OVV Ovintiv Inc

Permian & Montney Oil Powerhouse November 14, 2024 Exhibit 99.2

Cautionary Statements 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.   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 and Ovintiv’s most recent Annual Report on Form 10-K. 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 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 $67 WTI, $3.15 NYMEX and ($1.50) AECO differential. The scenario utilizes the midpoint of the expected asset production and capital. 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. Non-GAAP Free Cash Flow Yield is a non-GAAP measure defined as annualized Non-GAAP Free Cash Flow compared to current market capitalization. Net Debt is a non-GAAP measure defined as long-term debt, including the current portion, less cash and cash equivalents. At October 31, 2024, Net Debt of $5.65 B comprised long-term debt of approximately $5.89B, less cash and cash equivalents of approximately $240 MM. 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.

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 guidance and expected free cash flow, the expectation of delivering sustainable durable returns to shareholders in future years, plans regarding share buybacks and debt reduction, the anticipated success of, and benefits from, technology and innovation, the ability of the Company to meet and maintain certain targets, 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,” “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; future foreign exchange rates; the ability of the Company to access credit facilities and capital markets; 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 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.

High-Grading The Portfolio Acquiring Core Montney oil ~80% undeveloped acreage in high-return oil window For $2.377 B1 Divesting Uinta For $2.00 B A Permian & Montney Oil Powerhouse 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 please see advisories contained within this document. 1) C$3.325 B, assumes a 0.7150 CAD to USD FX rate per Bloomberg, Noon Rate, November 13, 2024. Significant Basin Scale In the two largest remaining oil resource basins in North America 85-90% of pro forma capital to Permian & Montney Permian Strong oil mix, deep inventory & proven well results Anadarko Low decline & High Free Cash FlowŦ Montney High-return oil & deep multi-product inventory Underpinned by Free Cash FlowŦ Engine in the Anadarko ~100 MBOE/d of low-decline production

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

Advancing Our Durable Returns Strategy Ŧ Non-GAAP measures defined in advisories. For additional information please see advisories contained within this document. 1) Pro-forma estimates and per share metric increases are for FY25E and assume both the acquisition and disposition close January 1, 2025, and strip pricing as of October 31, 2024: ~$67/bbl WTI, ~$3.15 NYMEX & ~($1.50)/MMBtu AECO differential. Transactions are immediately & long-term accretive on all key financial metrics ~20% increase in Free Cash FlowŦ per Share, low-single digit increase in Cash FlowŦ per Share & ~$125 MM in expected annual synergies1 Substantially boosts Free Cash FlowŦ & capital efficiency $300 MM more Free Cash FlowŦ for the same oil production, more BOE & less capital1 High-grades the portfolio Higher return, higher Free Cash FlowŦ asset with a lower FY25E capital requirement & a mid-single-digit oil growth option Enhances our Montney oil position & expands Montney oil inventory to ~15 years Adds ~900 net 10k locations in the core Montney oil window Leverages our industry-leading innovation & execution in Montney oil Applies our best-in-class operations, capital efficiency & DCFT to additional core acreage Expect credit ratings & stable outlook to be reaffirmed No new equity or long-term debt; net cash requirement funded by temporary buyback pause with expected resumption in 2Q25 P P P P P P

Asset Profile 70 MBOE/d expected at close1 25 Mbbls/d oil & condensate1, 230 MMcf/d natural gas1 Anticipate load-leveled pro forma activity of 3 rigs & 1 frac crew Inventory & Operational Details 109k contiguous net acres proximate to existing Pipestone position ~80% undeveloped ~900 net 10k locations (~600 Premium2 & ~300 upside) <$1 MM / Premium2 location (assuming ~$26k/BOE PDP value) 96% operated, 92% average WI Acreage held indefinitely / no HBP3 requirements Acquired Montney Asset Overview 1) NRI. 2) Premium reflects >35% IRR at $55/bbl WTI oil and $2.75/MMBtu NYMEX. 3) Held by production. 4) Reflects approximate metrics in 1Q25. OVV Montney at Close4 OVV Acquisition Pro Forma Net Core Acres (000s) 260 109 369 Oil & C5+ (Mbbls/d) 30 25 55 Total (MBOE/d) 240 70 310 *Oil productivity is ~20% higher in the over-pressured window vs. the normally pressured window (12-month cume)

Conservative Transaction Funding Expect agencies to reaffirm investment grade ratings & stable outlooks Committed to maintaining IG rating $4.0B debt target reaffirmed Temporary buyback pause funds net cash requirement of $377 MM Pause began with 3Q24 Free Cash FlowŦ that would have been used for repurchases in 4Q24 ($181 MM) Bolt-on activity effectively paused while share buybacks are paused No change to base dividend expected1 Anticipate buyback restart in 2Q252 Aligned timing for both transactions Effective Date: Oct 1, 2024 / Estimated Close: 1Q25 Ŧ Non-GAAP measures defined in advisories. For additional information please see advisories contained within this document. 1) Subject to Board discretion. 2) At strip pricing as of October 31, 2024: ~$67/bbl WTI, ~$3.15 NYMEX & ~($1.50)/MMBtu AECO differential. 3) Subject to customary adjustments. 4) Includes $50 MM of the $150 MM asset legal settlement, with the balance expected prior to YE24 Sources ($MM) Uinta Sale Proceeds3 $2,000 Cash and Short-Term Borrowings (recovered through buyback pause) $377 Total $2,377 Uses ($MM) Acquisition Purchase Price3 $2,377 $3,125/$2,500 Total $2,377 $2,500 Transaction Sources and Uses Net DebtŦ at Oct 31, 2024 $6,079 $MM $211 Net DebtŦ @ 6/30 3Q24 Net DebtŦ Paydown Net DebtŦ @ 9/30 Oct ’24 Net DebtŦ Paydown4 $5,868 ~$220 Net DebtŦ @ 10/31 ~$5,650

Immediately & Long-Term Accretive Accretive on all key financial metrics including Cash FlowŦ & Free Cash FlowŦ ~$300 MM higher Free Cash FlowŦ in FY25E1 ~$200 MM more Cash Flow,Ŧ ~$100 MM less capital Additional Free Cash FlowŦ supports higher shareholder returns, debt paydown acceleration & lower leverage Capital efficiency driven by execution excellence ~$125 MM in expected annual synergies >$1.5 MM / well in capital savings Additional synergies from Canadian cash tax savings & lower overhead Infrastructure in place unlocks mid-single-digit Montney oil growth option Enables more load-leveled development Cost & royalty advantaged Ŧ Non-GAAP measures defined in advisories. For additional information please see advisories contained within this document. 1) FY25E pro-forma vs. FY25E stand-alone Ovintiv. Pro-forma estimates assume both the acquisition and disposition close January 1, 2025, and strip pricing as of October 31, 2024: ~$67/bbl WTI, ~$3.15 NYMEX & ($1.50)/MMBtu AECO differential. Per share metrics include impact of temporary share buyback pause. ~20% More FY25E Free Cash Flow per ShareŦ1 P ~$125 MM Expected Annual Synergies P Higher ROCEŦ P

Acquiring the Best Rock in the Montney 1) Enverus. Horizontal wells online since ’22 with 10%+ liquids. Alberta Montney peers include AAV, ARX, BIR, CNQ, KEL, NVA, SCR, VRN & WCP. 2) Premium reflects >35% IRR at $55/bbl WTI oil and $2.75/MMBtu NYMEX. 3) Enverus. Horizontal wells online since ’22 with 10%+ liquids. Alberta Montney Avg. Oil Productivity1 12-Month Cume. bbls/ft >40% More Productive than the Peer Avg. Acquired Oil Productivity vs. Midland Basin3 12-Month Cume. bbls/ft Attractive acquisition cost (<$1MM / Premium2 location) Lowest D&C cost ($550/ft) Higher net royalty interest Strong oil price realizations (~97% of WTI) P P P Montney Oil Returns Advantage P Highest oil productivity in the Alberta Montney Enhances legacy Montney position High confidence in repeatability P P P 15.4 County Average Core-of-the Core Montney Oil

