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 February 2021Filed 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 February 2021
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 (the “Offer to Purchase Circular”), as varied by the Notice of Extension, Variation and Change document dated December 18, 2020 and the Notice of Extension dated January 25, 2021, 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 now open for acceptance until 5:00 p.m. (Mountain Daylight Time) on March 29, 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 more than 50% 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 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 (the “Offer to Purchase Circular”), as varied by the Notice of Extension, Variation and Change document dated December 18, 2020 and the Notice of Extension dated January 25, 2021, 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 now open for acceptance until 5:00 p.m. (Mountain Daylight Time) on March 29, 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 more than 50% 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 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 M Ma ar rk ke et t S Su um mm ma ar ry y Ticker Symbol OBE Peace River MM Shares Outstanding 74 3,196 boe/d Q3 2020 Cold flow heavy oil MM Market Capitalization $82 Manage base production MM Net Debt $479 MM Enterprise Value $561 C Co or rp po or ra at te e S Su um mm ma ar ry y 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 G Gu ui id da an nc ce e Period H1 2021 boe/d Production 23,000 – 23,400 MM Capital Expenditures $35 MM Decommissioning $5 Alberta Viking $/boe Operating Expenses $12.20 – 12.60 825 boe/d Q3 2020 Higher GOR oil play $/boe General & Administrative $1.75 – 1.85 Manage base production 3 3 See end notes for additional information Corporate Overview M Ma ar rk ke et t S Su um mm ma ar ry y Ticker Symbol OBE Peace River MM Shares Outstanding 74 3,196 boe/d Q3 2020 Cold flow heavy oil MM Market Capitalization $82 Manage base production MM Net Debt $479 MM Enterprise Value $561 C Co or rp po or ra at te e S Su um mm ma ar ry y 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 G Gu ui id da an nc ce e Period H1 2021 boe/d Production 23,000 – 23,400 MM Capital Expenditures $35 MM Decommissioning $5 Alberta Viking $/boe Operating Expenses $12.20 – 12.60 825 boe/d Q3 2020 Higher GOR oil play $/boe General & Administrative $1.75 – 1.85 Manage base production 3 3 See end notes for additional information
Short-term Strategic Priorities & Results S Sh ho or rt t- -t te er rm m P Pr ri io or ri it ti ie es s • 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 • Recommenced drilling in Winter of 2020/2021 in our Willesden Green Cardium asset with high $ per boe netback inventory • 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 $18 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 D De el li iv ve er ri in ng g R Re es su ul lt ts s 2020 Guidance Q1-Q3 2020 boe/d Production 25,300 – 25,500 25,995 MM Capital Expenditures $56 $46 MM Decommissioning $11 $9 $/boe Operating Expenses $11.00 – 11.20 $10.65 $/boe General & Administrative $1.45 – 1.55 $1.47 4 See end notes for additional information Short-term Strategic Priorities & Results S Sh ho or rt t- -t te er rm m P Pr ri io or ri it ti ie es s • 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 • Recommenced drilling in Winter of 2020/2021 in our Willesden Green Cardium asset with high $ per boe netback inventory • 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 $18 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 D De el li iv ve er ri in ng g R Re es su ul lt ts s 2020 Guidance Q1-Q3 2020 boe/d Production 25,300 – 25,500 25,995 MM Capital Expenditures $56 $46 MM Decommissioning $11 $9 $/boe Operating Expenses $11.00 – 11.20 $10.65 $/boe General & Administrative $1.45 – 1.55 $1.47 4 See end notes for additional information
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 • Creates the Cardium Champion with enhanced scale Pembina and capital markets relevance • Accretive across all equity metrics resulting in the potential for significant per share value appreciation to the benefit of both Bonterra and Obsidian Energy East shareholders Pembina West • Up to C$100 million expected in identified financial, Pembina 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 in a stronger combined pro forma entity • An outcome far superior to what Bonterra can achieve on a stand-alone basis East Crimson • Offer extended to March 29, 2021 with minimum tender Crimson condition set at more than 50% of Bonterra’s issued and Lake outstanding shares 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 • Creates the Cardium Champion with enhanced scale Pembina and capital markets relevance • Accretive across all equity metrics resulting in the potential for significant per share value appreciation to the benefit of both Bonterra and Obsidian Energy East shareholders Pembina West • Up to C$100 million expected in identified financial, Pembina 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 in a stronger combined pro forma entity • An outcome far superior to what Bonterra can achieve on a stand-alone basis East Crimson • Offer extended to March 29, 2021 with minimum tender Crimson condition set at more than 50% of Bonterra’s issued and Lake outstanding shares 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 W Wh hy y I Is s T Th hi is s T Tr ra an ns sa ac ct ti io on n C Co om mp pe el ll li in ng g F Fo or r B Bo ot th h O Ob bs si id di ia an n E En ne er rg gy y a an nd d B Bo on nt te er rr ra a? ? 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’s Shares would 1 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 1 ~$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 1. US$50 WTI/bbl and C$1.95/MMBtu AECO as per Obsidian Energy Ltd. Offer to Purchase Circular dated September 21, 2020; implied premium to BNE shown relative to the closing share price of 7 7 $1.35/share on September 18, 2020Regaining 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 W Wh hy y I Is s T Th hi is s T Tr ra an ns sa ac ct ti io on n C Co om mp pe el ll li in ng g F Fo or r B Bo ot th h O Ob bs si id di ia an n E En ne er rg gy y a an nd d B Bo on nt te er rr ra a? ? 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’s Shares would 1 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 1 ~$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 1. US$50 WTI/bbl and C$1.95/MMBtu AECO as per Obsidian Energy Ltd. Offer to Purchase Circular dated September 21, 2020; implied premium to BNE shown relative to the closing share price of 7 7 $1.35/share on September 18, 2020
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 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 • Q1-Q3 2020 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 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 • Q1-Q3 2020 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 O OP PE EX X C Co om mm me en nt ta ar ry y Exceeding our 2020 OPEX and G&A per boe guidance Operating Expenses (OPEX) Updated 2020 • Total reduction in OPEX per boe of 27% from Guidance 2017 to mid-point of 2020 Guidance ($11.10/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 G& &A A across our entire Cardium footprint • Abandonment of Legacy assets will reduce ongoing OPEX G&A • Total reduction in G&A per boe of 44% from 2017 to mid-point of 2020 Guidance • 2020 G&A per boe continues to fall despite Updated 2020 lower production volumes Guidance 9 See end notes for additional information Corporate Cost Improvements O OP PE EX X C Co om mm me en nt ta ar ry y Exceeding our 2020 OPEX and G&A per boe guidance Operating Expenses (OPEX) Updated 2020 • Total reduction in OPEX per boe of 27% from Guidance 2017 to mid-point of 2020 Guidance ($11.10/boe) • 2020 OPEX per boe continues to decrease despite lower production volumes Further OPEX Improvements • Take advantage of Crimson Lake’s low operating expenses when development capital resumes • Continue to optimize and drive efficiencies G G& &A A across our entire Cardium footprint • Abandonment of Legacy assets will reduce ongoing OPEX G&A • Total reduction in G&A per boe of 44% from 2017 to mid-point of 2020 Guidance • 2020 G&A per boe continues to fall despite Updated 2020 lower production volumes Guidance 9 See end notes for additional information
