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Obsidian Energy Ltd. Corporate Presentation January 2026
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OVERVIEW 2 Q3 2025 Production 27,316 boe/d Q3 2025 Annualized Funds Flow from Operations (FFO) $199 million Q3 2025 Annualized Net Debt to FFO 1.1x Shares Outstanding 67.3 million Market Capitalization $628 million Q3 2025 Net Debt $219 million Enterprise Value $847 million 2024 2P Pro Forma Reserves 149 million boe 2024 2P Pro Forma NPV10% at US$70/bbl WTI $1,799 million 2P Pro Forma Net Asset Value $22.49/sh Focused asset base with experienced team delivering value P E A C E R I V E R 13,503 boe/d Cold flow heavy oil V I K I N G 1,156 boe/d Light oil conventional development W I L L E S D E N G R E E N & P C U # 1 1 Q3 2025 27,316 boe/d 12,401 boe/d Light oil conventional development 2See endnotes and non-gaap measure advisory for additional information
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High Quality Assets Extensive land base with multiple productive horizons in both our core regions of Peace River and Willesden Green Strong EOR potential to reduce sustaining capital and realize full value from life of assets Grow intrinsic value of business via land sales, farm-ins and targeted bolt-on transactions Operational Excellence Proven technical expertise and knowledge of subsurface assets drives new well designs and improved returns Safety-first culture with strong community engagement Shareholder Focused Focused on per share growth via production additions, share buybacks and debt reduction Return of capital via share repurchases OBSIDIAN ENERGY STRATEGY 3 Focus on superior execution to deliver results and create value for shareholders Unlock the potential of our heavy and light oil assets, maintain operational excellence, and execute on share repurchase program to drive top quartile total shareholder returns
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RETURNING CAPITAL TO SHAREHOLDERS 4 0 5 10 15 20 25 30 35 40 0 5 10 15 20 25 30 35 Q1 21 Q1 22 Q1 23 Q1 24 Q1 25 Production (boe) per share (000s) Production (Mboe/d) CORPORATE PRODUCTION (Excluding fields included in Pembina Disposition) Production excluding Disposition Production per Share Opportunistic share buyback program under NCIB enhances growth profile 8% total production CAGR since Q1 23 18% production per share CAGR since Q1 23 NCIB implemented Feb 2023 • Over 20% of shares repurchased/cancelled (~17.2 million shares) since the implementation of our NCIB program in February 2023 • Fully utilized current NCIB in August 2025, we plan to renew program in March 2026 67% Utilized 61% Utilized 100% Utilized 0 2 4 6 8 Feb23-Feb24 Feb24-Feb25 Mar25-Mar26 Shares Cancelled (million) NCIB REPURCHASES See endnotes for additional information
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H1 Highlights • Peace River focused $169 million capital program, including ~$27 million for exploration/appraisal and waterflood projects • Active development program continued in HVS and Dawson, resulting in 19 (17.4 net) wells rig released • First Clearwater waterflood pilot with strong primary production results on the 3 (3.0 net) producing wells. Water injection initiated in August 2025 on two (2.0 net) injectors Q3 Highlights • $65 million capital program focused on Peace River, where 16 (16.0 net) wells were rig released, compared with two (2.0 net) wells in Willesden Green • Initiated water injection on a two (2.0 net) well Dawson waterflood pilot and two (2.0 net) well HVS waterflood pilot • First Belly River well at Crimson with an IP30 of 509 boe/d (76% oil) 2025 OPERATIONAL HIGHLIGHTS 5 Unlock future asset potential H2 2025 capital expenditures balance between Peace River and Willesden Green development Q4 Highlights • Peace River • Rig-released five (5.0 net) Clearwater development wells and two (2.0 net) Clearwater injector wells to expand our Dawson waterflood pilot • Brought on production six (6.0 net) Clearwater wells in Dawson and Peavine with encouraging rates • Willesden Green • Two (2.0 net) Belly River drilled wells in Open Creek, following up the success in the area in 2024 • Drilled and completed four (4.0 net) Cardium wells in Open Creek, which we plan to have on production in February 2026 • Completion of infrastructure project in late 2025 which was brought into service in early 2026, which connects the under exploited Open Creek field into our regional infrastructure system
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Completed Pembina Disposition • Sold operated Pembina assets in April 2025 for proceeds of $320 million • In August 2025, sold all IPO shares received as part of consideration in disposition, additional $6 million of value • Reduced inactive and active ARO by 57% and 48%, respectively Renewed Credit Facility • Extended $235 million credit facility into 2027 Refinanced Senior Notes • Closed $175 million senior note issuance at 8.125% due in 2030, significantly lower interest rate than previous notes at 11.95% • Used proceeds to fully repay previous notes and pay down outstanding amount on credit facility 2025 FINANCIAL HIGHLIGHTS 6 Buyback shares and maintain low leverage ratios Significant decrease in net debt in 2025 combined with active share buyback program Return of Capital to Shareholders • Fully utilized NCIB program as of August 31, 2025, purchased and cancelling ~7.6 million shares for $54.8 million in 2025 • Company expects to renew NCIB when up for renewal in March 2026 Prepaid Equity Forward Program • In Q3, began prepaid equity forward program with the purchase of ~3.7 million shares up to January 21 • The Company anticipates being active under this program in Q1 2026 See endnotes for additional information
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2026 GUIDANCE 7 Advance delineation and development in both our heavy and light oil areas Disciplined approach to 2026 given commodity price volatility with optionality to expand capital program in a higher price environment Heavy Oil Light Oil Based on midpoint Average production boe/d 12,700 16,200 Capital expenditures1 $ millions 80 128 Net operating costs $/boe 20.20 10.05 Netback $/boe 19.00 30.45 Net operating income $ millions 88 180 Asset level FCF $ millions 8 52 2026E Average production boe/d 27,900 – 29,900 Capital expenditures $ millions 190 – 230 Decommissioning expenditures $ millions 7 – 11 Net operating costs $/boe 14.00 – 15.00 General & administrative $/boe 2.00 – 2.10 Based on midpoint of above guidance FFO $ millions 225 FFO per share (basic) $/share 3.35 FCF $ millions 7 FCF per share (basic) $/share 0.10 Net Debt $ millions 272 Net Debt to FFO times 1.2 Pricing assumptions WTI (January – June) US$/bbl 58.00 WTI (July – December) US$/bbl 62.00 Foreign exchange $CAD/$USD 1.38 MSW differential US$/bbl 3.50 WCS differential US$/bbl 13.50 AECO CAD$/GJ 2.75 Sensitivity Range Change in 2026E FFO ($millions) WTI +/- US$1.00/bbl 9.4 Foreign Exchange Rate +/-$0.01/CAD/USD 3.4 MSW differential +/- US$1.00/bbl 3.6 WCS differential +/- US$1.00/bbl 6.1 AECO +/- CAD$0.25/GJ 1.6 1. Excludes environmental and corporate capital at asset level See endnotes for additional information
