Filed by Obsidian Energy Ltd. (Commission File No. 001-32895) Pursuant to Rule 425 under the Securities Act of 1933 Subject Company: Bonterra Energy Corp. Obsidian Energy Corporate Presentation November 2020Filed by Obsidian Energy Ltd. (Commission File No. 001-32895) Pursuant to Rule 425 under the Securities Act of 1933 Subject Company: Bonterra Energy Corp. Obsidian Energy Corporate Presentation November 2020

Important Notice to the Readers This presentation should be read in conjunction with the Company’s unaudited interim consolidated financial statements, Management's Discussion and Analysis ( MD&A ) for the three and nine months ended September 30, 2020. 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-generally accepted accounting practice (“Non-GAAP ) 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 Appendix & Endnotes at the end of this presentation for further details regarding these matters. All slides in this presentation should be read in conjunction with “Definitions and Industry Terms”, “Non-GAAP Measure Advisory”, “Oil and Gas Information Advisory”, “Reserves Disclosure and Definitions Advisory” and “Forward-Looking Information Advisory”. All locations are considered to be Unbooked locations unless otherwise noted. This presentation does not constitute an offer to buy or sell, or an invitation or a solicitation of an offer to buy or sell, any securities of the Company or Bonterra Energy Corp. (“Bonterra”). The Company’s offer to purchase all of the issued and outstanding common shares of Bonterra for consideration consisting of two common shares of the Company for each Bonterra share (the “Offer”) is pursuant to a take-over bid circular dated September 21, 2020 and related offer documents (collectively, “Offer Documents”) that were mailed to Bonterra shareholders and have also been filed with the Canadian and United States securities regulators and are available under Bonterra’s SEDAR profile at www.sedar.com and on the Company’s website at www.obsidianenergy.com. The Offer is made exclusively by means of, and subject to the terms and conditions set out in, the Offer Documents. While the Offer will be made to all holders of Bonterra shares, the Offer will not be made or directed to, nor will deposits of Bonterra shares be accepted from or on behalf of, holders of Bonterra shares in any jurisdiction in which the making or acceptance of the Offer would not be in compliance with the laws of such jurisdiction. The Offer is open for acceptance until 5:00 p.m. (Mountain Standard Time) on January 4, 2021, unless extended, accelerated or withdrawn. As set out in further detail in the Offer Documents, the Offer is subject to certain conditions, including: that the Bonterra shares validly deposited to the Offer, and not withdrawn, represent at least 66 2/3% of the then outstanding Bonterra shares (on a fully-diluted basis) and certain regulatory and third party approvals (as outlined in the Offer Documents) shall have been obtained, including the Company’s shareholders approving, as required by the rules of the Toronto Stock Exchange, the issuance of the shares to be distributed by the Company in connection with the Offer, and other customary conditions. Subject to applicable law, the Company reserves the right to withdraw, accelerate or extend the Offer and to not take up and pay for any Bonterra shares deposited under the Offer unless each of the conditions of the Offer is satisfied or waived by the Company at or prior to the expiry of the Offer. Bonterra shareholders are strongly encouraged to read the Offer Documents carefully and in their entirety since they contain additional important information regarding the Company and the terms and conditions of the Offer as well as detailed instructions on how Bonterra shareholders can tender their Bonterra shares to the Offer. The offer and sale of shares of the Company pursuant to the Offer is subject to a registration statement (the “Registration Statement”) filed with the United States Securities and Exchange Commission (the “SEC”) under the U.S. Securities Act of 1933, as amended. The Registration Statement includes various documents related to such offer and sale. THE COMPANY URGES INVESTORS AND SHAREHOLDERS OF BONTERRA TO READ THE REGISTRATION STATEMENT AND ANY AND ALL OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC IN CONNECTION WITH THE OFFER AND SALE OF OBSIDIAN SHARES AS THOSE DOCUMENTS BECOME AVAILABLE, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY CONTAIN OR WILL CONTAIN IMPORTANT INFORMATION. You will be able to obtain a free copy of such registration statement, as well as other relevant filings regarding the Company or the Offer, at the SEC’s website (www.sec.gov) under the issuer profile for the Company, or on request without charge from the Corporate Secretary of the Company at Suite 200, 207 – 9th Avenue, SW, Calgary, Alberta T2P 1K3. 2Important Notice to the Readers This presentation should be read in conjunction with the Company’s unaudited interim consolidated financial statements, Management's Discussion and Analysis ( MD&A ) for the three and nine months ended September 30, 2020. 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-generally accepted accounting practice (“Non-GAAP ) 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 Appendix & Endnotes at the end of this presentation for further details regarding these matters. All slides in this presentation should be read in conjunction with “Definitions and Industry Terms”, “Non-GAAP Measure Advisory”, “Oil and Gas Information Advisory”, “Reserves Disclosure and Definitions Advisory” and “Forward-Looking Information Advisory”. All locations are considered to be Unbooked locations unless otherwise noted. This presentation does not constitute an offer to buy or sell, or an invitation or a solicitation of an offer to buy or sell, any securities of the Company or Bonterra Energy Corp. (“Bonterra”). The Company’s offer to purchase all of the issued and outstanding common shares of Bonterra for consideration consisting of two common shares of the Company for each Bonterra share (the “Offer”) is pursuant to a take-over bid circular dated September 21, 2020 and related offer documents (collectively, “Offer Documents”) that were mailed to Bonterra shareholders and have also been filed with the Canadian and United States securities regulators and are available under Bonterra’s SEDAR profile at www.sedar.com and on the Company’s website at www.obsidianenergy.com. The Offer is made exclusively by means of, and subject to the terms and conditions set out in, the Offer Documents. While the Offer will be made to all holders of Bonterra shares, the Offer will not be made or directed to, nor will deposits of Bonterra shares be accepted from or on behalf of, holders of Bonterra shares in any jurisdiction in which the making or acceptance of the Offer would not be in compliance with the laws of such jurisdiction. The Offer is open for acceptance until 5:00 p.m. (Mountain Standard Time) on January 4, 2021, unless extended, accelerated or withdrawn. As set out in further detail in the Offer Documents, the Offer is subject to certain conditions, including: that the Bonterra shares validly deposited to the Offer, and not withdrawn, represent at least 66 2/3% of the then outstanding Bonterra shares (on a fully-diluted basis) and certain regulatory and third party approvals (as outlined in the Offer Documents) shall have been obtained, including the Company’s shareholders approving, as required by the rules of the Toronto Stock Exchange, the issuance of the shares to be distributed by the Company in connection with the Offer, and other customary conditions. Subject to applicable law, the Company reserves the right to withdraw, accelerate or extend the Offer and to not take up and pay for any Bonterra shares deposited under the Offer unless each of the conditions of the Offer is satisfied or waived by the Company at or prior to the expiry of the Offer. Bonterra shareholders are strongly encouraged to read the Offer Documents carefully and in their entirety since they contain additional important information regarding the Company and the terms and conditions of the Offer as well as detailed instructions on how Bonterra shareholders can tender their Bonterra shares to the Offer. The offer and sale of shares of the Company pursuant to the Offer is subject to a registration statement (the “Registration Statement”) filed with the United States Securities and Exchange Commission (the “SEC”) under the U.S. Securities Act of 1933, as amended. The Registration Statement includes various documents related to such offer and sale. THE COMPANY URGES INVESTORS AND SHAREHOLDERS OF BONTERRA TO READ THE REGISTRATION STATEMENT AND ANY AND ALL OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC IN CONNECTION WITH THE OFFER AND SALE OF OBSIDIAN SHARES AS THOSE DOCUMENTS BECOME AVAILABLE, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY CONTAIN OR WILL CONTAIN IMPORTANT INFORMATION. You will be able to obtain a free copy of such registration statement, as well as other relevant filings regarding the Company or the Offer, at the SEC’s website (www.sec.gov) under the issuer profile for the Company, or on request without charge from the Corporate Secretary of the Company at Suite 200, 207 – 9th Avenue, SW, Calgary, Alberta T2P 1K3. 2

Corporate Overview Market Summary Ticker Symbol OBE Peace River MM Shares Outstanding 73 3,196 boe/d Q3 2020 Cold flow heavy oil MM Market Capitalization $30 Manage base production MM Net Debt $479 MM Enterprise Value $509 Corporate Summary mmboe Reserves (2P YE 2019) 126 Cardium years RLI (2P YE 2019) 14 20,661 boe/d Q3 2020 Light oil conventional development % PDP Decline (YE 2019) 17 Manufacturing model for extensive, repeatable inventory. MM Tax Pools (YE 2019) $2,547 Leverage shallow decline base Guidance Period H2 2020 boe/d Production 24,000 – 24,500 25,000 – 25,500 MM Capital Expenditures $12 $53 MM Decommissioning $3 $11 Alberta Viking $/boe Operating Expenses $12.00 – $12.50 $11.10 – 11.50 825 boe/d Q3 2020 General & Higher GOR oil play $/boe $1.50 – $1.65 $1.50 – 1.60 Administrative Manage base production *Legacy Asset Production of 349 boe/d Q3 2020 3 3 See end notes for additional information Corporate Overview Market Summary Ticker Symbol OBE Peace River MM Shares Outstanding 73 3,196 boe/d Q3 2020 Cold flow heavy oil MM Market Capitalization $30 Manage base production MM Net Debt $479 MM Enterprise Value $509 Corporate Summary mmboe Reserves (2P YE 2019) 126 Cardium years RLI (2P YE 2019) 14 20,661 boe/d Q3 2020 Light oil conventional development % PDP Decline (YE 2019) 17 Manufacturing model for extensive, repeatable inventory. MM Tax Pools (YE 2019) $2,547 Leverage shallow decline base Guidance Period H2 2020 boe/d Production 24,000 – 24,500 25,000 – 25,500 MM Capital Expenditures $12 $53 MM Decommissioning $3 $11 Alberta Viking $/boe Operating Expenses $12.00 – $12.50 $11.10 – 11.50 825 boe/d Q3 2020 General & Higher GOR oil play $/boe $1.50 – $1.65 $1.50 – 1.60 Administrative Manage base production *Legacy Asset Production of 349 boe/d Q3 2020 3 3 See end notes for additional information