Corporate Breakeven Analysis B Br re ea ak ke ev ve en n U US S$ $ W WT TI I//b bb bl l - - H Hi is st to or ri ic ca al l a an nd d P Pr ro oj je ec ct te ed d O Ob bs si id di ia an n // O Ob bs si id di ia an n & & B Bo on nt te er rr ra a P Pr ro o F Fo or rm ma a Unhedged Cash Flow (US$/bbl) 2020 Breakeven Price ~$US39 WTI including Obsidian Hedge Positions C Co om mm me en nt ta ar ry y • 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 $37/bbl or better as synergies are realized 10 See end notes for additional information Corporate Breakeven Analysis B Br re ea ak ke ev ve en n U US S$ $ W WT TI I//b bb bl l - - H Hi is st to or ri ic ca al l a an nd d P Pr ro oj je ec ct te ed d O Ob bs si id di ia an n // O Ob bs si id di ia an n & & B Bo on nt te er rr ra a P Pr ro o F Fo or rm ma a Unhedged Cash Flow (US$/bbl) 2020 Breakeven Price ~$US39 WTI including Obsidian Hedge Positions C Co om mm me en nt ta ar ry y • 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 2 20 01 19 9 P PD DP P//1 1P P R Ra at ti io o 2 20 01 19 9 2 2P P L Lo oc ca at ti io on ns s//S Se ec ct ti io on n C Co om mm me en nt ta ar ry y • OBE has booked undeveloped locations based on achievable capital spending over the next 5 years. OBE is conservatively booked with one of the highest ratios of PDP/1P of all identified peer 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 2 20 01 19 9 P PD DP P//1 1P P R Ra at ti io o 2 20 01 19 9 2 2P P L Lo oc ca at ti io on ns s//S Se ec ct ti io on n C Co om mm me en nt ta ar ry y • OBE has booked undeveloped locations based on achievable capital spending over the next 5 years. OBE is conservatively booked with one of the highest ratios of PDP/1P of all identified peer 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 W Wes est t P Pem emb bi ina na C Cent entr ra al l P Pem emb bi ina na 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 C Cr ri im ms son on L La ak ke e E Ea as st t C Cr ri im ms son on 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 W Wes est t P Pem emb bi ina na C Cent entr ra al l P Pem emb bi ina na 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 C Cr ri im ms son on L La ak ke e E Ea as st t C Cr ri im ms son on 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
Leading Cardium Well Performance C Cu um mu ul la at ti iv ve e o oi il l r ra at te e o ov ve er r t ti im me e i in n t th he e W Wi il ll le es sd de en n G Gr re ee en n F Fi ie el ld d 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Month OBE (49 wells) Peer 1 (18 wells) Peer 2 (20 wells) Peer 3 (12 wells) Peer 4 (23 wells) Peer 5 (10 wells) Peer 6 (10 wells) C Co om mm me en nt ta ar ry y • Obsidian’s Cardium well performance continues to stand out in the Willesden Green field, reaching payout faster than peers and exhibiting leading capital efficiency • Early month curve behavior reflects Obsidian’s commitment not to overcapitalize completions for higher IP at the expense of overall economic return • Results exhibit both technical proficiency and our superior land base • Obsidian Energy has the largest well count of all competitors with 49 wells drilled since 2017 13 See end notes for additional information Cumulative Light Oil since Rig Release (bbl/well)Leading Cardium Well Performance C Cu um mu ul la at ti iv ve e o oi il l r ra at te e o ov ve er r t ti im me e i in n t th he e W Wi il ll le es sd de en n G Gr re ee en n F Fi ie el ld d 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Month OBE (49 wells) Peer 1 (18 wells) Peer 2 (20 wells) Peer 3 (12 wells) Peer 4 (23 wells) Peer 5 (10 wells) Peer 6 (10 wells) C Co om mm me en nt ta ar ry y • Obsidian’s Cardium well performance continues to stand out in the Willesden Green field, reaching payout faster than peers and exhibiting leading capital efficiency • Early month curve behavior reflects Obsidian’s commitment not to overcapitalize completions for higher IP at the expense of overall economic return • Results exhibit both technical proficiency and our superior land base • Obsidian Energy has the largest well count of all competitors with 49 wells drilled since 2017 13 See end notes for additional information Cumulative Light Oil since Rig Release (bbl/well)
Cardium Growth & Operational Improvements C Co om mm me en nt ta ar ry y T To ot ta al l C Ca ar rd di iu um m P Pr ro od du uc ct ti io on n • Our 2017-2020 drilling programs in Crimson Lake 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 – Q1-Q3 2020 in Willesden Green • Excellent safety performance with >1,150 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 W Wi il ll le es sd de en n G Gr re ee en n P Pr ro od du uc ct ti io on n W Wi il ll le es sd de en n G Gr re ee en n T To ot ta al l P Pr ro od du uc ct ti io on n & & O OP PE EX X 14 See end notes for additional information Cardium Growth & Operational Improvements C Co om mm me en nt ta ar ry y T To ot ta al l C Ca ar rd di iu um m P Pr ro od du uc ct ti io on n • Our 2017-2020 drilling programs in Crimson Lake 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 – Q1-Q3 2020 in Willesden Green • Excellent safety performance with >1,150 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 W Wi il ll le es sd de en n G Gr re ee en n P Pr ro od du uc ct ti io on n W Wi il ll le es sd de en n G Gr re ee en n T To ot ta al l P Pr ro od du uc ct ti io on n & & O OP PE EX X 14 See end notes for additional information
Execute Operationally H1 2021 Development Program C Cr ri im ms so on n L La ak ke e C Co om mm me en nt ta ar ry y • Seven well H1 2021 drilling program builds on drilling results with 3 kms R8W5 INDEX MAP wells adjacent to or nearby 2020 wells that produced above average 2 miles production rates at low operating costs • One rig program expected to result in further operating efficiencies 4-35 Cardium Pad (3 wells) • Five of seven wells expected on production by end of March; Adjacent to 1-27 & 12-26 pad wells remaining two in July • Optionality and flexibility to expand program to eight wells with supportive commodity prices and weather conditions • H1 2021 drilling to maintain first half average production at 2020 T43 13-19 Cardium Pad exit production levels (2 wells) Immediately W of 1-27 & 12-26 pad wells H H1 1 2 20 02 21 1 G Gu ui id da an nc ce e H1 2021 boe/d Production 23,000 – 23,400 MM Capital Expenditures $35 MM Decommissioning $5 6-21 Cardium Pad (2 – 3 wells) $/boe Operating Expenses $12.20 – 12.60 Adjacent to 3-29 pad wells; option for additional H1 $/boe well General & Administrative $1.75 – 1.85 OBE H1 2021 program OBE 2018-2020 well Peer well Unit land OBE Cardium WI land 15 See end notes for additional information Execute Operationally H1 2021 Development Program C Cr ri im ms so on n L La ak ke e C Co om mm me en nt ta ar ry y • Seven well H1 2021 drilling program builds on drilling results with 3 kms R8W5 INDEX MAP wells adjacent to or nearby 2020 wells that produced above average 2 miles production rates at low operating costs • One rig program expected to result in further operating efficiencies 4-35 Cardium Pad (3 wells) • Five of seven wells expected on production by end of March; Adjacent to 1-27 & 12-26 pad wells remaining two in July • Optionality and flexibility to expand program to eight wells with supportive commodity prices and weather conditions • H1 2021 drilling to maintain first half average production at 2020 T43 13-19 Cardium Pad exit production levels (2 wells) Immediately W of 1-27 & 12-26 pad wells H H1 1 2 20 02 21 1 G Gu ui id da an nc ce e H1 2021 boe/d Production 23,000 – 23,400 MM Capital Expenditures $35 MM Decommissioning $5 6-21 Cardium Pad (2 – 3 wells) $/boe Operating Expenses $12.20 – 12.60 Adjacent to 3-29 pad wells; option for additional H1 $/boe well General & Administrative $1.75 – 1.85 OBE H1 2021 program OBE 2018-2020 well Peer well Unit land OBE Cardium WI land 15 See end notes for additional information