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2026 CAPITAL PROGRAM 8 Balanced capital program while furthering our waterflood initiatives in Peace River Further delineation in Belly River, while strategically prioritizing Clearwater injectors in H1 while focusing on Bluesky development in H2 1. Including the last well of our 2025 program rig released on January 2, 2026 2. In addition, Obsidian Energy expects to participate in 10 (4.5 net) non-operated wells in 2026 Development Appraisal Injector 2026E Gross (Net) Wells DEVELOPMENT WELLS Heavy Oil Assets H1 Peace River (Bluesky) 1 (1.0) 1 (1.0) - 2 (2.0) H1 Peace River (Clearwater)1 8 (8.0) - 7 (7.0) 15 (15.0) H2 Peace River (Bluesky) 7 (7.0) - - 7 (7.0) H2 Peace River (Clearwater) - 1 (1.0) 1 (1.0) 2 (2.0) Light Oil Assets H1 Willesden Green (Belly River) 5 (5.0) - - 5 (5.0) H1 Willesden Green (Cardium) - - - - H2 Willesden Green (Belly River) 3 (3.0) - - 3 (3.0) H2 Willesden Green (Cardium) 4 (4.0) - - 4 (4.0) Total Operated Wells2 28 (28.0) 2 (2.0) 8 (8.0) 38 (38.0) P E A C E R I V E R W I L L E S D E N G R E E N V I K I N G
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Nampa Cadotte Walrus Seal Main Gift Lake Dawson Peavine West Dawson Peace River T77 R12 W5 HVS • Large, contiguous, long-term land base of >700 sections with Bluesky and Clearwater heavy oil rights • New development fields at Dawson (Clearwater) and Walrus (Bluesky) • Extensive owned infrastructure and multiple sales points • Dominant owned road network and gas infrastructure position with ~70% of available gas facilities • Growing inventory of booked and unrisked locations for future growth • Simultaneous drilling and equipping operations reduce production cycle times Ownership in high-quality Bluesky and Clearwater heavy oil resource provides upside for future growth PEACE RIVER ASSET 9 Highly economic plays with significant scale See endnotes for additional information; see ‘Well Economics’ for area economics <1.0 years Payout (2P) 160 2P locations (2024, net) 7.9 RLI (2P 2024, years) 99% WI (operated) 13,503 boe/d (Q3 2025 production) 24% decline rate (PDP, 3-year average)
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PEACE RIVER ASSET 10 Asset transformation Expanded holdings, increased production and established new Bluesky and Clearwater development fields December 2021 (post 45% WI PROP acquisition) 2025 (as at September 30)2021 2025 4,891 (Dec./21)1 Average production (boe/d) 13,503 (Q3 2025) 473 (year-end 2021) # net sections >700 (Q3 2025) ~34 # producing net sections ~105 26 Bluesky 1.5 Clearwater (year-end 2021) # booked locations (2P, net) 63 Bluesky 97 Clearwater (year-end 2024) BLUESKY 6 dev. # wells in program 14 dev. 3 exp./app. 4,890 (Dec./21) Average production (boe/d) 8,649 (Q3 2025) CLEARWATER 4 exp./acq. # wells in program 25 dev. 4 exp./app. 2 (Dec./21) Average production (boe/d) 4,854 (Q3 2025) 1. December 2021 average production includes ~2,200 boe/d from the acquisition of the remaining 45% interest of the Peace River Oil Partnership C A D O T T E Cadotte HVS Nampa Cadotte Walrus Seal Main Gift Lake Dawson Peavine West Dawson Peace River T77 R12 W5 HVS Peace River T77 R13 W5
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Nampa Cadotte Walrus Seal Main Gift Lake Dawson Peavine West Dawson Peace River T77 R12 W5 HVS GIFT LAKE • 2025 H1: 1 exploration/appraisal well NAMPA • Mapping indicates large development potential with stacked pay potential through multiple zones • 2025 H1: 3 exploration/appraisal wells • 2025 H2: 1 development well WALRUS • New 2024 field for continued development • 2025 H1: 2 (1.8 net) development wells DAWSON/PEAVINE • Production rates above initial internal well type economics • Substantial opportunity for future growth • 2025 H1: • 7 development wells • 2 injector wells • New Clearwater waterflood pilot • 2025 H2: • 18 development wells • 2 injector wells drilled HARMON VALLEY SOUTH • Long-life producing field • Extension of main, proven, productive pool • 2025 H1: • 8 (7.3 net) development wells • 2 exploration/appraisal wells • 2025 H2: • 2 development wells drilled in Q3 • 2025 H1: 1 exploration/appraisal well SEAL • Stacked pay potential through multiple zones • 2025 H1: 2 (1.3 net) development wells ~99% ownership in wells allows for ability to control pace of development PEACE RIVER 2025 CAPITAL PROGRAM 11 46 (44.4 net) development and appraisal/delineation wells Bluesky Clearwater See endnotes for additional information
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Willesden Green (Cardium/Belly River/Mannville) • A high-grade light oil field with proven Cardium and emerging Belly River success • Increased working interest in Willesden Green Cardium Unit #2, with strong drilling results from 2023 and 2024 programs • Significant reserve-based inventory of compelling drilling opportunities across extensive operated land base • Flexible operated infrastructure provides options to maximize production across the area Pembina Cardium Unit #11 (Cardium, Non-operated) • Strong rates and production additions from development programs • Provides FCF and returns for reinvestment in operated properties Viking • Shallow, low-risk, highly economic resource play with high impact development programs • Drill ready inventory provides optionality for our portfolio LIGHT OIL ASSETS 12 History of highly economic returns with years of low-risk inventory 10,481 1,156 1,920 LIGHT OIL ASSETS PRODUCTION ( Q 3 2 0 2 5 , b o e / d ) Willesden Green Viking PCU#11 (non-operated) V i k i n g 118 net booked 2P Cardium locations 50 net booked 2P Viking locations W i l l e s d e n G r e e n P C U # 1 1 T49 R4 W5 T31 R1 W4 See endnotes for additional information