Short-term Strategic Priorities & Year to Date 2020 Results Short-term Priorities • Pursue successful acquisition of Bonterra to create “The Cardium Champion” • Transformational opportunity for both companies’ shareholders • Continue operational momentum and cost reduction initiatives to improve the base business • Protect long-term asset value • Substantial future development program optionality exists within Obsidian Energy’s portfolio in both available drilling inventory and product mix (gas/oil) – the asset base allows us significant flexibility to navigate volatility in commodity price environments • Decommissioning activity utilizing $17 million in grants and $4 million in allocation eligibility within the Alberta Site Rehabilitation Program (ASRP) will significantly reduce inactive ARO in our non-core Legacy area • We continually evaluate our potential participation in additional phases of the ASRP Delivering Results Full Year Guidance YTD Results boe/d Production 25,000 – 25,500 25,995 • Obsidian Energy has maintained our guidance and is on track to meet or exceed our targets MM Capital Expenditures $53 $46 • Production continues to benefit from strong development program results MM Decommissioning $11 $9 • Operating and G&A expenses performance continues to improve on a year-over-year basis $/boe Operating Expenses $11.10 – 11.50 $10.65 due to cost cutting efforts and proactive decision making General & $/boe $1.50 – 1.60 $1.47 Administrative 4Short-term Strategic Priorities & Year to Date 2020 Results Short-term Priorities • Pursue successful acquisition of Bonterra to create “The Cardium Champion” • Transformational opportunity for both companies’ shareholders • Continue operational momentum and cost reduction initiatives to improve the base business • Protect long-term asset value • Substantial future development program optionality exists within Obsidian Energy’s portfolio in both available drilling inventory and product mix (gas/oil) – the asset base allows us significant flexibility to navigate volatility in commodity price environments • Decommissioning activity utilizing $17 million in grants and $4 million in allocation eligibility within the Alberta Site Rehabilitation Program (ASRP) will significantly reduce inactive ARO in our non-core Legacy area • We continually evaluate our potential participation in additional phases of the ASRP Delivering Results Full Year Guidance YTD Results boe/d Production 25,000 – 25,500 25,995 • Obsidian Energy has maintained our guidance and is on track to meet or exceed our targets MM Capital Expenditures $53 $46 • Production continues to benefit from strong development program results MM Decommissioning $11 $9 • Operating and G&A expenses performance continues to improve on a year-over-year basis $/boe Operating Expenses $11.10 – 11.50 $10.65 due to cost cutting efforts and proactive decision making General & $/boe $1.50 – 1.60 $1.47 Administrative 4

Long-term Strategic Priorities Superior Shareholder Return Generate excess free cash Create scale and further Drive per share growth via flow while holding production decrease cost structure via organic development and flat with growth optionality Cardium consolidation debt pay down at increased commodity strategy prices 5Long-term Strategic Priorities Superior Shareholder Return Generate excess free cash Create scale and further Drive per share growth via flow while holding production decrease cost structure via organic development and flat with growth optionality Cardium consolidation debt pay down at increased commodity strategy prices 5

Creating The Cardium Champion st On September 21 2020 Obsidian Energy commenced a formal offer to purchase all of the issued and outstanding common shares of Bonterra Energy Corp. • Obsidian Energy has offered 2 Obsidian Energy Shares for each Bonterra Share Central Pembina • Creates the Cardium Champion with enhanced scale and capital markets relevance • Accretive across all equity metrics resulting in the potential for significant per share value appreciation to East the benefit of both Bonterra and Obsidian Energy Pembina shareholders West Pembina • Up to C$100 million expected in identified financial, operational and other synergies over the first three years resulting in significantly improved free cash flow • The re-introduction of a monthly dividend payment after an appropriate level of debt repayment • Retain significant upside to higher commodity prices East through continued participation with a 48% pro forma Crimson ownership in a stronger combined company Crimson Lake • An outcome far superior to what Bonterra can achieve on a stand-alone basis Obsidian Energy is the #1 Cardium Producer and the Logical Consolidator 6Creating The Cardium Champion st On September 21 2020 Obsidian Energy commenced a formal offer to purchase all of the issued and outstanding common shares of Bonterra Energy Corp. • Obsidian Energy has offered 2 Obsidian Energy Shares for each Bonterra Share Central Pembina • Creates the Cardium Champion with enhanced scale and capital markets relevance • Accretive across all equity metrics resulting in the potential for significant per share value appreciation to East the benefit of both Bonterra and Obsidian Energy Pembina shareholders West Pembina • Up to C$100 million expected in identified financial, operational and other synergies over the first three years resulting in significantly improved free cash flow • The re-introduction of a monthly dividend payment after an appropriate level of debt repayment • Retain significant upside to higher commodity prices East through continued participation with a 48% pro forma Crimson ownership in a stronger combined company Crimson Lake • An outcome far superior to what Bonterra can achieve on a stand-alone basis Obsidian Energy is the #1 Cardium Producer and the Logical Consolidator 6

Regaining Market Relevance Pro Forma Company is poised to deliver a compelling overall investment thesis and to maximize value for all stakeholders of both Bonterra and Obsidian Energy Why Is This Transaction Compelling For Both Obsidian Energy and Bonterra? ü Top 20 WCSB oil producer with 35,000 boe/d of oil-weighted production Cardium Champion: ü Ability to deploy combined capital spending towards best-return inventory at ü Willesden Green Enhanced Scale + Relevance ü Pro Forma Company is ~2x the size of any other Cardium-focused firm ü At US$50 WTI/bbl and a 4.5x EV/EBITDA multiple, Bonterra’ Shares would Significant Accretion to appreciate by ~375% to ~C$6.40 per share (~$3.20/share OBE) ü ü Under the same assumptions, Bonterra’s 2022E shares appreciate by over 670% to Shareholders of BNE+OBE ~$10.40 per share (~$5.20/share OBE) ü Pro Forma Company base decline of ~18% Maintain Strengths: ü High netbacks of $23/boe 2022E based on US$50 WTI/bbl and C$1.95/MMBtu Low Decline + High Netback ü AECO Light Oil ü Continue success in lowering operating expenses and improving capital efficiency Stable Balance Sheet, ü Deleveraging for Bonterra (2x Debt/EBITDA by 2022E at US$50 WTI/bbl) Debt Reduction,ü Extend debt maturities with support of lenders ü ü Improved ability to secure new capital to refinance existing bank debt Improved Access to Capital ü Synergies from lower G&A and operating expenses, improved capital efficiency, aligned decommissioning liability strategy, and lower interest costs over time Meaningful Synergies Drive 1 ü Pro Forma Company will have up to $100 million greater free cash flow over the ü Equity Appreciation first three years versus the stand-alone entities, creating a clear path to significant equity appreciation Obsidian Energy remains prepared to immediately engage in prompt discussions with Bonterra to negotiate mutually acceptable definitive agreements to finalize a transaction For further detailed information see “Creating the Cardium Champion” presentation available at www.ObsidianEnergy.com 7 7 1. US$50 WTI/bbl and C$1.95/MMBtu AECORegaining Market Relevance Pro Forma Company is poised to deliver a compelling overall investment thesis and to maximize value for all stakeholders of both Bonterra and Obsidian Energy Why Is This Transaction Compelling For Both Obsidian Energy and Bonterra? ü Top 20 WCSB oil producer with 35,000 boe/d of oil-weighted production Cardium Champion: ü Ability to deploy combined capital spending towards best-return inventory at ü Willesden Green Enhanced Scale + Relevance ü Pro Forma Company is ~2x the size of any other Cardium-focused firm ü At US$50 WTI/bbl and a 4.5x EV/EBITDA multiple, Bonterra’ Shares would Significant Accretion to appreciate by ~375% to ~C$6.40 per share (~$3.20/share OBE) ü ü Under the same assumptions, Bonterra’s 2022E shares appreciate by over 670% to Shareholders of BNE+OBE ~$10.40 per share (~$5.20/share OBE) ü Pro Forma Company base decline of ~18% Maintain Strengths: ü High netbacks of $23/boe 2022E based on US$50 WTI/bbl and C$1.95/MMBtu Low Decline + High Netback ü AECO Light Oil ü Continue success in lowering operating expenses and improving capital efficiency Stable Balance Sheet, ü Deleveraging for Bonterra (2x Debt/EBITDA by 2022E at US$50 WTI/bbl) Debt Reduction,ü Extend debt maturities with support of lenders ü ü Improved ability to secure new capital to refinance existing bank debt Improved Access to Capital ü Synergies from lower G&A and operating expenses, improved capital efficiency, aligned decommissioning liability strategy, and lower interest costs over time Meaningful Synergies Drive 1 ü Pro Forma Company will have up to $100 million greater free cash flow over the ü Equity Appreciation first three years versus the stand-alone entities, creating a clear path to significant equity appreciation Obsidian Energy remains prepared to immediately engage in prompt discussions with Bonterra to negotiate mutually acceptable definitive agreements to finalize a transaction For further detailed information see “Creating the Cardium Champion” presentation available at www.ObsidianEnergy.com 7 7 1. US$50 WTI/bbl and C$1.95/MMBtu AECO

Obsidian Energy Investment Highlights • Base business continues to improve through strong production performance leveraging significantly improved cost structure Corporate • Focused on Cardium consolidation to realize significant synergies, continue to lower our US$ WTI/bbl breakeven costs and achieve market relevance • Largest acreage holder in the Cardium • Cardium is one of Canada’s lowest cost light oil resources, with strong IRR and recycle ratios • Drilling inventory of over 900 (gross) Cardium locations • Strong well performance since the beginning of 2018 in the Willesden Green Cardium (Crimson Lake and East Crimson) High Quality Assets • YTD OPEX of $4.31/boe in Willesden Green with Large • 8% decrease in Willesden Green DCET costs since Q2 2018 Inventory and Acreage Position • H1 2020 program exceeded expectations with some of the strongest production rates seen to date in our multi-year Cardium program • Flexible operations allow for proactive decisions with respect to production targets in response to commodity price changes at minimal cost • Additional opportunities, such as waterflood and EOR projects, become competitive with increased pricing • Ownership and control of strategic infrastructure including pipelines, processing and Infrastructure compression facilities Ownership and Control • Ability to grow near-term production in both Willesden Green and Pembina with minimal infrastructure spend 8 See end notes for additional information Obsidian Energy Investment Highlights • Base business continues to improve through strong production performance leveraging significantly improved cost structure Corporate • Focused on Cardium consolidation to realize significant synergies, continue to lower our US$ WTI/bbl breakeven costs and achieve market relevance • Largest acreage holder in the Cardium • Cardium is one of Canada’s lowest cost light oil resources, with strong IRR and recycle ratios • Drilling inventory of over 900 (gross) Cardium locations • Strong well performance since the beginning of 2018 in the Willesden Green Cardium (Crimson Lake and East Crimson) High Quality Assets • YTD OPEX of $4.31/boe in Willesden Green with Large • 8% decrease in Willesden Green DCET costs since Q2 2018 Inventory and Acreage Position • H1 2020 program exceeded expectations with some of the strongest production rates seen to date in our multi-year Cardium program • Flexible operations allow for proactive decisions with respect to production targets in response to commodity price changes at minimal cost • Additional opportunities, such as waterflood and EOR projects, become competitive with increased pricing • Ownership and control of strategic infrastructure including pipelines, processing and Infrastructure compression facilities Ownership and Control • Ability to grow near-term production in both Willesden Green and Pembina with minimal infrastructure spend 8 See end notes for additional information