Crimson Lake S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 9,715 boe/d DCET Capex ($MM) $3.2 • Obsidian Energy cornerstone for revitalized primary EUR (Mboe) 229 development on our Cardium acreage Oil IP365 (bbl/d) 157 • Banked oil from historical pressure maintenance in WGCU#9 Total IP365 (boe/d) 235 • Top quality reservoir previously undeveloped due to surface NPV BTAX 10% ($MM) $2.6 and infrastructure challenges for vertical drilling IRR (%) 95% • Existing flexible infrastructure at the Crimson 13-27 facility with optionality to East Crimson Payout (years) 1.1 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2021 program OBE 2018-2020 wells 12 Month Efficiency ($/boed) $13,700 Peer wells Inventory Breakeven (IRR 10%) WTI ($US/bbl) $28.34 Unit land OBE Cardium WI land OBE East Crimson land T Ty yp pe e C Cu ur rv ve e – – C Cr ri im ms so on n L La ak ke e 500 160 450 T43 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 16 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)Crimson Lake S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 9,715 boe/d DCET Capex ($MM) $3.2 • Obsidian Energy cornerstone for revitalized primary EUR (Mboe) 229 development on our Cardium acreage Oil IP365 (bbl/d) 157 • Banked oil from historical pressure maintenance in WGCU#9 Total IP365 (boe/d) 235 • Top quality reservoir previously undeveloped due to surface NPV BTAX 10% ($MM) $2.6 and infrastructure challenges for vertical drilling IRR (%) 95% • Existing flexible infrastructure at the Crimson 13-27 facility with optionality to East Crimson Payout (years) 1.1 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2021 program OBE 2018-2020 wells 12 Month Efficiency ($/boed) $13,700 Peer wells Inventory Breakeven (IRR 10%) WTI ($US/bbl) $28.34 Unit land OBE Cardium WI land OBE East Crimson land T Ty yp pe e C Cu ur rv ve e – – C Cr ri im ms so on n L La ak ke e 500 160 450 T43 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 16 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)
East Crimson S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 3,127 boe/d DCET Capex ($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) $2.0 program IRR (%) 77% • Combination of pressure supported edge drilling and underdeveloped unit fairways Payout (years) 1.2 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2021 program 12 Month Efficiency ($/boed) $14,700 OBE 2018-2020 wells Peer wells Inventory Breakeven (IRR 10%) WTI ($US/bbl) $31.26 Unit land OBE Cardium WI land OBE Crimson Lake land T Ty yp pe e C Cu ur rv ve e – – E Ea as st t C Cr ri im ms so on n 40 0 140 T43 350 120 300 WGCU#1 100 250 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40,, FX CAD/USD $1.28 17 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)East Crimson S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 3,127 boe/d DCET Capex ($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) $2.0 program IRR (%) 77% • Combination of pressure supported edge drilling and underdeveloped unit fairways Payout (years) 1.2 Technical F&D ($/boe) $14.00 R7W5 OBE H1 2021 program 12 Month Efficiency ($/boed) $14,700 OBE 2018-2020 wells Peer wells Inventory Breakeven (IRR 10%) WTI ($US/bbl) $31.26 Unit land OBE Cardium WI land OBE Crimson Lake land T Ty yp pe e C Cu ur rv ve e – – E Ea as st t C Cr ri im ms so on n 40 0 140 T43 350 120 300 WGCU#1 100 250 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40,, FX CAD/USD $1.28 17 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Production (mboe)
Central Pembina S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 4,579 boe/d DCET Capex ($MM) $2.1 • The epicenter of low decline and pressure-maintained EUR (Mboe) 193 development Oil IP365 (bbl/d) 102 • Ability to de-risk inventory and add additional locations Total IP365 (boe/d) 123 through geological and reservoir modelling • Proven and booked waterflood response as the foundation NPV BTAX 10% ($MM) $2.0 for growth – Strong F&D IRR (%) 70% • Ability to grow waterflood scale through existing wells and infrastructure for minimal capital cost allows for corporate Payout (years) 1.4 decline maintenance Technical F&D ($/boe) $11.00 Inventory Unit land OBE Cardium WI land 12 Month Efficiency ($/boed) $17,400 OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $30.31 T Ty yp pe e C Cu ur rv ve e – – C Ce en nt tr ra al l P Pe em mb bi in na a 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 18 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)Central Pembina S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 4,579 boe/d DCET Capex ($MM) $2.1 • The epicenter of low decline and pressure-maintained EUR (Mboe) 193 development Oil IP365 (bbl/d) 102 • Ability to de-risk inventory and add additional locations Total IP365 (boe/d) 123 through geological and reservoir modelling • Proven and booked waterflood response as the foundation NPV BTAX 10% ($MM) $2.0 for growth – Strong F&D IRR (%) 70% • Ability to grow waterflood scale through existing wells and infrastructure for minimal capital cost allows for corporate Payout (years) 1.4 decline maintenance Technical F&D ($/boe) $11.00 Inventory Unit land OBE Cardium WI land 12 Month Efficiency ($/boed) $17,400 OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $30.31 T Ty yp pe e C Cu ur rv ve e – – C Ce en nt tr ra al l P Pe em mb bi in na a 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 18 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)
West Pembina S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 4,194 boe/d DCET Capex ($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) $2.1 • Existing flexible infrastructure with significant available IRR (%) 56% capacity in multiple facilities Payout (years) 1.5 • Additional uncaptured inventory in non-operated lands Technical F&D ($/boe) $16.00 R10W5 Inventory 12 Month Efficiency ($/boed) $18,800 Unit land OBE Cardium WI land OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $32.62 T Ty yp pe e C Cu ur rv ve e – – W We es st t P Pe em mb bi in na a 300 120 250 100 T48 20 0 80 150 60 W est 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 19 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)West Pembina S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 4,194 boe/d DCET Capex ($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) $2.1 • Existing flexible infrastructure with significant available IRR (%) 56% capacity in multiple facilities Payout (years) 1.5 • Additional uncaptured inventory in non-operated lands Technical F&D ($/boe) $16.00 R10W5 Inventory 12 Month Efficiency ($/boed) $18,800 Unit land OBE Cardium WI land OBE Pembina land Breakeven (IRR 10%) WTI ($US/bbl) $32.62 T Ty yp pe e C Cu ur rv ve e – – W We es st t P Pe em mb bi in na a 300 120 250 100 T48 20 0 80 150 60 W est 