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Cardium • Open Creek field has limited horizontal Cardium development to date • Consolidated to ~100% working interest in Willesden Green Cardium Unit #2 as part of recent acquisition Belly River • Development is rapidly evolving with widespread industry activity in area • We drilled our first Belly River well at Crimson, which was brought on production in early October • 12-21 pad – 1 (1.0) well with strong initial rates with an IP30 of 509 boe/d (76% oil) • Two wells brought on production in Belly River at Open Creek in Q4 • 06-33 pad – 2 (2.0) wells with improving production rates after prolonged clean-up, recent 10-day average of 418 boe/d (80% liquids) per well with IP30 average of 199 boe/d (86% oil) per well Infrastructure • Completed project to expand and integrate Open Creek field in late 2025, in service early 2026. New pipeline and facilities will support concurrent and efficient development of Belly River and Cardium WILLESDEN GREEN ASSET 13 Underexploited Cardium at Open Creek with Belly River upside See endnotes for additional information; see ‘Well Economics’ for area economics Existing Cardium Existing Belly River Proposed 2H25 OBE Open Creek Q4 2025 OBE Belly River Q4 2025 OBE Cardium Q4 2025 OBE Mannville OBE 15-06 Belly River Existing Gas Plant Crimson <0.9 years Payout (2P) 94 2P locations (2024, net) 17.0 RLI (2P 2024, years) INF Project T45 R6 W5 74% WI (operated) 10,481 boe/d (Q3 2025 production 17% decline rate (PDP, 3-year average) OBE 12-21 Belly River
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HEDGING PROGRAM 14 Risk management program to preserve cash flow F X F O R WA R D CO N T R AC T S ( U S D / C A D ) • January 2026 - $2.5M CAD @ $1.3840 • February 2026 - $3.0M CAD @ $1.3842 • March 2026 - $3.0M CAD @ $1.3842 6,127 $84.12 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Jan-26 Oil Swaps W T I O I L H E D G E S ($, bbl/d) 50% hedge level 26,540 34,360 1,896 $3.30 $2.71 $3.73 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 2025 - 2026 Winter 2026 Summer 2026 - 2027 Winter Gas Swaps A E CO G A S H E D G E S ($, mcf/d) P R E PA I D E Q U I T Y F O R WA R D CO N T R AC T S • September 2028 – 720,000 @ $8.89 • October 2028 – 1,300,000 @ $8.72 • November 2028 – 550,000 @ $8.43 • December 2028 – 715,000 @ 8.31 • January 2029 – 390,000 @ $8.70 Disciplined approach to risk management to protect cash flows for capital investment, debt repayment and return of capital 50% hedge level
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Proved Developed Producing (PDP) Total Proved (1P) Total Proved Plus Probable (2P) Light and medium crude oil 33 MMbbl 59 MMbbl 81 MMbbl Heavy crude oil and bitumen 15 MMbbl 28 MMbbl 47 MMbbl Natural gas liquids 8 MMbbl 16 MMbbl 22 MMbbl Conventional natural gas 177 Bcf 297 Bcf 424 Bcf Total reserves 85 MMboe 151 MMboe 221 MMboe NPV10% (US$60 WTI) $1,078 million $1,317 million $1,808 million NPV10% (US$70 WTI) $1,370 million $1,807 million $2,476 million NPV10% (US$80 WTI) $1,642 million $2,294 million $3,121 million Pro forma reserves (post Pembina Disposition) 53 MMboe 99 MMboe 149 MMboe NPV10% (US$60 WTI) $732 million $942 million $1,336 million NPV10% (US$70 WTI) $913 million $1,271 million $1,799 million NPV10% (US$80 WTI) $1,081 million $1,593 million $2,240 million RESERVES UNDERPIN OUR CURRENT AND FUTURE VALUE 15 YE AR -END 2024 AND PRO FORMA RESERVES SUMMARY Trading at substantial discount on booked reserves basis Focus on growing per share metrics to increase shareholder value • Flat price decks using WTI pricing as noted and assuming US$12.50 WCS differential, US$3.50/bbl MSW differential, C$2.00/GJ AECO and FX of 1.38x USD/CDN • Pro forma net asset value/share includes the ~$91 million received from the monetization of our InPlay shares 9.33 7.31 9.88 12.28 10.68 15.21 19.65 16.11 22.49 28.57 $0 $5 $10 $15 $20 $25 $30 (C$ per share) P R O F O R M A N E T A S S E T V A L U E / S H A R E Current Share Price PDP 1P 2P US$80 WTIUS$60 WTI US$70 WTI 71 76 79 85 114 127 133 151 148 181 194 221 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 0 50 100 150 200 2021 2022 2023 2024 G R O W T H I N R E S E R V E S PDP 1P 2P Reserves/share (2P, basic shares) (MMboes) See endnotes for additional information
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WHY INVEST IN OBSIDIAN ENERGY 16 • Strategy directed to unlocking asset potential to drive future production and funds flow per share growth while continuing to return capital to shareholders • Low decline, oil-weighted asset base with significant underlying reserves • Trades at a significant discount in both reserve values and cash flow multiples compared to peers • Substantial share buyback program through the NCIB • Purchased and cancelled >20% of shares outstanding since inception of the NCIB to August 31, 2025 (~17.2 million shares for $143.9 million) • Significant tax pools allow for Obsidian Energy to be a non-cash taxpayer for ~10 years at US$70.00/bbl WTI • Dedicated to making a positive difference to stakeholders and communities where we live and work Peace River growth combined with established light oil assets offers shareholder upside Unlocking asset potential while maintaining operational excellence and returning capital to shareholders FOCUSED STRATEGY SUBSTANTIAL RESERVES & RESULTS DIFFERENTIATED VALUE PROPOSITION RETURNING SHAREHOLDER CAPITAL SIGNIFICANT TAX POOLS STAKEHOLDER FOCUSED OPERATOR See endnotes for additional information
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Appendix 17
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DELIVERING RESULTS 18 Strategy and execution create momentum for long-term value creation 2024 Q1 2025 Q2 2025 Q3 2025 WTI US$/bbl $75.72 $71.42 $63.74 $64.93 AECO $/GJ $1.36 $2.06 $1.60 $0.57 Production boe/d 37,474 38,416 28,943 27,316 Capital expenditures $ millions $343.1 $128.4 $40.2 $65.3 Decommissioning expenditures $ millions $23.9 $6.6 $4.0 $7.9 Net operating costs $/boe $13.85 $15.72 $13.54 $15.01 Netback $/boe $35.45 $33.10 $27.13 $24.90 General & administrative $/boe $1.50 $1.61 $1.92 $1.95 FFO $ millions $432.0 $100.1 $65.8 $49.7 FFO/share (basic) $ per share $5.69 $1.36 $0.94 $0.74 FCF $ millions $65.0 ($34.9) $21.6 ($23.5) FCF/share (basic) $ per share $0.86 ($0.47) $0.31 ($0.35) Net Debt $ millions $411.7 $459.9 $270.2 $219.3 Net Debt to FFO (annualized) times 1.0 1.1 1.0 1.1 * Sold ~11,000 boe/d of production on April 7, 2025, in Pembina disposition * Sold ~11,000 boe/d of production on April 7, 2025, in Pembina disposition See endnotes and non-gaap measure advisory for additional information 37 38 29 27 29 0 50 100 150 200 0 10 20 30 40 2024 Q1/25 Q2/25* Q3/25 Q4/25E Ann. Production (boe) per share (000s) Production (Mboe/d) CORPORATE PRODUCTION Production per Share $412 $460 $270 $219 $235 0.0 0.5 1.0 1.5 2.0 2.5 0 100 200 300 400 500 2024 Q1/25 Q2/25* Q3/25 Q4/25E Net Debt / FFO Net Debt ($ million) NET DEBT Net Debt/FFO