Corporate Cost Improvements OPEX Commentary Exceeding our 2020 OPEX and G&A per boe guidance Operating Expenses (OPEX) • Total reduction in OPEX per boe of 26% from 2020 Guidance 2017 to mid-point of 2020 Guidance ($11.30/boe) • 2020 OPEX per boe continues to decrease despite lower production volumes Further OPEX Improvements • Take advantage of Crimson Lake’s low operating expenses when development capital resumes • Continue to optimize and drive efficiencies G&A across our entire Cardium footprint • Abandonment of Legacy assets will reduce ongoing OPEX G&A • Total reduction in G&A per boe of 42% from 2017 to mid-point of 2020 Guidance • 2020 G&A per boe continues to fall despite lower production volumes 2020 Guidance 9 See end notes for additional information Corporate Cost Improvements OPEX Commentary Exceeding our 2020 OPEX and G&A per boe guidance Operating Expenses (OPEX) • Total reduction in OPEX per boe of 26% from 2020 Guidance 2017 to mid-point of 2020 Guidance ($11.30/boe) • 2020 OPEX per boe continues to decrease despite lower production volumes Further OPEX Improvements • Take advantage of Crimson Lake’s low operating expenses when development capital resumes • Continue to optimize and drive efficiencies G&A across our entire Cardium footprint • Abandonment of Legacy assets will reduce ongoing OPEX G&A • Total reduction in G&A per boe of 42% from 2017 to mid-point of 2020 Guidance • 2020 G&A per boe continues to fall despite lower production volumes 2020 Guidance 9 See end notes for additional information

Corporate Breakeven Analysis Breakeven US$ WTI/bbl - Historical and Projected Obsidian / Obsidian & Bonterra Pro Forma Unhedged Cash Flow (US$/bbl) 2020 Breakeven Price ~$US39 WTI including Obsidian Hedge Positions Commentary • Our focus on improving the efficiency of the business is yielding material reductions in our WTI break-even assessment • Continued focus on cost optimization throughout the business (G&A/ OPEX/ CAPEX) • Execution of our development and optimization programs yielding top tier results • Pro Forma combination with Bonterra will drive break-even US$ WTI/bbl costs to $37/bbl or better as synergies are realized 10 See end notes for additional information Corporate Breakeven Analysis Breakeven US$ WTI/bbl - Historical and Projected Obsidian / Obsidian & Bonterra Pro Forma Unhedged Cash Flow (US$/bbl) 2020 Breakeven Price ~$US39 WTI including Obsidian Hedge Positions Commentary • Our focus on improving the efficiency of the business is yielding material reductions in our WTI break-even assessment • Continued focus on cost optimization throughout the business (G&A/ OPEX/ CAPEX) • Execution of our development and optimization programs yielding top tier results • Pro Forma combination with Bonterra will drive break-even US$ WTI/bbl costs to $37/bbl or better as synergies are realized 10 See end notes for additional information

Undeveloped Reserves 2019 PDP/1P Ratio 2019 2P Locations/Section Commentary • OBE has booked undeveloped locations based on achievable capital spending over the next 5 years. In comparison to peers, OBE is conservatively booked with one of the highest ratio of PDP/1P of all identified companies • OBE has a significant land base with a low booked location per section metric compared to peers indicating significant room to book future locations as development progresses 11 See end notes for additional information Undeveloped Reserves 2019 PDP/1P Ratio 2019 2P Locations/Section Commentary • OBE has booked undeveloped locations based on achievable capital spending over the next 5 years. In comparison to peers, OBE is conservatively booked with one of the highest ratio of PDP/1P of all identified companies • OBE has a significant land base with a low booked location per section metric compared to peers indicating significant room to book future locations as development progresses 11 See end notes for additional information

Cardium Play Fairways A Large High-Graded Inventory West Pembina Central Pembina R10W5 INDEX MAP 132 680 Type Curve Locations Type Curve Locations • Well established productive • Individual fairways and unit trend significantly de-risked boundaries in historically by major Cardium players pressure supported West • Underdeveloped acreage properties Pembina • Easy access to existing OBE • Ability to waterflood for facilities and direct access to minimal capital through Central regional transportation existing infrastructure Pembina • Recent technical work has added ~500 identified inventory locations Crimson Lake East Crimson T45 36 71 Type Curve Locations Type Curve Locations 15 kms 10 miles East • Banked oil from historical • Continued eastward Crimson pressure maintenance extension of Crimson Lake Crimson • Top quality reservoir development program Lake previously underdeveloped • De-risked by new competitor by vertical drilling drilling in 2018-2020 OBE Cardium WI land • Recent top quartile results • Existing flexible Peer lands • Existing flexible infrastructure infrastructure 900+ total identified inventory 135 YE 2019 Net Booked Cardium Locations 12 See end notes for additional information Cardium Play Fairways A Large High-Graded Inventory West Pembina Central Pembina R10W5 INDEX MAP 132 680 Type Curve Locations Type Curve Locations • Well established productive • Individual fairways and unit trend significantly de-risked boundaries in historically by major Cardium players pressure supported West • Underdeveloped acreage properties Pembina • Easy access to existing OBE • Ability to waterflood for facilities and direct access to minimal capital through Central regional transportation existing infrastructure Pembina • Recent technical work has added ~500 identified inventory locations Crimson Lake East Crimson T45 36 71 Type Curve Locations Type Curve Locations 15 kms 10 miles East • Banked oil from historical • Continued eastward Crimson pressure maintenance extension of Crimson Lake Crimson • Top quality reservoir development program Lake previously underdeveloped • De-risked by new competitor by vertical drilling drilling in 2018-2020 OBE Cardium WI land • Recent top quartile results • Existing flexible Peer lands • Existing flexible infrastructure infrastructure 900+ total identified inventory 135 YE 2019 Net Booked Cardium Locations 12 See end notes for additional information

Cardium Growth & Operational Improvements Commentary Total Cardium Production • Our 2017-2020 drilling programs in Crimson Lake have delivered robust production growth with high-netbacks and low operating costs • Lowered DCET costs by 8% since Q2 2018 • OPEX has decreased 41% from FY 2017 – YTD 2020 in Willesden Green, • Excellent safety performance with >1,000 days since last lost time incident • Results from the H1 2020 10 well program to date have been above our expectations, with 5 of our 10 wells were among the top performing wells in the Cardium in a June 2020 analyst report Willesden Green Production Willesden Green Production & Operating Costs 14,000 12,000 46% 45% 10,000 8,000 43% 13% 13% 6,000 42% 9% 4,000 9% 42% 41% 2,000 48% 48% 0 FY 2017 FY 2018 FY 2019 YTD 2020 Oil (bbl/d) NGL (bbl/d) Gas (boe/d) 13 See end notes for additional information Average Daily Production (boe/d)Cardium Growth & Operational Improvements Commentary Total Cardium Production • Our 2017-2020 drilling programs in Crimson Lake have delivered robust production growth with high-netbacks and low operating costs • Lowered DCET costs by 8% since Q2 2018 • OPEX has decreased 41% from FY 2017 – YTD 2020 in Willesden Green, • Excellent safety performance with >1,000 days since last lost time incident • Results from the H1 2020 10 well program to date have been above our expectations, with 5 of our 10 wells were among the top performing wells in the Cardium in a June 2020 analyst report Willesden Green Production Willesden Green Production & Operating Costs 14,000 12,000 46% 45% 10,000 8,000 43% 13% 13% 6,000 42% 9% 4,000 9% 42% 41% 2,000 48% 48% 0 FY 2017 FY 2018 FY 2019 YTD 2020 Oil (bbl/d) NGL (bbl/d) Gas (boe/d) 13 See end notes for additional information Average Daily Production (boe/d)

Crimson Lake Summary Economics • YTD average production of 9,715 boe/d DCET Capex ($MM) $3.2 • Obsidian Energy cornerstone for revitalized primary EUR (Mboe) 229 development on our Cardium acreage Oil IP365 (bbl/d) 156 • Banked oil from historical pressure maintenance in WGCU#9 Total IP365 (boe/d) 234 • Top quality reservoir previously undeveloped due to surface NPV BTAX 10% ($MM) $2.2 and infrastructure challenges for vertical drilling IRR (%) 74% • Existing flexible infrastructure at the Crimson 13-27 facility with optionality to East Crimson Payout (years) 1.2 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2020 program OBE 2018-2019 well 12 Month Efficiency ($/boed) $13,700 Peer well Inventory Unit land Breakeven (IRR 10%) WTI ($US/bbl) $22.62 OBE Cardium WI land OBE East Crimson land Type Curve – Crimson Lake 500 160 450 140 40 0 120 350 100 300 250 80 Crimson Lake - Daily Production 20 0 60 Crimson Lake - Cumulative Production 150 40 100 20 50 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 14 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)Crimson Lake Summary Economics • YTD average production of 9,715 boe/d DCET Capex ($MM) $3.2 • Obsidian Energy cornerstone for revitalized primary EUR (Mboe) 229 development on our Cardium acreage Oil IP365 (bbl/d) 156 • Banked oil from historical pressure maintenance in WGCU#9 Total IP365 (boe/d) 234 • Top quality reservoir previously undeveloped due to surface NPV BTAX 10% ($MM) $2.2 and infrastructure challenges for vertical drilling IRR (%) 74% • Existing flexible infrastructure at the Crimson 13-27 facility with optionality to East Crimson Payout (years) 1.2 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2020 program OBE 2018-2019 well 12 Month Efficiency ($/boed) $13,700 Peer well Inventory Unit land Breakeven (IRR 10%) WTI ($US/bbl) $22.62 OBE Cardium WI land OBE East Crimson land Type Curve – Crimson Lake 500 160 450 140 40 0 120 350 100 300 250 80 Crimson Lake - Daily Production 20 0 60 Crimson Lake - Cumulative Production 150 40 100 20 50 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 14 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)