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 19 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 2 20 02 20 0 T To ot ta al l O Op pt ti im mi iz za at ti io on n P Pr ro og gr ra am m P Pr ro od du uc ct ti io on n C Co om mm me en nt ta ar ry y Optimization at Obsidian 1,400 • Multi-year inventory of targeted, low 1,200 2020 Annual Average Optimization cost projects to increase base 735 boe/d (75% Oil) production, improve injection, reduce 1,000 OPEX, maximize reserves recovery 800 • Maintains very low decline rates and adds to recognized PDP reserves 600 • $8.5 million capital spend focused on 400 wellbore stimulations, reactivations and 200 recompletions - Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Opti Actuals L Lo ow w- -D De ec cl li in ne e P Pe em mb bi in na a P Pr ro od du uc ct ti io on n 12,000 10,000 8,000 6,000 4,000 Shut-in of uneconomic Resumption of production and deferred optimization spending 2,000 maintenance 0 2020 20 2019 boe/d boe/d Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecOptimization Finding low cost, high value opportunities in our base 2 20 02 20 0 T To ot ta al l O Op pt ti im mi iz za at ti io on n P Pr ro og gr ra am m P Pr ro od du uc ct ti io on n C Co om mm me en nt ta ar ry y Optimization at Obsidian 1,400 • Multi-year inventory of targeted, low 1,200 2020 Annual Average Optimization cost projects to increase base 735 boe/d (75% Oil) production, improve injection, reduce 1,000 OPEX, maximize reserves recovery 800 • Maintains very low decline rates and adds to recognized PDP reserves 600 • $8.5 million capital spend focused on 400 wellbore stimulations, reactivations and 200 recompletions - Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Opti Actuals L Lo ow w- -D De ec cl li in ne e P Pe em mb bi in na a P Pr ro od du uc ct ti io on n 12,000 10,000 8,000 6,000 4,000 Shut-in of uneconomic Resumption of production and deferred optimization spending 2,000 maintenance 0 2020 20 2019 boe/d boe/d Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Alberta Viking Strengthening AECO gas prices improving economics S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 882 boe/d DCET Capex ($MM) $1.1 • Sweet, light oil development play with significant drilling EUR (Mboe) 73 inventory, including both low risk infill and step-out development, and torque to AECO pricing Oil IP365 (bbl/d) 57 • Low DCET well costs, combined with owned and controlled Total IP365 (boe/d) 95 infrastructure and direct market access yields superior netbacks NPV BTAX 10% ($MM) $0.6 • Shallow, low geological risk resource play IRR (%) 57% • Asset is proximal to multiple, successful offset producers Payout (years) 1.5 Technical F&D ($/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) $31.18 T Ty yp pe e C Cu ur rv ve e – – A AB B V Vi ik ki in ng g 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 21 See end notes for additional information A verage Daily Production (boe/ d) Cumulative Prod (mboe)Alberta Viking Strengthening AECO gas prices improving economics S Su um mm ma ar ry y E Ec co on no om mi ic cs s • Q1 – Q3 2020 average production of 882 boe/d DCET Capex ($MM) $1.1 • Sweet, light oil development play with significant drilling EUR (Mboe) 73 inventory, including both low risk infill and step-out development, and torque to AECO pricing Oil IP365 (bbl/d) 57 • Low DCET well costs, combined with owned and controlled Total IP365 (boe/d) 95 infrastructure and direct market access yields superior netbacks NPV BTAX 10% ($MM) $0.6 • Shallow, low geological risk resource play IRR (%) 57% • Asset is proximal to multiple, successful offset producers Payout (years) 1.5 Technical F&D ($/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) $31.18 T Ty yp pe e C Cu ur rv ve e – – A AB B V Vi ik ki in ng g 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 $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD $1.28 21 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 S Su um mm ma ar ry y P PR RO OP P • Q1 – Q3 2020 average production of 3,123 boe/d, with an R25 R20 R15W5 INDEX MAP ALBERTA average of 1,701 boe/d shut-in during Q2 2020 in response T90 to low commodity prices, majority of the production was brough back on in Q3 2020 • 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 Nampa • Emerging Clearwater formation oil play and T85 EOR potential provides additional upside Cadotte H Hi is st to or ri ic ca al l P Pr ro od du uc ct ti io on n ( (b bo oe e//d d) ) Seal Harmon Valley Managed production through H1 South 2020 low price environment- economic volumes returned to production July 1 T80 T75 OBE land 22 See end notes for additional information Peace River Oil Partnership (PROP) Ongoing optimization allowing for continued positive net income S Su um mm ma ar ry y P PR RO OP P • Q1 – Q3 2020 average production of 3,123 boe/d, with an R25 R20 R15W5 INDEX MAP ALBERTA average of 1,701 boe/d shut-in during Q2 2020 in response T90 to low commodity prices, majority of the production was brough back on in Q3 2020 • 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 Nampa • Emerging Clearwater formation oil play and T85 EOR potential provides additional upside Cadotte H Hi is st to or ri ic ca al l P Pr ro od du uc ct ti io on n ( (b bo oe e//d d) ) Seal Harmon Valley Managed production through H1 South 2020 low price environment- economic volumes returned to production July 1 T80 T75 OBE land 22 See end notes for additional information
Reducing Decommissioning Liability Commentary D De em mo on ns st tr ra at te ed d R Re ed du uc ct ti io on n i in n W We el ll l A Ab ba an nd do on nm me en nt t C Co os st ts s Compelling Decommissioning Liability reductions • Multi-year trend of decommissioning liability reduction Q3 2020: $605 million 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 $18 million in grants and additional $4 million allocation eligibility to date on our 3,492 applications within the ASRP; closely monitoring future programs • Field ASRP work began in Oct. 2020 U Un nd di is sc co ou un nt te ed d & & U Un ni in nf fl la at te ed d D De ec co om mm mi is ss si io on ni in ng g L Li ia ab bi il li it ty y ( ($ $M MM M) ) • 247 net wells abandoned in 2020 • Actively engaged with EPAC and the AER to 2019 Active and Inactive improve closure programs and regulations breakdown by area Targeted, Efficient spending • Focus on inactive Legacy assets. ASRP grants received to date will help abandon 85% of inactive Legacy 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 23 See end notes for additional information Reducing Decommissioning Liability Commentary D De em mo on ns st tr ra at te ed d R Re ed du uc ct ti io on n i in n W We el ll l A Ab ba an nd do on nm me en nt t C Co os st ts s Compelling Decommissioning Liability reductions • Multi-year trend of decommissioning liability reduction Q3 2020: $605 million 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 $18 million in grants and additional $4 million allocation eligibility to date on our 3,492 applications within the ASRP; closely monitoring future programs • Field ASRP work began in Oct. 2020 U Un nd di is sc co ou un nt te ed d & & U Un ni in nf fl la at te ed d D De ec co om mm mi is ss si io on ni in ng g L Li ia ab bi il li it ty y ( ($ $M MM M) ) • 247 net wells abandoned in 2020 • Actively engaged with EPAC and the AER to 2019 Active and Inactive improve closure programs and regulations breakdown by area Targeted, Efficient spending • Focus on inactive Legacy assets. ASRP grants received to date will help abandon 85% of inactive Legacy wellbores by end of 2022 • Activity will reduce fixed OPEX from non-productive assets at costs well below D11 estimates • Shallow decline, long life, high netback, oil-weighted Pembina assets extend ARO requirements over a long time period, stretching well into the future • Many wells in the Cardium can be reactivated, recompleted, or repurposed for use in reservoir monitoring 23 See end notes for additional information