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H2 2025 GUIDANCE 19 Capital program and guidance Balanced capital allocation between Peace River and Willesden Green assets to set the stage for future growth when commodity prices improve Heavy Oil Light Oil Based on midpoint Average production boe/d 13,900 14,150 Capital expenditures1 $ millions 64 58 Net operating costs $/boe 18.10 10.35 Netback $/boe 27.80 23.65 Net operating income $ millions 70 60 Asset level FCF $ millions 6 2 H2 2025E Average production boe/d 27,800 – 28,300 Capital expenditures $ millions 120 – 125 Decommissioning expenditures $ millions 14 – 15 Net operating costs $/boe 14.35 – 14.60 General & administrative $/boe 1.95 – 2.05 Based on midpoint of above guidance FFO $ millions 114 FFO per share (basic) $/share 1.70 FCF $ millions (23) FCF per share (basic) $/share (0.34) Net Debt $ millions 235 Net Debt to FFO times 1.0 Pricing assumptions WTI US$/bbl 60.00 MSW differential US$/bbl 4.00 WCS differential US$/bbl 11.50 AECO CAD$/GJ 2.75 Sensitivity Range Δ H2 2025E FFO ($millions) WTI +/- US$1.00/bbl 0.7 Foreign Exchange Rate +/-$0.01/CAD/USD 0.2 MSW differential +/- US$1.00/bbl 0.2 WCS differential +/- US$1.00/bbl 0.3 AECO +/- CAD$0.25/GJ 0.3 1. Excludes environmental and corporate capital at asset level See endnotes for additional information
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2025 CAPITAL PROGRAM 20 Development focused H2 2025 capital program in Peace River and Willesden Green Second half 2025 Peace River program focused on production growth and EOR, Willesden Green focus on core Cardium and emerging Belly River formations 1. Capital expenditures for the Pembina wells were paid by InPlay and included in the interim closing adjustments of the Pembina Disposition 2. In addition, Obsidian Energy participated in six (2.7) net non-operated wells in the first nine months of 2025 and anticipates participating in six (2.7) non-operated wells in the fourth quarter of 2025 3. The number of wells also excludes the two (2.0 net) Peace River single leg injector wells 4. OBE anticipates drilling an additional two (2.0 net) injectors in Q4 which are not included in the total Q1-Q3 2025 Gross (Net) Wells Q4 2025E Gross (Net) Wells 2025E Gross (Net) Wells DEVELOPMENT WELLS Heavy Oil Assets Peace River (Bluesky) 14 (12.4) - 14 (12.4) Peace River (Clearwater) 21 (21.0) 4 (4.0) 25 (25.0) Light Oil Assets Willesden Green (Cardium) - 4 (4.0) 4 (4.0) Willesden Green (Belly River) 1 (1.0) 2 (2.0) 3 (3.0) Willesden Green (Mannville) 1 (1.0) - 1 (1.0) Pembina (Cardium)1 4 (4.0) - 4 (4.0) 41 (39.4) 10 (10.0) 51 (49.4) EXPLORATION/APPRAISAL WELLS Peace River (Bluesky) 3 (3.0) - 3 (3.0) Peace River (Clearwater) 4 (4.0) - 4 (4.0) 7 (7.0) - 7 (7.0) Total Operated Wells2 48 (46.4)3 10 (10.0)4 58 (56.4) P E A C E R I V E R W I L L E S D E N G R E E N V I K I N G
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STRATEGIC PEMBINA DISPOSITION 21 • Sold operated Pembina assets in April 2025 for proceeds of $326 million including the monetization of the IPO share position in August 2025 Sales Metrics • ~10,300 boe/d production (2024 average production) • Received ~$31,600 boe/d on production value and 3.1x 2024 net operating income (prior to adjustments) Pro Forma Reduction of ARO (Q1/25) Rationalizes portfolio at a value accretive to our shareholders Obsidian Energy emerged as a significantly more focused Company with an ability to accelerate the shareholder value creation strategy See endnotes for additional information $415 million $214 million $332 million $143 million $747 million $357 million 52% less ARO Inactive ARO Active ARO T52 R4 W5 PCU #11 Willesden Green Pembina (Disposition)
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T48 R9 W5 • Large non-operated unit with 45% working interest, 35 gross sections • Historically underdeveloped area in the heart of the Pembina Cardium region with multi-year development agreement in place • Proven asset performance with repeatable development potential • Approximately 5x growth since 2022 PEMBINA CARDIUM UNIT #11 ASSET 22 Non-Operated unit with years of low-risk inventory See endnotes for additional information; see ‘Well Economics’ for area economics 0 1 2 3 4 5 6 7 Jan-22 Jul-22 Jan-23 Jul-23 Jan-24 Jul-24 Jan-25 Gross Production (mboe/d) GROSS PCU#11 PRODUCTION 45% WI (non-operated) 1,920 boe/d (Q3 2025 production 19% decline rate (PDP, 3-year average) See endnotes for additional information; see ‘Well Economics’ in Appendix for area economics <1.3 years Payout (2P) 24 2P locations (2024, net) 17.5 RLI (2P 2024, years)
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VIKING ASSET 23 History of unlocking reserves and production value • Sweet, light oil development play with associated natural gas • Significant drilling inventory, including both low risk infill and de-risked step- out development • Superior netbacks due to lower well costs, combined with owned and controlled infrastructure and direct market access • Shallow, low geological risk resource play • 2022/23: Material discovery/results outperform area average Stable returns with development upside Revitalized light oil asset that provides high IP rates, highly economic return and quick payouts 0 50 100 150 1 2 3 4 5 6 7 8 9 10 11 12 OBE PROGRAMS VS AREA AVERAGE (boe/d) AVG (N=245) AVG OBE 2023 (N=19) **Area defined as TWP 30-33, RGE 01-06W4 See endnotes for additional information; see ‘Well Economics’ in Appendix for area economics 100% WI (operated) 1,156 boe/d (Q3 2025 production 23% decline rate (PDP, 3-year average) T31 R6 W4 <1.3 years Payout (2P) 50 2P locations (2024, net) 14.4 RLI (2P 2024, years)
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$1.4 billion $0.1 billion $0.4 billion $0.3 billion TAX POOL COMPOSITION Non-Capital Losses CEE & SR&ED CDE Other Pools (Q3 2025) CONSIDERABLE FUTURE VALUE FROM TAX POOLS 24 $2.2 billion of tax pools in unrecognized value to be leveraged with future growth $1.5 billion of tax pools immediately deductible $2.2 billion of tax pools Amount of Pools Utilized by Year1 Illustrative Value of Tax Pools @ 8% Discount Rate2 $200 million $329 million $4.55/share $300 million $372 million $5.15/share $400 million $397 million $5.49/share $500 million $413 million $5.72/share 1. Refers to an illustrative amount of pools used annually, assuming deductions available, until fully exhausted 2. Tax pool value based on tax rate of 23% (tax pools estimated, as at Q3 2025). Value presented per Obsidian Energy share, using fully diluted shares outstanding as of September 30, 2025 Maximum Theoretical Value1 Total $468 million $6.48/share Immediately deductible $337 million $4.66/share 1. Maximum theoretical value is calculated based on average 2025 tax rate of 23%, applied to Obsidian Energy’s estimated Q3 2025 and immediately deductible tax pools, and using fully diluted shares outstanding as of September 30, 2025