East Crimson Summary Economics • YTD average production of 3,127 boe/d DCET Capex ($MM) $2.9 • Continued Eastward extension of the successful Crimson EUR (Mboe) 203 Lake development program Oil IP365 (bbl/d) 136 • Area has been de-risked by recent peer drilling results supporting the revitalized development Total IP365 (boe/d) 194 • Shared and scalable infrastructure with the Crimson Lake NPV BTAX 10% ($MM) $1.6 program IRR (%) 58% • Combination of pressure supported edge drilling and underdeveloped unit fairways Payout (years) 1.4 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2020 program 12 Month Efficiency ($/boed) $14,700 OBE 2018-2019 well Peer well Inventory Breakeven (IRR 10%) WTI ($US/bbl) $25.20 Unit land OBE Cardium WI land OBE Crimson land Type Curve – East Crimson 40 0 140 350 120 T43 300 100 WGCU#1 250 80 WGCU#2 20 0 East Crimson - Daily Production 60 150 East Crimson - Cumulative Production WGCU#6 40 100 20 50 WGCU#3 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 15 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)East Crimson Summary Economics • YTD average production of 3,127 boe/d DCET Capex ($MM) $2.9 • Continued Eastward extension of the successful Crimson EUR (Mboe) 203 Lake development program Oil IP365 (bbl/d) 136 • Area has been de-risked by recent peer drilling results supporting the revitalized development Total IP365 (boe/d) 194 • Shared and scalable infrastructure with the Crimson Lake NPV BTAX 10% ($MM) $1.6 program IRR (%) 58% • Combination of pressure supported edge drilling and underdeveloped unit fairways Payout (years) 1.4 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2020 program 12 Month Efficiency ($/boed) $14,700 OBE 2018-2019 well Peer well Inventory Breakeven (IRR 10%) WTI ($US/bbl) $25.20 Unit land OBE Cardium WI land OBE Crimson land Type Curve – East Crimson 40 0 140 350 120 T43 300 100 WGCU#1 250 80 WGCU#2 20 0 East Crimson - Daily Production 60 150 East Crimson - Cumulative Production WGCU#6 40 100 20 50 WGCU#3 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 15 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)

Central Pembina Summary Economics • YTD average production of 4,579 boe/d DCET Capex ($MM) $2.1 • The epicenter of low decline and pressure-maintained EUR (Mboe) 193 development Oil IP365 (bbl/d) 93 • Ability to de-risk inventory and add additional locations Total IP365 (boe/d) 115 through geological and reservoir modelling • Proven and booked waterflood response as the foundation NPV BTAX 10% ($MM) $1.7 for growth – Strong F&D IRR (%) 55% • Ability to grow waterflood scale through existing wells and infrastructure for minimal capital cost allows for corporate Payout (years) 1.7 decline maintenance Technical F&D ($/boe) $11.00 Inventory Unit land OBE Cardium WI land 12 Month Efficiency ($/boed) $18,600 OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $22.13 Type Curve – Central Pembina 20 0 100 180 90 160 80 140 70 120 60 Pembina-Daily Production 100 50 80 Pembina Cumulative Production 40 60 30 40 20 20 10 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 16 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)Central Pembina Summary Economics • YTD average production of 4,579 boe/d DCET Capex ($MM) $2.1 • The epicenter of low decline and pressure-maintained EUR (Mboe) 193 development Oil IP365 (bbl/d) 93 • Ability to de-risk inventory and add additional locations Total IP365 (boe/d) 115 through geological and reservoir modelling • Proven and booked waterflood response as the foundation NPV BTAX 10% ($MM) $1.7 for growth – Strong F&D IRR (%) 55% • Ability to grow waterflood scale through existing wells and infrastructure for minimal capital cost allows for corporate Payout (years) 1.7 decline maintenance Technical F&D ($/boe) $11.00 Inventory Unit land OBE Cardium WI land 12 Month Efficiency ($/boed) $18,600 OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $22.13 Type Curve – Central Pembina 20 0 100 180 90 160 80 140 70 120 60 Pembina-Daily Production 100 50 80 Pembina Cumulative Production 40 60 30 40 20 20 10 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 16 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)

West Pembina Summary Economics • YTD average production of 4,194 boe/d DCET Capex ($MM) $3.0 • Proven oil rich Cardium trend with undeveloped primary EUR (Mboe) 190 development acreage Oil IP365 (bbl/d) 148 • Significant offsetting production from established Cardium Total IP365 (boe/d) 160 players throughout the West side of Pembina • Underdeveloped core acreage NPV BTAX 10% ($MM) $1.6 • Existing flexible infrastructure with significant available IRR (%) 41% capacity in multiple facilities Payout (years) 1.9 • Additional uncaptured inventory in non-operated lands Technical F&D ($/boe) $16.00 R10W5 Inventory 12 Month Efficiency ($/boed) $18,900 Unit land OBE Cardium WI land OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $25.40 Type Curve – West Pembina 300 120 250 100 T48 20 0 80 150 60 West Pembina-Daily Production W est Pembina Cumulative Production 100 40 50 20 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 17 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)West Pembina Summary Economics • YTD average production of 4,194 boe/d DCET Capex ($MM) $3.0 • Proven oil rich Cardium trend with undeveloped primary EUR (Mboe) 190 development acreage Oil IP365 (bbl/d) 148 • Significant offsetting production from established Cardium Total IP365 (boe/d) 160 players throughout the West side of Pembina • Underdeveloped core acreage NPV BTAX 10% ($MM) $1.6 • Existing flexible infrastructure with significant available IRR (%) 41% capacity in multiple facilities Payout (years) 1.9 • Additional uncaptured inventory in non-operated lands Technical F&D ($/boe) $16.00 R10W5 Inventory 12 Month Efficiency ($/boed) $18,900 Unit land OBE Cardium WI land OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $25.40 Type Curve – West Pembina 300 120 250 100 T48 20 0 80 150 60 West Pembina-Daily Production W est Pembina Cumulative Production 100 40 50 20 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 17 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)

Optimization Finding low cost, high value opportunities in our base Total Optimization Program Production Commentary Optimization at Obsidian 2019 Annual Average • Multi-year inventory of targeted, low 787 boe/d (71% Oil) cost projects to increase base production, improve injection, reduce OPEX, maximize reserves recovery 2020 Optimization 745 boe/d (75% Oil) • Maintains very low decline rates and adds to recognized PDP reserves 2019 Summary • $8.4MM Capital spend across 200 projects • 12 Month Capital Efficiency <$8,000/boe with high oil weighting (>70%) Low-Decline Pembina Production • PDP additions of 1.1 mmboe 2020 Summary • YTD spend of $6.5MM focused on wellbore stimulations, reactivations, and recompletions Shut-in of uneconomic Resumption of • $1.6 MM planned in Q4 2020 production and deferred optimization spending maintenance 2019 2020 18Optimization Finding low cost, high value opportunities in our base Total Optimization Program Production Commentary Optimization at Obsidian 2019 Annual Average • Multi-year inventory of targeted, low 787 boe/d (71% Oil) cost projects to increase base production, improve injection, reduce OPEX, maximize reserves recovery 2020 Optimization 745 boe/d (75% Oil) • Maintains very low decline rates and adds to recognized PDP reserves 2019 Summary • $8.4MM Capital spend across 200 projects • 12 Month Capital Efficiency <$8,000/boe with high oil weighting (>70%) Low-Decline Pembina Production • PDP additions of 1.1 mmboe 2020 Summary • YTD spend of $6.5MM focused on wellbore stimulations, reactivations, and recompletions Shut-in of uneconomic Resumption of • $1.6 MM planned in Q4 2020 production and deferred optimization spending maintenance 2019 2020 18

Alberta Viking Strengthening AECO gas prices improving economics Summary Economics • YTD average production of 882 boe/d DCET Capex ($MM) $1.1 • Sweet, light oil development play with significant drilling EUR (Mboe) 73 inventory, including both low risk infill and step-out development, and torque to AECO pricing Oil IP365 (bbl/d) 57 • Low DCET well costs, combined with owned and controlled Total IP365 (boe/d) 94 infrastructure and direct market access yields superior netbacks NPV BTAX 10% ($MM) $0.6 • Shallow, low geological risk resource play IRR (%) 55% • Asset is proximal to multiple, successful offset producers Payout (years) 1.5 Technical F&D ($/boe) $15.00 INDEX MAP OBE Inventory 12 Month Efficiency ($/boed) $11,600 Viking Producer OBE Viking WI Land Industry Land Breakeven (IRR 10%) WTI ($US/bbl) $22.82 Type Curve – AB Viking 20 0 60 180 50 160 140 40 120 AB Viking-Daily Production 100 30 80 AB Viking-Cumulative Production 20 60 40 10 20 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $47.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 19 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)Alberta Viking Strengthening AECO gas prices improving economics Summary Economics • YTD average production of 882 boe/d DCET Capex ($MM) $1.1 • Sweet, light oil development play with significant drilling EUR (Mboe) 73 inventory, including both low risk infill and step-out development, and torque to AECO pricing Oil IP365 (bbl/d) 57 • Low DCET well costs, combined with owned and controlled Total IP365 (boe/d) 94 infrastructure and direct market access yields superior netbacks NPV BTAX 10% ($MM) $0.6 • Shallow, low geological risk resource play IRR (%) 55% • Asset is proximal to multiple, successful offset producers Payout (years) 1.5 Technical F&D ($/boe) $15.00 INDEX MAP OBE Inventory 12 Month Efficiency ($/boed) $11,600 Viking Producer OBE Viking WI Land Industry Land Breakeven (IRR 10%) WTI ($US/bbl) $22.82 Type Curve – AB Viking 20 0 60 180 50 160 140 40 120 AB Viking-Daily Production 100 30 80 AB Viking-Cumulative Production 20 60 40 10 20 0 0 0 12 24 36 M onths *Economics Flat Pricing Assumptions: WTI USD $47.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 19 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)

Peace River Oil Partnership (PROP) Ongoing optimization allowing for continued positive net income Summary PROP • YTD average production of 3,123 boe/d, with an average of R25 R20 R15W5 INDEX MAP ALBERTA 1,701 boe/d shut-in during Q2 2020 in response to low T90 commodity prices • Large contiguous heavy oil resource developed with cold- flow, multi-leg horizontal wells • Reliable and steady base production with multiple sales points to allow for pricing optimization • Emerging Clearwater formation oil play and Nampa EOR potential provides additional upside T85 Cadotte Historical Production (boe/d) Seal Harmon Valley Managed production through H1 South 2020 low price environment- economic volumes returned to production July 1 T80 T75 OBE land 20 See end notes for additional information Peace River Oil Partnership (PROP) Ongoing optimization allowing for continued positive net income Summary PROP • YTD average production of 3,123 boe/d, with an average of R25 R20 R15W5 INDEX MAP ALBERTA 1,701 boe/d shut-in during Q2 2020 in response to low T90 commodity prices • Large contiguous heavy oil resource developed with cold- flow, multi-leg horizontal wells • Reliable and steady base production with multiple sales points to allow for pricing optimization • Emerging Clearwater formation oil play and Nampa EOR potential provides additional upside T85 Cadotte Historical Production (boe/d) Seal Harmon Valley Managed production through H1 South 2020 low price environment- economic volumes returned to production July 1 T80 T75 OBE land 20 See end notes for additional information