Current Hedge Strategy and Position P Ph hy ys si ic ca al l O Oi il l H He ed dg ge es s ( (C CA AD D$ $//b bb bl l) ) H He ed dg gi in ng g S St tr ra at te eg gy y W WT TI I H He ea av vy y O Oi il l H He ed dg ge e L Li ig gh ht t O Oi il l D Di if ff fe er re en nt ti ia al l • Target to hedge up to 50% of production volumes Locked-in WTI, Light oil after royalty differentials and differential based foreign exchange on on WTI less MSW, • Hedge at price levels to: lowest API barrels foreign exchange in PROP to generate • Protect FFO and support economic capital fixed NOI of >$5/bbl program • Protect positive NOI on specific heavy oil assets via physical hedges • Potential debt repayment • Hedges are typically done on a $CAD basis to avoid FX management H He ed dg ge ed d O Oi il l P Po os si it ti io on n & & E Ex xe er rc ci is se e P Pr ri ic ce e ( (C CA AD D$ $ H He ed dg ge ed d A AE EC CO O G Ga as s P Po os si it ti io on n & & E Ex xe er rc ci is se e P Pr ri ic ce e ( (C CA AD D$ $//m mc cf f) ) W WT TI I//b bb bl l) ) *Hedged Positions are current as of January 27, 2021 24 See end notes for additional information Current Hedge Strategy and Position P Ph hy ys si ic ca al l O Oi il l H He ed dg ge es s ( (C CA AD D$ $//b bb bl l) ) H He ed dg gi in ng g S St tr ra at te eg gy y W WT TI I H He ea av vy y O Oi il l H He ed dg ge e L Li ig gh ht t O Oi il l D Di if ff fe er re en nt ti ia al l • Target to hedge up to 50% of production volumes Locked-in WTI, Light oil after royalty differentials and differential based foreign exchange on on WTI less MSW, • Hedge at price levels to: lowest API barrels foreign exchange in PROP to generate • Protect FFO and support economic capital fixed NOI of >$5/bbl program • Protect positive NOI on specific heavy oil assets via physical hedges • Potential debt repayment • Hedges are typically done on a $CAD basis to avoid FX management H He ed dg ge ed d O Oi il l P Po os si it ti io on n & & E Ex xe er rc ci is se e P Pr ri ic ce e ( (C CA AD D$ $ H He ed dg ge ed d A AE EC CO O G Ga as s P Po os si it ti io on n & & E Ex xe er rc ci is se e P Pr ri ic ce e ( (C CA AD D$ $//m mc cf f) ) W WT TI I//b bb bl l) ) *Hedged Positions are current as of January 27, 2021 24 See end notes for additional information
Environmental, Social & Governance Environmental Social Governance • Obsidian Energy makes it a • Obsidian Energy is committed to • Obsidian Energy is committed to priority to ensure all minimizing the impact of our making a positive impact in the stakeholders have a clear operations on the environment. communities in which we understanding of our approach operate and live. to business operations and our • The ABC program allows for expectations for regulatory significant progress on • Obsidian Energy supported and compliance. abandonment and reclamation of donated to children’s areas as a whole while development organizations, • The Board is comprised of 88% increasing efficiencies and various food banks where we independents, with an average decreasing costs of managing our operate, the Prostate Cancer tenure for Board members of 4+ years. ARO profile. Center, and mental health organizations over the past two • Our governance policies include • Our environmental programs years. written documents such as a aim to meet or exceed all Diversity Policy, Business environmental regulation, • Obsidian Energy is a member of Conduct, Ethics Code of Conduct encompass stakeholder Explorers and Producers and Whistleblower Policy. communication, resource Association of Canada (EPAC), conservation, and proper site supporting Canada’s abandonment and reclamation conventional energy producers practices. and its employees across western Canada. 25Environmental, Social & Governance Environmental Social Governance • Obsidian Energy makes it a • Obsidian Energy is committed to • Obsidian Energy is committed to priority to ensure all minimizing the impact of our making a positive impact in the stakeholders have a clear operations on the environment. communities in which we understanding of our approach operate and live. to business operations and our • The ABC program allows for expectations for regulatory significant progress on • Obsidian Energy supported and compliance. abandonment and reclamation of donated to children’s areas as a whole while development organizations, • The Board is comprised of 88% increasing efficiencies and various food banks where we independents, with an average decreasing costs of managing our operate, the Prostate Cancer tenure for Board members of 4+ years. ARO profile. Center, and mental health organizations over the past two • Our governance policies include • Our environmental programs years. written documents such as a aim to meet or exceed all Diversity Policy, Business environmental regulation, • Obsidian Energy is a member of Conduct, Ethics Code of Conduct encompass stakeholder Explorers and Producers and Whistleblower Policy. communication, resource Association of Canada (EPAC), conservation, and proper site supporting Canada’s abandonment and reclamation conventional energy producers practices. and its employees across western Canada. 25
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 26Experienced 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 26
Appendix & Endnotes 27Appendix & Endnotes 27
End Notes Slide 3: Corporate Overview Slide 15: Execute Operationally Market Capitalization and Enterprise Value was determined at the close of business on January 27, Mid-point of H1 2021 Guidance Range: 10,225 bbl/d light oil, 2,775 bbl/d heavy oil, 1,950 bbl/d NGLs and 49.5 2021. Net Debt, Tax Pools and Common Shares Outstanding is based on Q3 2020 financials. mmcf/d natural gas Reserves (2P), RLI, is based on 2P, PDP Decline are as disclosed in our press release dated February Slide 16-19, 21-22: Asset Slides 6, 2020, titled “Obsidian Energy Releases 2019 Reserves Results” (the “Release”). Inventory locations are internal estimates and are subject to change. No inventory locations have been assigned to land where Obsidian Energy is not the operator. See end note for Slide 16, 17, 18, 19, 21 and 22 for further details regarding production breakdown. Crimson Lake and East Crimson Mid-point of H1 2021 Guidance Range: 10,225 bbl/d light oil, 2,775 bbl/d heavy oil, 1,950 bbl/d NGLs Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. Well lengths are and 49.5 mmcf/d natural gas normalized in length to 2600m. Slide 4: Short-term Strategic Priorities and Results Central Pembina Mid-point of 2020 Guidance Range: 11,600 bbl/d light oil, 2,850 bbl/d heavy oil, 2,200 bbl/d NGLs and The economics shown reflect the tier 1 locations (279 of the 680 type curve locations). 52.5 mmcf/d natural gas West Pembina, Central Pembina, and Viking Slide 8: Investment Highlights Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. DCE&T costs were been normalized to a 2,600m lateral well and are internal estimates Economic metrics are defined from provided type curves, on the Plan Pricing Scenario and break-even IRR10%. Slide 10: Corporate Breakeven Analysis Source: Company filings, Obsidian, Wall Street Research. 