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2024 RESERVES HIGHLIGHTS 25 Growth in reserves volumes and values reflect development program success YEAR -END 2024 RESERVES SUMMARY Reserves are shown on a gross working interest basis; F&D and FD&A costs include changes in future development capital. See endnotes for additional information. 8th Consecutive Year of >100% reserve replacement (1P & 2P) ___________ 146% to 296% replacement of 2024 production ___________ 7% & 14% improvements in F&D and FD&A costs (1P & 2P) ___________ 1.7x to 2.1x recycle ratios15% increase in PDP volumes/share 23% increase in 1P volumes/share 26% increase in 2P volumes/share Proved Developed Producing (PDP) Total Proved (1P) Total Proved Plus Probable (2P) 2024 Pro forma 2024 Pro forma 2024 Pro forma Reserves volume (Mmboe) 85.3 52.8 151.1 98.9 221.2 148.6 Reserves value (NPV10, before tax, billions) $1.6 $1.1 $2.3 $1.6 $3.1 $2.2 Reserve life index (years) 6.9 6.0 10.3 9.2 13.5 12.2 Reserve replacement (% of production) 146% n/a 229% n/a 296% n/aRecycle ratios 1.7x 1.8x 2.1x F&D costs ($/boe) $19.55 $19.27 $16.31 FD&A costs ($/boe) $21.15 $20.44 $17.08
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2024 RESERVES LOCATIONS 26 Replacing production by >146% and increasing booked locations with significant future inventory potential Significant unbooked potential Additional booked locations expected as assets are delineated 311 236 24 49 343 237 53 48 458 242 160 50 - 50 100 150 200 250 300 350 400 450 Total Cardium Peace River Viking B O O K E D R E S E R V E L O C A T I O N S (number, 2P, net) 2022 2023 2024 Pembina Disposition net booked locations: 2022: 131 2023: 125 2024: 129 135 289 16 691 129 OBE LAND (net sections prospective for formation) Willesden Green - Cardium Pembina Assets - Cardium PCU#11 Peace River Viking See endnotes for additional information
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WELL ECONOMICS 27 HALF CYCLE RESERVE TYPE CURVE ECONOMICS1,2 PEACE RIVER WILLESDEN GREEN VIKING Formation Bluesky3 Clearwater Cardium4 Belly River W. Viking (Esther)5 Well Length 10 legs 8 legs 2.0 mile 1.6 mile 1.8 mile DCET Capex $3.3 million $2.3 million $4.5 million $5.5 million $2.1 million EUR 250 Mboe 186 Mboe 327 Mboe 365 Mboe 121 Mboe Total IP365 184 boe/d 159 boe/d 270 boe/d 275 boe/d 115 boe/d NPV Btax 10% $3.6 million $3.1 million $4.3 million $8.9 million $2.1 million IRR 84% 144% 100% 169% 91% Payout 1.0 years 0.8 years 0.9 years 0.7 years 1.0 years F&D $11.71/boe $12.48/boe $13.91/boe $15.12/boe $17.66/boe Capital efficiency (12-month) $17,951 boe/d $14,592 boe/d $16,842 boe/d $20,034 boe/d $18,697 boe/d 1. Price assumptions: US$70/bbl WTI, US$13.00/bbl WCS, US$4.50/bbl MSW,$2.50/GJ AECO and FX of $1.40 CAD/USD 2. Type curves are derived using two years (or remaining inventory) of type well and input parameters provided by our Independent, Qualified Reserve Evaluator, attributable to the Company’s reserves effective as at December 31, 2024 3. Bluesky type curve economics are based on internal estimates for the Harmon Valley South Field 4. Willesden Green Cardium curve excludes gas wells 5. West Viking defined as OBE operated wells in 32-03 with IRR>25%
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EXPERIENCED TEAM WITH STRONG TECHNICAL SKILLS 28 MANAGEMENT TEAM Stephen E. Loukas President and Chief Executive Officer Peter D. Scott Senior Vice President, Chief Financial Officer Gary Sykes Senior Vice President, Commercial and Development Mark Hawkins Vice President, Legal, General Counsel and Corporate Secretary Cliff Swadling Vice President, Operations Jay McGilvary Vice President, Development Working together as a top tier developer that provides solid returns to stakeholders FINANCIAL AND COMMERCIAL Strong financial, commercial and capital markets experience leading the Company DRILLING, COMPLETIONS AND SUBSURFACE TECHNICAL Strong understanding of geological subsurface, reservoir modelling, advanced design, multi-stage fractured horizontal wells, multi-leg heavy oil wells OPERATIONS Expertise in facility design and construction, automation, production management, field operations, and asset retirement, with a strong focus on safety performance EMPLOYEES Staff & contractors with deep experience in their professions, representing the top tier expertise
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ADVISORY 29 This presentation should be read in conjunction with the Company’s unaudited interim consolidated financial statements and MD&A for the three and nine months ended September 30, 2025. All dollar amounts contained in this presentation are expressed in millions of Canadian dollars unless otherwise indicated. Certain financial measures included in this presentation do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered Non-GAAP measures, Non-GAAP ratios or supplementary financial measures; accordingly, they may not be comparable to similar measures provided by other issuers. This presentation also contains oil and gas disclosures, various industry terms, and forward-looking statements, including various assumptions on which such forward-looking statements are based and related risk factors. Please see the Company’s disclosures located in the Endnotes at the end of this presentation for further details regarding these and other matters. All slides in this presentation should be read in conjunction with “Definitions and Industry Terms”, “Non-GAAP Measures Advisory”, “Oil and Gas Information Advisory”, “2024 Reserves Disclosure and Definitions” and “Forward-Looking Information Advisory”. All drilling locations are considered to be unbooked unless otherwise noted. Please be advised that the archived releases contained in this presentation are for historical information and reference purposes only. While information contained within the releases was believed to be accurate at the time of issue, this information does not constitute an active representation of Obsidian Energy, and the Company fully disclaims any liability for the use of such information and undertakes no obligation to update such information except as required by applicable law.
