EX-99.1

APPENDIX A – RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Appendix A-1 – Report of Management and Directors on Reserves Data and Other Information
Appendix A-2 – Report on Reserves Data
Appendix A-3 – Statement of Reserves Data and Other Oil and Gas Information

APPENDIX B – MANDATE OF THE AUDIT COMMITTEE

The following is a glossary of certain terms used in this Annual Information Form.

"ABCA" means the Business Corporations Act (Alberta), R.S.A. 2000, C. B‑9, as amended, including the regulations promulgated thereunder.

"Annual Information Form" means this annual information form dated February 22, 2023.

"Board" or "Board of Directors" means the board of directors of Obsidian Energy.

"Engineering Report" means the report prepared by GLJ dated January 20, 2023, where they evaluated one hundred percent of the 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, 2022.

"Form 40-F" means our Annual Report on Form 40-F for the fiscal year ended December 31, 2022, filed with the SEC.

"Handbook" means the Chartered Professional Accountant Canada Handbook, as amended from time to time.

"IFRS" means International Financial Reporting Standards, being the standards and interpretations issued by the International Accounting Standards Board, as amended from time to time. Canadian generally accepted accounting principles applicable to publicly accountable enterprises is determined with reference to Part I of the Handbook, which is IFRS.

"NI 51‑101" means National Instrument 51‑101 Standards of Disclosure for Oil and Gas Activities.

"Obsidian Energy", the "Company", the "Corporation", "we", "us" or "our" each means Obsidian Energy Ltd., a corporation existing under the ABCA. Where the context permits or requires, these terms also include all of Obsidian Energy's Subsidiaries on a consolidated basis. The Company completed a corporate name change in June 2017 from Penn West Petroleum Ltd. (“Penn West”).

"Senior Secured Notes" means our previously outstanding guaranteed, secured senior notes.

"Senior Unsecured Notes" means our senior unsecured notes consisting of $127.6 million principal amount of notes, as described under the heading Capitalization of Obsidian Energy – Debt Capital – Notes".

"Subsidiaries" has the meaning ascribed thereto in the Securities Act (Ontario) and, for greater certainty, includes all corporations and partnerships owned, controlled or directed, directly or indirectly, by Obsidian Energy.

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, C. 1 (5th Supp.), as amended, including the regulations promulgated thereunder, as amended from time to time.

"undeveloped land" and "unproved property" each mean a property or part of a property to which no reserves have been specifically attributed.

Certain terms used herein are defined in the "Glossary of Terms". Certain other terms used herein but not defined herein are defined in NI 51‑101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51‑101.

All dollar amounts in this document are expressed in Canadian dollars, except where otherwise indicated. References to "$" or "Cdn$" are to Canadian dollars and references to "US$" are to United States dollars. On February 22, 2023, the exchange rate based on the noon rate as reported by WM/Refinitiv, was Cdn$1.00 equals US$0.7384.

Where any disclosure of reserves data is made in this Annual Information Form (including the Appendices hereto) that does not reflect all of the reserves of Obsidian Energy, the reader should note that the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

All production and reserves quantities included in this Annual Information Form (including the Appendices hereto) have been prepared in accordance with Canadian practices and specifically in accordance with NI 51‑101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by United States companies. Nevertheless, as part of Obsidian Energy's Form 40-F for the year ended December 31, 2022, filed with the SEC, Obsidian Energy has disclosed proved reserves quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with the U.S. Financial Accounting Standards Board, "Disclosures About Oil and Gas Producing Activities", which disclosure complies with the SEC's rules for disclosing oil and gas reserves.

References in this Annual Information Form to land and properties held, owned, acquired or disposed by us, or in respect of which we have an interest, refer to land or properties in respect of which we have a lease or other contractual right to explore for, develop, exploit and produce hydrocarbons underlying such land or properties.

Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl 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 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.

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

Except where otherwise indicated, the information in this Annual Information Form is presented as at the end of Obsidian Energy's most recently completed financial year, being December 31, 2022.

In the interest of providing our securityholders and potential investors with information regarding Obsidian Energy, including management's assessment of Obsidian Energy's future plans and operations, certain statements contained and incorporated by reference in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document and the documents incorporated by reference herein contain, without limitation, forward-looking statements pertaining to the following: the details of our expected 2023 guidance including capital, development, production, and decommissioning plans; our updated syndicated credit facility and the possible reconfirmation, redetermination and term-out dates; details of our ongoing acquisition, disposition, farm-out and financing strategy; the maturity date of our Senior Unsecured Notes; our dividend policy; our expectations regarding the operational and financial impact that climate change regulations in the jurisdictions in which we operate will have on us; our expectations on what our environmental programs will entail, how we expect to monitor and ensure compliance with our policies; our expected commitments as set forth in our ESG Report and timelines to achieve those commitments; our expectations in connection with decommissioning and reclamation; the belief that we have several low-cost opportunities to reduce our emissions profile, and that our financial obligations related to compliance with existing federal and provincial legislation regarding GHG emissions are not material at this time; that the Corporation is unable to predict what additional legislation or amendment governments may enact in the future and what will need to be reported, remitted and in what time frame the possibility that we could faces increase in costs in order to comply with emissions legislation; that we are committed to mitigating the environmental impact from our operations, and to involving stakeholders throughout the exploration, development, production and abandonment process; that we will seek to drive improvement and to ensure compliance with our environmental policies; that we seek to communicate our commitment to environmental stewardship to our stakeholders in order to always be held accountable; that we continue to work cooperatively with governments to develop an approach to deal with climate change issues that protects the industry's competitiveness, limits the cost and administrative burden of compliance, and supports continued investment in the oil and gas sector; our belief that

the trend towards heightened and additional standards in environmental legislation and regulation will continue and our expectation that we will be making increased expenditures as a result of the expansion of our operations and the adoption of new legislation relating to the protection of the environment; our assessment of the operational and financial impacts that certain risks factors could have on us and the value of our Common Shares should such risk factors materialize; the quantity of our oil, natural gas liquids and natural gas reserves, the recoverability thereof, and the net present values of future net revenue to be derived from our reserves using forecast prices and costs, including the disclosure set forth in Appendix A-3 under "Statement of Reserves Data and Other Oil and Gas Information – Reserves Data"; the amount of royalties, operating costs, development costs, abandonment and reclamation costs and income taxes that we will incur in connection with the production of our reserves; our outlook for oil, natural gas liquids and natural gas prices; our expectations regarding future currency exchange rates and inflation rates; our expectations regarding funding the development of our reserves and impact if we failed to develop those reserves; our expectations regarding the timing for developing our proved undeveloped reserves and probable undeveloped reserves and the amount of future capital expenditures required to develop such reserves; our expectations regarding the significant economic factors and other significant uncertainties that could affect our reserves data; the number of net well bores, facilities and the length of pipeline in respect of which we expect to incur abandonment and reclamation costs and the total amount of such costs that we expect to incur and the timing thereof; our expected A&R Costs; the details of our exploration and development plans in the Cardium, Peace River, Viking and optimization activity in 2023; the expected lands that will be surrendered unless we qualify them in some manner; our expectations regarding when we will be required to pay income taxes; our intention to continue to actively identify and evaluate hedging opportunities in order to reduce our exposure to fluctuations in commodity prices and protect our future cash flows and capital programs; and the nature of, effectiveness of, and benefits to be derived from, our future marketing arrangements and risk management strategies.

With respect to forward-looking statements contained or incorporated by reference in this document, we have made assumptions regarding, among other things that: the Company does not dispose of additional material producing properties other than stated herein; how the Supreme Court of Canada Redwater decision will impact our Company moving forward; that the Government of Alberta will not impose oil and bitumen production quotas under its curtailment rules again in the future; the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that the Company's operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to the pandemic; global energy policies going forward, including the continued ability of members of OPEC, Russia and other nations to agree on and adhere to production quotas from time to time; the impact (and duration, thereof) of the ongoing military actions between Russia and Ukraine and related sanctions on crude oil, NGLs, and natural gas prices; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; that we are able to move forward through the various reconfirmation, redetermination dates with the credit facility and pay the Senior Unsecured Notes at the maturity dates; the terms and timing of any anticipated asset dispositions or acquisitions; our ability to execute our long-term plan as described herein and in our other disclosure documents and the impact that the successful execution of such plan will have on us and our shareholders; the economic returns anticipated from expenditures on our assets; future oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future capital expenditure levels and capital programs; future oil, natural gas liquids and natural gas production levels; the laws and regulations that we will be required to comply with, including laws and regulations relating to taxation, royalty regimes and environmental protection, and the continuance of those laws and regulations; that we will have the financial resources required to fund our capital and operating expenditures and requirements as needed; drilling results and the recoverability of our reserves; the estimates of our reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; expectations that continuous monitoring can lead to reducing emissions; the amount of royalties, operating costs, development costs, abandonment and reclamation costs and income taxes that we will incur in connection with the production of our reserves; future exchange rates, inflation rates and interest rates; future debt levels; future income tax rates; the amount of tax pools available to us; the cost of expanding our property holdings; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including weather, 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 reduce our exposure to commodity price fluctuations and counterparty risks through our risk management programs; the impact of increasing competition; our ability to obtain financing on acceptable terms, that our conduct and results of operations will be consistent with expectations; our ability to add production and reserves through our development and exploitation activities; if necessary; and that we will have the ability to develop our oil and gas properties in the manner currently contemplated. In addition, many of the forward-looking statements contained or incorporated by reference 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: see in particular the assumptions identified in Appendix A-3 under "Statement of Reserves Data and Other Oil and Gas Information – Reserves Data" and "Statement of Reserves Data and Other Oil and Gas Information – Notes to Reserves Data Tables".