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 Price deck based on WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33. counts are indicative and based on internal estimates under our Plan Pricing Scenario. Breakeven WTI price defined as US$ WTI price required to fund sustaining capital to maintain flat Historical PROP production includes production data as of September 30, 2020. production within cash flow on an exit to exit basis. Q3 2020 Asset Production is broken down as follows: Obsidian breakeven analysis based on unhedged cash flow, per Wall Street Research estimates. Crimson Lake: Light Oil – 4,230 bbl/d, NGL – 939 bbl/d, Gas – 25,092 mcf/d East Crimson: Light Oil – 1,412 bbl/d, NGL – 364 bbl/d, Gas – 6,875 mcf/d Obsidian breakeven burdened by $18.3MM of cash lease expenses in 2018 and 2019, $10MM 2020 West Pembina: Light Oil – 2,688 bbl/d, NGL – 352 bbl/d, Gas – 5,786 mcf/d go-forward. 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 Slide 11: Undeveloped Reserves PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,700 bbl/d, NGL – 0 bbl/d, Gas – 2,974 mcf/d Reserves data was collected from publicly available information. Peers include BNE, CJ, IPO, PRQ, Legacy: Light Oil – 55 bbl/d, Heavy Oil – 17 bbl/d, NGL – 28 bbl/d, Gas – 1,486 mcf/d SGY, TVE, TOG, WCP and YGR. Reserves data based on YE 2019 reserves evaluation (Sproule Associates Limited) YTD 2020 Asset Production is broken down as follows: Crimson Lake: Light Oil – 4,785 bbl/d, NGL – 967 bbl/d, Gas – 23,780 mcf/d Slide 12: Cardium Play Fairways East Crimson: Light Oil – 1,624 bbl/d, NGL – 364 bbl/d, Gas – 6,831 mcf/d Individual play fairways are Obsidian Energy defined trends displaying similar reservoir and geological West Pembina: Light Oil – 2,858 bbl/d, NGL – 340 bbl/d, Gas – 5,976 mcf/d characteristics. Type curves are defined by existing productive wells within the defined trend displaying Central Pembina: Light Oil – 2,527 bbl/d, Heavy Oil – 38 bbl/d, NGL – 512 bbl/d, Gas – 9,009 mcf/d similar reservoir and geological characteristics and normalized for horizontal length and completion. AB Viking: Light Oil – 215 bbl/d, Heavy Oil – 83 bbl/d, NGL – 38 bbl/d, Gas – 3,276 mcf/d PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,646 bbl/d, NGL – 0 bbl/d, Gas – 2,848 mcf/d Slide 13: Leading Cardium Well Performance Legacy: Light Oil –73 bbl/d, Heavy Oil – 44 bbl/d, NGL – 29 bbl/d, Gas – 1,355 mcf/d Cumulative Light Oil since Rig Release. Shown on a gross basis. Not adjusted for well length. Data set: HZ Cardium wells rig-released in the Willesden Green Field 2017-2020, showing licensees Slide 20: Optimization with > 10 wells. Production and capital costs are both based on internal estimates. Peers: Baccalieu Energy Inc., Bonterra Energy Corp., Entrada Resources Inc, Inplay Oil Corp, Prairie Storm Energy Corp., Yangara Resources Corp. Slide 23: Reducing Decommissioning Liability Actuals per Obsidian Energy 2019 ARO activities and spending results. Slide 14: Cardium Growth & Operational Improvements Liquids include oil, condensates, and propane. Production is A&D adjusted. Willesden Green consists of Crimson Lake and East Crimson. Slide 24: Current Hedge Strategy and Position Source for June 2020 Report: Top Cardium Wells is GeoLOGIC Systems Ltd., Google, and Raymond Current Hedge Position and the weighted average price, or the “Exercise Price” is current as of January 27, 2021. James Ltd. All hedges have been executed in Canadian dollars. 28End Notes Slide 3: Corporate Overview Slide 15: Execute Operationally Market Capitalization and Enterprise Value was determined at the close of business on January 27, Mid-point of H1 2021 Guidance Range: 10,225 bbl/d light oil, 2,775 bbl/d heavy oil, 1,950 bbl/d NGLs and 49.5 2021. Net Debt, Tax Pools and Common Shares Outstanding is based on Q3 2020 financials. mmcf/d natural gas Reserves (2P), RLI, is based on 2P, PDP Decline are as disclosed in our press release dated February Slide 16-19, 21-22: Asset Slides 6, 2020, titled “Obsidian Energy Releases 2019 Reserves Results” (the “Release”). Inventory locations are internal estimates and are subject to change. No inventory locations have been assigned to land where Obsidian Energy is not the operator. See end note for Slide 16, 17, 18, 19, 21 and 22 for further details regarding production breakdown. Crimson Lake and East Crimson Mid-point of H1 2021 Guidance Range: 10,225 bbl/d light oil, 2,775 bbl/d heavy oil, 1,950 bbl/d NGLs Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. Well lengths are and 49.5 mmcf/d natural gas normalized in length to 2600m. Slide 4: Short-term Strategic Priorities and Results Central Pembina Mid-point of 2020 Guidance Range: 11,600 bbl/d light oil, 2,850 bbl/d heavy oil, 2,200 bbl/d NGLs and The economics shown reflect the tier 1 locations (279 of the 680 type curve locations). 52.5 mmcf/d natural gas West Pembina, Central Pembina, and Viking Slide 8: Investment Highlights Capital estimates do not include field infrastructure or rig mobilization and demobilization costs. DCE&T costs were been normalized to a 2,600m lateral well and are internal estimates Economic metrics are defined from provided type curves, on the Plan Pricing Scenario and break-even IRR10%. Slide 10: Corporate Breakeven Analysis Source: Company filings, Obsidian, Wall Street Research. 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 Price deck based on WTI USD $45.00, Ed Par Diff USD$5.00, AECO CAD$2.75, FX CAD/USD $1.33. counts are indicative and based on internal estimates under our Plan Pricing Scenario. Breakeven WTI price defined as US$ WTI price required to fund sustaining capital to maintain flat Historical PROP production includes production data as of September 30, 2020. production within cash flow on an exit to exit basis. Q3 2020 Asset Production is broken down as follows: Obsidian breakeven analysis based on unhedged cash flow, per Wall Street Research estimates. Crimson Lake: Light Oil – 4,230 bbl/d, NGL – 939 bbl/d, Gas – 25,092 mcf/d East Crimson: Light Oil – 1,412 bbl/d, NGL – 364 bbl/d, Gas – 6,875 mcf/d Obsidian breakeven burdened by $18.3MM of cash lease expenses in 2018 and 2019, $10MM 2020 West Pembina: Light Oil – 2,688 bbl/d, NGL – 352 bbl/d, Gas – 5,786 mcf/d go-forward. 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 Slide 11: Undeveloped Reserves PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,700 bbl/d, NGL – 0 bbl/d, Gas – 2,974 mcf/d Reserves data was collected from publicly available information. Peers include BNE, CJ, IPO, PRQ, Legacy: Light Oil – 55 bbl/d, Heavy Oil – 17 bbl/d, NGL – 28 bbl/d, Gas – 1,486 mcf/d SGY, TVE, TOG, WCP and YGR. Reserves data based on YE 2019 reserves evaluation (Sproule Associates Limited) YTD 2020 Asset Production is broken down as follows: Crimson Lake: Light Oil – 4,785 bbl/d, NGL – 967 bbl/d, Gas – 23,780 mcf/d Slide 12: Cardium Play Fairways East Crimson: Light Oil – 1,624 bbl/d, NGL – 364 bbl/d, Gas – 6,831 mcf/d Individual play fairways are Obsidian Energy defined trends displaying similar reservoir and geological West Pembina: Light Oil – 2,858 bbl/d, NGL – 340 bbl/d, Gas – 5,976 mcf/d characteristics. Type curves are defined by existing productive wells within the defined trend displaying Central Pembina: Light Oil – 2,527 bbl/d, Heavy Oil – 38 bbl/d, NGL – 512 bbl/d, Gas – 9,009 mcf/d similar reservoir and geological characteristics and normalized for horizontal length and completion. AB Viking: Light Oil – 215 bbl/d, Heavy Oil – 83 bbl/d, NGL – 38 bbl/d, Gas – 3,276 mcf/d PROP: Light Oil – 0 bbl/d, Heavy Oil – 2,646 bbl/d, NGL – 0 bbl/d, Gas – 2,848 mcf/d Slide 13: Leading Cardium Well Performance Legacy: Light Oil –73 bbl/d, Heavy Oil – 44 bbl/d, NGL – 29 bbl/d, Gas – 1,355 mcf/d Cumulative Light Oil since Rig Release. Shown on a gross basis. Not adjusted for well length. Data set: HZ Cardium wells rig-released in the Willesden Green Field 2017-2020, showing licensees Slide 20: Optimization with > 10 wells. Production and capital costs are both based on internal estimates. Peers: Baccalieu Energy Inc., Bonterra Energy Corp., Entrada Resources Inc, Inplay Oil Corp, Prairie Storm Energy Corp., Yangara Resources Corp. Slide 23: Reducing Decommissioning Liability Actuals per Obsidian Energy 2019 ARO activities and spending results. Slide 14: Cardium Growth & Operational Improvements Liquids include oil, condensates, and propane. Production is A&D adjusted. Willesden Green consists of Crimson Lake and East Crimson. Slide 24: Current Hedge Strategy and Position Source for June 2020 Report: Top Cardium Wells is GeoLOGIC Systems Ltd., Google, and Raymond Current Hedge Position and the weighted average price, or the “Exercise Price” is current as of January 27, 2021. James Ltd. All hedges have been executed in Canadian dollars. 28