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Endnotes
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ENDNOTES 31 Slide 2: Overview Market capitalization determined with share price on the close of business on January 21, 2026, on the TSX ($9.33 per share) and common shares outstanding at December 31, 2025. Enterprise value calculated by adding net debt as at September 30, 2025, to market capitalization. Reserves (2P) are based on 2P reserve numbers as disclosed in our news release dated February 4, 2025, titled “Obsidian Energy Announces Increase in 2024 Reserves Across All Categories” (the “Release”). PDP decline is based on the first-year forecast from the Reserves Report. All reserves numbers have been adjusted to remove the Pembina assets. Map volumes do not include additional legacy wells outside these core areas (256 boe/d). Slide 4: Returning Capital to Shareholders Percentage of shares purchased and cancelled through the share buyback program calculated based on shares outstanding at December 31, 2022. Slide 6: 2025 Financial Highlights The percent reductions on ARO related to the Pembina disposition was calculated on an uninflated, undiscounted basis. Slide 7: 2026 Guidance Further details of production guidance ranges, by product type, are as follows: Asset level capital does not include $1 million in corporate capital. 2026E pricing assumptions include risk management (hedging) adjustments as of January 14, 2026. WTI assumption for H1 2026 (Jan – June) is US$58.00/bbl and H2 2026 (July – December) is US$62.00/bbl. 2026E per share calculations are based on an estimated 67.2 million weighted average shares outstanding, for the year ended December 31, 2026. 2026E Net Debt figures are estimated at December 31, 2026. Slide 9: Peace River Asset Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. No locations have been assigned to land where Obsidian Energy is not the operator. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Slide 11: Peace River 2025 Capital Program Individual play fairways are Obsidian Energy defined trends displaying similar reservoir and geological characteristics. Slide 12: Light Oil Assets Booked locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. In the case of Willesden Green, booked locations have been updated to include the impact of the Pembina Disposition, which includes an additional 34.6% working interest in the WGCU#2. Slide 13: Willesden Green Asset Statistics in table are post the Pembina Disposition and include the additional 34.6% working interest in the WGCU#2, unless noted otherwise. Obsidian Energy’s working interest is based on the Company’s booked locations where we invest capital. Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Slide 14: Hedging Program In accordance with policies approved by our Board of Directors, the Company may, from time to time, manage commodity price risks through the use of swaps or other financial instruments up to a maximum of 50% of forecast sales volumes, net of royalties, for the balance of any current year plus one additional year forward and up to a maximum of 25%, net of royalties, for one additional year thereafter. The Board of Directors approved the following changes to our hedging policy on a rolling 15-month period: - Allow for hedges up to 50% of net oil production on a rolling 15-month period (up to 80% in near three months); - Allow for hedges up to 80% of net gas production on a rolling basis for the current and next gas season (i.e. current summer plus next winter season); - Allow for hedges on liquid volumes (i.e. oil and natural gas liquids) in Canadian dollars on 80% of the associated direct United States foreign exchange revenue exposure, net of royalties, on a rolling 12-month basis; and - Allow for hedges on liquid volumes (i.e. oil and natural gas liquids) in Canadian dollars on 50% of the associated direct United States foreign exchange revenue exposure, net of royalties on a rolling 18-month basis. Summer gas season is from April to October, Winter gas season is from November to March. Slide 15: Reserves Underpin our Current and Future Value Reserves evaluation excludes inactive ARO. Our YE2024 reserves evaluation conforms to the requirements of National Instrument 51-101 and uses definitions and guidelines contained in the COGE Handbook. Obsidian Energy abandonment and reclamation costs associated with active wells, facilities, and pipelines have been included in the Reserves Report as part of future net revenue calculations. The price assumptions in our YE2024 reserves evaluation were based on an average of three independent reserve evaluators’ forecasts (GLJ Ltd., Sproule Associates Ltd. and McDaniel & Associates Consultants). Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Pro forma NAV/share based on YE 2024 reserves run at flat pricing adjusted for the impact of the Pembina Disposition, and assumes $219 million Net Debt as at September 30, 2025. Shares outstanding calculated using common shares outstanding as of December 31, 2025, and includes RSUs and options as at September 30, 2025. Share price depicted is at the close of business on January 21, 2026. Additional reserve information is available in Appendix A-3 of our Annual Information Form for the year ended December 31, 2024, at www.obsidianenergy.com. Flat price calculation generated by the Company using Reserves Report data while strip pricing obtained from FactSet. “Growth in Reserves” graph based on NAV/share calculation with total number of basic common shares outstanding as of December 31 per year. Light Oil (bbl/d) Heavy Oil (bbl/d) NGL (bbl/d) Natural Gas (mmcf/d) Total (boe/d 2026E 7,300 11,800 2,000 46.8 28,900
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ENDNOTES, CONT. 32 Slide 16: Why Invest in Obsidian Energy Percentage of shares purchased and cancelled through the share buyback program calculated based on shares outstanding at December 31, 2022. Slide 18: Delivering Results Production per share data based on average boe/d and basic shares for the year, as applicable. Slide 19: H2 2025 Guidance Further details of production guidance ranges, by product type, are as follows: Asset level capital does not include $1 million in corporate capital. H2 2025E pricing assumptions include risk management (hedging) adjustments as of October 29, 2025. WTI, Foreign Exchange and AECO price assumptions for second half 2025 are forecasted for November to December 2025. MSW and WCS differential assumptions for the second half 2025 are forecasted for December 2025. H2 2025E per share calculations are based on an estimated 67.1 million weighted average shares outstanding, for the six months ended December 31, 2025. H2 2025E Net Debt figures are estimated at December 31, 2025. Slide 21: Strategic Pembina Asset Disposition Pembina production of 10,300 boe/d based on actual production for 2024 broken down as follows: Light Oil – 5,902 bbl/d, Heavy Oil – 61 bbl/d, NGL – 900 bbl/d, Gas – 20.8 mmcf/d 2024 net operating income calculation reduced for annual decommissioning expenditures. Slide 22: Pembina Cardium Unit #11 Asset Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Slide 23: Viking Asset Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Average Viking well based on data pulled from GeoScout for Viking Sandstone horizontal wells in Township 30-33, Range 1-6W4. Normalized to daily oil rate and condensed to exclude months with zero production. Slide 25: 2024 Reserve Highlights Reserves evaluation excludes inactive ARO. Our YE2024 reserves evaluation conforms to the requirements of National Instrument 51-101 and uses definitions and guidelines contained in the COGE Handbook. Obsidian Energy abandonment and reclamation costs associated with active wells, facilities, and pipelines have been included in the Reserves Report as part of future net revenue calculations. The price assumptions in our YE2024 reserves evaluation were based on an average of three independent reserve evaluators’ forecasts (GLJ Ltd., Sproule Associates Ltd. and McDaniel & Associates Consultants). Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. See ‘2024 Reserves Disclosure and Definitions’ for further details. Additional reserve information is available in Appendix A-3 of our Annual Information Form for the year ended December 31, 2024, available at www.obsidianenergy.com. F&D and FD&A costs are non-GAAP measures. See ‘Non-GAAP Measures Advisory’ and ‘2024 Reserves Disclosure and Definitions’ for further details. Pro forma reserves represent Obsidian Energy’s net reserves post-close of the Pembina Disposition, calculated using the Company’s 2024 Reserves Report. Slide 26: 2024 Reserves Locations Booked 2P reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Bluesky locations increased to 63 from 42 and Clearwater locations increased to 97 from 11 over 2023 totals.