Reducing Decommissioning Liability Commentary Demonstrated Reduction in Well Abandonment Costs Compelling Decommissioning Liability reductions • Multi-year trend of decommissioning liability reduction Q3 2020: $605MM undiscounted • Active participant in AER’s Area-Base Closure (ABC) Near-term spending minimized • 2020 ABC spend requirements suspended; YTD 2020 spend fully creditable to 2021 requirements Government support & engagement • Obsidian sites awarded $17MM million in grants and additional $4MM allocation eligibility to date on our 3,492 applications within the ASRP; closely monitoring future programs • Field ASRP work began in Oct. 2020 Undiscounted & Uninflated Decommissioning Liability ($MM) • Actively engaged with EPAC and the AER to improve closure programs and regulations 2019 Active and Inactive breakdown by area Targeted, Efficient spending • Focus on inactive Legacy assets. ASRP grants received to date will help abandon 85% of inactive wellbores by end of 2022 • Activity will reduce fixed OPEX from non-productive assets at costs well below D11 estimates • Shallow decline, long life, high netback, oil-weighted Pembina assets extend ARO requirements over a long time period, stretching well into the future • Many wells in the Cardium can be reactivated, recompleted, or repurposed for use in reservoir monitoring See end notes for additional information 21Reducing Decommissioning Liability Commentary Demonstrated Reduction in Well Abandonment Costs Compelling Decommissioning Liability reductions • Multi-year trend of decommissioning liability reduction Q3 2020: $605MM undiscounted • Active participant in AER’s Area-Base Closure (ABC) Near-term spending minimized • 2020 ABC spend requirements suspended; YTD 2020 spend fully creditable to 2021 requirements Government support & engagement • Obsidian sites awarded $17MM million in grants and additional $4MM allocation eligibility to date on our 3,492 applications within the ASRP; closely monitoring future programs • Field ASRP work began in Oct. 2020 Undiscounted & Uninflated Decommissioning Liability ($MM) • Actively engaged with EPAC and the AER to improve closure programs and regulations 2019 Active and Inactive breakdown by area Targeted, Efficient spending • Focus on inactive Legacy assets. ASRP grants received to date will help abandon 85% of inactive wellbores by end of 2022 • Activity will reduce fixed OPEX from non-productive assets at costs well below D11 estimates • Shallow decline, long life, high netback, oil-weighted Pembina assets extend ARO requirements over a long time period, stretching well into the future • Many wells in the Cardium can be reactivated, recompleted, or repurposed for use in reservoir monitoring See end notes for additional information 21

Current Hedge Strategy and Position Hedging Strategy • Hedge up to 50% of production volumes after royalty • Hedge at price levels to: • Protect FFO • Protect positive NOI on specific heavy oil assets • Support economic capital program • Potential debt repayment • Hedges are done on a $CAD basis to avoid FX management Hedged Oil Position & Exercise Price (CAD$/bbl) Hedged AECO Gas Position & Exercise Price (CAD$/mcf) Volumes hedged physically to ensure positive NOI on specific heavy oil assets *Hedged Positions are current as of Oct. 31, 2020 22 See end notes for additional information Current Hedge Strategy and Position Hedging Strategy • Hedge up to 50% of production volumes after royalty • Hedge at price levels to: • Protect FFO • Protect positive NOI on specific heavy oil assets • Support economic capital program • Potential debt repayment • Hedges are done on a $CAD basis to avoid FX management Hedged Oil Position & Exercise Price (CAD$/bbl) Hedged AECO Gas Position & Exercise Price (CAD$/mcf) Volumes hedged physically to ensure positive NOI on specific heavy oil assets *Hedged Positions are current as of Oct. 31, 2020 22 See end notes for additional information

Environmental, Social & Governance Environmental Social Governance Obsidian Energy is committed to Obsidian Energy is committed to Obsidian Energy makes it a minimizing the impact of our making a positive impact in the priority to ensure all stakeholders operations on the environment. communities in which we operate have a clear understanding of our and live. approach to business operations The ABC program allows for and our expectations for regulatory significant progress on Obsidian Energy supported and compliance. abandonment and reclamation of donated to children’s development areas as a whole while increasing organizations, the Prostate Cancer The Board is comprised of 88% efficiencies and decreasing costs of Center, and mental health independents, with an average managing our ARO profile. organizations in 2019. tenure for Board members of 3 years. Our environmental programs aim Obsidian Energy is a member of to meet or exceed all Explorers and Producers Our governance policies include environmental regulation, Association of Canada (EPAC), written documents such as a encompass stakeholder supporting Canada’s conventional Diversity Policy, Business Conduct, communication, resource energy producers and its employees Ethics Code of Conduct and conservation, and proper site across western Canada. Whistleblower Policy. abandonment and reclamation practices. 23Environmental, Social & Governance Environmental Social Governance Obsidian Energy is committed to Obsidian Energy is committed to Obsidian Energy makes it a minimizing the impact of our making a positive impact in the priority to ensure all stakeholders operations on the environment. communities in which we operate have a clear understanding of our and live. approach to business operations The ABC program allows for and our expectations for regulatory significant progress on Obsidian Energy supported and compliance. abandonment and reclamation of donated to children’s development areas as a whole while increasing organizations, the Prostate Cancer The Board is comprised of 88% efficiencies and decreasing costs of Center, and mental health independents, with an average managing our ARO profile. organizations in 2019. tenure for Board members of 3 years. Our environmental programs aim Obsidian Energy is a member of to meet or exceed all Explorers and Producers Our governance policies include environmental regulation, Association of Canada (EPAC), written documents such as a encompass stakeholder supporting Canada’s conventional Diversity Policy, Business Conduct, communication, resource energy producers and its employees Ethics Code of Conduct and conservation, and proper site across western Canada. Whistleblower Policy. abandonment and reclamation practices. 23

Experienced management and strong technical team Stephen E. Loukas, Interim President and Chief Executive Officer Financial and commercial • Vast experience in corporate transactions, capital markets, corporate finance and Strong financial, commercial leadership and capital markets $ • Mr. Loukas is a partner, managing member, and portfolio manager at FrontFour $ experience leading the Capital Group LLC, one of the Company’s top shareholders, and has been a member Company of the Board of Directors since 2018 Peter D. Scott, Senior Vice President, Chief Financial Officer Drilling, completions and Subsurface technical • 30 years of extensive financial experience, 20 years in CFO roles primarily in Canadian Oil and Gas companies Strong understanding of • Previously, Senior Vice President and Chief Financial Officer at Ridgeback geological subsurface, Resources Inc., previously Lightstream Resources Ltd. reservoir modelling, advanced design, construction and production Aaron Smith, Senior Vice President, Development & Operations of multi-stage fractured • 20 years of engineering expertise across a broad range of technical and leadership horizonal wells roles • Prior to Obsidian, VP-level leadership roles at Sinopec Canada and early career experience in Corporate Planning, Completions, and Reservoir Engineering Encana Corp. Operations Well-established routines Gary Sykes, Vice President, Commercial with methodical planning § Over 25 years of experience in a variety of technical, operational and managerial and preparations, which has positions in domestic and international oil and gas, primarily with ConocoPhillips resulted in exemplary safety • Extensive Board experience, including the Qatargas 3 joint venture, The performance Mackenzie Valley Pipeline Board and Calgary Zoo Employees Mark Hawkins, Vice President, Legal, General Counsel and Deeply experienced with long Corporate Secretary track-record, representing • Served as the corporate secretary at Obsidian Energy since 2015 and was formerly the General Counsel and Corporate Secretary the top tier • 15 years of legal experience of Cardium expertise 24Experienced management and strong technical team Stephen E. Loukas, Interim President and Chief Executive Officer Financial and commercial • Vast experience in corporate transactions, capital markets, corporate finance and Strong financial, commercial leadership and capital markets $ • Mr. Loukas is a partner, managing member, and portfolio manager at FrontFour $ experience leading the Capital Group LLC, one of the Company’s top shareholders, and has been a member Company of the Board of Directors since 2018 Peter D. Scott, Senior Vice President, Chief Financial Officer Drilling, completions and Subsurface technical • 30 years of extensive financial experience, 20 years in CFO roles primarily in Canadian Oil and Gas companies Strong understanding of • Previously, Senior Vice President and Chief Financial Officer at Ridgeback geological subsurface, Resources Inc., previously Lightstream Resources Ltd. reservoir modelling, advanced design, construction and production Aaron Smith, Senior Vice President, Development & Operations of multi-stage fractured • 20 years of engineering expertise across a broad range of technical and leadership horizonal wells roles • Prior to Obsidian, VP-level leadership roles at Sinopec Canada and early career experience in Corporate Planning, Completions, and Reservoir Engineering Encana Corp. Operations Well-established routines Gary Sykes, Vice President, Commercial with methodical planning § Over 25 years of experience in a variety of technical, operational and managerial and preparations, which has positions in domestic and international oil and gas, primarily with ConocoPhillips resulted in exemplary safety • Extensive Board experience, including the Qatargas 3 joint venture, The performance Mackenzie Valley Pipeline Board and Calgary Zoo Employees Mark Hawkins, Vice President, Legal, General Counsel and Deeply experienced with long Corporate Secretary track-record, representing • Served as the corporate secretary at Obsidian Energy since 2015 and was formerly the General Counsel and Corporate Secretary the top tier • 15 years of legal experience of Cardium expertise 24

Appendix & Endnotes 25Appendix & Endnotes 25

End Notes Slide 3: Corporate Overview Slide 14-17, 19-20: Asset Slides Market Capitalization and Enterprise Value was determined at the close of business on October 30, Inventory locations are internal estimates and are subject to change. No inventory locations have been assigned 2020. Net Debt, Tax Pools and Common Shares Outstanding is based on Q3 2020 financials. to land where Obsidian Energy is not the operator. Reserves (2P), RLI, is based on 2P, PDP Decline are as disclosed in our press release dated February Crimson Lake and East Crimson 6, 2020, titled “Obsidian Energy Releases 2019 Reserves Results” (the “Release”). Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. Well lengths are normalized in length to 2600m. See end note for Slide 17 – 22 for further details regarding production breakdown. Central Pembina Mid-points of guidance: The economics shown reflect the tier 1 locations (279 of the 680 type curve locations). Second half of 2020: 10,840 bbl/d light oil, 2,995 bbl/d heavy oil, 2,000 bbl/d NGLs and 50.5 mmcf/d natural gas West Pembina, Central Pembina, and Viking Full year 2020: 11,680 bbl/d light oil, 2,885 bbl/d heavy oil, 2,135 bbl/d NGLs and 51.3 mmcf/d natural Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. gas Economic metrics are defined from provided type curves, on the Plan Pricing Scenario and break-even IRR10%. Slide 8: Investment Highlights DCE&T costs were been normalized to a 2,600m lateral well and are internal estimates Type curve production is defined by existing productive wells within the defined trend displaying similar reservoir and geological characteristics and normalized for horizontal length and completion. Development plan well Slide 10: Corporate Breakeven Analysis counts are indicative and based on internal estimates under our Plan Pricing Scenario. Source: Company filings, Obsidian, Wall Street Research. Historical PROP production includes production data as of September 30, 2020. Price deck based on WTI USD $47.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33. Q3 2020 Asset Production is broken down as follows: Breakeven WTI price defined as US$ WTI price required to fund sustaining capital to maintain flat Crimson Lake: Light Oil – 4,230 bbl/d, NGL – 939 bbl/d, Gas – 25,092 mcf/d production within cash flow on an exit to exit basis. East Crimson: Light Oil – 1,412 bbl/d, NGL – 364 bbl/d, Gas – 6,875 mcf/d West Pembina: Light Oil – 2,688 bbl/d, NGL – 352 bbl/d, Gas – 5,786 mcf/d Obsidian breakeven analysis based on unhedged cash flow, per Wall Street Research estimates. Central Pembina: Light Oil – 2,365 bbl/d, Heavy Oil – 43 bbl/d, NGL – 519 bbl/d, Gas – 8,735 mcf/d AB Viking: Light Oil – 202 bbl/d, Heavy Oil – 62 bbl/d, NGL – 41 bbl/d, Gas – 3,118 mcf/d Obsidian breakeven burdened by $18.3MM of cash lease expenses in 2018 and 2019, $10MM 2020 PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,700 bbl/d, NGL – 0 bbl/d, Gas – 2,974 mcf/d go-forward. Legacy: Light Oil – 55 bbl/d, Heavy Oil – 17 bbl/d, NGL – 28 bbl/d, Gas – 1,486 mcf/d Slide 11: Underdeveloped Reserves YTD 2020 Asset Production is broken down as follows: Reserves data was collected from publicly available information. Peers include BNE, CJ, IPO, PRQ, Crimson Lake: Light Oil – 4,785 bbl/d, NGL – 967 bbl/d, Gas – 23,780 mcf/d SGY, TVE, TOG, WCP and YGR. East Crimson: Light Oil – 1,624 bbl/d, NGL – 364 bbl/d, Gas – 6,831 mcf/d West Pembina: Light Oil – 2,858 bbl/d, NGL – 340 bbl/d, Gas – 5,976 mcf/d Slide 12: Cardium Play Fairways Central Pembina: Light Oil – 2,527 bbl/d, Heavy Oil – 38 bbl/d, NGL – 512 bbl/d, Gas – 9,009 mcf/d Individual play fairways are Obsidian Energy defined trends displaying similar reservoir and geological AB Viking: Light Oil – 215 bbl/d, Heavy Oil – 83 bbl/d, NGL – 38 bbl/d, Gas – 3,276 mcf/d characteristics. Type curves are defined by existing productive wells within the defined trend displaying PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,646 bbl/d, NGL – 0 bbl/d, Gas – 2,848 mcf/d similar reservoir and geological characteristics and normalized for horizontal length and completion. Legacy: Light Oil –73 bbl/d, Heavy Oil – 44 bbl/d, NGL – 29 bbl/d, Gas – 1,355 mcf/d Slide 13: Cardium Growth & Operational Improvements Slide 18: Optimization Liquids include oil, condensates, and propane. Production is A&D adjusted. Production and capital costs are both based on internal estimates. Willesden Green consists of Crimson Lake and East Crimson. Source for June 2020 Report: Top Cardium Wells is GeoLOGIC Systems Ltd., Google, and Raymond Slide 22: Reducing Decommissioning Liability James Ltd. Actuals per Obsidian Energy 2019 ARO activities and spending results Slide 22: Current Hedge Position and Strategy Current Hedge Position and the weighted average price, or the “Exercise Price” is current as of Nov. 1, 2020. All hedges have been executed in Canadian dollars. (1) Production profiles are based on reserve profiles 26 (2) Reserves data based on YE 2019 reserves evaluation (Sproule Associates Limited)End Notes Slide 3: Corporate Overview Slide 14-17, 19-20: Asset Slides Market Capitalization and Enterprise Value was determined at the close of business on October 30, Inventory locations are internal estimates and are subject to change. No inventory locations have been assigned 2020. Net Debt, Tax Pools and Common Shares Outstanding is based on Q3 2020 financials. to land where Obsidian Energy is not the operator. Reserves (2P), RLI, is based on 2P, PDP Decline are as disclosed in our press release dated February Crimson Lake and East Crimson 6, 2020, titled “Obsidian Energy Releases 2019 Reserves Results” (the “Release”). Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. Well lengths are normalized in length to 2600m. See end note for Slide 17 – 22 for further details regarding production breakdown. Central Pembina Mid-points of guidance: The economics shown reflect the tier 1 locations (279 of the 680 type curve locations). Second half of 2020: 10,840 bbl/d light oil, 2,995 bbl/d heavy oil, 2,000 bbl/d NGLs and 50.5 mmcf/d natural gas West Pembina, Central Pembina, and Viking Full year 2020: 11,680 bbl/d light oil, 2,885 bbl/d heavy oil, 2,135 bbl/d NGLs and 51.3 mmcf/d natural Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. gas Economic metrics are defined from provided type curves, on the Plan Pricing Scenario and break-even IRR10%. Slide 8: Investment Highlights DCE&T costs were been normalized to a 2,600m lateral well and are internal estimates Type curve production is defined by existing productive wells within the defined trend displaying similar reservoir and geological characteristics and normalized for horizontal length and completion. Development plan well Slide 10: Corporate Breakeven Analysis counts are indicative and based on internal estimates under our Plan Pricing Scenario. Source: Company filings, Obsidian, Wall Street Research. Historical PROP production includes production data as of September 30, 2020. Price deck based on WTI USD $47.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33. Q3 2020 Asset Production is broken down as follows: Breakeven WTI price defined as US$ WTI price required to fund sustaining capital to maintain flat Crimson Lake: Light Oil – 4,230 bbl/d, NGL – 939 bbl/d, Gas – 25,092 mcf/d production within cash flow on an exit to exit basis. East Crimson: Light Oil – 1,412 bbl/d, NGL – 364 bbl/d, Gas – 6,875 mcf/d West Pembina: Light Oil – 2,688 bbl/d, NGL – 352 bbl/d, Gas – 5,786 mcf/d Obsidian breakeven analysis based on unhedged cash flow, per Wall Street Research estimates. Central Pembina: Light Oil – 2,365 bbl/d, Heavy Oil – 43 bbl/d, NGL – 519 bbl/d, Gas – 8,735 mcf/d AB Viking: Light Oil – 202 bbl/d, Heavy Oil – 62 bbl/d, NGL – 41 bbl/d, Gas – 3,118 mcf/d Obsidian breakeven burdened by $18.3MM of cash lease expenses in 2018 and 2019, $10MM 2020 PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,700 bbl/d, NGL – 0 bbl/d, Gas – 2,974 mcf/d go-forward. Legacy: Light Oil – 55 bbl/d, Heavy Oil – 17 bbl/d, NGL – 28 bbl/d, Gas – 1,486 mcf/d Slide 11: Underdeveloped Reserves YTD 2020 Asset Production is broken down as follows: Reserves data was collected from publicly available information. Peers include BNE, CJ, IPO, PRQ, Crimson Lake: Light Oil – 4,785 bbl/d, NGL – 967 bbl/d, Gas – 23,780 mcf/d SGY, TVE, TOG, WCP and YGR. East Crimson: Light Oil – 1,624 bbl/d, NGL – 364 bbl/d, Gas – 6,831 mcf/d West Pembina: Light Oil – 2,858 bbl/d, NGL – 340 bbl/d, Gas – 5,976 mcf/d Slide 12: Cardium Play Fairways Central Pembina: Light Oil – 2,527 bbl/d, Heavy Oil – 38 bbl/d, NGL – 512 bbl/d, Gas – 9,009 mcf/d Individual play fairways are Obsidian Energy defined trends displaying similar reservoir and geological AB Viking: Light Oil – 215 bbl/d, Heavy Oil – 83 bbl/d, NGL – 38 bbl/d, Gas – 3,276 mcf/d characteristics. Type curves are defined by existing productive wells within the defined trend displaying PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,646 bbl/d, NGL – 0 bbl/d, Gas – 2,848 mcf/d similar reservoir and geological characteristics and normalized for horizontal length and completion. Legacy: Light Oil –73 bbl/d, Heavy Oil – 44 bbl/d, NGL – 29 bbl/d, Gas – 1,355 mcf/d Slide 13: Cardium Growth & Operational Improvements Slide 18: Optimization Liquids include oil, condensates, and propane. Production is A&D adjusted. Production and capital costs are both based on internal estimates. Willesden Green consists of Crimson Lake and East Crimson. Source for June 2020 Report: Top Cardium Wells is GeoLOGIC Systems Ltd., Google, and Raymond Slide 22: Reducing Decommissioning Liability James Ltd. Actuals per Obsidian Energy 2019 ARO activities and spending results Slide 22: Current Hedge Position and Strategy Current Hedge Position and the weighted average price, or the “Exercise Price” is current as of Nov. 1, 2020. All hedges have been executed in Canadian dollars. (1) Production profiles are based on reserve profiles 26 (2) Reserves data based on YE 2019 reserves evaluation (Sproule Associates Limited)

Definitions and Industry Terms GJ means gigajoules RLI means Reserve Life Index PDP means proved developed producing reserves as per Oil and Gas Disclosures Advisory G&A means general and administrative expenses SEC means U.S. Securities and Exchange Commission 1P means proved reserves as per Oil and Gas Disclosures Advisory GOR means gas oil ratio Spud means the process of beginning to drill a well 2P means proved plus probable reserves as per Oil and Gas Disclosures Advisory H1 means first half of the year Unbooked means locations that are internal estimates based on Obsidian Energy’s prospective acreage and an assumption as to the ABC means area based closure program initiative from the AER number of wells that can be drilled per section based on industry H2 means second half of the year practice and internal review. Unbooked locations do not have A&D means oil and natural gas property acquisitions and attributed reserves or resources (including contingent and divestitures Hz means horizontal well prospective). Unbooked locations have been identified by management as an estimation of Obsidian Energy’s multi-year drilling AER means Alberta Energy Regulor IP means initial production, which is the average production over a activities based on evaluation of applicable geologic, seismic, ARO means Asset Retirement Obligation specified number of days engineering, production and reserves information. ASRP means Alberta Ste Rehabilitation Program IRR means Internal Rate of Return which is the interest rate at USD means United States Dollar which the NPV equals zero Avg means Average WCS means Western Canadian Select bbl and bbl/d means barrels of oil and barrels of oil per day, Liquids means crude oil and NGLs respectively WI means working interest M or k means thousands boe, boe/d means barrels of oil equivalent and barrels of oil equivalent per day, respectively WTI means West Texas Intermediate MM means millions Bonterra means Bonterra Energy Corp. YE means year end Mboe means thousand barrels oil equivalent Bonterra Shares means one common share of Bonterra YDT means year to date CAD means Canadian Dollar MMboe means million barrels oil equivalent Capital Expenditures & Capex includes all direct costs related to our operated and non-operated development programs including N, S, E, W means the North, South, East, West or in any drilling, completions, tie-in, development of and expansions to combination existing facilities and major infrastructure, optimization and EOR activities Netback means the summary of all costs associated with bringing one unit of oil to the marketplace and the revenues from the sale of Company, Obsidian Energy or OBE means Obsidian Energy all products generated from that same unit and is expressed as a Ltd.; as applicable gross profit per barrel DCE&T means drilling, completion, equip and tie-in NGL means natural gas liquids which includes hydrocarbon not Decommissioning means decommissioning expenditures marketed as natural gas (methane) or various classes of oil EOR means enhance oil recovery NPV means net present value, before tax discounted at 10 percent EUR means estimated ultimate recovery Obsidian Share means one common share of Obsidian Energy F&D means finding and development costs Opex means operating costs Frac means fraccing or fracturing, short name for Hydraulic Payout means the time it takes to cover the return of your initial fracturing, a method for extracting oil and natural gas cash outlay Free Cash Flow, which is Funds Flow from Operations less Total Plan Pricing Scenario means the flat price deck at WTI USD Capital Expenditures $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates PROP and Peace River means Peace River Oil Partnership FFO means funds flow from operations, detailed in the Non-GAAP Release means our a press release dated February 6, 2020 measure advisory 27 Recycle Ratio means Netback divided by F&D FY means fiscal yearDefinitions and Industry Terms GJ means gigajoules RLI means Reserve Life Index PDP means proved developed producing reserves as per Oil and Gas Disclosures Advisory G&A means general and administrative expenses SEC means U.S. Securities and Exchange Commission 1P means proved reserves as per Oil and Gas Disclosures Advisory GOR means gas oil ratio Spud means the process of beginning to drill a well 2P means proved plus probable reserves as per Oil and Gas Disclosures Advisory H1 means first half of the year Unbooked means locations that are internal estimates based on Obsidian Energy’s prospective acreage and an assumption as to the ABC means area based closure program initiative from the AER number of wells that can be drilled per section based on industry H2 means second half of the year practice and internal review. Unbooked locations do not have A&D means oil and natural gas property acquisitions and attributed reserves or resources (including contingent and divestitures Hz means horizontal well prospective). Unbooked locations have been identified by management as an estimation of Obsidian Energy’s multi-year drilling AER means Alberta Energy Regulor IP means initial production, which is the average production over a activities based on evaluation of applicable geologic, seismic, ARO means Asset Retirement Obligation specified number of days engineering, production and reserves information. ASRP means Alberta Ste Rehabilitation Program IRR means Internal Rate of Return which is the interest rate at USD means United States Dollar which the NPV equals zero Avg means Average WCS means Western Canadian Select bbl and bbl/d means barrels of oil and barrels of oil per day, Liquids means crude oil and NGLs respectively WI means working interest M or k means thousands boe, boe/d means barrels of oil equivalent and barrels of oil equivalent per day, respectively WTI means West Texas Intermediate MM means millions Bonterra means Bonterra Energy Corp. YE means year end Mboe means thousand barrels oil equivalent Bonterra Shares means one common share of Bonterra YDT means year to date CAD means Canadian Dollar MMboe means million barrels oil equivalent Capital Expenditures & Capex includes all direct costs related to our operated and non-operated development programs including N, S, E, W means the North, South, East, West or in any drilling, completions, tie-in, development of and expansions to combination existing facilities and major infrastructure, optimization and EOR activities Netback means the summary of all costs associated with bringing one unit of oil to the marketplace and the revenues from the sale of Company, Obsidian Energy or OBE means Obsidian Energy all products generated from that same unit and is expressed as a Ltd.; as applicable gross profit per barrel DCE&T means drilling, completion, equip and tie-in NGL means natural gas liquids which includes hydrocarbon not Decommissioning means decommissioning expenditures marketed as natural gas (methane) or various classes of oil EOR means enhance oil recovery NPV means net present value, before tax discounted at 10 percent EUR means estimated ultimate recovery Obsidian Share means one common share of Obsidian Energy F&D means finding and development costs Opex means operating costs Frac means fraccing or fracturing, short name for Hydraulic Payout means the time it takes to cover the return of your initial fracturing, a method for extracting oil and natural gas cash outlay Free Cash Flow, which is Funds Flow from Operations less Total Plan Pricing Scenario means the flat price deck at WTI USD Capital Expenditures $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33 FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates PROP and Peace River means Peace River Oil Partnership FFO means funds flow from operations, detailed in the Non-GAAP Release means our a press release dated February 6, 2020 measure advisory 27 Recycle Ratio means Netback divided by F&D FY means fiscal year

Non-GAAP Measures Advisory In this presentation, we refer to certain financial measures that are not determined in accordance with IFRS. These measures as presented do not have any standardized meaning prescribed by IFRS and therefore they may not be comparable with calculations of similar measures for other companies. We believe that, in conjunction with results presented in accordance with IFRS, these measures assist in providing a more complete understanding of certain aspects of our results of operations and financial performance. You are cautioned, however, that these measures should not be construed as an alternative to measures determined in accordance with IFRS as an indication of our performance. These measures include the following: EBITDA is net earnings (loss) plus finance expenses (income), provisions for (recovery of) income taxes, and depletion, depreciation and amortization. Net Debt in regard to Obsidian Energy, it is the amount of long-term debt, comprised of long-term notes and bank debt, plus net working capital (surplus)/deficit. Net Debt is a measure of leverage and liquidity Debt is bank debt, notes and, solely in respect of Bonterra, subordinated debt. Cash cost is sum of operating costs, transport costs and G&A on a $/boe basis. Production per Debt Adjusted Share is based on the year over year change in net debt adjusted at the Pro Forma Company equity value per share at 4.5x EV/EBITDA Enterprise Value or EV is a measure of total value of the applicable company calculated by aggregating the market value of its common shares at a specific date, adding its total Debt and subtracting its cash and cash and cash equivalents. Funds Flow from Operations is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, onerous office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments, restructuring charges and certain other expenses and is representative of cash related to continuing operations. Funds flow from operations is used to assess the combined entity’s ability to fund planned capital programs. Cash Flow is funds flow from operations before changes in any non-cash working capital changes and decommissioning liabilities. Free cash flow is funds flow from operations less capital and decommissioning expenditures. Netback is the per unit of production amount of revenue less royalties, operating expenses, transportation expenses and realized risk management gains and losses, 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. 28Non-GAAP Measures Advisory In this presentation, we refer to certain financial measures that are not determined in accordance with IFRS. These measures as presented do not have any standardized meaning prescribed by IFRS and therefore they may not be comparable with calculations of similar measures for other companies. We believe that, in conjunction with results presented in accordance with IFRS, these measures assist in providing a more complete understanding of certain aspects of our results of operations and financial performance. You are cautioned, however, that these measures should not be construed as an alternative to measures determined in accordance with IFRS as an indication of our performance. These measures include the following: EBITDA is net earnings (loss) plus finance expenses (income), provisions for (recovery of) income taxes, and depletion, depreciation and amortization. Net Debt in regard to Obsidian Energy, it is the amount of long-term debt, comprised of long-term notes and bank debt, plus net working capital (surplus)/deficit. Net Debt is a measure of leverage and liquidity Debt is bank debt, notes and, solely in respect of Bonterra, subordinated debt. Cash cost is sum of operating costs, transport costs and G&A on a $/boe basis. Production per Debt Adjusted Share is based on the year over year change in net debt adjusted at the Pro Forma Company equity value per share at 4.5x EV/EBITDA Enterprise Value or EV is a measure of total value of the applicable company calculated by aggregating the market value of its common shares at a specific date, adding its total Debt and subtracting its cash and cash and cash equivalents. Funds Flow from Operations is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, onerous office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments, restructuring charges and certain other expenses and is representative of cash related to continuing operations. Funds flow from operations is used to assess the combined entity’s ability to fund planned capital programs. Cash Flow is funds flow from operations before changes in any non-cash working capital changes and decommissioning liabilities. Free cash flow is funds flow from operations less capital and decommissioning expenditures. Netback is the per unit of production amount of revenue less royalties, operating expenses, transportation expenses and realized risk management gains and losses, 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. 28

Oil and Gas Information Advisory 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. Inventory This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Sproule Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked 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. Corporately, the Company has 212 gross booked proved locations and 228 gross booked probable locations as set forth in the Sproule Report. 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 drilling 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 derisked 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. 29Oil and Gas Information Advisory 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. Inventory This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Sproule Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked 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. Corporately, the Company has 212 gross booked proved locations and 228 gross booked probable locations as set forth in the Sproule Report. 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 drilling 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 derisked 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. 29

Reserves Disclosure and Definitions Unless otherwise noted, any reference to reserves in this presentation are based on the report ( Sproule Report ) prepared by Sproule Associates Limited dated February 3, 2020 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, 2019. For further information regarding the Sproule 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. For additional reserve definitions, see the Release. 30Reserves Disclosure and Definitions Unless otherwise noted, any reference to reserves in this presentation are based on the report ( Sproule Report ) prepared by Sproule Associates Limited dated February 3, 2020 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, 2019. For further information regarding the Sproule 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. For additional reserve definitions, see the Release. 30

Forward-Looking Information Advisory Certain statements contained in this presentation constitute forward-looking statements or information (collectively forward-looking statements). 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. Please note that initial production and/or peak rates are not necessarily indicative of long-term performance or ultimate recovery. In particular, this presentation contains, without limitation, forward-looking statements pertaining to the following: our second half and full year 2020 guidance including production, capital expenditures including decommissioning, operating and G&A expense range and that we are on track to meet or exceed or targets; the expected decline rates and reserve life index on reserves; our go-forward strategic priorities in both the short and long term; the timing for acceptance of the offer to Bonterra (the “Offer”); the satisfaction of the conditions to the Offer; the anticipated strategic, operational and financial benefits and synergies that may result from the proposed combination between the Company and Bonterra, including as to expected cost synergies, accretion, and expectations for each of the entities on a stand-alone basis; the resulting benefits of the Offer to the Company and Bonterra shareholders; and that the Offer is the better option compared to adding more debt to an already over-levered balance sheet for Bonterra shareholders; that flexible operations allow for proactive decisions with respect to production targets in response to commodity price changes at minimal cost; that there are additional opportunities in the portfolio, such as waterflood and EOR projects, which become competitive with increased pricing; how we plan to reduce certain costs; that we will continue to optimize and drive efficiencies across our entire Cardium footpint; that the abandonment of Legacy assets will reduce ongoing OPEX; our projected 2020 and 2021 breakeven prices; our potential inventory locations; that certain locations have been de-risked due to various reasons; how our optimization program is structured and the anticipated spend amount for H2 2020; our Cardium development program including timing, locations, costs, optionality, spacing and frac design; the potential for Alberta Viking activity due to AECO gas prices improving the economics; that the emerging Clearwater formation oil play provides potential upside with stacked development potential and that there is future EOR potential which can provide additional upside; that the AER has suspended 2020 ABC spend requirements and will credit 2021 targets by our year to date 2020 spend; the ASRP grants and impact that they will have on the Company; the impact the targeted, efficient spending will have on the Company’s decommissioning liability; our hedges; that recent technical work done has increased our Pembina inventory to over 900 gross Cardium locations; our ability to grow near-term production in both Willesden Green and Pembina with minimal infrastructure spend; that there is additional uncaptured inventory in non-operated lands; and our ability to waterflood certain locations and for minimal capital through existing infrastructure and impact that has on corporate decline maintenance. In addition, all other statements and other information that address the Offer (including satisfaction of the Offer conditions) are forward-looking statements. The key metrics for the Company set forth in this presentation may be considered to be future-oriented financial information or a financial outlook for the purposes of applicable Canadian securities laws. Financial outlook and future-oriented financial information contained in this presentation are based on assumptions about future events based on management's assessment of the relevant information currently available. In particular, this presentation contains projected operational and financial information for 2020 and beyond for the Company. The future-oriented financial information and financial outlooks contained in this presentation have been approved by management as of the date of this presentation. Readers are cautioned that any such financial outlook and future- oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: the benefits to be derived by the Company and its stakeholders from the proposed acquisition of Bonterra; we will have the ability to continue as a going concern going forward and realize our assets and discharge our liabilities in the normal course of business; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements contained herein (including our guidance set out under Outlook ) do not assume the completion of the proposed transaction); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that the Company's operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to the pandemic; global energy policies going forward, including the continued ability of members of OPEC, Russia and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the Canadian Emergency Wage Subsidy program and ASRP) or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; 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; future capital expenditure and decommissioning expenditure levels; future operating costs and G&A costs; future crude 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 crude oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in additional production due to the continuation of low commodity prices or the further deterioration of commodity prices and our expectations regarding when commodity prices will improve such that any remaining shut-in properties can be returned to production; future exchange rates and interest 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, wild fires, infrastructure access and delays in obtaining regulatory approvals and third party consents; 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 continue 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 to renew or replace our syndicated bank facility and our ability to finance the repayment of our senior notes on maturity; and our ability to add production and reserves through our development and exploitation activities. In addition, many of the forward-looking statements 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. Although the Company believes that the expectations reflected in the forward-looking statements 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 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 possibility that we are not able to continue as a going concern and realize our assets and discharge our liabilities in the normal course of business; 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; the possibility that the Company is unable to complete one or more of the potential transactions being pursued pursuant to our ongoing strategic alternatives review process (including the proposed acquisition of Bonterra), on favorable terms or at all, or that the Company and its stakeholders do not realize the anticipated benefits of any such transaction that is completed (including the benefits of the proposed acquisition of Bonterra described herein); the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that the significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally that has been caused by the COVID-19 pandemic persists or worsens; the risk that the COVID-19 pandemic adversely affects the financial capacity of the Company's contractual counterparties 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 notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew our credit facilities on acceptable terms or at all and/or finance the repayment of our senior notes when they mature on acceptable terms or at all and/or obtain debt and/or equity financing to replace one or both of our credit facilities and senior notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior notes; the possibility that we are forced to shut-in additional production or continue existing production shut-ins longer than anticipated, whether due to commodity prices failing to rise or decreasing further or changes to existing government curtailment programs or the imposition of new programs; the risk that OPEC, Russia 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 crude 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 crude oil, natural gas liquids and natural gas, price differentials for crude 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 or interest rates; 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 and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons 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 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 and consumers to the ongoing COVID-19 pandemic; and the other factors described under Risk Factors in our Annual Information Form and described in our public filings, available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive. Unless otherwise specified, the forward-looking statements contained in this document speak only as of October 30, 2020. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward. Please note that illustrative examples are not to be construed as guidance for the Company and further details on assumptions can be found in the End Notes section of the presentation. 31Forward-Looking Information Advisory Certain statements contained in this presentation constitute forward-looking statements or information (collectively forward-looking statements). 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. Please note that initial production and/or peak rates are not necessarily indicative of long-term performance or ultimate recovery. In particular, this presentation contains, without limitation, forward-looking statements pertaining to the following: our second half and full year 2020 guidance including production, capital expenditures including decommissioning, operating and G&A expense range and that we are on track to meet or exceed or targets; the expected decline rates and reserve life index on reserves; our go-forward strategic priorities in both the short and long term; the timing for acceptance of the offer to Bonterra (the “Offer”); the satisfaction of the conditions to the Offer; the anticipated strategic, operational and financial benefits and synergies that may result from the proposed combination between the Company and Bonterra, including as to expected cost synergies, accretion, and expectations for each of the entities on a stand-alone basis; the resulting benefits of the Offer to the Company and Bonterra shareholders; and that the Offer is the better option compared to adding more debt to an already over-levered balance sheet for Bonterra shareholders; that flexible operations allow for proactive decisions with respect to production targets in response to commodity price changes at minimal cost; that there are additional opportunities in the portfolio, such as waterflood and EOR projects, which become competitive with increased pricing; how we plan to reduce certain costs; that we will continue to optimize and drive efficiencies across our entire Cardium footpint; that the abandonment of Legacy assets will reduce ongoing OPEX; our projected 2020 and 2021 breakeven prices; our potential inventory locations; that certain locations have been de-risked due to various reasons; how our optimization program is structured and the anticipated spend amount for H2 2020; our Cardium development program including timing, locations, costs, optionality, spacing and frac design; the potential for Alberta Viking activity due to AECO gas prices improving the economics; that the emerging Clearwater formation oil play provides potential upside with stacked development potential and that there is future EOR potential which can provide additional upside; that the AER has suspended 2020 ABC spend requirements and will credit 2021 targets by our year to date 2020 spend; the ASRP grants and impact that they will have on the Company; the impact the targeted, efficient spending will have on the Company’s decommissioning liability; our hedges; that recent technical work done has increased our Pembina inventory to over 900 gross Cardium locations; our ability to grow near-term production in both Willesden Green and Pembina with minimal infrastructure spend; that there is additional uncaptured inventory in non-operated lands; and our ability to waterflood certain locations and for minimal capital through existing infrastructure and impact that has on corporate decline maintenance. In addition, all other statements and other information that address the Offer (including satisfaction of the Offer conditions) are forward-looking statements. The key metrics for the Company set forth in this presentation may be considered to be future-oriented financial information or a financial outlook for the purposes of applicable Canadian securities laws. Financial outlook and future-oriented financial information contained in this presentation are based on assumptions about future events based on management's assessment of the relevant information currently available. In particular, this presentation contains projected operational and financial information for 2020 and beyond for the Company. The future-oriented financial information and financial outlooks contained in this presentation have been approved by management as of the date of this presentation. Readers are cautioned that any such financial outlook and future- oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: the benefits to be derived by the Company and its stakeholders from the proposed acquisition of Bonterra; we will have the ability to continue as a going concern going forward and realize our assets and discharge our liabilities in the normal course of business; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements contained herein (including our guidance set out under Outlook ) do not assume the completion of the proposed transaction); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that the Company's operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to the pandemic; global energy policies going forward, including the continued ability of members of OPEC, Russia and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the Canadian Emergency Wage Subsidy program and ASRP) or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; 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; future capital expenditure and decommissioning expenditure levels; future operating costs and G&A costs; future crude 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 crude oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in additional production due to the continuation of low commodity prices or the further deterioration of commodity prices and our expectations regarding when commodity prices will improve such that any remaining shut-in properties can be returned to production; future exchange rates and interest 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, wild fires, infrastructure access and delays in obtaining regulatory approvals and third party consents; 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 continue 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 to renew or replace our syndicated bank facility and our ability to finance the repayment of our senior notes on maturity; and our ability to add production and reserves through our development and exploitation activities. In addition, many of the forward-looking statements 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. Although the Company believes that the expectations reflected in the forward-looking statements 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 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 possibility that we are not able to continue as a going concern and realize our assets and discharge our liabilities in the normal course of business; 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; the possibility that the Company is unable to complete one or more of the potential transactions being pursued pursuant to our ongoing strategic alternatives review process (including the proposed acquisition of Bonterra), on favorable terms or at all, or that the Company and its stakeholders do not realize the anticipated benefits of any such transaction that is completed (including the benefits of the proposed acquisition of Bonterra described herein); the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that the significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally that has been caused by the COVID-19 pandemic persists or worsens; the risk that the COVID-19 pandemic adversely affects the financial capacity of the Company's contractual counterparties 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 notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew our credit facilities on acceptable terms or at all and/or finance the repayment of our senior notes when they mature on acceptable terms or at all and/or obtain debt and/or equity financing to replace one or both of our credit facilities and senior notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior notes; the possibility that we are forced to shut-in additional production or continue existing production shut-ins longer than anticipated, whether due to commodity prices failing to rise or decreasing further or changes to existing government curtailment programs or the imposition of new programs; the risk that OPEC, Russia 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 crude 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 crude oil, natural gas liquids and natural gas, price differentials for crude 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 or interest rates; 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 and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons 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 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 and consumers to the ongoing COVID-19 pandemic; and the other factors described under Risk Factors in our Annual Information Form and described in our public filings, available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive. Unless otherwise specified, the forward-looking statements contained in this document speak only as of October 30, 2020. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward. Please note that illustrative examples are not to be construed as guidance for the Company and further details on assumptions can be found in the End Notes section of the presentation. 31