Definitions and Industry Terms PDP means proved developed producing reserves as per Oil and FFO means funds flow from operations, detailed in the Non-GAAP Q1-Q3 2020 means the first 9 months of 2020 Gas Disclosures Advisory measure advisory 1P means proved reserves as per Oil and Gas Disclosures Recycle Ratio means Netback divided by F&D G&A means general and administrative expenses Advisory RLI means Reserve Life Index 2P means proved plus probable reserves as per Oil and Gas GOR means gas oil ratio Disclosures Advisory SEC means U.S. Securities and Exchange Commission H1 means first half of the year ABC means area based closure program initiative from the AER Unbooked means locations that are internal estimates based on A&D means oil and natural gas property acquisitions and Hz means horizontal well Obsidian Energy’s prospective acreage and an assumption as to the divestitures number of wells that can be drilled per section based on industry IP means initial production, which is the average production over a practice and internal review. Unbooked locations do not have AER means Alberta Energy Regulator specified number of days attributed reserves or resources (including contingent and ARO means Asset Retirement Obligation prospective). Unbooked locations have been identified by management as an estimation of Obsidian Energy’s multi-year drilling IRR means Internal Rate of Return which is the interest rate at ASRP means Alberta Ste Rehabilitation Program activities based on evaluation of applicable geologic, seismic, which the NPV equals zero engineering, production and reserves information. bbl and bbl/d means barrels of oil and barrels of oil per day, respectively Liquids means crude oil and NGLs USD means United States Dollar boe, boe/d means barrels of oil equivalent and barrels of oil M means thousands equivalent per day, respectively WCS means Western Canadian Select Bonterra means Bonterra Energy Corp. MM means millions WTI means West Texas Intermediate Bonterra Shares means one common share of Bonterra Mboe means thousand barrels oil equivalent YE means year end CAD means Canadian Dollar MMboe means million barrels oil equivalent Capital Expenditures & Capex includes all direct costs related to YDT means year to date 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 Company, Obsidian Energy or OBE means Obsidian Energy one unit of oil to the marketplace and the revenues from the sale of Ltd.; as applicable all products generated from that same unit and is expressed as a gross profit per barrel D11 means the AER’s Directive 11 Directive 011: Licensee Liability Rating (LLR) Program: Updated Industry Parameters and Liability NGL means natural gas liquids which includes hydrocarbon not Costs” is published by the Alberta Energy Regulator and is marketed as natural gas (methane) or various classes of oil available at: https://www.aer.ca/regulating-development/rules-and- directives/directives/directive-011 NPV means net present value, before tax discounted at 10 percent DCE&T means drilling, completion, equip and tie-in Obsidian Share means one common share of Obsidian Energy Decommissioning means decommissioning expenditures Opex means operating expenses EOR means enhance oil recovery Payout means the time it takes to cover the return of your initial EUR means estimated ultimate recovery cash outlay F&D means finding and development costs Plan Pricing Scenario means the flat price deck at WTI USD $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD Fractured means fraccing or fracturing, short name for Hydraulic $1.28 fracturing, a method for extracting oil and natural gas Free Cash Flow, which is Funds Flow from Operations less Total PROP and Peace River means Peace River Oil Partnership Capital Expenditures Release means our a press release dated February 6, 2020 FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates 29Definitions and Industry Terms PDP means proved developed producing reserves as per Oil and FFO means funds flow from operations, detailed in the Non-GAAP Q1-Q3 2020 means the first 9 months of 2020 Gas Disclosures Advisory measure advisory 1P means proved reserves as per Oil and Gas Disclosures Recycle Ratio means Netback divided by F&D G&A means general and administrative expenses Advisory RLI means Reserve Life Index 2P means proved plus probable reserves as per Oil and Gas GOR means gas oil ratio Disclosures Advisory SEC means U.S. Securities and Exchange Commission H1 means first half of the year ABC means area based closure program initiative from the AER Unbooked means locations that are internal estimates based on A&D means oil and natural gas property acquisitions and Hz means horizontal well Obsidian Energy’s prospective acreage and an assumption as to the divestitures number of wells that can be drilled per section based on industry IP means initial production, which is the average production over a practice and internal review. Unbooked locations do not have AER means Alberta Energy Regulator specified number of days attributed reserves or resources (including contingent and ARO means Asset Retirement Obligation prospective). Unbooked locations have been identified by management as an estimation of Obsidian Energy’s multi-year drilling IRR means Internal Rate of Return which is the interest rate at ASRP means Alberta Ste Rehabilitation Program activities based on evaluation of applicable geologic, seismic, which the NPV equals zero engineering, production and reserves information. bbl and bbl/d means barrels of oil and barrels of oil per day, respectively Liquids means crude oil and NGLs USD means United States Dollar boe, boe/d means barrels of oil equivalent and barrels of oil M means thousands equivalent per day, respectively WCS means Western Canadian Select Bonterra means Bonterra Energy Corp. MM means millions WTI means West Texas Intermediate Bonterra Shares means one common share of Bonterra Mboe means thousand barrels oil equivalent YE means year end CAD means Canadian Dollar MMboe means million barrels oil equivalent Capital Expenditures & Capex includes all direct costs related to YDT means year to date 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 Company, Obsidian Energy or OBE means Obsidian Energy one unit of oil to the marketplace and the revenues from the sale of Ltd.; as applicable all products generated from that same unit and is expressed as a gross profit per barrel D11 means the AER’s Directive 11 Directive 011: Licensee Liability Rating (LLR) Program: Updated Industry Parameters and Liability NGL means natural gas liquids which includes hydrocarbon not Costs” is published by the Alberta Energy Regulator and is marketed as natural gas (methane) or various classes of oil available at: https://www.aer.ca/regulating-development/rules-and- directives/directives/directive-011 NPV means net present value, before tax discounted at 10 percent DCE&T means drilling, completion, equip and tie-in Obsidian Share means one common share of Obsidian Energy Decommissioning means decommissioning expenditures Opex means operating expenses EOR means enhance oil recovery Payout means the time it takes to cover the return of your initial EUR means estimated ultimate recovery cash outlay F&D means finding and development costs Plan Pricing Scenario means the flat price deck at WTI USD $50.00, Ed Par Diff USD$5.00, AECO CAD$2.40, FX CAD/USD Fractured means fraccing or fracturing, short name for Hydraulic $1.28 fracturing, a method for extracting oil and natural gas Free Cash Flow, which is Funds Flow from Operations less Total PROP and Peace River means Peace River Oil Partnership Capital Expenditures Release means our a press release dated February 6, 2020 FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates 29