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NPV or NPV Btax 10% means net present value, before tax discounted at 10% NYSE American means the New York Stock Exchange, American Payout means the time it takes to cover the return of the initial cash outlay PCU#11 means the non-operated Pembina Cardium Unit #11 Pembina Disposition refers to the Pembina Asset Disposition or Transaction, referring to disposition of the Company’s operated Pembina assets for $211 million in cash (after interim closing adjustments), 9.1 million in InPlay shares (post InPlay’s 6:1 share consolidation) and the $15 million estimated value for InPlay’s 34.6% interest in the WGCU#2 PROP refers to the Peace River Oil Partnership, which the Company acquired the remaining ownership in 2021 Reserves references are based on the report prepared by GLJ Ltd. dated January 24, 2025, (the “Reserves Report”) attributable to the Company’s reserves effective as at December 31, 2024. For additional reserve definitions, see the Release RLI means Reserve Life Index Rig Release refers to the date when drilling is finished at a wellsite and the drilling rig is ‘released’ to go to another site SR&ED is the Scientific Research & Experimental Development program, a government incentive tax credit TSX means the Toronto Stock Exchange Total IP365 means total barrels of oil equivalent produced over the first 365 days of well production, excluding any required cleanup time US or USD means United States Dollar WCS means Western Canadian Select WG means Willesden Green WGCU#2 means the Willesden Green Cardium Unit #2. WI means working interest WTI means West Texas Intermediate YE means year-end YoY means year-over-year DEFINITIONS AND INDUSTRY TERMS 33 2026E means the guidance for 2026 for the full year, based on internal assumptions and estimates H2 2025E means the guidance for 2025 results for the second half of the year, based on internal assumptions and estimates PDP means proved developed producing reserves as per Oil and Gas Disclosures Advisory 1P means proved reserves as per Oil and Gas Disclosures Advisory 2P means proved plus probable reserves as per Oil and Gas Disclosures Advisory Acquisition means the purchase and sale agreement to acquire approximately 1,700 boe/d (100 percent oil, based on April 2024 actual production) of Clearwater production and 148 net sections of land in the Peace River area from a third-party (the “Vendor”) as outlined in Company’s news release of May 28, 2024, which closed on June 26, 2024 AECO means Alberta benchmark price for natural gas ARO means Asset Retirement Obligation bbl and bbl/d means barrels of oil and barrels of oil per day, respectively BCF means billion cubic feet of natural gas boe and boe/d means barrels of oil equivalent and barrels of oil equivalent per day, respectively CAD means Canadian Dollar CAGR means compound annual growth rate CAPEX means capital expenditures Capital Efficiency is a metric that approximates cash flow generated for each investment dollar, and measures the ratio of how much a company spends growing revenue and how much they get in return CDE means Canadian development expense CEE means Canadian exploration expenses COGE Handbook stands for the Canadian Oil and Gas Evaluation Company, Obsidian Energy or OBE means Obsidian Energy Ltd.; as applicable DCET stands for Drilling, Case, Equip and Tie-in capital, and represents all necessary capital to drill and produce a well into the existing field infrastructure. Value does not include additional field infrastructure or lease construction and acquisition costs Debt is bank debt and senior notes Decommissioning means decommissioning expenditures EOR stands for enhanced oi recovery EUR means expected ultimate recovery, which is the total economic recoverable hydrocarbon F&D means finding and development cost, and refers to costs incurred when a company purchases, researches and develops properties to establish reserves FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates G&A means general and administrative costs GJ means gigajoule H1 means the first half of the year H2 means the second half of the year HVS means Harmon Valley South in Peace River Independent, Qualified Reserve Evaluator refers to GLJ Ltd. IP rates means initial production rates for a well InPlay stands for InPlay Oil Corp. IRR stands for Internal Rate of Return Legacy refers to a collection of all OBE properties outside of our core development areas of Cardium (Central), Peace River, and Viking Liquids means crude oil and NGLs m means metres Mboe means thousand barrels of oil equivalent MMbbl means million barrels of oil MMboe means million barrels of oil equivalent Mcf and mcf/d means thousand cubic feet and thousand cubic feet per day, respectively Mmcf and mmcf/d means million cubic feet and million cubic feet per day, respectively MSW means Mixed Sweet Blend crude oil NCIB means normal course issuer bid
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NON-GAAP MEASURES ADVISORY 34 Asset level FCF is based on net operating income less capital expenditures for the area. Enterprise Value or EV is a measure of total value of the company calculated by aggregating the market value of its common shares at a specific date (share price multiplied by shares outstanding), adding its Net Debt. Free Cash Flow (FCF) is FFO less capital and decommissioning expenditures. Funds Flow from Operations (FFO) is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, equity forward contracts, onerous office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments, restructuring charges, transaction costs and certain other expenses and is representative of cash related to continuing operations. FFO is used to assess the combined entity’s ability to fund planned capital programs. Netback is production revenues plus sales of commodities purchased from third parties less commodities purchased from third parties (sales), less royalties, net operating costs, transportation expenses and realized risk management gains and losses on commodity contracts, and is used in capital allocation decisions and to economically rank projects. Notice to Shareholders in the United States The financial information presented herein has been prepared in accordance with Canadian GAAP and is subject to Canadian auditing and auditor independence standards, and thus may not be comparable to financial statements of U.S. companies presented in accordance with U.S. GAAP . Throughout this presentation and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income and cash flow from operating activities as indicators of our performance. The Company’s unaudited interim consolidated financial statements and notes and management’s discussion and analysis (“MD&A”) as at and for the three and nine months ended September 30, 2025, are available on the Company’s website at www.obsidianenergy.com and under our SEDAR+ profile at www.sedarplus.ca. The disclosure under the section “Non-GAAP and Other Financial Measures” in the MD&A is incorporated by reference into this presentation. Non-GAAP Financial Measures The following measures are non-GAAP financial measures: FCF, FFO, Net Debt; netback, net operating costs and net operating income. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. Non-GAAP Ratios The following measures are non-GAAP ratios: FCF per share which uses FCF as a component; Asset level FCF which uses net operating income as a component; FFO per share which uses FFO as a component; Enterprise Value which uses Net Debt as a component; net operating costs per boe, which uses net operating costs as a component; Net Debt to FFO which uses both Net Debt and FFO as components; . These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. Supplementary Financial Measures G&A per boe uses G&A per boe on a net basis. Net Debt is the amount of long-term debt, comprised of senior notes, term loan and drawings under our syndicated credit facility, plus net working capital (surplus)/deficit. Net Debt is a measure of leverage and liquidity. Net Debt to Funds Flow from Operations is Net Debt divided by funds flow from operations. Net operating costs are calculated by deducting processing income, road use recoveries and realized gains and losses on power risk management hedges from operating costs and is used to assess the Company’s cost position. Processing fees are primarily generated by processing third party volumes at the Company’s facilities. In situations where the Company has excess capacity at a facility, it may agree with third parties to process their volumes to reduce the cost of operating/owning the facility. Road use recoveries are a cost recovery for the Company as we operate and maintain roads that are also used by third parties. Realized gains and losses on power risk management contracts occur upon settlement of our contracts. Net operating income is the absolute value of production revenues plus sales of commodities purchased from third parties less commodities purchased from third parties (sales), less royalties, net operating costs and transportation expenses and is used to determine the profitability of our assets. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our corresponding MD&As for further information.
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OIL AND GAS INFORMATION ADVISORY 35 Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value. Drilling Locations This presentation discloses drilling locations or inventory in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Reserves Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked drilling locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production. Test Results and Initial Production Rates Readers are cautioned that initial production rates and/or production test results disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.
