Gas priced outside AECO
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35 Higher Cash Flow per ShareŦ Along with Inventory Expansion Delivering Cash Flow & Inventory Growth ~25% Cash Flow per ShareŦ Growth, FY21-FY24 2025E supported by Montney integration, buybacks & continued focus on profitability Not driven by price – FY24 unhedged realized price per BOE was ~10% lower than FY21 Change in Sub-$50/bbl Oil Inventory Life, 2023-20251 (5) (3) (1) 1 3 OVV Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Years Ŧ Non-GAAP measures defined in advisories . For additional information regarding non- GAAP measures see the Company’s website. 1) Enverus NAV Compass, 2Q23 & 1Q25. Peers include APA, CHRD, CIVI, COP, CTRA, DVN, EOG, FANG, MGY, MTDR, OXY, PR, SM & VTLE.
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36 Cube Development Supports Inventory Duration Ovintiv established cube development in 2015 – simultaneous co- development of multiple stacked zones in a single development window 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 Drilled wells within a cube (illustrative) 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 Approach Alternative Approach Risk that future child wells are no longer economic 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 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 2022-25E Cube Development Drives Durable Returns vs. -2%/yr Avg. Permian Oil Productivity per Foot Decline 2022-24A Industry Average
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37Ŧ Non-GAAP measures defined in advisories . For additional information regarding non- GAAP measures see the Company’s website. 1) Midpoint of FY25 guide vs. FY24. 2) Realizations shown before hedges. FY25E Completions Activity Finished in Early 4Q25 • Closed out FY25 program with 37 net TILs • Achieved Company record Anadarko completions speed in 3Q25 On track for expected D&C savings • Continue to operate one rig in the play • FY25E D&C at ~$550/ft, a ~14% improvement from FY24 1 ~16% FY25E Base Decline Provides optionality in deploying capital while maintaining scale Contributes significant Free Cash FlowŦ with small capital requirement 3Q25 Anadarko Realizations2 102% Oil Percent Of WTI 88% Gas Percent Of NYMEX Anadarko Free Cash FlowŦ Machine Anadarko Drilling ~14,200ft Avg. Lateral Length in 3Q25 2024 YTD25 ~3,200Ft/d Anadarko Completions Speed >3,500ft/d Avg. Completion Speed in 3Q25
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38 Flaring TCFD SASB 20 Years Top Quartile Committed to eliminating routine flaring from our operations 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 peers3 50% Intensity Reduction1 (from ’19 – ’30) Achieved 46% Reduction Through YE24 Tied to Compensation For All Employees Track Record of Responsible Operations 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 goal s, or ability to achieve such targets or goals in the future. 1) Measured in Tons CO2e / MBOE. 2) From ’19 to ’24 Measured in Tons CH 4 / MBOE. 3) Based on AXPC membership. OVV has been in the top quartile every year since 2021. Scope 1&2 GHG Intensity Reduction Target Achieved 33% Reduction from ’19 Target Four Years Early Eliminating natural gas venting control devices Leading LDAR Program Emissions Tracking 73% Methane Intensity Reduction2 Committed ~$10 MM to children’s hospitals to make a positive difference in our communities Donated ~$2.5 MM to more than 1,000 charities through our employee matching program and logged over 3,000 volunteer hours Dedicated to our Communities