~600 Premium Locations1 12-16 WPS, two benches across position + 3rd bench in highest oil-in-place acreage ~300 Upside Locations1 3rd bench across position & add’l infill opportunities Enhancing Our Montney Oil Position 1) Premium reflects >35% IRR at $55/bbl WTI oil and $2.75/MMBtu NYMEX. Locations are net 10k. 2) Expected to close in 1Q25. 3) Mid-cycle prices: $55/bbl WTI, $2.75/MMBtu NYMEX. Well IRR at Mid-Cycle Prices3 Premium1 Well Count Legacy Montney Acquired Premium Locations1 IRR 35% ~15 years of Premium1 Montney oil inventory Legacy Montney & acquired Premium locations1 Transaction expands our leading Montney scale Returns driven by oil >60% FY25E pro-forma IRR at October 31 strip Economics do not require high NYMEX or AECO Improved oil realizations Montney oil receives ~97% of WTI Structurally short condensate market provides durable support for Montney oil pricing Acquisition immediately competes for capital Today’s Transactions2 100% ~900 Added Premium & Upside Locations1 Typical Development Program Three bench development is typical by OVV & others offsetting acquired acreage

OVV Spud-Rig Release vs. Peers2 Ovintiv is the Best-in-Class Montney Operator 1) OVV capital efficiency reflects FY24E Montney capex guidance and 2Q24 Montney production. Peer capital efficiency reflects FY24 total company capex guidance converted to USD at 0.75 CAD/US FX and total company 2Q24 production actuals. For comparison purposes, capital efficiency calculations for peers also include an assumed 10% royalty rate across all products – Montney peers report pre-royalty production, OVV reports after-royalty production. Peers include AAV, ARX, BIR, NVA and TOU. 2) Enverus 2024 YTD as of October 16, 2024. Spud-rig release timing normalized to 10k ft lateral. Peer Average includes AAV, ARX, BIR, CNQ, COP, KEL, NVA, POU, PRQ, SRC, TOU and VRN. OVV Montney Oil Capital Efficiency1 Days >8days Faster than Peers ’24 YTD ‘000 ft >1.5k ft Longer than Peers ’24 YTD Peer Average OVV <10 ~18 >11 ~9.5 OVV Lateral Length vs. Peers2 ~60% Better than Peer Avg. FY24E Capex / Oil & Condensate ($MM USD / Mbbls/d) Peer Average OVV Industry-Leading Montney Operator Decades of experience in the Montney Execution leadership drives top tier capital efficiency Real-time frac optimization maximizes productivity per foot & lowers costs Digital operations control center maximizes production & lowers costs Integrated learnings and best practices from Lower 48 operations Peers

Speed Driving Montney Efficiencies Drilled Ft/Day Completed Ft/Day <$500/ft Pacesetter D&C $525-$575/ft FY24 D&C Guidance ~1,700 ~1,725 ~3,300 ~4,100 6% faster drilling in 3Q24 vs. FY23 Longest industry lateral in Montney history at 18,110 ft1 Ovintiv has drilled 14 of the 20 longest Montney laterals1 P P P 3Q24 OVV Drilling 24% faster completions in 3Q24 vs. FY23 Pacesetter completion of >5,400 ft/d Completions speed on par with Permian Trimulfrac P P P 3Q24 OVV Completions Montney D&C 1) Geoscout. ~1,700 ~1,800 ~1,820 ~4,100 ~4,450 ~5,100 6% Faster 3Q24 vs. FY23 24% Faster 3Q24 vs. FY23

Builds on strong year-to-date company wide performance Immediately & long-term accretive Drives capital efficiency gain & ROCEŦ boost High-grades portfolio & enhances Montney oil position Leverages industry-leading innovation & execution in Montney oil Expect credit ratings & stable outlook to be reaffirmed Advancing Our Durable Returns Strategy ~620MBOE/d Total Production P P P P P ~$2.2B Capex ~205Mbbls/d Oil & Condensate Production 2025 Pro-Forma Guidance1 Ŧ Non-GAAP measures defined in advisories. For additional information please see advisories contained within this document. 1) Assumes both the acquisition and disposition close January 1, 2025. P

Appendix

Focused & Efficient Portfolio Pairing the top two oil basins with stable, low-decline Free Cash FlowŦ Substantial basin scale in each asset Innovations transferred across the assets to drive returns Operational Excellence Drives Efficiencies Proven operational flexibility and margin enhancement Optimized development programs across asset base Multi-Product Commodity Exposure Premium return options across both oil & condensate and gas Maximizing price realizations through market diversification Deep Premium1 Inventory 10-15 yrs of oil & condensate & >20 yrs of natural gas Premium inventory Proven organic assessment and appraisal program Oil Inventory Powerhouse P P P Permian Strong oil mix, deep inventory & proven well results Anadarko Low decline & High Free Cash FlowŦ Montney High-return oil & deep multi-product inventory P Premium Multi-Basin Portfolio & Resource Expertise & Culture to Convert Resource to Free Cash FlowŦ Disciplined Capital Allocation Durable Return on Invested Capital & Return of Cash to Shareholders Durable Returns Recipe = 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.

Details on Uinta Basin Exit All Cash Proceeds $2.00 $B Funds Significant Portion of Montney Acquisition Production Profile 29 Mbbls/d 3Q24 Oil & Condensate Production Key Dates October 1, 2024 Effective Date 1Q25 Estimated Close

Acquired acreage among the highest oil productivity in the Montney Proven Montney Oil Well Performance Note: Production data based on wells with 12 months of production brought on production January 2020 or later. Acquisition 46 Wells 14.5 bo/ft -12mo OVV Acreage Acquired Acreage (109k acres) Overpressured Oil Gas Window Montney well Acquisition 60 Wells 17.5 bo/ft -12mo Over-Pressured* Normally Pressured* ~106k Acquired Net Core Acres ~80% Undeveloped ~900 Acquired Net 10k Locations *Oil productivity is ~20% higher in the over-pressured window vs. the normally pressured window (12-month cume) Pipestone Wapiti Karr Kakwa

Midstream & Marketing Overview Sufficient Access to Processing & Transportation Capacity Scaled with near-term development plans Option for mid-single-digit oil growth Leverages & Builds on Existing Relationships Ongoing business with midstream providers Plants operated by CSV & Keyera Manageable Increase in AECO Exposure Continue to diversify exposure through physical transport & AECO hedges P P P Midstream Infrastructure

Condy Fundamentals Support Parity to WTI 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. 2024 YTD is through September 2024. Montney Condensate Competes with WTI ($/bbl)2 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, 2021-2024 YTD3

WCSB Supply & Demand Balance (Bcf/d) In-Basin WCSB Demand Exports Out of the WCSB WCSB Production Note: WCSB: Western Canadian Sedimentary Basin. 1) YTD 2024. ~18Bcf/d Natural Gas Production ~10Bcf/d Pipeline Exports ~8Bcf/d Local, In-Basin Demand WCSB Natural Gas Balance by the Numbers1 WCSB Gas Market Balances on Exports

Station 2 Malin Sumas Emerson Chicago Dawn Empress Montney / WCSB Gas Export Infrastructure NGTL System TC Energy 1) Unhedged through 2Q24. 2) BBtu/d. Montney firm transport values are calculated from AECO. Northern Border TC Energy Alliance Pembina GTN TC Energy BC (Westcoast) Enbridge Ovintiv’s Montney Gas Gets Near NYMEX Pricing Long-term Firm Transport to premium US & Canadian Markets Renewal rights on all long-term Firm Transport agreements Physical price protection supplemented by financial hedges to NYMEX Consistent history of above AECO realized pricing P P P P Canadian Mainline TC Energy Montney Firm Transport2 2024 – 2025+ Dawn 330 Sumas 21 Malin 113 Chicago 245 Total 709 Diversified & ex AECO Pricing

LNG Canada WCSB LNG Infrastructure Note: ISD: In-service date. FID: Final investment decision. Cedar Ksi Lisims Woodfibre Prince Rupert Gas Transmission Western & Nisga’a LNG Canada Phases 1 (2.0 Bcf/d) & 2 (2.0 Bcf/d) Phase 1: ISD: ~2025 (has taken FID) Phase 2: ISD: ~2030 Owner/Supplier: Shell (40%), Petronas (25%), PetroChina (15%), Mitsubishi (15%), Kogas (5%) Access: Coastal Gas Link (TC) Cedar LNG (0.4 Bcf/d) ISD: ~2028 (has taken FID) Owner: Pembina/Haisla partnership Supplier: ARC (50%) / Pembina (50%) Access: Coastal Gas Link (TC) Woodfibre LNG (0.3 Bcf/d) ISD: ~2027 (has taken FID) Owner: Pacific Energy (70%) / Enbridge (30%) Supplier: Pacific Canbriam Access: To link to Westcoast system Ksi Lisims LNG (1.7 Bcf/d) ISD: ~2030 Owner: Western LNG Supplier: Rockies LNG (WCSB Producers) Access: Pipeline under construction (Nisga’a) West Coast LNG Projects Coastal Gas Link connected to Sunrise Plant BC Montney Partner (Mitsubishi) is an Owner Participant in Rockies LNG Ovintiv Optionality >6 Bcf/d of potential LNG exports before 2030 Coastal Gas Link connected to Sunrise Plant Coastal GasLink TC Energy BC (Westcoast) Enbridge Well-Positioned for West Coast LNG

Note: Royalty calculations assume AECO benchmark prices of approximately 80% of NYMEX. Royalties reflect “Net Effective Royalties 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 US and Canadian assets Changes in royalty rates seen in changes to reported net production Observed Montney Rates at or Below US Basins US royalties are traditionally a “fixed” percentage Even in a “high” scenario Montney royalties screen in-line with US basins Incentives Programs Exist to Lower Realized Royalties Upfront & early life royalty incentives derived from development costs Additional royalty incentives from infrastructure and facility cost credits 6 – 8% 13 – 15% Royalty Sensitivity1 US 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

Durable Cash Return Framework Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website. Note: Future dividends are subject to Board approval. 1) $78 MM base dividend in 4Q24, held flat to 3Q24 for illustrative purposes. 4Q24 Free Cash FlowŦ Allocation ($ MM) 3Q24 Results $978 Non-GAAP Cash FlowŦ ($538) Capex $440 Non-GAAP Free Cash FlowŦ ($78) 3Q24 Base Dividend $362 Available for Allocation 4Q24 Capital Allocation $181 50% Allocated to Balance Sheet $181 50% Add’l Allocation to Balance Sheet (from buyback pause to fund net cash requirement) $362 4Q24 Balance Sheet Allocation $78 4Q24 Shareholder Return (Base Dividend)1 Uses of Post-Base Dividend Free Cash FlowŦ Buybacks temporarily paused to fund transaction net cash requirement Net Cash Requirement 4Q24 Buyback Pause Remaining Net Cash Requirement $377 $181 Funded with Buyback pause (expected restart in 2Q25) Buyback Pause & Restart $MM Shareholder Return Framework Shareholder Returns At least 50% Share Buybacks Variable Dividend Balance Sheet Up to 50% Debt Paydown Low-cost Bolt-Ons $196

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