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2024 RESERVES DISCLOSURE AND DEFINITIONS 36 Unless otherwise noted, any reference to 2024 reserves in this presentation are based on the report (the “Reserves Report”) prepared by GLJ Ltd. dated January 24, 2025, where they evaluated one hundred percent of the crude oil, natural gas and natural gas liquids reserves of Obsidian Energy and the net present value of future net revenue attributable to those reserves effective as at December 31, 2024. For further information regarding the Reserves Report, see our Release. It should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained, and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. Production and Reserves The use of the word “gross” in this presentation (i) in relation to our interest in production and reserves, means our working interest (operating or non-operating) share before deduction of royalties and without including our royalty interests, (ii) in relation to wells, means the total number of wells in which we have an interest, and (iii) in relation to properties, means the total area of properties in which we have an interest. The use of the word “net” in this presentation (i) in relation to our interest in production and reserves, means our working interest (operating or non-operating) share after deduction of royalty obligations, plus our royalty interests, (ii) in relation to our interest in wells, means the number of wells obtained by aggregating our working interest in each of our gross wells, and (iii) in relation to our interest in a property, means the total area in which we have an interest multiplied by the working interest owned by us. Unless otherwise stated, production volumes and reserves estimates in this presentation are stated on a gross basis. All references to well counts are net to the Company, unless otherwise indicated. Reserve Definitions Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. • Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. • Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories: Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable) to which they are assigned. Finding and development (F&D) costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category, all divided by the change in reserves during the period. F&D costs exclude the impact of acquisitions and divestitures. FD&A costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category and including the impact of acquisition and disposition activity, all divided by the change in reserves during the period for the reserve category. Recycle ratio is calculated by dividing the operating netback by the F&D costs for the year. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. RLI or Reserve Life Index is calculated as total Company gross reserves divided by GLJ’s forecasted 2024 production for the associated reserve category. For additional reserve definitions, see the Release.
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FORWARD-LOOKING INFORMATION ADVISORY 37 Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this presentation contains, without limitation, forward-looking statements pertaining to the following: our business, assets, plans, strategies, outlook, focuses and ability to deliver value and results to our shareholders; how we plan to deliver superior shareholder returns and our strategic advantages; our plans for our NCIB and prepaid equity forward programs; our future development and exploration/appraisal/injector well opportunities, program and locations; our expectations for our Peace River and Cardium assets both operationally and financially; our expected on production timing; the extension of our credit facility into 2027; our 2026 guidance for production, capital and decommissioning expenditures, net operating costs, general & administrative costs, FFO and FFO/share, FCF and FCF/share, Net Debt and Net Debt to FFO; our expected sensitivities to changes in WTI, MSW, AECO and WCS; our decline rates; our 2026 guidance for asset level average production, capital expenditures, net operating costs, netbacks, net operation income and the asset level FCF; our plans for a discipline approach in 2026 given commodity price volatility; our expectations for booked and unbooked locations; how we plan to create optionality for our portfolio; our expectations for the Open Creek field infrastructure; our hedges and how we plan to manage risk going forward; our expected 2025 Q4 corporate production and net debt; our second half updated 2025 guidance for production, capital and decommissioning expenditures, net operating costs, general & administrative costs, FFO and FFO/share, FCF and FCF/share, Net Debt and Net Debt to FFO, and the expected sensitivities to changes in WTI, MSW, AECO and WCS; our second half 2025 guidance for asset level average production, capital expenditures, net operating costs, netbacks, net operation income and the asset level FCF; that our Pembina Disposition was accretive to our shareholders; our expectations for our Viking asset; the reasons to invest in Obsidian Energy; and our anticipated tax pools and savings therefrom. Certain of the foregoing information set forth in this presentation may be considered to be future-oriented financial information (“FOFI”) or a financial outlook for the purposes of applicable Canadian securities laws. This FOFI is related to the Company's prospective results of operations, operating costs and expenditures, capital expenditures, production, general & administrative, decommissioning expenditures; FFO, FFO per share, FCF, FCF per share, asset level FCF, net debt and net debt to FFO ratio, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company's business as of the date hereof and such information may not be appropriate for other purposes. To the extent that such estimates constitute FOFI or a financial outlook, they were approved by management of the Company on the date hereof and are included to provide readers with an understanding of the Company's anticipated plans and financial results based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. With respect to forward-looking statements and FOFI contained in this document, the Company has made assumptions regarding, among other things: the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than as stated herein (provided that, except where otherwise stated, the forward-looking statements and FOFI contained herein do not assume the completion of any transaction); that regional and/or global health related events will not have any adverse impact on energy demand and commodity prices in the future; global energy policies going forward, including the continued ability and willingness of members of OPEC and other nations to agree on and adhere to production quotas from time to time; our ability to execute our plans as described herein and in our other disclosure documents, and the impact that the successful execution of such plans will have on our Company and our stakeholders, including our ability to return capital to shareholders and/or further reduce debt levels; future capital expenditure and decommissioning expenditure levels; expectations and assumptions concerning applicable laws and regulations, including with respect to environmental, safety and tax matters; future operating costs and G&A costs and the impact of inflation thereon; future oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future oil, natural gas liquids and natural gas production levels; future exchange rates, interest rates and inflation rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events such as wild fires, flooding and drought, infrastructure access (including the potential for blockades or other activism) and delays in obtaining regulatory approvals and third party consents; the ability of the Company's contractual counterparties to perform their contractual obligations; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our senior unsecured notes on maturity or pursuant to the terms of the underlying agreement; the accuracy of our estimated reserve volumes; and our ability to add production and reserves through our development and exploitation activities. In addition, many of the forward-looking statements and FOFI contained in this document are located proximate to assumptions that are specific to those forward-looking statements, and such assumptions should be taken into account when reading such forward-looking statements and FOFI.
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FORWARD-LOOKING INFORMATION ADVISORY (CONT.) 38 Although the Company believes that the expectations reflected in the forward-looking statements and FOFI contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements and FOFI included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the risk that (i) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S., will trigger a broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company, including by decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; the possibility that we change our budgets (including our capital expenditure budgets) in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize (such as our inability to return capital to shareholders and/or reduce debt levels to the extent anticipated or at all); the impact on energy demand and commodity prices of regional and/or global health related events and the responses of governments and the public thereto, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and in confidence in the oil and natural gas industry generally, whether caused by regional and/or global health related events, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the financial capacity of the Company's contractual counterparties is adversely affected and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our senior unsecured notes is not extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our senior unsecured notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace our credit facilities and/or senior unsecured notes or to fund other activities; the possibility that we are forced to shut-in production, whether due to commodity prices decreasing, extreme weather events such as wild fires, inability to access our properties due to blockades or other activism, or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of oil, natural gas liquids and natural gas, price differentials for oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange, including the impact of the Canadian/U.S. dollar exchange rate on our revenues and expenses; fluctuations in interest rates, including the effects of interest rates on our borrowing costs and on economic activity, and including the risk that elevated interest rates cause or contribute to the onset of a recession; the risk that our costs increase due to inflation, supply chain disruptions, scarcity of labour and/or other factors, adversely affecting our profitability; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires, flooding and droughts (which could limit our access to the water we require for our operations)); the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russian and Ukraine and/or hostilities in the Middle East; the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons, government mandates requiring the sale of electric vehicles and/or electrification of the power grid, and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company's ability to obtain financing and/or insurance on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments, financial institutions and consumers to a regional and/or global health related event and/or the influence of public opinion and/or special interest groups; and the other factors described under "Risk Factors" in our Annual Information Form and described in our public filings, available in Canada at www.sedarplus.ca and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive and the impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are independent and Obsidian Energy’s future course of action depends on management’s assessment of all information available at the relevant time. Unless otherwise specified, the forward-looking statements contained in this document speak only as of January 22, 2026. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward.