Exhibit 99.2 Montney Webcast September 19, 2022 1

Today’s Agenda & Speakers Agenda 1 Introduction Corporate Review 2 Cash Returns & Debt Reduction OVV’s Advantaged Montney Position 3 Type curves, economics, & undeveloped resource Ovintiv Edge 4 OVV’s approach to differentiated operations Canadian Midstream and Marketing 5 Commodity fundamentals & OVV’s marketing strategy Speakers Brendan McCracken Tony Baffa 6 Closing Remarks / Q&A President & CEO Sr. Manager CAN Development Corey Code Aaron Felton EVP & CFO Chief Operations Engineering Greg Givens Jim Zadvorny EVP & COO VP Marketing Jason Verhaest VP IR & Planning 2

Introduction Brendan McCracken – President & CEO

I N TR O DU C TI O N Executing Our Business Plan Returns Based Strategy Industry-Leading Value Proposition Delivering Value to our P Superior ROIC and return of cash to our shareholders Shareholders 1 Returning Material Cash to Shareholders P 2 ~$1B of shareholder returns in ‘22 & expected to more than double in ‘23 Ŧ Rapid Net Debt Reduction P Ŧ 2 $3.0 B Net Debt to be achieved in ‘22 Operational Excellence P Leading capital efficiency 3 Market Cap Reserve Life Index 2Q22 Production 1-Yr TSR ($B) (Years) (MBOE/d) (%) Culture of Innovation P D&C execution, supply chain sophistication, cube development OVV $13 75% >11.5 >500 Top Tier Multi-Basin Portfolio P NYSE & TSX ~2.3 BBOE 52% Liquids >10-yrs premium inventory & multi-product commodity exposure 1P Reserves Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab. Note: ROIC reflects Return on Invested Capital. Market data as of September 15, 2022 1) Cash returns include base dividends and share buybacks 2) Assumes $100 WTI & $8.00 NYMEX in 3Q22-4Q22 4 3) Bloomberg market data. Reflects reinvested dividends

I N TR O DU C TI O N High Quality Balanced Multi-Product Portfolio Premium Portfolio P Ŧ • Each asset generates substantial Free Cash Flow • Provides risk mitigation against single basin headwinds Multi-Basin Advantage P 2Q22 • Cross-basin learnings reinforce innovative culture Production • Operational best practices distributed across the portfolio Montney 198 MBOE/d Multi-Product Commodity Exposure P Bakken • Balanced production across oil & condensate and gas 28 MBOE/d • Maximized price realizations through market diversification Uinta 23 MBOE/d 1 Production Mix Premium Inventory Anadarko 128 MBOE/d >10Years Oil & Condensate Permian 116 MBOE/d 48% 52% >20Years Gas Liquids Natural Gas Opportunities Across the Portfolio Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab. 5 1) Premium defined as >35% at $55 WTI and $2.75 NYMEX

I N TR O DU C TI O N Corporate Values One • We achieve strong results working together, we use collaboration to advance our common goals • Transparency and information sharing across the organization “We aim to be the leading North Agile American E&P by generating free cash • We are proactive in identifying opportunity and take action to capture value flow and delivering superior returns of • Not stuck in our ways – willing to utilize different both cash to our shareholders and on approaches to find the best outcome the capital we invest in our multi-basin Innovative portfolio” • We achieve extraordinary results by applying novel solutions to meaningful opportunity - Brendan McCracken – President & CEO • Attitude focused on everyday improvement Driven • We are motivated by purpose – to make modern life possible • We set high standards and are accountable for delivering results 6

Corporate Review Corey Code – CFO

CORPORATE REVIEW Shareholder Return Projections 2 Returning Substantial Cash Growing Cash Returns 1 • ~$1B through base dividends and buybacks in FY22 Additional Shareholder Returns (Buyback or Variable Dividend) • Repurchased 6.7 MM shares since June 30, 2022 for $325 MM Base Dividend Ŧ Cash Return Yield expected to More Than Double Into ‘23 • Tailwind from reduced hedge impact in 2023+ ~24% Ŧ • Upside participation preserved by using three-way structures Cash Return Yield Transparent and Durable Capital Allocation Framework • Flexibility to return through buybacks or variable dividends • Will make appropriate value-based decision quarterly ~12% Ŧ Free Cash Flow After Base DividendŦ Cash Return Yield $729 Shareholder Share Buybacks 50% Returns ~6% Variable Dividend Ŧ $325 Reduced At least Cash Return Yield Hedge Tailwind (Illustrative) Debt Paydown $135 Balance Small low-cost property bolt-ons 50% 50% Inflection Sheet (Up to $300 MM /yr) Up to (Actual) $64 $64 $64 2Q22 3Q22 3Q22 Unhedged Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab 1) Assumes $100 WTI & $8.00 NYMEX for 3Q22-4Q22 Ŧ 2) Cash Return Yields reflect annualized returns versus FactSet market cap data as of September 15, 2022. “3Q22 Unhedged’ is illustrative and adds back $808 MM of 2Q22 realized commodity hedge losses into the 2Q22 Free Cash Flow 8 calculation used to calculate shareholder returns. This illustrates what the 3Q22 returns would have been if the company was unhedged

2041 2040 2039 2038 2037 2036 2035 2034 2033 2032 2031 2030 2029 2028 2027 2026 2025 2024 2023 2022 CORPORATE REVIEW Balance Sheet Supports Higher Returns Ŧ Continued Net Debt Reduction ($B) Proactive Absolute Debt Management • Redeemed $1B of notes in June (~$55 MM/yr int. exp. savings) $7.3 • ~$340 MM of additional YTD22 open market note repurchases Ŧ 1 $3.0B Net Debt target to be achieved in ‘22 2 generate ~$19 MM/yr interest expense savingsP $3.0B is not a stopping point • $279 MM since June 30, 2022 P 3 Strengthening Leverage Profile ŦŦ • 1.0x Net Debt to Adjusted EBITDA $5.2 Ŧ • >$4B Adjusted EBITDA (trailing 12-month) Investment Grade rated across four agencies $3.9 2 Long-Term Debt Profile ($MM) ~10yrs $850 Wtd Avg Maturity $716 Continued $471 $459 $456 Ŧ Net Debt Reduction $300 $149 Unlocks >50% Cash Returns 2Q20 2Q21 2Q22 Go Forward Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab. 1) Assumes $100 WTI & $8.00 NYMEX in 3Q22-4Q22 2) Reflects data as of September 15, 2022 9 3) Reflects June 30, 2022

OVV’s Advantaged Montney Position Greg Givens – EVP & COO Tony Baffa – Sr. Manager Canadian Development

OVV’S ADVANTAGED MONTNEY POSITION The Montney’s Role in Our Portfolio The Montney Basin Ŧ1 Substantial Free Cash Generation – >$2B Upstream Op FCF P British Alberta • Free cash flow driven by strong well results and advantaged midstream & marketing Columbia Fort St. John Premium Returns – #1 Capital Efficiency in the Basin P 2 • >200% IRR Oil & Condensate window & >200% IRR Gas window wells at strip Dawson Creek 3 • OVV drilled top 13 of 15 Montney industry wells in the last 12 months One Stop Shop – Multiple Product Optionality P • World class oil and gas play in one asset Grande Prairie • >30 MMcf/d gas & >1,000 Bbls/d oil & condensate wells Deep Inventory – Scale & Development Runway P 4 • Premium Inventory: >10 years oil & condensate & >30 years natural gas • Continuing to delineate asset footprint to organically add premium inventory Montney Basin Outline Strong Market Access – Natural Gas & Condensate P OVV Acreage • Montney Condensate Realizes 100% of WTI – trades like oil Oil & Condensate Window • >90% of OVV Montney gas priced outside of AECO (2023 – 2025) Gas Window Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab. 1) Assumes $100 WTI & $8.00 NYMEX in 3Q22-4Q22 2) Strip prices as of September 15, 2022 3) Enverus data based on total 6 month cumulative BOE production for wells online in last 12 months 11 4) Premium defined as >35% return at $55 WTI and $2.75 NYMEX

OVV’S ADVANTAGED MONTNEY POSITION Montney Well Positioned Today & Go-Forward • Free Cash Flow >$2B Today Ŧ1 • Strong Commodity Optionality Upstream Operating FCF in FY22 • Modest growth optionality with current midstream infrastructure Near-Term 0% – 5% Growth Option • Efficiency gains and enhanced well performance • LNG exposure and additional 2 Bcf/d >4 Bcf/d growth potential Medium & Canadian LNG Incremental LNG • Substantial inventory runway Long-Term Capacity Under Capacity Across 5 and further delineation potential Construction & Proposed Projects & on-line in 2025 Expansions Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab. 1) Assumes $100 WTI & $8.00 NYMEX in 3Q22-4Q22 12

OVV’S ADVANTAGED MONTNEY POSITION OVV’s Premium Acreage Position OVV’s Montney Position Substantial Premium Acreage Position with Proven Development British Alberta 1 Columbia • Largest Montney operator today • Multi-decade development history started in the early 2000’s Advantaged Development with Consolidated Freehold Position • Primarily freehold surface (private ownership) reduces permitting considerations • Contiguous acreage footprint aligned with OVV’s cube development approach >$2B 198 Ŧ2 Upstream Op FCF 2Q22 MBOE/d OVV 3 OVV Premium Montney OVV Upside $300 - $350 907 OVV BY THE Capex ($ MM) 2Q22 Gas MMCF/d NUMBERS 60 - 65 47 (FY22 unless noted) Net TILs 2Q22 Liquids MBBLS/d BC AB Total Net Premium Acres 155K 105K 260K Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab. 1) Based on gross operated gas production 13 2) Assumes $100 WTI & $8.00 NYMEX in 3Q22-4Q22 3) Premium defined as >35% return at $55 WTI and $2.75 NYMEX

OVV’S ADVANTAGED MONTNEY POSITION World Class Resource Successfully Maximizing Resource Through Cube Development • Accessing up to ~1,000 foot productive pay thickness during development • Customize every cube with precise well placement to maximize resource extraction Developing Multi-Well Pads at Full-Field Development Spacing • Seeing consistent well results across acreage footprint at full spacing • Thoughtful development approach and well spacing maximizes value World Class Subsurface Resource OVV Montney Spacing —— —— —— —— Productive Pay Thickness (Ft) Upper Montney —— —— —— —— 2,000 Middle Up to —————————— Montney 1,500 ~ 1,000 Ft Lower 1,000 ————————— Montney Low: ~8 High: ~27 500 Wells Per Section Wells Per Section 0 Wtd Avg: ~12 Permian Montney Haynesville Utica Marcellus 1 Wells Per Section 14 1) Targeted stacking and spacing varies across the extent of the play

OVV’S ADVANTAGED MONTNEY POSITION Montney Oil & Condensate Window Profile Volatile Oil Wells Drive OVV’s Condensate Production BC AB 2 OVV Premium OVV Upside • Strong well results & quick cycle capital provide rapid payouts and >200% IRR at strip OVV • Condensate realizes prices at parity with WTI (100% of WTI over past 12 months) • Oil & Condensate window has been a focus of OVV’s development over past 5-years Oil & Condensate Type Curve Type Curve Details 500 160 DCFT $/Ft ~$550 Oil & Condensate TC Oil & Condensate TC (MBOE) (Mbbls) 400 120 EUR (MMBOE) 1.1 Oil & Condensate Inventory 300 80 Premium Net Acres Avg WI (%) 115,000 (40K BC / 75K AB) 200 British Columbia 60% 1,280 Acres in 10K DSU 1 2022 Mbbls Alberta 100% 40 100 1 2022 MBOE 90 DSUs 11 Avg Wells / DSU 0 0 24 Month Cume: 0 3 6 9 12 15 18 21 24 0 3 6 9 12 15 18 21 24 5% ~990 Total Wells Oil & C5+ Months Months 30% (390) Net Wells Drilled to Date Other NGL (C2 – C4) 3 $55/$2.75 Strip Single Well 65% Gas 600 Wells Remaining 65% >200% IRR (%) 16 <6 Payout (Mos) ~55 Stay Flat TILs / Year Note: All well data normalized to 10,000 ft >10 Yrs Inventory Life 1) Reflects OVV 2022 program results in the Oil & Condensate Window 2) Premium defined as >35% return at $55 WTI and $2.75 NYMEX 15 3) Strip as of September 15, 2022. ATAX IRR Shown. Assumes Gas realizations of ~90% of NYMEX Cumulative MBOE Cume. Oil & Condensate Mbbls

OVV’S ADVANTAGED MONTNEY POSITION Montney Gas Window Profile Dry Gas Wells Drive OVV’s Natural Gas Exposure & Optionality BC AB 2 OVV Premium OVV Upside • Strong well results & quick cycle capital provide rapid payouts and >200% IRR at strip OVV • Gas economics supported by our active management of AECO price risk • Our Montney gas wells compete with the best natural gas basins in lower 48 Gas Type Curve Type Curve Details 1,000 Gas TC (MBOE) DCFT $/Ft ~$525 800 EUR (MMBOE) 2.5 Gas Inventory Premium Net Acres Avg WI (%) 600 145,000 (115K BC / 30K AB) British Columbia 60% 1,280 Acres in 10K DSU 1 Alberta 100% 2022 MBOE 400 113 DSUs 3 13 Avg Wells / DSU $55/$2.75 Strip Single Well 24 Month Cume: 200 64% >200% IRR (%) 5% ~1,470 Total Wells Oil & C5+ 5% 16 <6 Payout (Mos) (445) Wells Drilled to Date Other NGL (C2 – C4) 0 Gas 1,025 Wells Remaining 90% 0 2 4 6 8 10 12 14 16 18 20 22 24 ~30 Stay Flat TILs / Year Months Note: All well data normalized to 10,000 ft >30 Yrs Inventory Life 1) Reflects OVV 2022 program results in the Oil & Condensate Window 2) Premium defined as >35% return at $55 WTI and $2.75 NYMEX 16 3) Strip as of September 15, 2022. ATAX IRR Shown. Assumes Gas realizations of ~90% of NYMEX Cumulative MBOE

OVV’S ADVANTAGED MONTNEY POSITION Leading Capital Efficiency & Well Results Crude & Condensate Economic BOE (20:1) Traditional BOE (6:1) 70 12 7 70% Better 60% Better 55% Better 60 6 10 #1 Montney vs. Peer Avg vs. Peer Avg vs. Peer Avg 50 5 8 40 4 Capital Efficiency… 6 30 3 ’22 Capex ($MM USD) / 4 20 2 2Q22 Production (MBOE/d or Mbbls/d) 2 10 1 If we were just average… 0 0 0 OVV 1 2 3 4 5 6 7 OVV 1 2 3 4 5 6 7 OVV 1 2 3 4 5 6 7 …Our Montney capex would Montney Peers Montney Montney Peers Peers be >2x higher for the same production 1 Top Industry Montney Basin Wells in Last 12 Months 900 …Driven by Strong 600 Well Results 300 0 OVV OVV OVV OVV OVV OVV OVV OVV OVV OVV OVV OVV Peer OVV Peer Note: OVV capital efficiency reflects current FY22 Montney capex guidance and 2Q22 Montney production. Peer capital efficiency reflects FY22 total company guidance converted to USD at 0.8x CAD/US FX and total company 2Q22 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 and OVV reports after royalty production. Montney Peers reflect AAV, ARX, BIR, CR, NVA, PIPE, and TOU 17 1) Enverus data as of July 2022 6 mos cume MBOE

OVV’S ADVANTAGED MONTNEY POSITION Strong Wells Across the Commodity Mix OVV 16-27 Pad Oil & Condensate Production Bbls/d NRI Production (Mid Montney Average) 1,500 >1,000 Bbl/d Strong 1 Oil Wells Provide Exposure to Prices at 1,000 or Near WTI and a Prolific Oil & C5+ 500 Return Profile Per Well Average 0 Wells 0 30 60 90 120 150 180 Days “One Stop Shop” – Proven Multi Product Optionality OVV 13-33 Pad Gas Production MMCF/d NRI Production (Upper Montney Average) 40 Drive Long-Term Gas Optionality Strong & Compete With World Class Natural Gas Basins 20 Gas Wells >30 MMCF/d 1 Gas Wells Per Well Average 0 0 30 60 90 120 150 180 Days Note: Production data normalized for down days 18 1) Reflects once well production is fully online

OVV’S ADVANTAGED MONTNEY POSITION Royalty Structure Supports Returns 1 Royalty Sensitivity Royalty Rates Vary Based on Commodity Prices 24 – 26% • OVV Reports “NRI” volumes after royalties across its US and Canadian assets US Basin Average (20 – 25%) • Changes in royalty rates seen in changes to reported net production Observed Montney Rates at or Below US Basins 13 – 15% • US royalties are traditionally a “fixed” percentage 6 – 8% • Even in a “high” scenario Montney royalties screen in-line with US basins MAX Effective Royalties Incentives Programs Exist to Lower Realized Royalties $55/ $2.75 $85 / $5.00 $135 / $9.00 • Upfront & early life royalty incentives derived from development costs $55 / $54 $70 / $69 $135 / $134 WTI / Condensate $2.75 / $2.15 $5.00 / $4.00 $9.00 / $7.00 NYMEX / AECO • Additional royalty incentives from infrastructure and facility cost credits Montney Sliding Scale Royalty Details Gas Oil & Condensate Minimal Returns Impact $55 / $54 $55 / $54 WTI / Condensate Strip Strip $2.75 / $2.15 $2.75 / $2.15 NYMEX / AECO From Sliding Royalties 64% >200% 65% >200% IRR (%) 16 <6 16 <6 Payout (Mos) Sliding Scale Royalty @ Each Price Deck: Higher prices more than offset [ 6% 16% 7% 16% Total Well higher royalty impact 5% 15% 4% 15% Gas Royalty 15% 22% 13% 20% Oil & C5+ Royalty Royalty % significantly 8% 17% 7% 15% Other NGL (C2 – C4) below average US basins Note: Strip prices as of September 15, 2022. Economics reflect natural gas realizations of approximately 90% of NYMEX. Royalty calculations assume AECO benchmark prices of approximately 80% of NYMEX. Royalties reflect “Net 19 Effective Royalties to OVV” after incentives 1) Total BOE Production

OVV’S ADVANTAGED MONTNEY POSITION Permitting & Regulatory Landscape in BC OVV has majority of its 2023 permits in-hand today P with additional permits continuing to be released Flexible Operations Provide Certainty Regardless of permit activity OVV can execute its plan & P achieve strategic objectives with its multi-basin portfolio Well Positioned Recent British Columbia Permitting Discussion Permitting slowdown for all industrial development in BC WHAT: 50% Of Premium Net Acreage Located in AB Started mid- 2021 - Talks continue towards a resolution WHEN: 95% Of Premium Net Acreage in BC is in low impact Negligible areas and receiving permits today OVV Shifted 2022 capital to Alberta & Bakken IMPACT: Now have majority of 2023 permits in-hand 20

Ovintiv Edge Aaron Felton – Chief Operations Engineering Tony Baffa – Sr. Manager Canadian Development

OVINTIV EDGE Unmatched Operations Drilling Completions Faster Spud to Rig Release More Proppant Pumped per 35% vs. Montney Peers 90% Day vs. Montney Peers Prudent Development Stacked Innovation Faster Cycle Time Lower Scope 1&2 GHG 1 40% For Recent 15 Well Pad 60% Emissions vs Peers P Note: Montney Peer data from Enverus and represents >50 public and private Montney Basin operators 22 1) Scope 1 & 2 GHG Emissions Peers reflect AAV, ARX, BIR, CR, PIPE, TOU. 2021 peer data used where reported. Where 2021 peer data has not been published yet, 2020 data is used

OVINTIV EDGE Proven Industry Leadership Drilling Completion Driving Faster Drilling Speed Demonstrating Sand Efficiencies Spud to Rig Release (days) Proppant Pumped (tons/day) 30 5,000 4,000 20 3,000 35% 90% 2,000 OVV 10 Faster Spud to Rig Release Better Sand Efficiency 1,000 OVV Peer Avg YTD22 vs. Peer Avg YTD22 vs. Peer Avg 0 Peer Avg 0 '19 '20 '21 '22 '19 '20 '21 '22 Proven Excellence Over Longer Laterals Industry Leading Completions Lateral Length (ft) Completed (ft/day) 6,000 12,000 10% 15% 9,000 4,000 Longer Laterals Faster Completions OVV OVV YTD22 vs. Peer Avg YTD22 vs. Peer Avg Peer Avg Peer Avg 6,000 2,000 '19 '20 '21 '22 '19 '20 '21 '22 Drilling Longer Laterals Completing Wells Faster While in Less Time Pumping More Proppant 23 Note: Peer Average data from Enverus and represents >40 public and private Montney Basin operators

OVINTIV EDGE Leading Edge Drilling Performance 1 Extending Laterals (Ft) Operational Execution Driving Montney Performance • Leading longer-lateral length evolution in the basin 10,700 10,300 • Continuously innovating to push past mechanical limits & set new standards 9,700 Counterbalancing Inflation Through Efficiencies & Innovation 9,100 • 35% Faster spud to rig-release vs. basin peers • OVV custom drilling fluids, bits and specialized drill pipe run on leading edge high 8,300 spec rigs 2019 2020 2021 2022 2023 2 2023 DCFT ($/Ft) ~$550 5% - Facilities & Tie-in 30% - Drilling 65% - Completions DCFT ($/Ft) 24 1) Rounded to nearest 100 ft 2) Reflects assumed 2023 program of 25% gas window wells and 75% oil & condensate window wells

OVINTIV EDGE Demonstrated Completions Execution Completion Efficiencies Maximizing Operational Up-Time • Eliminating critical path bottlenecks Sand Pumped (MMLBS / Day) • Driving record completed lateral and sand pumped per day Completed Lateral Length (Feet / Day) 14-13 Pad Set Multiple Pacesetter Performance Records 10,375 • 15-well pad brought online in early 3Q22 • Strong 14-13 completions performance drove 40% full cycle time reduction 19 5,940 3,700 10 6 2019 2022 Pacesetter 25

OVINTIV EDGE Stacked Innovation Approach CASE STUDY – OVV Pipestone 14-13 Pad (15 well pad, on-line 3Q22) Drilling Completions Production Innovation Initiatives: Innovation Initiatives: Innovation Initiatives: 1 Multi-coil Tubing 1 Redesigned Drill Bits 1 Real Time Frac Optimization 2 Integrated Service Rigs 2 Motor Optimization 2 Simul-Frac Results: Results: Results: 1 Drilling Record Completions Record Record Pad Production 2,406 10,375 12,000 PPP Feet / Day Feet / Day Bbls/d Oil & Condensate Faster Cycle Time Spud to Rig Release Record Proppant ~9 19 40% PPP vs. Original Plan Days One Day Proppant MM Lbs (Spud to Turned-in-Line) Rigs Completion Wells Utilized Crews Online 26 1) Reflects record total pad production volumes

OVINTIV EDGE Strategic Utilization of Next Gen Frac Crews Establishing First 100% Natural Gas Fleet In Canada • Extensive development benefits from the thoughtful integration of 100% natural gas frac fleets • Reinforces leading edge operational execution Drives Efficiency & Flexibility – A Cornerstone of OVV Operations • Reduced footprint is primed for OVV’s proven simulfrac development approach • Dynamic mobility and automated controls align with OVV’s operational execution Saves >3 MM Gallons >30% Reduction in of Diesel per Year Labor New 100% Drives cost savings while reducing Provides cost savings and emissions and logistical complexity increases safety protocols Natural Gas Crew 80% Reduction in 55% Reduction in BY THE Fuel Cost Equipment NUMBERS Driven by utilization of natural Reduces operational footprint and gas and optimized operations increases pad design optionality 27

OVINTIV EDGE Leading TRIF Affirms Operational Excellence P 1 2021 TRIF Performance Driving Leading Safety Performance Year-over-Year • Safety is a top priority across the organization • Continue to advance and ingrain safety culture throughout the organization Continuously Improving Safety Performance • >120 training courses are offered and guide the workforce on best practices for managing EH&S risks and the procedures required to complete work safely Focused on Fostering a “Speak Up” Culture • Increase employee safety awareness and reinforce the power to speak up • Drive an open and trusting environment where employees feel comfortable elevating safety risks th” Recorded “8 Safest Year in a Row in 2021 • Company Wide TRIF of 0.15 in 2021 2 • ~75% Better than AXPC Peer Average Energy Safety OVV Montney Canada Peer Average 28 1) TRIF is Total Injury Frequency per 200,000 employee and contractor hours worked. Peer data reflects 2021 Energy Safety Canada 2) AXPC reflects American Exploration and Production Council

OVINTIV EDGE Top Tier Emissions Performance Continues P 1 2021 GHG Scope 1&2 Intensity Regulatory Framework Supports Improvement Initiatives Tons CO e/MBOE 2 • Access Government incentives to improve emissions profile at low costs • All projects completed to date have also been economically successful Production Operations Run on Low Emissions Power Grid • Substantially all operations run on hydroelectric, natural gas or renewable power Implementing First 100% Natural Gas Fleet in Canada • Reduces completions CO e emissions by 20% 2 • Reduces diesel consumption by >3 MM gallons / year “We have a proven track record and an eighteen-year history of sustainability reporting. We are driving strong performance today through multiple initiatives including tangible goal setting and company wide compensation alignment. Our ESG progress to-date has been outstanding and we are committed to continuing this performance.” Montney Peer OVV - Brendan McCracken – President & CEO Average Montney 29 1) Montney Peers include AAV, ARX, BIR, CR, PIPE, and TOU. 2021 peer data used where reported. Where 2021 peer data has not been published, 2020 used

Canadian Midstream and Marketing Jim Zadvorny – VP Marketing

CANADIAN MIDSTREAM AND MARKETING Montney Natural Gas and the AECO Market Very Liquid Natural Gas Market ~17 Bcf/d physical supply & substantial daily trading volume P AECO Natural Gas Strong In-Basin Demand Growth ~3% 5-yr growth CAGR or ~1 Bcf/d additional demand by ’27 P Marketing “101” Multiple & Growing Export Options 5 long-haul export pipelines today (>10 Bcf/d) P + LNG Canada in ’25 (~2 Bcf/d), proposed add’l ~4 Bcf/d by ~’30 Gas Marketing Exported via Pipe ~40% OVV Montney is Delinked from AECO Prices 2 ~60% Dynamics Today In-Basin Demand 1 >90% of Our Montney Gas is Priced Outside of AECO Firm Transportation Exiting AECO To other price hubs - Dawn, Malin, Sumas and Chicago P OVV AECO Price Financial Hedges Moves exposure from AECO to NYMEX P Management Balanced Residual AECO Sales Volumes Between monthly and daily sales prices P 1) Reflects 2023 – 2025 and assumes flat 2022 volumes 31 2) 2021 annual average

CANADIAN MIDSTREAM AND MARKETING Western Canadian Natural Gas Dynamics 2 Western Canadian Gas Supply & Demand (Bcf/d) Growth Basin Gas Prices ($/MMBtu) In-Basin Natural Gas Demand Other LNG Waha Pipeline Export Capacity Production Dominion Appalachia LNG Canada AECO 25 Additional Proposed LNG Fixed-Price AECO trades LNG Canada like other export basins 1 2 Bcf/d online ~’25, (Ph 1, >60% Complete) 20 2 Bcf/d online ~’30 (Ph 2) 15 Multiple Pipe Export Options 5 export pipelines today 10 In-Basin Demand Growth 5 ~3% CAGR in-basin growth for next 5 yrs Driven by oil sands and power Settled Forward 0 1) Completion progress from LNG Canada Project Mid-Year Update, Summer 2022, July 28, 2022 32 2) Market data as of September 15, 2022 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

CANADIAN MIDSTREAM AND MARKETING Diversifying & Managing AECO Exposure Montney / WCSB Gas Export Infrastructure NGTL Legend System Station 2 (AECO) Added Capacity on Kitimat TC Energy Alliance to Chicago Northern Border (begins Nov 1, 2022) Empress Alliance GTN Emerson Westcoast Sumas Coastal GasLink Market Hub LNG Terminal Malin Dawn Chicago Incremental Market Access Announced in 2Q22 Incremental Transport to Chicago Supports Price Diversification • Direct flow, Montney plant outlets to Chicago on Alliance • Supplements access to Dawn, Malin and Sumas 1 • >10-year term beginning Nov 1, 2022 @ 245 BBtu/d Enhances Margins • By accessing premium markets in the U.S. Midwest 33 Note: Physical transport volumes represent transport receipt volume 1) Volumes converted to Mcf at a 1:1 ratio from MMBtu

CANADIAN MIDSTREAM AND MARKETING OVV Montney is Delinked from ’23-’25 AECO 1 2 2023-2025 Montney Price Exposures 2023-2025 AECO Sensitivity AECO Sensitivity Assumption ~50% % of NYMEX ~65% Pre-Hedge Realization Physical Transport Outside AECO ~80% Chicago Montney % of NYMEX Post-Hedge Realization ~90% Montney % of NYMEX ~25% Covered by AECO Basis Hedges Malin NYMEX Updated Since 2Q22 Earnings (AECO Basis Compelling realizations even if AECO Sumas Hedges) remains weak / 50% of NYMEX P >90% Priced outside of AECO Dawn AECO Firm transport supplemented by attractive financial hedges P <10% Exposed to AECO Note: All physical transport volumes represent Transport Receipt Volume and transport volumes are converted to Mcf at 1:1 ratio from MMBtu. Physical transport extends beyond 2025 34 1) Assumes flat 2022 volumes 2) Scenario shows 2023-2025 average realizations at 3Q22 NYMEX, AECO, downstream market prices and AECO hedges as of September 15, 2022. Post-hedge realizations include AECO basis hedges only

CANADIAN MIDSTREAM AND MARKETING Canadian West Coast LNG Export Potential 3 Proposed Export Facilities (Bcf/d) FID taken on ~2 Bcf/d & >6 Bcf/d possible by 2030+ • LNG Canada Phase 1, ramp-up expected to begin ~1Q25 (>60% 6.5 1 complete) Ksi Lisims LNG • First feeder pipeline (Coastal GasLink) complete in ‘23 Cedar LNG • Represents ~1/3 of WCSB gas production Woodfibre LNG 5.5 LNG Canada Phase 2 Supported by Substantial Resource Potential 2 • >26k of total Montney basin locations with breakeven of <$3/Mcf LNG Canada Phase 1 4.5 OVV Well Positioned to 3.5 Benefit from Western Canada LNG 2.5 1.5 >30-Years Premium Montney Gas Window LNG Canada Under Construction Today Inventory with Prolific Economics 1 Phase 1 60% Complete P 0.5 Substantial In-Place Midstream Infrastructure with Access to LNG 2024 2025 2026 2027 2028 2029 2030+ P 1) Completion progress from LNG Canada Project Mid-Year Update, Summer 2022. July 28, 2022 2) Enverus, Montney Play Fundamentals: Drill for Years with No Inventory Fears, July 2022 35 3) Volumes are estimated feedgas requirements

CANADIAN MIDSTREAM AND MARKETING Strong Condensate Market Fundamentals 1 2 Captive Demand Growth (Mbbls/d) Montney Condensate Competes with WTI ($/bbl) Required Condensate Imports to Meet Demand WTI Montney Condensate Domestic Condensate Production High & growing import ~6% 5-yr Import requirement Demand CAGR Even with domestic production growth 3 OVV & Market Realizations ~100% OVV & Broader Market Condensate Realizations vs. WTI Jul Nov Mar Jul Nov Mar Jul Nov Mar Jul 2019 2019 2020 2020 2020 2021 2021 2021 2022 2022 1) Canada Energy Regulator, December 2021 (Current Policies case) 2) Montney Condensate: ICE C5 1a + NYMEX Calendar Basis Swap. WTI: WTI Calendar Basis Swap. Market data as of September 15, 2022 36 3) OVV realizations reflect average unhedged condensate realizations from 1Q21 – 2Q22 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Closing Remarks & Q&A Brendan McCracken – President & CEO

CLOSING REMARKS & Q&A Today’s Key Takeaways Basin has substantial resource in The Montney Basin place and commodity optionality P is World Class We hold 260K net premium acres Our Montney Position is with deep inventory runway P Best of the Best Unmatched operations and culture of Setting Leading Edge innovation & we are maximizing P Operations & Marketing the value of our production Actively paying down debt & returning We Are Delivering cash to shareholders P Our Strategy 38

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 Ovintiv Inc. (“the Company”) 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 is 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, by their nature, involve numerous assumptions and 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: future commodity prices and basis differentials; future foreign exchange rates; the ability of the Company to access credit facilities and shelf prospectuses; data contained in key modeling statistics, including type curves; 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; 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; 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 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, NGL and natural gas; availability of equipment, services, resources and personnel required to perform the Company’s operating activities; 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 (such as the COVID-19 pandemic) on commodity prices and the Company’s operations; our ability to secure adequate transportation and storage for oil, NGL and natural gas, as well as access to end markets or physical sales locations; interruptions to oil, 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, NGLs and natural gas production and the resulting impacts on oil, 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 1A. Risk Factors 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 periodic 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 in this presentation and all subsequent forward-looking statements attributable to the Company, whether written or oral, are expressly qualified by these cautionary statements. 39

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. Reserves are the estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on an analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are those reserves which can be estimated with a high degree of certainty to be recoverable. All reserves estimates referenced in this presentation are effective as of December 31, 2021 and prepared by qualified reserves evaluators in accordance with United States Securities and Exchange Commission (“SEC”) regulations. Detailed U.S. protocol disclosure, as well as additional information relating to risks associated with the estimates of reserves, is contained in the Company’s most recent Annual Report on Form 10-K and other filings we make with the SEC. 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. These measures have been provided for meaningful comparisons between current results and other periods and should not be viewed as a substitute for measures reported under U.S. GAAP. For additional information regarding non-GAAP measures, including reconciliations, see the Company’s website under the Investors tab and Ovintiv’s most recent Annual Report on Form 10-K and other filings on SEDAR and EDGAR. This presentation contains references to non-GAAP measures as follows: • Non-GAAP Cash Flow, Non-GAAP Free Cash Flow and Non-GAAP Free Cash Flow Yield – Non-GAAP Cash Flow (or Cash Flow) is defined as cash from (used in) operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and current tax on sale of assets. Non-GAAP Free Cash Flow (or Free Cash Flow) is Non-GAAP Cash Flow in excess of capital expenditures, excluding net acquisitions and divestitures. Non-GAAP Free Cash Flow Yield is annualized Non-GAAP Free Cash Flow compared to current market capitalization. Management believes these measures are useful to the company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, and are an indication of the company’s ability to generate cash to finance capital programs, to service debt and to meet other financial obligations. These measures may be used, along with other measures, in the calculation of certain performance targets for the company’s management and employees. Due to the forward-looking nature of projected free cash flow used herein, 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 a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Amounts excluded from this non-GAAP measure in future periods could be significant. • Upstream Operating Cash Flow, excluding Risk Management and Upstream Operating Free Cash Flow – Upstream Operating Cash Flow, excluding Risk Management is a measure that adjusts the USA and Canadian Operations revenues for production, mineral and other taxes, transportation and processing expense, operating expense and the impacts of realized risk management activities. It is calculated as total upstream operating income excluding upstream depreciation, depletion and amortization, and the impact of risk management activities. Upstream Operating Free Cash Flow is defined as Upstream Operating Cash Flow, excluding Risk Management, in excess of upstream capital investment, excluding net acquisitions and divestitures. Management monitors these measures as it reflects operating performance and measures the amount of cash generated from the Company’s upstream operations. • Net Debt, Adjusted EBITDA and Net Debt to Adjusted EBITDA – Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents. Management uses this measure as a substitute for total long-term debt in certain internal debt metrics as a measure of the company’s ability to service debt obligations and as an indicator of the company’s overall financial strength. Adjusted EBITDA is defined as trailing 12-month net earnings (loss) before income taxes, DD&A, 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. Net Debt to Adjusted EBITDA is monitored by management as an indicator of the company’s overall financial strength. 40

CLOSING REMARKS & Q&A Executing Our Business Plan Returns Based Strategy Industry-Leading Value Proposition Delivering Value to our P Superior ROIC and return of cash to our shareholders Shareholders 1 Returning Material Cash to Shareholders P 2 ~$1B of shareholder returns in ‘22 & expected to more than double in ‘23 Ŧ Rapid Net Debt Reduction P Ŧ 2 $3.0 B Net Debt to be achieved in ‘22 Operational Excellence P Leading capital efficiency 3 Market Cap Reserve Life Index 2Q22 Production 1-Yr TSR ($B) (Years) (MBOE/d) (%) Culture of Innovation P D&C execution, supply chain sophistication, cube development OVV $13 75% >11.5 >500 Top Tier Multi-Basin Portfolio P NYSE & TSX ~2.3 BBOE 52% Liquids >10-yrs premium inventory & multi-product commodity exposure 1P Reserves Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website under the Investors tab. Note: ROIC reflects Return on Invested Capital. Market data as of September 15, 2022 1) Cash returns include base dividends and share buybacks 2) Assumes $100 WTI & $8.00 NYMEX in 3Q22-4Q22 41 3) Bloomberg market data. Reflects reinvested dividends

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Appendix

APPE N D I X OVV Montney Type Curve Details Type Curve Window Details Oil & Condensate Gas IRRs $55 WTI & $2.75 NYMEX 65% 64% Strip (9.13.22) >200% >200% EUR - MMBOE (% Liquids) 1.1 (30%) 2.5 (10%) Gas Shrink / Yield Shrink % 10% 10% 1 NGL Yield BBLs / MMCF 18 bbls 15 bbls 2023 DCFT Costs - $/ft ~$550 ~$525 Inventory Net 10K Locations remaining ~600 ~1,025 Years >10 years >30 years WI - % 60% BC / 100% AB 60% BC / 100% AB 2 Royalty (Avg. All Products) $55 & $2.75 7% 6% 3 Strip 16% 16% Note: All well data normalized to 10,000 ft. IRRs represent ATAX returns 1) BBLS / MMCF vs. Raw gas volumes. Yield reflects all products (C2 – C5+) 44 2) Royalties assume AECO benchmark pricing is approximately 80% of NYMEX 3) Reflects Strip as of September 15, 2022

APPE N D I X Ample Midstream Access & Optionality Ovintiv’s Montney Midstream Infrastructure Gas Midstream Running Room • 9 gas processing facilities • > 1.5 Bcf/d of inlet processing capacity (BC/AB) Legend • Allows for volume growth in the medium-to-long term TC Energy Alliance Gas Connectivity to Multiple Pipeline Systems Westcoast 1 • Connected to NGTL, Alliance, Westcoast and LNG header Coastal GasLink • Flexibility / redundancy to mitigate maintenance / market conditions • Proximity and connectivity to LNG provides future optionality Ample Processing Capacity Flow Assurance P Ample liquids handling and market egress Access to Multiple Pathways Flexibility P capacity Out of the Basin • Reliable / flexible access rights Connection to LNG Header Upside P • Allows for volume growth in the medium-to-long term 45 1) Connection to LNG header pending completion of Coastal GasLink

APPE N D I X Montney Natural Gas Realizations 1 1 Gas Unhedged % of AECO Gas Unhedged % of NYMEX 150% ~127% 150% ~95% 1Q21 – 2Q22 Average 1Q21 – 2Q22 Average 140% 140% 130% 130% 120% 120% 110% 110% 100% of AECO 100% of NYMEX 100% 100% 90% 90% 80% 80% 70% 70% 60% 60% 50% 50% 1Q21 2Q21 3Q21 4Q21 1Q22 2Q22 1Q21 2Q21 3Q21 4Q21 1Q22 2Q22 46 1) Montney only

APPE N D I X Montney Other NGL (C2-C4) Realizations 1 NGL Unhedged % of WTI Montney NGL Unhedged % of Conway 1Q21-2Q22 Montney Ethane (C ) ~160% 100% of WTI 2 100% Montney Propane (C ) ~80% 3 Montney n-Butane (nC ) ~60% 90% 4 Montney iso-Butane (iC ) ~50% 4 80% 70% ~44% 2 Montney NGL Volume by Component 1Q21 – 2Q22 Average 60% Ethane Propane 50% Butane 40% 30% 20% 10% 0% 1Q21 2Q21 3Q21 4Q21 1Q22 2Q22 47 1) Montney only 2) Based on 1Q21-2Q22

APPE N D I X Montney Gas Pricing Details 3Q22 4Q22 2023 2024 2025 1 Physical Firm Transport ~70% 3Q22 Pre-hedge Montney Dawn 330 330 330 330 330 Natural Gas Sumas 21 21 21 21 21 3 Realizations ~80% Malin 113 113 113 113 113 Total Ovintiv Chicago 71 186 245 245 245 Total FT 535 650 709 709 709 2023-2025 3Q22 4Q22 2023 2024 2025 Transport & hedges insulate against AECO 2 P AECO Basis Swaps weakness Volume MMcf/d 0 0 260 190 190 ~90% post-hedge realizations even if AECO Price $/Mcf - - ($1.07) ($1.08) ($1.08) P is ~50% of NYMEX 2 AECO % of NYMEX Swaps Hedges bridge to LNG ramp-up beginning in Volume MMcf/d 200 137 50 100 100 P 2025 % of NYMEX 70% 65% 71% 72% 72% 1) All physical transport volumes represent Transport Receipt Volume and transport volumes are converted to Mcf at 1:1 ratio from MMBtu. Physical transport extends beyond 2025 48 2) As of September 15, 2022 3) Percent of NYMEX

APPE N D I X Track Record of Environmental Leadership Achieved 24% Reduction Through ’21; Gross Annual Scope 1&2 P Reduction of >2 MM Metric Tons of CO e 2 GHG Intensity 50% 1 Intensity Reduction Tied to Compensation For All Employees Reduction Target P (from ‘19 – ‘30) >50% Methane Intensity 2 2022 Sustainability P Reduction in ‘21 vs. ‘19 Leading LDAR Program Replacing High-Bleed Devices Report Out Venting & Flaring (<0.4% FY21 & YTD22) Real-time Emissions Tracking th Fully Aligned TCFD SASB 18yrs 8 with World Bank’s Zero Reporting Aligned with Task Utilizing Sustainability of Transparent Consecutive Safest Routine Flaring Initiative Force on Climate-related Accounting Standards Sustainability Reporting Year in ‘21 (9-yrs ahead of WB’s 2030 Target) Financial Disclosure (TCFD) Board (SASB) guidance 49 1) Measured in Tons CO e / MBOE 2 2) Measured in Tons CH / MBOE 4

APPE N D I X OVV is the Montney’s Largest Operator Top 10 Montney E&Ps By Production Gross Operated Production (BCF/d) Benefits Of Montney Scale 1.5 Capital efficient development P Effective supply chain management P Accelerated learning curve P 1 OVV Operates 0.5 Mitsubishi’s Portion of Cutbank Ridge Partnership 0 OVV ARC TOU CNQ PETRONAs SHELL Advantage Birchliff MUR Pacific Montney is highly concentrated with the Top 5 companies controlling >65% of the production 50 Note: Production data for gross operated over last 12 month average