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: Cash cost is sum of operating costs, transport costs and G&A on a $/boe basis. Cash Flow is funds flow from operations before changes in any non-cash working capital changes and decommissioning liabilities. Debt is bank debt, notes and, solely in respect of Bonterra, subordinated debt. EBITDA is net earnings (loss) plus finance expenses (income), provisions for (recovery of) income taxes, and depletion, depreciation and amortization. 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. Free cash flow is funds flow from operations less capital and decommissioning expenditures. 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, transaction cots 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. 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 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. 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 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. 30Non-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: Cash cost is sum of operating costs, transport costs and G&A on a $/boe basis. Cash Flow is funds flow from operations before changes in any non-cash working capital changes and decommissioning liabilities. Debt is bank debt, notes and, solely in respect of Bonterra, subordinated debt. EBITDA is net earnings (loss) plus finance expenses (income), provisions for (recovery of) income taxes, and depletion, depreciation and amortization. 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. Free cash flow is funds flow from operations less capital and decommissioning expenditures. 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, transaction cots 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. 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 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. 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 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. 30
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 at December 31, 2019. 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. 31Oil 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 at December 31, 2019. 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. 31
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 February 3, 2020 Release. 32Reserves 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 February 3, 2020 Release. 32
Forward-Looking Information Advisory Certain statements contained in this document constitute forward-looking statements or information (collectively forward-looking statements ) within the meaning of the safe harbour provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as anticipate , continue , estimate , expect , forecast , budget , may , will , project , could , plan , intend , should , believe , outlook , objective , aim , potential , target and similar words suggesting future events or future performance. In addition, statements relating to reserves or resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. 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 full year 2020 guidance including production, capital expenditures including decommissioning, operating and G&A expense ranges; 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; 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 footprint; 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, benefits and impact to decline rates; our Cardium development program including timing, number of rigs, locations, costs, optionality, spacing and frac design, expected production; our half year 2021 guidance including production, capital expenditures including decommissioning, operating and G&A expense ranges; 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; 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; the goals of our environmental, social and governance programs; that we have 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 2021 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; that 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 2020 guidance set out under Corporate Overview and “Short-term Strategic Priorities & Results” and the first half 2021 guidance under “Execute Operationally” ) do not assume the completion of the Offer); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that Bonterra’s publicly available information, including its public reports and securities filings as of January 27, 2021, are accurate and complete; 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 January 27, 2021. 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. 33Forward-Looking Information Advisory Certain statements contained in this document constitute forward-looking statements or information (collectively forward-looking statements ) within the meaning of the safe harbour provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as anticipate , continue , estimate , expect , forecast , budget , may , will , project , could , plan , intend , should , believe , outlook , objective , aim , potential , target and similar words suggesting future events or future performance. In addition, statements relating to reserves or resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. 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 full year 2020 guidance including production, capital expenditures including decommissioning, operating and G&A expense ranges; 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; 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 footprint; 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, benefits and impact to decline rates; our Cardium development program including timing, number of rigs, locations, costs, optionality, spacing and frac design, expected production; our half year 2021 guidance including production, capital expenditures including decommissioning, operating and G&A expense ranges; 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; 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; the goals of our environmental, social and governance programs; that we have 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 2021 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; that 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 2020 guidance set out under Corporate Overview and “Short-term Strategic Priorities & Results” and the first half 2021 guidance under “Execute Operationally” ) do not assume the completion of the Offer); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that Bonterra’s publicly available information, including its public reports and securities filings as of January 27, 2021, are accurate and complete; 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 January 27, 2021. 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. 33