Although Obsidian Energy believes that the expectations reflected in the forward-looking statements contained or incorporated by reference 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 or incorporated by reference 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 predictions, forecasts, projections and other 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 unable to execute some or all of our ongoing asset acquisition or disposition programs on favourable terms or at all, whether due to the failure to receive requisite regulatory or other third party approvals or satisfy applicable closing conditions or for other reasons that we cannot anticipate; inability to further reduce emissions intensity and meet stated commitments, if at all possible, in our ESG Report; changes in our plans regarding the implementation of new technologies, facilities replacement and construction, and operations based on key learnings and experience gained through the design and implementation of such plans; the impact that any government assistance programs could have on the Company in connection with, among other things, the COVID-19 pandemic and other regional and/or global health related events; the impact on energy demands due to regional and/or global health related events; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; the possibility that we will not be able to successfully execute our long-term plan in part or in full, and the possibility that some or all of the benefits that we anticipate will accrue to us and our securityholders as a result of the successful execution of such plan do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued 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; 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, among other things, the COVID-19 pandemic and the worldwide transition towards less reliance on fossil fuels 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 Unsecured 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 Unsecured Notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or all of our credit facilities, Senior Unsecured 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 Unsecured Notes; the impact of weather conditions on seasonal demand; the impact of weather conditions on our ability to execute capital programs; the risk that we will be unable to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including weather, infrastructure access and delays in obtaining regulatory approvals and third party consents; risks inherent in oil and natural gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions, including the historical acquisitions discussed herein; geological, technical, drilling and processing problems; general economic and political conditions in Canada, the U.S., Europe and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of oil, natural gas liquids and natural gas, price differentials for oil and natural gas produced in Canada as compared to other markets and transportation restrictions, including pipeline and railway capacity constraints; royalties payable in respect of our oil and natural gas production and changes to government royalty frameworks in jurisdictions in which we operate and the impact that such changes may have on

us; changes in government regulation of the oil and natural gas industry, including environmental regulation; 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; failure to obtain regulatory, industry partner and other third-party consents and approvals when required, including for acquisitions, dispositions, joint ventures, partnerships and mergers; failure to realize the anticipated benefits of dispositions, acquisitions, joint ventures and partnerships, including the historical dispositions, acquisitions, joint ventures and partnerships discussed herein; changes in taxation and other laws and regulations that affect us and our securityholders; the potential failure of counterparties to honour their contractual obligations; stock market volatility and market valuations; the ability of OPEC to control production and balance global supply and demand of oil at desired price levels; political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; delays in exploration and development activities if drilling and related equipment is unavailable or if access to drilling locations is restricted; the impact of pipeline interruptions and apportionments and the actions or inactions of third party operators; the possibility that we breach one or more of the financial covenants pursuant to our agreements with the syndicated banks, and the holders of our Senior Unsecured Notes; and the other factors described under "Risk Factors" in this document and in Obsidian Energy's 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.

The forward-looking statements contained and incorporated by reference in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, Obsidian Energy does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained and incorporated by reference in this document are expressly qualified by this cautionary statement.

In addition, this document contains future-oriented financial information ("FOFI") and financial outlook information relating to the Corporation's prospective operations, expenditures and production for 2023, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Obsidian Energy's actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits Obsidian Energy will derive therefrom. Obsidian Energy has included this FOFI in order to provide readers with a more complete perspective on Obsidian Energy's business in 2023 and such information may not be appropriate for other purposes. This FOFI is prepared as of the date of this document.

Obsidian Energy is a corporation amalgamated under the ABCA. Obsidian Energy's head and registered office is located at Suite 200, 207 – 9th Avenue S.W., Calgary, Alberta, T2P 1K3.

The following diagram sets forth the organizational structure of Obsidian Energy and our material Subsidiaries as at the date hereof. On December 31, 2022 and January 1, 2023, the Company completed an internal corporate reorganization whereby some of the partnerships, being Penn West PROP Limited Partnership, Penn West Northern Harrier Partnership, Peace River Oil Partnership and PROP Energy 45 Limited Partnership, were dissolved and Penn West PROP Holdco Ltd., Penn West Sandhill Crane Ltd., Cordova Gas Resources Ltd., Obsidian Energy Ltd., PROP Energy 45 GP Ltd., and 2476625 Alberta Ltd. (formerly 1116760 B.C. Ltd.) were amalgamated into Obsidian Energy Ltd.

Obsidian Energy is an intermediate-sized oil and gas producer with a well-balanced portfolio of high-quality assets based in Western Canada. Obsidian Energy is a company based on disciplined, relentless passion for the work we do and resolute accountability to our shareholders, our partners and the communities in which we operate. As at December 31, 2022, Obsidian Energy had 191 employees.

See Appendices A-1, A-2 and A-3 for complete NI 51-101 oil and gas reserves disclosure for Obsidian Energy as at December 31, 2022.

The following is a description of the general development of Obsidian Energy's business over the last three completed financial years.

On February 27, 2020, the Company entered into an amending agreement with our banking syndicate whereby the underlying borrowing base of the syndicated credit facility and the amount available to be drawn under the syndicated credit facility was $550 million and $450 million, respectively. Additionally, the following terms were included in the amending agreement:

On March 15, 2020, the Company announced that we had entered an agreement with holders of our Senior Secured Notes to amend the maturity dates. Changes to our maturity dates were as follows:

Additionally, on March 27, 2020, the noteholders and banking syndicate agreed to amend the Company’s financial covenants as follows:

The execution of definitive documentation for the agreement was completed on March 27, 2020.

Additionally, the banking syndicate agreed to enter into an amending agreement to extend the previously scheduled re-confirmation date on June 22, 2020 to September 4, 2020 with the following terms:

Further, the banking syndicate agreed to enter into amending agreements to: (i) extend the syndicated credit facility to be available on a revolving basis until October 31, 2020, subject to further extensions, with the end date of the term period set at November 30, 2021; and then (ii) extend the syndicated credit facility to be available on a revolving basis until January 29, 2021; subject to further extensions, with the end date of the term period set at November 30, 2021. In connection with the extension, the lenders had the option to complete a borrowing base redetermination on January 29, 2021.

On March 15, 2020, the Company reached an agreement with our building landlord on renewed lease terms for our Calgary office space. The effective date of these terms was February 1, 2020. The concessions were:

The execution of definitive documentation for the agreement was completed on March 27, 2020.

On April 1, 2020, the Company received notification from the NYSE that we had not regained compliance with the NYSE's continued listing standard regarding share price pursuant to Rule 802.01C of the NYSE’s Listed Company Manual. As a result, the Obsidian Energy common shares were suspended from trading on the NYSE effective April 1, 2020. To facilitate trading in the United States, Obsidian Energy obtained a listing on the OTCQB on April 2, 2020 under the symbol OBELF. The Obsidian Energy common shares graduated to the OTCQX trading tier on June 16, 2020 and continued trading on the Toronto Stock Exchange throughout under the symbol OBE.

The Company submitted various applications for consideration under the Alberta Site Rehabilitation Program (“ASRP”) during the year. By February 2021, the Company received ASRP gross grants and allocations of approximately $30 million. For further details, see the Company’s news release dated January 5, 2021 which is available on SEDAR at www.sedar.com and subsequent disclosures announcing the use of and additional grants received.

Additionally, in 2020, the Company applied for the Canadian Emergency Wage Subsidy which resulted in grants received of $3.5 million during the year. For further details, see the Company’s news release dated June 22, 2020 which is available on SEDAR at www.sedar.com and subsequent disclosures announcing the use of and additional grants received.

On August 31, 2020, the Company sent a letter to Bonterra Energy Corp. (“Bonterra”) proposing a combination transaction that would result in significant cost synergies and drive substantial accretion for both the Company and Bonterra. On September 8, 2020, the Company announced that it intended to launch an exchange offer (the “Offer”) to purchase all of the issued and outstanding common shares (the “Bonterra Shares”) in the capital of Bonterra for consideration consisting of two common shares of the Company for each Bonterra Share. On September 21, 2020, the Company formally commenced the Offer. For further details, see the Company’s news release dated September 21, 2020 and material change report dated September 29, 2020 which are available on SEDAR at www.sedar.com. In connection with the Offer, the Company held a special meeting of shareholders on November 23, 2020 in order to obtain their consent to the Offer and the requisite issuance of Company common shares. For further details, see the Company’s news release dated November 23, 2020 which is available on SEDAR at www.sedar.com. The Company extended the Offer on December 21, 2020. For further details, see the Company’s news release dated December 21, 2020 which is available on SEDAR at www.sedar.com.

On January 28, 2021, the Company announced an extension to the syndicated credit facility, which resulted in the revolving period shifting to February 26, 2021, which was previously January 31, 2021. For further details, see the Company’s news release dated January 28, 2021which is available on SEDAR at www.sedar.com.

On February 24, 2021, the Company announced an extension to the syndicated credit facility, which resulted in the revolving period shifting to March 31, 2021, which was previously February 26, 2021. For further details, see the Company’s news release dated February 24, 2021which is available on SEDAR at www.sedar.com.

On March 26, 2021, the Company entered into an amending agreement with our banking syndicate whereby the aggregate amount drawn or available to be drawn under the syndicated credit facility to be set at $440 million. Additionally, the following terms were included in the amending agreement:

On March 26, 2021, the Company entered an agreement with holders of our Senior Secured Notes to amend the maturity dates from November 30, 2021 to November 30, 2022. For further details, see the Company’s news release dated March 26, 2021 which is available on SEDAR at www.sedar.com.

On November 30, 2021, the Company announced that the semi-annual borrowing base redetermination had been completed, resulting in a $35 million increase to our revolving syndicated credit facility from $225 million to $260 million together with a $155 million non-revolving term loan. The revolving period under the syndicated credit facility remains at May 31, 2022, with the maturity date of both the revolving credit facility and non-revolving term loan of November 30, 2022. For further details, see the Company’s news release dated November 30, 2021 which is available on SEDAR at www.sedar.com.

On January 25, 2021, the Company extended the Offer to purchase the Bonterra shares to March 29, 2021. On March 29, 2021, the Company allowed the offer to purchase all of the issued and outstanding common shares of Bonterra to expire due to a strengthening in our business and operational outlook. For further details, see the Company’s news releases dated January 25, 2021 and March 29, 2021 which are available on SEDAR at www.sedar.com.

On May 7, 2021, the Company publicly announced in connection with its first quarter results that the Company had formally closed its previously announced strategic review process, considering the successful completion of the syndicated credit facility and Senior Secured Notes maturity extension to November 2022 and the stronger operational and improved financial position. For further details, see the Company’s news release dated May 7, 2021 which is available on SEDAR at www.sedar.com.

On June 14, 2021, Maureen Cormier Jackson and William (Bill) Friley resigned from the Board of Directors. Ms. Cormier Jackson had joined the Board in 2016 and Mr. Friley joined in 2015. For further details, see the Company’s news release dated June 14, 2021 which is available on SEDAR at www.sedar.com.

PROP – Acquisition of 45 Percent Partnership Interest with Concurrent Subscription Receipts Offering

On November 2, 2021, the Company announced that it had entered into a purchase and sale agreement to acquire the remaining 45 percent partnership interest in PROP from our joint venture partner, through a wholly-owned subsidiary. This acquisition (the “Acquisition”) gives the Company a 100 percent interest in the asset and full operating and funding control of PROP. The total consideration paid was $43.5 million prior to closing adjustments with an effective date of July 1, 2021. The cash consideration for the Acquisition was funded by a $16.3 million limited-recourse amortizing loan secured by the additional 45 percent interest in PROP, and proceeds from our marketed public offering of subscription receipts (the “Subscription Receipts”), which closed on November 18, 2021 (the “Offering”). The Offering was priced at $4.40 per Subscription Receipt for aggregate gross proceeds of approximately $25.9 million, which included the full exercise of the over-allotment option granted to the agents. Concurrent with the completion of the Acquisition, the Subscription Receipts were converted into

Common Shares on November 24, 2021. For further details, see the Company’s news releases dated November 2, November 4, November 18 and November 24, 2021 respectively which are available on SEDAR at www.sedar.com.

On January 11, 2022, the Company announced an update to the syndicated credit facility, which resulted in the previously announced one-time adjustment to the syndicated credit facility to reduce our undrawn availability to $35 million, effective December 31, 2021, resulting in a new commitment amount of $366.8 million from the previous amount of $415.0 million. For further details, see the Company’s news release dated January 11, 2022 which is available on SEDAR at www.sedar.com.

On January 18, 2022, the Company announced the reconfirmation of our syndicated credit facility by our lenders with no changes to our revolving period. On May 31, 2022, Obsidian Energy announced that the syndicated credit facility revolving period extended to July 15, 2022 to accommodate timing of debt refinancing. For further details, see the Company’s news releases dated January 18, 2022 and May 31, 2022, respectively, which is available on SEDAR at www.sedar.com

On July 19, 2022, the Company announced a private placement of the Senior Unsecured Notes in the amount of up to $125 million. It also announced proposed new syndicated credit facilities to provide up to $225.0 million of available capacity. It further announced on July 27, 2022 that it had entered into an underwriting agreement to sell the Senior Unsecured Notes due July 27, 2027. In connection with the private placement of the Senior Unsecured Notes, the Company entered into a new $175.0 million revolving syndicated credit facility and a new $30.0 million non-revolving term loan (which was subsequently repaid in September 2022). With the net proceeds from the Senior Unsecured Notes and the initial draws on the new credit facilities, the Company repaid a portion of its outstanding debt. For further details, see the Company’s news releases dated July 19, 2022, July 27, 2022 and September 13, 2022, respectively, which are available on SEDAR at www.sedar.com.

On January 17, 2022, Cliff Swadling was promoted to Vice President, Operations. On January 31, 2022, Aaron Smith resigned from his position of Senior Vice President, Development. Ms. Shani Bosman joined the Board of Directors on May 4, 2022.

On January 24, 2022, the Company announced the 2022 guidance, including a total of $143 to $149 million in capital expenditures, plus $14 million in decommissioning expenditures. The Company’s average production guidance for 2022 was also set at 29,100 to 30,100 boe/d. For further details, see the Company’s news release dated January 24, 2022 which is available on SEDAR at www.sedar.com.

On April 12, 2022, the Company announced updated 2022 production guidance to 30,100 to 31,100 boe/d. The production guidance was further updated on May 4, 2022, to 30,300 to 31,300 boe/d For further details, see the Company’s news releases dated April 12, 2022 and May 4, 2022, respectively, which are available on SEDAR at www.sedar.com.

On June 16, 2022, the Company announced an updated 2022 production range guidance of 31,500 to 32,500 boe/d based on an expanded capital development program, including a total of $295 to $305 million in capital expenditures and an additional $17 million in decommissioning expenditures. For further details, see the Company’s news release dated June 16, 2022 which is available on SEDAR at www.sedar.com.

On November 8, 2022, the Company announced an updated 2022 production range guidance of 30,800 to 31,200 boe/d and an expanded capital development program, including a total of $320 to $330 million in capital expenditures and an additional $18 million in decommissioning expenditures. For further details, see the Company’s news release dated November 8, 2022 which is available on SEDAR at www.sedar.com.

On January 26, 2022, the Company announced that the NYSE American had approved the listing of the Company’s common shares on the NYSE American stock exchange. The common shares began trading on the NYSE American on January 31,

2022, under the trading ticker symbol “OBE”. In association, trading of the Company’s common shares on the OTCQX market exchange was suspended at the end of trading on January 28, 2022. For further details, see the Company’s news release dated January 26, 2022 which is available on SEDAR at www.sedar.com.

On January 30, 2023, the Company announced the 2023 guidance, including a total of $260 to $270 million in capital expenditures, plus $26 to $28 million in decommissioning expenditures. The Company’s average production guidance for 2023 was also set at 32,000 to 33,500 boe/d. For further details, see the Company’s news release dated January 30, 2023 which is available on SEDAR at www.sedar.com.

In January 2023, the Company’s Board of Directors authorized a normal course issuer bid (“NCIB”) to provide a return of capital to shareholders. In February, the Company's application to the Toronto Stock Exchange (“TSX”) for the NCIB was approved. This has allowed the Company to initiate a share buyback program over the next 12 months beginning February 27, 2023 on the TSX, NYSE American and other marketplaces, of up to 10 percent of the Company’s "public float", as defined by the TSX (a maximum of 8,073,847 common shares, with a daily purchase limit on the TSX of 85,192 common shares, subject to certain exceptions for block purchases). Purchases under the NCIB are subject to maintaining at least $65 million of liquidity and otherwise complying with our debt agreements.

On February 22, 2023, Stephen Loukas was named President and Chief Executive Officer, he previously held the title of Interim President and Chief Executive Officer since December 2019.

Obsidian Energy continues to evaluate potential acquisitions of all types of petroleum and natural gas and other energy-related assets as part of our ongoing asset portfolio management program. At times, Obsidian Energy could be in the process of evaluating several potential acquisitions which individually or in the aggregate could be material. As of the date hereof, Obsidian Energy has not reached agreement on the price or terms of any potential material acquisitions. Obsidian Energy cannot predict whether any current or future opportunities will result in one or more acquisitions for Obsidian Energy.

Obsidian Energy continues to evaluate potential dispositions of its petroleum and natural gas assets as part of its ongoing portfolio asset management program.

In addition, Obsidian Energy continues to consider potential farm-out opportunities with other industry participants in respect of its petroleum and natural gas assets in circumstances where Obsidian Energy believes it is prudent to do so based on, among other things, our capital program, development plan timelines and the risk profile of such assets. Obsidian Energy is normally in the process of evaluating several potential dispositions of our assets and farm-out opportunities at any one time, which individually or in the aggregate could be material. As of the date hereof, Obsidian Energy has not reached agreement on the price or terms of any potential material dispositions or farm-outs. Obsidian Energy cannot predict whether any current or future opportunities will result in one or more dispositions or farm-outs for Obsidian Energy.

Obsidian Energy continuously evaluates its capital structure, liquidity and capital resources, and financing opportunities that arise from time to time. Obsidian Energy may in the future complete financings of Common Shares or debt (including debt

which may be convertible into Common Shares) for purposes that may include the financing of acquisitions, the financing of Obsidian Energy's operations and capital expenditures, the repayment of indebtedness and a return of capital to shareholders. As of the date hereof, Obsidian Energy has not reached agreement on the pricing or terms of any potential material financing. Obsidian Energy cannot predict whether any current or future financing opportunity will result in one or more material financings being completed.

Obsidian Energy did not complete an acquisition during its most recently completed financial year that was a significant acquisition for the purposes of Part 8 of National Instrument 51-102 Continuous Disclosure Obligations.

The authorized capital of Obsidian Energy consists of an unlimited number of Common Shares without nominal or par value and 90,000,000 preferred shares without nominal or par value. A description of the share capital of Obsidian Energy is set forth below. This description is a summary only. Shareholders are encouraged to read the full text of such share provisions, which are available on SEDAR at www.sedar.com.

Shareholders are entitled to notice of, to attend and to one vote per Common Share held at any meeting of the shareholders of Obsidian Energy (other than meetings of a class or series of shares of Obsidian Energy other than the Common Shares).

Shareholders are entitled to receive dividends as and when declared by the Board of Directors on the Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends attached to shares of other classes of shares of Obsidian Energy ranking in priority to the Common Shares in respect of dividends.

The holders of Common Shares are entitled in the event of any liquidation, dissolution or winding-up of Obsidian Energy, whether voluntary or involuntary, or any other distribution of the assets of Obsidian Energy among its Shareholders for the purpose of winding-up its affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of shares of Obsidian Energy ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of shares of Obsidian Energy ranking equally with the Common Shares in respect of return of capital on dissolution, in such assets of Obsidian Energy as are available for distribution.

Preferred shares of Obsidian Energy may at any time or from time to time be issued in one or more series. Before any shares of a particular series are issued, the Board shall, by resolution, fix the number of shares that will form such series and shall, subject to the limitations set out in Obsidian Energy's articles, by resolution fix the designation, rights, privileges, restrictions and conditions to be attached to the preferred shares of such series, including, but without in any way limiting or restricting the generality of the foregoing, the rate, amount or method of calculation of dividends thereon, the time and place of payment of dividends, the consideration for and the terms and conditions of any purchase for cancellation, retraction or redemption thereof, conversion or exchange rights (if any), and whether into or for securities of Obsidian Energy or otherwise, voting rights attached thereto (if any), the terms and conditions of any share purchase or retirement plan or sinking fund, and restrictions on the payment of dividends on any shares other than preferred shares or payment in respect of capital on any shares in the capital of Obsidian Energy or creation or issue of debt or equity securities; the whole subject to filing of Articles of Amendment setting forth a description of such series, including the designation, rights, privileges, restrictions and conditions attached to the shares of such series. Notwithstanding the foregoing, other than in the case of a failure to declare or pay dividends specified in any series of preferred shares, the voting rights attached to the preferred shares shall be limited to one vote per preferred share at any meeting where the preferred shares and Common Shares vote together as a single class.

Obsidian Energy has a syndicated credit facility and has outstanding Senior Unsecured Notes. A description of the debt capital of Obsidian Energy is set forth below. This description is a summary only. Shareholders are encouraged to read the full text of the agreements governing Obsidian Energy's Senior Unsecured Notes and syndicated credit facility, which are available on SEDAR at www.sedar.com.

The Company has a $175.0 million revolving syndicated credit facility. The syndicated credit facility has a revolving period ending on July 27, 2023, with a term out period ending on July 27, 2024, subject to customary annual extension terms. The revolving credit facility is subject to a semi-annual borrowing base redetermination typically in May and November of each year. The syndicated credit facility is secured by all the assets of the Company.

Obsidian Energy has issued the Senior Unsecured Notes, which consist of $127.6 million principal, pursuant to a trust indenture with Computershare Trust Company of Canada dated July 27, 2022. The Senior Unsecured Notes were issued at a price of $980.00 per $1,000.00 principal amount for aggregate gross proceeds of approximately $125.0 million. The Notes have a 11.95 percent coupon, payable semi-annually in equal installments. The Senior Unsecured Notes will be direct senior unsecured obligations of Obsidian Energy ranking equal with all other present and future senior unsecured indebtedness of the Company.

The Senior Unsecured Notes have a semi-annual repurchase offer feature whereby, subject to the terms and conditions of the new trust indenture governing the Senior Unsecured Notes, the Company must offer to purchase the maximum principal amount equal to 75 percent of excess free cash flow (as defined in the new trust indenture) up to and including July 27, 2024, and 50 percent of excess free cash flow thereafter at a price equal to 103 percent of the principal of the Senior Unsecured Notes, plus accrued and unpaid interest. The repurchase offer feature remains in place until an aggregate amount of $63.8 million of Senior Unsecured Notes are repurchased by the Company. Additionally, Obsidian Energy may redeem up to 40 percent of the aggregate principal amount of the Senior Unsecured Notes at any time prior to July 27, 2024, for a redemption price equal to 111.95 percent of the principal amount of the Senior Unsecured Notes, together with accrued and unpaid interest, with cash received from equity offerings (provided that at least 60 percent of the aggregate principal amount of the Senior Unsecured Notes remains outstanding after such redemption). At its option, the Company may also redeem all or part of the Senior Unsecured Notes at: 105.975 percent from July 27, 2024 to July 26, 2025; or 102.988 percent from July 27, 2025 to July 26, 2026; or 100 percent from July 27, 2026, to July 27, 2027.

For additional information regarding our Senior Unsecured Notes and our credit facility, see "Description of Our Business – General Development of the Business – Year Ended December 31, 2020, Year Ended December 31, 2021, Year Ended December 31, 2022 and 2023 Developments" in this Annual Information Form, Note 5 to our audited consolidated financial statements for the year ended December 31, 2022 (collectively, the "Financial Statement Disclosure"), and "Financing" and "Liquidity and Capital Resources" in our related MD&A (collectively, the "MD&A Disclosure"), both of which are available on SEDAR at www.sedar.com. The Financial Statement Disclosure and the MD&A Disclosure are both incorporated by reference into this Annual Information Form.

The following table sets forth, as at February 22, 2023, the name, province and country of residence and positions and offices held for each of the directors and executive officers of Obsidian Energy, together with their principal occupations during the last five years. The directors of Obsidian Energy will hold office until the next annual meeting of Shareholders or until their respective successors have been duly elected or appointed.

As at the date hereof, the directors and executive officers of Obsidian Energy, as a group, beneficially owned, or controlled or directed, directly or indirectly, approximately 1.6 million Common Shares, or approximately two percent of the issued and outstanding Common Shares. Steve Loukas is also a partner of FrontFour Capital Group and as a group with the directors and executive officers of Obsidian Energy, they beneficially owned, or controlled or directed, directly or indirectly, approximately 5.6 million Common Shares, or approximately seven percent of the issued and outstanding Common Shares

To the knowledge of Obsidian Energy, except as otherwise set forth herein, no director or executive officer of Obsidian Energy (nor any personal holding company of any of such persons) is, as of the date of this Annual Information Form, or was within ten years before the date of this Annual Information Form, a director, Chief Executive Officer or Chief Financial Officer of any company (including Obsidian Energy), that:

(a)

was subject to a cease trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an "Order") that was issued while the director or executive officer was acting in the capacity as director, Chief Executive Officer or Chief Financial Officer; or

On July 29, 2014, Penn West announced that the Audit Committee of the Board was conducting a voluntary, internal review of certain of the Company's accounting practices and that certain of the Company's historical financial statements and related MD&A must be restated, which might result in the release of its second quarter 2014 financial results being delayed (which ultimately proved to be the case). Furthermore, the Company advised that its historical financial statements and related audit reports and MD&A should not be relied on. As a result, the Alberta Securities Commission issued a Management Cease Trade Order on August 5, 2014 (the "ASC MCTO") against certain members of management and the board, including Mr. Brydson. On September 18, 2014, Penn West filed restated audited annual financial statements for the years ended December 31, 2013 and 2012, restated unaudited interim financial statements for the three months ended March 31, 2014 and 2013, restated MD&A for the year ended December 31, 2013 and the quarter ended March 31, 2014, and related amended documents. Penn West also filed its unaudited interim financial statements for the three and six month periods ended June 30, 2014 and 2013 and the related MD&A and management certifications. The ASC MCTO was revoked on September 23, 2014.

To the knowledge of Obsidian Energy, except as otherwise set forth herein, no director or executive officer of Obsidian Energy or shareholder holding a sufficient number of securities of Obsidian Energy to affect materially the control of Obsidian Energy (nor any personal holding company of any of such persons):

(a)

is, as of the date of this Annual Information Form, or has been within the ten years before the date of this Annual Information Form, a director or executive officer of any company (including Obsidian Energy) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or

(b)

has, within the ten years before the date of this Annual Information Form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

Mr. Peter D. Scott was a director of Shoreline Energy Corp. (“Shoreline”), a reporting issuer listed on the Toronto Stock Exchange, when Shoreline obtained protection under the Companies’ Creditor Arrangement Act (Canada) (“CCAA”) on April 13, 2015. Shoreline’s securities were halted from trading on April 14, 2015 and delisted on May 14, 2015. On May 22, 2015 Shoreline received cease trade orders from various provincial securities commissions for failure to file interim unaudited financial statements, management discussion and analysis and certifications of interim filings for the period ended March 31, 2015. The filings were made on June 26, 2015 and all cease trade orders were lifted by August 25, 2015. On December 23, 2015 all directors and officers resigned from Shoreline when it filed an assignment under the Bankruptcy and Insolvency Act (Canada). In addition, Mr. Peter D. Scott was the Senior Vice President and Chief Financial Officer of Lightstream Resources Ltd. (“Lightstream”) when it obtained creditor protection under the CCAA on September 26, 2016. On December 29, 2016, as a result of the CCAA sales process, substantially all of the assets and business of Lightstream were sold to Ridgeback Resources Inc. (“Ridgeback”), a new company owned by former holders of Lightstream’s secured notes. Mr. Scott resigned as an officer of Lightstream and was concurrently appointed Senior Vice President and Chief Financial Officer of Ridgeback upon closing of the sale transaction, a position he held to July 2017.

Mr. Gordon Ritchie was a director of Gemini Corporation (“Gemini”), a reporting issuer listed on the TSX Venture Exchange, from November 2012 to December 2016, and again from May 2017 to April 2018. In April 2018, Gemini’s senior secured creditor ATB Financial applied to the Alberta Court of Queen’s Bench for a receivership order, which was granted on April 19, 2018. FTI Consulting Canada Inc. was appointed as receiver and manager of all the company’s current and future assets, undertakings and properties. The shares of Gemini were officially cease-traded on May 4, 2018 and all of the company’s board of directors and officers resigned concurrently with the appointment of the receiver.

Mr. Michael J. Faust is a Director and was the President and Chief Executive Officer of SAExploration Holdings, Inc. (“SAEX”), and a number of its subsidiaries until December 31, 2021. SAEX, at the time a publicly-traded company on the OTC Markets Pink Open Market, and four wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on August 27, 2020 (the “Restructuring”). SAEX and its subsidiaries continued to operate their businesses and manage their properties as debtors in possession and emerged from bankruptcy on December 18, 2020 further to the December 10, 2020 Confirmation Order entered by United States Bankruptcy Court, Southern District of Texas, Houston Division, approving the Debtors’ Second Amended Chapter 11 Plan of Reorganization. Mr. Faust was Chairman of

the Board of Directors of SAEX at the time of the Restructuring and is currently a member of the Board of Directors. SAEX completed the Restructuring and emerged as a privately held company.

To the knowledge of Obsidian Energy, no director or executive officer of Obsidian Energy or shareholder holding a sufficient number of securities of Obsidian Energy to affect materially the control of Obsidian Energy (nor any personal holding company of any of such persons), has been subject to:

provided that for the purposes of the foregoing, a late filing fee, such as a filing fee that applies to the late filing of an insider report, is not considered to be a "penalty or sanction".

The Board of Directors approved an amendment to the Code of Business Conduct and Ethics (the "Code") in July of 2015 which made the Code the applicable policy in regard to conflicts of interest (whereas previously there was also the Code of Ethics for Directors, Officers and Senior Financial Management). In general, the private investment activities of employees, directors and officers are not prohibited; however, should an existing investment pose a potential conflict of interest, the potential conflict is required by the Code to be disclosed to an officer or a member of Obsidian Energy's legal department or to the Board of Directors. Any other activities posing a potential conflict of interest are also required by the Code to be disclosed to an officer or to a member of Obsidian Energy's legal department. Any such potential conflicts of interests will be dealt with openly with full disclosure of the nature and extent of the potential conflicts of interests with Obsidian Energy. It is acknowledged in the Code that the directors may be directors or officers of other entities engaged in the oil and gas business, and that such entities may compete directly or indirectly with Obsidian Energy. Passive investments in public or private entities of less than one per cent of the outstanding shares will not be viewed as "competing" with Obsidian Energy. No executive officer or employee of Obsidian Energy should be a director, employee, contractor, consultant or officer of any entity that is or may be in competition with Obsidian Energy unless expressly authorized by an executive officer or the Board of Directors. Any director of Obsidian Energy who is a director or officer of, or who is otherwise actively engaged in the management of, or who owns an investment of one per cent or more of the outstanding shares, in public or private entities shall disclose such holding to the Board of Directors. In the event that any circumstance should arise as a result of such positions or investments being held or otherwise which in the opinion of the Board of Directors constitutes a conflict of interest which reasonably affects such person's ability to act with a view to the best interests of Obsidian Energy, the Board of Directors will take such actions as are reasonably required to resolve such matters with a view to the best interests of Obsidian Energy. Such actions, without limitation, may include excluding such directors, officers or employees from certain information or activities of Obsidian Energy. During 2019, the Code of Ethics was amended in order to update the threshold amount for a gift that needs to be approved prior to being accepted and other technical and immaterial amendments.

The ABCA provides that in the event that an officer or director is a party to, or is a director or an officer of, or has a material interest in any person who is a party to, a material contract or material transaction or proposed material contract or proposed material transaction, such officer or director shall disclose the nature and extent of his or her interest and shall refrain from voting to approve such contract or transaction.

As of the date hereof, Obsidian Energy is not aware of any existing or potential material conflicts of interest between Obsidian Energy or a Subsidiary of Obsidian Energy and any director or officer of Obsidian Energy or of any Subsidiary of Obsidian Energy.

No person or company has been, within the two most recently completed financial years or during the current financial year, a "promoter" (as defined in the Securities Act (Ontario)) of Obsidian Energy or of a Subsidiary of Obsidian Energy.

National Instrument 52-110 Audit Committees ("NI 52-110") relating to audit committees has mandated certain disclosures for inclusion in this Annual Information Form. The text of the Audit Committee's mandate is attached as Appendix B to this Annual Information Form.

As of the date hereof, the members of the Audit Committee are Raymond Crossley (Chair), John Brydson and Gordon Ritchie, each of whom is independent and financially literate within the meaning of NI 52-110. The following comprises a brief summary of each member's education and experience that is relevant to the performance of his or her responsibilities as an Audit Committee member.

Mr. Brydson has over 30 years of experience in the financial sector and has occupied senior roles in both major investment and commercial banks. Since 2012, Mr. Brydson has been a private investor. From 2010 until the end of 2012, he was Chairman of a small full-service management consulting firm, Hestan Consulting Group ("HCG"), which he founded. Prior to HCG, Mr. Brydson was a Managing Director with Credit Suisse First Boston, now Credit Suisse ("CS"), from 1995 until 2009, where he was in charge of the Multi-Product Event Trading group. He was also a Managing Director with Lehman Brothers in a similar function from 1983 until he joined CS. The early years of his career were spent as an equity analyst before joining Chase Manhattan Bank ("Chase") in London in 1977. He transferred to the head office in New York in 1980 where he became a Vice President in the Project Finance Group, specializing in international projects in the energy, mining and metals sectors. He left Chase to join Lehman Brothers in 1983. Mr. Brydson holds an Honors Degree in Economics from Heriot-Watt University in Edinburgh, Scotland. Mr. Brydson served over 10 years as the President and a Board Member of The American Friends of Heriot-Watt University, a charitable organization.

Mr. Crossley is a corporate director and serves on the boards of the Alberta Securities Commission. He departed the Canada West Foundation Board in April 2022. Mr. Crossley is also the Chief Financial Officer of the Calgary Health Foundation. The Foundation is a Calgary based charity focused on fundraising to support health care in Alberta. In March 2015, Mr. Crossley retired from the global professional services firm, PwC LLP, after more than 33 years. During his career at PwC he served as a member of the firm’s management, as Managing Partner, Western Canada from 2011-2013 and was the Managing Partner of PwC’s Calgary office from 2005-2011. Prior to becoming the Calgary Managing Partner, Mr. Crossley served as an elected member of the firm’s Partnership Board from 2001-2005. Mr. Crossley also served as the audit partner for several of PwC’s largest audit clients. Mr. Crossley graduated from the University of Western Ontario, is a Chartered Professional Accountant in Alberta and holds the ICD.D designation from the Institute of Corporate Directors.

Mr. Ritchie retired as Vice Chairman of RBC Capital Markets on April 1, 2016 after 37 years with RBC. Previously, Mr. Ritchie served as Managing Director and Head of RBC’s Global E&P Energy Group, from 2000 to 2005; spent six years in New York where he served as President and Chief Executive Officer of RBC’s U.S. Broker/Dealer, RBC Dominion Securities Corporation, from 1993 to 1999; served as Managing Director of RBC’s International Corporate Finance Group based in London, England, from 1989 to 1993; and worked as Investment Banker and Energy Research Analyst in Calgary, from 1979 through 1988. Mr. Ritchie also sits on the boards of Coril Holdings Ltd. and Pipestone Energy Corp.

The terms of the engagement of Obsidian Energy's external auditors to provide audit services, including the budgeted fees for such audit services and the representations and disclaimer relating thereto, must be pre-approved by the entire Audit Committee.

With respect to any engagements of Obsidian Energy's external auditors for non-audit services, Obsidian Energy must obtain the approval of the Audit Committee or the Chairman of the Audit Committee prior to retaining the external auditors to

complete such engagement. If such pre-approval is provided by the Chairman of the Audit Committee, the Chairman must report to the Audit Committee on any non-audit service engagement pre-approved by him at the Audit Committee's first scheduled meeting following such pre-approval. The fees for such non-audit services shall not exceed $50,000, either individually or in the aggregate, for a particular financial year without the approval of the Audit Committee.

If, after using its reasonable best efforts, Obsidian Energy is unable to contact the Chairman of the Audit Committee on a timely basis to obtain the pre-approval contemplated by the preceding paragraph, Obsidian Energy may obtain the required pre-approval from any other member of the Audit Committee, provided that any such Audit Committee member shall report to the Audit Committee on any non-audit service engagement pre-approved by him or her at the Audit Committee's first scheduled meeting following such pre-approval and the fees for such services do not exceed $50,000 as noted above.

The following table summarizes the fees billed to Obsidian Energy by KPMG LLP and Ernst & Young LLP for external audit and other services during the periods indicated. KPMG LLP became the auditors for Obsidian Energy effective August 23, 2021.

(1)

The aggregate fees billed by our external auditors in each of the last two fiscal years for audit services, including fees for the integrated audit of Obsidian Energy's annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements, reviews in connection with acquisitions and Sarbanes-Oxley Act related services, and review procedures on the unaudited interim consolidated financial statements.

(2)

The aggregate fees billed in each of the last two fiscal years by our external auditors for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements (and not included in audit services fees in note (1)). In 2022 and 2021, the services comprising the fees disclosed under this category principally consisted of fees for the PROP audit and certain audit requirements of the seller as part of the Company’s purchase of the 45% partnership interest in PROP.

At no time since the commencement of Obsidian Energy's most recently completed financial year has Obsidian Energy relied on any of the exemptions contained in Sections 2.4, 3.2, 3.4 or 3.5 of NI 52‑110, or an exemption from NI 52‑110, in whole or in part, granted under Part 8 thereof. In addition, at no time since the commencement of Obsidian Energy's most recently completed financial year has Obsidian Energy relied upon the exemptions in Subsection 3.3(2) or Section 3.6 of NI 52‑110. Furthermore, at no time since the commencement of Obsidian Energy's most recently completed financial year has Obsidian Energy relied upon Section 3.8 of NI 52‑110.

At no time since the commencement of Obsidian Energy's most recently completed financial year has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the Board of Directors.

The Company has not declared a dividend in the last three financial years. Any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, the Company’s results of operations, current and anticipated cash requirements and surplus, financial condition, solvency tests imposed by corporate law, contractual restrictions and financing agreement covenants, if any, and other factors that the Board may determine relevant. See "Risk Factors".

The credit agreement governing our syndicated credit facility and the note purchase agreement governing our Senior Unsecured Notes also contain provisions which restrict our ability to pay dividends to Shareholders in the event of the occurrence of certain events of default. The full text of the agreements governing our credit facility and our Senior Unsecured Notes is available on SEDAR at www.sedar.com. For additional information regarding our credit facility and our Senior Unsecured Notes, see "Capitalization of Obsidian Energy – Debt Capital".

The following tables set forth certain trading information for the Common Shares in 2022 as reported by the TSX and the OTCQX and the NYSE American, as applicable.

Other than incentive securities issued pursuant to Obsidian Energy's director and employee compensation plans and the Senior Unsecured Notes, Obsidian Energy does not have any classes of securities that are outstanding but that are not listed or quoted on a market place.

To Obsidian Energy's knowledge, no securities of Obsidian Energy are held in escrow, are subject to a pooling agreement, or are subject to a contractual restriction on transfer (except in respect Obsidian Energy's equity compensation plans).

Companies operating in the Canadian oil and natural gas industry are subject to extensive regulation and control of operations (including with respect to land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government; and with respect to the pricing and taxation of petroleum and natural gas through legislation enacted by, and agreements among, the federal and provincial governments of Canada, all of which should be carefully considered by investors in the Western Canadian oil and natural gas industry. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments governments may enact in the future.

The Corporation's assets and operations are regulated by administrative agencies that derive their authority from legislation enacted by the applicable level of government. Regulated aspects of the Corporation's upstream oil and natural gas business include all manner of activities associated with the exploration for and production of oil and natural gas, including, among other matters: (i) permits for the drilling of wells and construction of related infrastructure; (ii) technical drilling and well requirements; (iii) permitted locations and access to operation sites; (iv) operating standards regarding conservation of produced substances and avoidance of waste, such as restricting flaring and venting; (v) minimizing environmental impacts, including by reducing emissions; (vi) storage, injection and disposal of substances associated with production operations; and (vii) the abandonment and reclamation of impacted sites. In order to conduct oil and natural gas operations and remain in good standing with the applicable federal or provincial regulatory scheme, producers must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance in this regard can be costly and a breach of the same may result in fines or other sanctions.

The following discussion provides an overview of some of the principal aspects of the legislation, regulations, agreements, orders, directives and other pertinent conditions that impact the oil and gas industry in Western Canada, particularly in the province of Alberta, where the Corporation's assets are primarily located. While these matters do not affect the Corporation's operations in any manner that is materially different than the manner in which they affect other similarly-sized industry participants with similar assets and operations, investors should consider such matters carefully.

Oil producers are entitled to negotiate sales contracts directly with purchasers. As a result, macroeconomic and microeconomic market forces determine the price of oil. Worldwide supply and demand factors are the primary determinant of oil prices, but regional market and transportation issues also influence prices. The specific price that a producer receives will depend, in part, on oil quality, prices of competing products, distance to market, availability of transportation, value of refined products, supply/demand balance and contractual terms of sale.

Global oil markets have recovered significantly from price drops resulting from the COVID-19 pandemic. In 2022, oil prices rose to the highest levels since 2014 due to tight supply and a resurgence in demand. The Organization of Petroleum Exporting Countries ("OPEC") forecasts robust growth in world oil demand in 2023, spurred by the relaxation of China's zero-COVID policy. OPEC predicts global oil demand to rise by 2.25 million barrels per day in 2023, despite newly emerging COVID-19 variants, interest rate increases in major economies and other uncertainties with respect to the world economy.

In February 2022, Russian military forces invaded Ukraine. Ongoing military conflict between Russia and Ukraine has significantly impacted the supply of oil and gas from the region. In addition, certain countries including Canada and the United States have imposed strict financial and trade sanctions against Russia, which sanctions may have far reaching effects on the global economy in addition to the near term effects on Russia. The long-term impacts of the conflict remain uncertain.

Negotiations between buyers and sellers determine the price of natural gas sold in intra-provincial, interprovincial and international trade. The price received by a natural gas producer depends, in part, on the price of competing natural gas supplies and other fuels, natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions, supply/demand balance and other contractual terms of sale. Spot and future prices can also be influenced by supply and demand fundamentals on various trading platforms.

The pricing of condensates and other NGLs such as ethane, butane and propane sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. The profitability of NGLs extracted from natural gas is based on the products extracted being of greater economic value as separate commodities than as components of natural gas and therefore commanding higher prices. Such prices depend, in part, on the quality of the NGLs, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply/demand balance and other contractual terms of sale.

The Canada Energy Regulator (the "CER") regulates the export of oil, natural gas and NGLs from Canada through the issuance of short-term orders and longer-term licences pursuant to its authority under the Canadian Energy Regulator Act (the "CERA"). Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the CER and the federal government. The Corporation does not directly enter into contracts to export its production outside of Canada.

Capacity to transport production from Western Canada to Eastern Canada, the United States and other international markets has been, and continues to be, a major constraint on the exportation of crude oil, natural gas and NGLs. Although certain pipeline and other transportation projects have been announced or are underway, many proposed projects have been cancelled or delayed due to regulatory hurdles, court challenges and economic and socio-political factors. Due in part to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low commodity pricing relative to other markets in the last several years.

Under Canadian constitutional law, the development and operation of interprovincial and international pipelines fall within the federal government's jurisdiction and, under the CERA, new interprovincial and international pipelines require a federal

regulatory review and approval of the cabinet of the Canadian federal government ("Cabinet") before they can proceed. However, recent years have seen a perceived lack of policy and regulatory certainty in this regard such that, even when projects are approved, they often face delays due to actions taken by provincial and municipal governments and legal opposition related to issues such as Indigenous rights and title, the government's duty to consult and accommodate Indigenous peoples and the sufficiency of all relevant environmental review processes. Export pipelines from Canada to the United States face additional unpredictability as such pipelines also require approvals from several levels of government in the United States.

Producers negotiate with pipeline operators to transport their products to market on a firm or interruptible basis depending on the specific pipeline and the specific substance. Transportation availability is highly variable across different jurisdictions and regions. This variability can determine the nature of transportation commitments available, the number of potential customers and the price received.

The Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of political opposition in British Columbia, the federal government acquired the Trans Mountain Pipeline in August 2018. Following the resolution of a number of legal challenges and a second regulatory hearing, construction on the Trans Mountain Pipeline expansion commenced in late 2019. Earlier estimated at $12.6 billion, the project budget has risen to $21.4 billion as of February 2022. The pipeline is expected to be in service in the third quarter of 2023, an extension from Trans Mountain's initial December 2022 estimate. The budget increase and in-service date delay have been attributed to, among other things, the ongoing effects of the COVID-19 pandemic and the widespread flooding in British Columbia in late 2021.

In November 2020, the Attorney General of Michigan filed a lawsuit to terminate an easement that allows the Enbridge Line 5 pipeline system to operate below the Straits of Mackinac, attempting to force the lines comprising this segment of the pipeline system to be shut down. Enbridge Inc. stated in January 2021 that it intends to defy the shut down order, as the dual pipelines are in full compliance with U.S. federal safety standards. The Government of Canada invoked a 1977 treaty with the United States on October 4, 2021, triggering bilateral negotiations over the pipeline. In August 2022, the United States District Court for Western Michigan rejected the Attorney General of Michigan's efforts to move the dispute to Michigan state court, citing important federal interests at stake in having the dispute heard in federal court. Michigan's Attorney General intends to appeal the decision.

In September 2022, the District Court of Wisconsin ruled in favour of the Bad River Band in its dispute with Enbridge Inc. over the Enbridge Line 5 pipeline system in that state. Stopping short of ordering the system to be shut down, the Court ruled that the Bad River Band is entitled to financial compensation, and ordered Enbridge Inc. to reroute the pipeline around Bad River territory within five years.

Natural gas prices in Western Canada have been constrained in recent years due to increasing North American supply, limited access to markets and limited storage capacity. Companies that secure firm access to infrastructure to transport their natural gas production out of Western Canada may be able to access more markets and obtain better pricing. Companies without firm access may be forced to accept spot pricing in Western Canada for their natural gas, which is generally lower than the prices received in other North American regions. The Corporation has an active hedging policy in place in order to mitigate our exposure to volatile spot AECO pricing.

Required repairs or upgrades to existing pipeline systems in Western Canada have also led to reduced capacity and apportionment of access, the effects of which have been exacerbated by storage limitations. In October 2020, TC Energy Corporation received federal approval to expand the Nova Gas Transmission Line system (the "NGTL System") and the expanded NGTL System was completed in April 2022.

While a number of LNG export plants have been proposed in Canada, regulatory and legal uncertainty, social and political opposition and changing market conditions have resulted in the cancellation or delay of many of these projects. Nonetheless, in October 2018, the joint venture partners of the LNG Canada LNG export terminal announced a positive final investment decision. Once complete, the project will allow producers in northeastern British Columbia to transport natural gas to the LNG

Canada liquefaction facility and export terminal in Kitimat, British Columbia via the Coastal GasLink pipeline (the "CGL Pipeline"). With more Alberta and northeastern British Columbia gas egressing through the CGL Pipeline, the NGTL System is expected to have more capacity, which may result in a closer link between AECO and NYMEX gas prices. Phase 1 of the LNG Canada project reached 70% completion in October 2022, with a completion target of 2025.

In May 2020, TC Energy Corporation sold a 65% equity interest in the CGL Pipeline to investment companies KKR & Co Inc. and Alberta Investment Management Corporation while remaining the pipeline operator. Despite its regulatory approval, the CGL Pipeline has faced legal and social opposition. For example, protests involving the Hereditary Chiefs of the Wet'suwet'en First Nation and their supporters have delayed construction activities on the CGL Pipeline, although construction is proceeding. As of November 2022, construction of the CGL Pipeline was approximately 80% complete.

Woodfibre LNG Limited issued a notice to proceed with construction of the Woodfibre LNG project to its prime contractor in April 2022. The Woodfibre LNG project is located near Squamish, British Columbia, and upon completion will produce approximately 2.1 million tonnes of LNG per year. Major construction is set to commence in 2023, with substantial completion of the project expected in late 2027. In November 2022, Enbridge Inc. completed a transaction with Pacific Energy Corporation Limited, the owner of Woodfibre LNG Limited, to retain a 30% ownership stake in the project.

In addition to LNG Canada, the CGL Pipeline and the Woodfibre LNG project, a number of other LNG projects are underway at varying stages of progress, though none have reached a positive final investment decision.

The Oil Tanker Moratorium Act (Canada), which was enacted in June 2019, imposes a ban on tanker traffic transporting crude oil or persistent crude oil products in excess of 12,500 metric tonnes to and from ports located along British Columbia's north coast. The ban may prevent pipelines from being built to, and export terminals from being located on, the portion of the British Columbia coast subject to the moratorium.

Canada is party to a number of international trade agreements with other countries around the world that generally provide for, among other things, preferential access to various international markets for certain Canadian export products. Examples of such trade agreements include the Comprehensive Economic and Trade Agreement ("CETA"), the Comprehensive and Progressive Agreement for Trans-Pacific Partnership and, most importantly, the United States Mexico Canada Agreement (the "USMCA"), which replaced the former North American Free Trade Agreement ("NAFTA") on July 1, 2020. Because the United States remains Canada's primary trading partner and the largest international market for the export of oil, natural gas and NGLs from Canada, the implementation of the USMCA could impact Western Canada's oil and gas industry as a whole, including the Corporation's business.

While the proportionality rules in Article 605 of NAFTA previously prevented Canada from implementing policies that limit exports to the United States and Mexico relative to the total supply produced in Canada, the USMCA does not contain the same proportionality requirements. This may allow Canadian producers to develop a more diversified export portfolio than was possible under NAFTA, subject to the construction of infrastructure allowing more Canadian production to reach Eastern Canada, Asia and Europe.

Canada is also party to the CETA, which provides for duty-free, quota-free market access for Canadian crude oil and natural gas products to the European Union. Following the United Kingdom's departure from the European Union on January 31, 2020, the United Kingdom and Canada entered into the Canada-United Kingdom Trade Continuity Agreement ("CUKTCA"), which replicates CETA on a bilateral basis to maintain the status quo of the Canada-United Kingdom trade relationship.

While it is uncertain what effect CETA, CUKTCA or any other trade agreements will have on the petroleum and natural gas industry in Canada, the lack of available infrastructure for the offshore export of crude oil and natural gas may limit the ability of Canadian crude oil and natural gas producers to benefit from such trade agreements.

With the exception of Manitoba, each provincial government in Western Canada owns most of the mineral rights to the oil and natural gas located within their respective provincial borders. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits (collectively, "leases") for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments in lieu thereof. The provincial governments in Western Canada conduct regular land sales where oil and natural gas companies bid for the leases necessary to explore for and produce oil and natural gas owned by the respective provincial governments. These leases generally have fixed terms, but they can be continued beyond their initial terms if the necessary conditions are satisfied.

All of the provinces of Western Canada have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a disposition. In addition, Alberta has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for new leases and licenses.

In addition to Crown ownership of the rights to oil and natural gas, private ownership of oil and natural gas (i.e. freehold mineral lands) also exists in Western Canada. Rights to explore for and produce privately owned oil and natural gas are granted by a lease or other contract on such terms and conditions as may be negotiated between the owner of such mineral rights and companies seeking to explore for and/or develop oil and natural gas reserves.

An additional category of mineral rights ownership includes ownership by the Canadian federal government of some legacy mineral lands and within Indigenous reservations designated under the Indian Act (Canada). Indian Oil and Gas Canada manages subsurface and surface leases in consultation with applicable Indigenous peoples, for the exploration and production of oil and natural gas on Indigenous reservations through An Act to Amend the Indian Oil and Gas Act and the accompanying regulations. The Corporation does not have operations on Indigenous reserve lands.

To develop oil and natural gas resources, producers must also have access rights to the surface lands required to conduct operations. For Crown lands, surface access rights can be obtained directly from the government. For private lands, access rights can be negotiated with the landowner. Where an agreement cannot be reached, however, each province has developed its own process that producers can follow to obtain and maintain the surface access necessary to conduct operations throughout the lifespan of a well, including notification requirements and providing compensation to affected persons for lost land use and surface damage. Similar rules apply to facility and pipeline operators.

Each province has legislation and regulations in place to govern Crown royalties and establish the royalty rates that producers must pay in respect of the production of Crown resources. The royalty regime in a given province is in addition to applicable federal and provincial taxes and is a significant factor in the profitability of oil sands projects and oil, natural gas and NGL production. Royalties payable on production from lands where the Crown does not hold the mineral rights are negotiated between the mineral freehold owner and the lessee, though certain provincial taxes and other charges on production or revenues may be payable. Royalties from production on Crown lands are determined by provincial regulation and are generally calculated as a percentage of the value of production.

Producers and working interest owners of oil and natural gas rights may create additional royalties or royalty-like interests, such as overriding royalties, net profits interests and net carried interests, through private transactions, the terms of which are subject to negotiation.

Occasionally, both the federal government and the provincial governments in Western Canada create incentive programs for the oil and natural gas industry. These programs often provide for volume-based incentives, royalty rate reductions, royalty holidays or royalty tax credits and may be introduced when commodity prices are low to encourage exploration and

development activity. Governments may also introduce incentive programs to encourage producers to prioritize certain kinds of development or utilize technologies that may enhance or improve recovery of oil, natural gas and NGLs, or improve environmental performance.

In addition, from time-to-time, including during the COVID-19 pandemic, the federal government creates incentives and other financial aid programs intended to assist businesses operating in the oil and natural gas industry as well as other industries in Canada.

In Alberta, oil and natural gas producers are responsible for calculating their royalty rate on an ongoing basis. The Crown's royalty share of production is payable monthly and producers must submit their records showing the royalty calculation.

In 2016, the Government of Alberta adopted a modernized Crown royalty framework (the "Modernized Framework") that applies to all conventional oil (i.e., not oil sands) and natural gas wells drilled after December 31, 2016 that produce Crown-owned resources. The previous royalty framework (the "Old Framework") will continue to apply to wells producing Crown-owned resources that were drilled prior to January 1, 2017 until December 31, 2026, following which time they will become subject to the Modernized Framework. The Royalty Guarantee Act (Alberta) came into effect on July 18, 2019 and provides that no major changes will be made to the current oil and natural gas royalty structure for a period of at least 10 years.

Royalties on production from wells subject to the Modernized Framework are determined on a "revenue-minus-costs" basis. The cost component is based on a Drilling and Completion Cost Allowance formula that relies, in part, on the industry's average drilling and completion costs, determined annually by the Alberta Energy Regulator (the "AER"), and incorporates information specific to each well such as vertical depth and lateral length.

Under the Modernized Framework, producers initially pay a flat royalty of 5% on production revenue from each producing well until payout, which is the point at which cumulative gross revenues from the well equals the applicable Drilling and Completion Cost Allowance. After payout, producers pay an increased royalty of up to 40% that will vary depending on the nature of the resource and market prices. Once the rate of production from a well is too low to sustain the full royalty burden, its royalty rate is gradually adjusted downward as production declines, eventually reaching a floor of 5%.

Under the Old Framework, royalty rates for conventional oil production can be as high as 40% and royalty rates for natural gas production can be as high as 36%. Similar to the Modernized Framework, these rates vary based on the nature of the resource and market prices. The natural gas royalty formula also provides for a reduction based on the measured depth of the well, as well as the acid gas content of the produced natural gas.

In addition to royalties, producers of oil and natural gas from Crown lands in Alberta are also required to pay annual rentals to the Government of Alberta.

Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner. Producers and working interest participants may also pay additional royalties to parties other than the freehold mineral owner where such royalties are negotiated through private transactions.

The Government of Alberta levies annual freehold mineral taxes for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties and is payable by the registered owner of the mineral rights.

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage crude oil and natural gas development and new drilling. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources, including coalbed methane wells, shale gas wells and horizontal crude oil and natural gas wells.

The Canadian oil and natural gas industry is subject to environmental regulation under a variety of Canadian federal, provincial, territorial, and municipal laws and regulations, all of which are subject to governmental review and revision from time to time. Such regulations provide for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and natural gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well, facility and pipeline sites. Compliance with such regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability, and the imposition of material fines and penalties. In addition, future changes to environmental legislation, including legislation related to air pollution and greenhouse gas ("GHG") emissions (typically measured in terms of their global warming potential and expressed in terms of carbon dioxide equivalent ("CO2e")), may impose further requirements on operators and other companies in the oil and natural gas industry.

Canadian environmental regulation is the responsibility of both the federal and provincial governments. While provincial governments and their delegates are responsible for most environmental regulation, the federal government can regulate environmental matters where they impact matters of federal jurisdiction or when they arise from projects that are subject to federal jurisdiction, such as interprovincial transportation undertakings, including pipelines and railways, and activities carried out on federal lands. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law prevails.

The CERA and the Impact Assessment Act (the "IAA") provide a number of important elements to the regulation of federally regulated major projects and their associated environmental assessments. The CERA separates the CER's administrative and adjudicative functions. The CER has jurisdiction over matters such as the environmental and economic regulation of pipelines, transmission infrastructure and certain offshore renewable energy projects. In its adjudicative role, the CERA tasks the CER with reviewing applications for the development, construction and operation of many of these projects, culminating in their eventual abandonment.

The IAA relies on a designated project list as a trigger for a federal assessment. Designated projects that may have effects on matters within federal jurisdiction will generally require an impact assessment administered by the Impact Assessment Agency (the "IA Agency") or, in the case of certain pipelines, a joint review panel comprised of members from the CER and the IA Agency. The impact assessment requires consideration of the project's potential adverse effects and the overall societal impact that a project may have, both of which may include a consideration of, among other items, environmental, biophysical and socio-economic factors, climate change, and impacts to Indigenous rights. It also requires an expanded public interest assessment. Designated projects specific to the oil and natural gas industry include pipelines that require more than 75 kilometers of new rights of way and pipelines located in national parks, large scale in situ oil sands projects not regulated by provincial GHG emissions caps and certain refining, processing and storage facilities.

The federal government has stated that an objective of the legislative changes was to improve decision certainty and turnaround times. Once a review or assessment is commenced under either the CERA or IAA, there are limits on the amount of time the relevant regulatory authority will have to issue its report and recommendation. Designated projects will go through a planning phase to determine the scope of the impact assessment, which the federal government has stated should provide more certainty as to the length of the full review process.

In May 2022, the Alberta Court of Appeal released its decision in response to the Government of Alberta's submission of a reference question regarding the constitutionality of the IAA. The Court found the IAA to be unconstitutional in its entirety, stating that the legislation effectively granted the federal government a veto over projects that were wholly within provincial jurisdiction. Shortly after the decision was released, the Government of Canada announced its intention to appeal the decision to the Supreme Court of Canada.

The AER is the principal regulator responsible for all energy resource development in Alberta. It derives its authority from the Responsible Energy Development Act and a number of related statutes including the Oil and Gas Conservation Act (the "OGCA"), the Oil Sands Conservation Act, the Pipeline Act, and the Environmental Protection and Enhancement Act. The AER is responsible for ensuring the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources, including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Land and Property Rights Tribunal, as well as the Alberta Ministry of Energy's responsibility for mineral tenure.

The Government of Alberta relies on regional planning to accomplish its resource development goals. Its approach to natural resource management provides for engagement and consultation with stakeholders and the public and examines the cumulative impacts of development on the environment and communities. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including the Alberta Ministry of Environment and Parks, the Alberta Ministry of Energy, the Aboriginal Consultation Office and the Land Use Secretariat.

The Government of Alberta's land-use policy sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.

The AER monitors seismic activity across Alberta to assess the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate oil and natural gas production. The Corporation routinely conducts hydraulic fracturing in its drilling and completion programs. In recent years, hydraulic fracturing has been linked to increased seismicity in certain areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further.

The AER has developed monitoring and reporting requirements that apply to all oil and natural gas producers working in certain areas where the likelihood of an earthquake is higher, and implemented the requirements in Subsurface Order Nos. 2, 6, and 7. The regions with seismic protocols in place are Fox Creek, Red Deer and Brazeau (the "Seismic Protocol Regions"). The Corporation does have operations in these regions. Oil and natural gas producers in each of the Seismic Protocol Regions are subject to a "traffic light" reporting system that sets thresholds on the Richter scale of earthquake magnitude. The thresholds vary among the Seismic Protocol Regions and trigger a sliding scale of obligations from the oil or natural gas producers operating there. Such obligations range from no action required, to informing the AER and invoking an approved response plan, to ceasing operations and informing the AER. The AER has the discretion to suspend operations while it investigates following a seismic event until it has assessed the ongoing risk of earthquakes in a specific area and/or may require the operator to update its response plan. The AER may extend these requirements to other areas of Alberta if necessary, subject to the results of its ongoing province-wide monitoring.

The AER administers the Liability Management Framework (the "AB LM Framework") and the Liability Management Rating Program (the "AB LMR Program") to manage liability for most conventional upstream oil and natural gas wells, facilities and pipelines in Alberta. The AER is in the process of replacing the AB LMR Program with the AB LM Framework. This change was effected under key new AER directives in 2021, and further updates released in 2022. Broadly, the AB LM Framework is intended to provide a more holistic approach to liability management in Alberta, as the AER found that the more formulaic approach under the AB LMR Program did not necessarily indicate whether a company could meet its liability obligations. New developments under the AB LM Framework include a new Licensee Capability Assessment System (the "AB LCA"), a new Inventory Reduction Program (the "AB IR Program"), and a new Licensee Management Program ("AB LM Program"). Meanwhile, some programs under the AB LMR Program remain in effect, including the Oilfield Waste Liability Program (the "AB OWL Program"), the Large Facility Liability Management Program (the "AB LF Program") and elements of the Licensee Liability Rating Program (the "AB LLR Program"). The mix between active programs under the AB LM Framework and the AB LMR Program highlights the transitional and dynamic nature of liability management in Alberta. While the province is moving towards the AB LM Framework and a more holistic approach to liability management, the AER has noted that this will be a gradual process that will take time to complete. In the meantime, the AB LMR Program continues to play an important role in Alberta's liability management scheme.

Complementing the AB LM Framework and the AB LMR Program, Alberta's OGCA establishes an orphan fund (the "Orphan Fund") to help pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program and the AB OWL Program if a licensee or working interest participant becomes insolvent or is unable to meet its obligations. Licensees in the AB LLR Program and the AB OWL Program fund the Orphan Fund through a levy administered by the AER. However, given the increase in orphaned oil and natural gas assets, the Government of Alberta has loaned the Orphan Fund approximately $335 million to carry out abandonment and reclamation work. In response to the COVID-19 pandemic, the Government of Alberta also covered $113 million in levy payments that licensees would otherwise have owed to the Orphan Fund, corresponding to the levy payments due for the first six months of the AER's fiscal year. A separate orphan levy applies to persons holding licences subject to the AB LF Program. Collectively, these programs are designed to minimize the risk to the Orphan Fund posed by the unfunded liabilities of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines.

The Supreme Court of Canada's decision in Orphan Well Association v Grant Thornton (also known as the "Redwater" decision), provides the backdrop for Alberta's approach to liability management. As a result of the Redwater decision, receivers and trustees can no longer avoid the AER's legislated authority to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a licence transfer when any such licensee is subject to formal insolvency proceedings. This means that insolvent estates can no longer disclaim assets that have reached the end of their productive lives (and therefore represent a net liability) in order to deal primarily with the remaining productive and valuable assets without first satisfying any abandonment and reclamation obligations associated with the insolvent estate's assets. In April 2020, the Government of Alberta passed the Liabilities Management Statutes Amendment Act, which places the burden of a defunct licensee's abandonment and reclamation obligations first on the defunct licensee's working interest partners, and second, the AER may order the Orphan Fund to assume care and custody and accelerate the clean-up of wells or sites which do not have a responsible owner. These changes came into force in June 2020.

One important step in the shift to the AB LM Framework has been amendments to Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals ("Directive 067"), which deals with licensee eligibility to operate wells and facilities. All licence transfers and the granting of new well, facility and pipeline licences in Alberta are subject to AER approval. Previously under the AB LMR Program, as a condition of transferring existing AER licences, approvals and permits, all transfers required transferees to demonstrate that they had a liability management rating of 2.0 or higher immediately following the transfer. If transferees did not have the required rating, they would have to otherwise prove to the satisfaction of the AER that they could meet their abandonment and reclamation obligations, through means such as posting security or reducing their existing obligations. However, amendments from April 2021 to Directive 067 expanded the criteria for assessing licensee eligibility. Notably, the recent amendments increase requirements for financial disclosure, detail new requirements for when a licensee poses an "unreasonable risk" of orphaning assets, and adds additional general requirements for maintaining eligibility.

Alongside changes to Directive 067, the AER introduced Directive 088: Licensee Life-Cycle Management ("Directive 088") in December 2021 under the AB LM Framework. Directive 088 replaces, to an extent, the AB LLR Program with the AB LCA. Whereas the AB LLR Program previously assessed a licensee based on a liability rating determined by the ratio of a licensee's deemed asset value relative to the deemed liability value of its oil and natural gas wells and facilities, the AB LCA now considers a wider variety of factors and is intended to be a more comprehensive assessment of corporate health. Such factors are wide reaching and include: (i) a licensee's financial health; (ii) its established total magnitude of liabilities, (iii) the remaining lifespan of its mineral resources and infrastructure; (iv) the management of its operations; (v) the rate of closure activities and spending, and pace of inactive liability growth; and (vi) its compliance with administrative and regulatory requirements. These various factors feed into a broader holistic assessment of a licensee under the AB LM Framework. In turn, that holistic assessment provides the basis for assessing risk posed by licence transfers, as well as any security deposit that the AER may require from a licensee in the event that the regulator deems a licensee at risk of not being able to meet its liability obligations. However, the liability management rating under the AB LLR Program is still in effect for other liability management programs such as the AB OWL Program and the AB LF Program, and will remain in effect until a broadened scope of Directive 088 is phased in over time.

In addition to the AB LCA, Directive 088 also implemented other new liability management programs under the AB LM Framework. These include the AB LM Program and the AB IR Program. Under the AB LM Program the AER will continuously monitor licensees over the life-cycle of a project. If, under the AB LM Program, the AER identifies a licensee as high risk, the regulator may employ various tools to ensure that a licensee meets its regulatory and liability obligations. In addition, under the AB IR Program the AER sets industry wide spending targets for abandonment and reclamation activities.

Licensees are then assigned a mandatory licensee specific target based on the licensee's proportion of provincial inactive liabilities and the licensee's level of financial distress. Certain licensees may also elect to provide the AER with a security deposit in place of their closure spend target. The AER has also indicated that it will implement a closure nomination program (the "CN Program") in 2023. Under the program, those who qualify may nominate certain oil and gas sites for closure. Details regarding the CN Program and the mechanism through which nominated sites will be abandoned and reclaimed are forthcoming.

The Government of Alberta followed the announcement of the AB LM Framework with amendments to the Oil and Gas Conservation Rules and the Pipeline Rules in late 2020. The changes to these rules fall into three principal categories: (i) they introduce "closure" as a defined term, which captures both abandonment and reclamation; (ii) they expand the AER's authority to initiate and supervise closure; and (iii) they permit qualifying third parties on whose property wells or facilities are located to request that licensees prepare a closure plan.

Climate change regulation at each of the international, federal and provincial levels has the potential to significantly affect the future of the oil and natural gas industry in Canada. These impacts are uncertain and it is not possible to predict what future policies, laws and regulations will entail. Any new laws and regulations (or additional requirements to existing laws and regulations) could have a material impact on the Corporation's operations and cash flow.

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") since 1992. Since its inception, the UNFCCC has instigated numerous policy changes with respect to climate governance. On April 22, 2016, 197 countries, including Canada, signed the Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. To date, 189 of the 197 parties to the UNFCCC have ratified the Paris Agreement, including Canada. In 2016, Canada committed to reducing its emissions by 30% below 2005 levels by 2030. In 2021, Canada updated its original commitment by pledging to reduce emissions by 40-45% below 2005 levels by 2030, and to net-zero by 2050.

During the course of the 2021 United Nations Climate Change Conference in Glasgow, Scotland, Canada made several pledges aimed at reducing Canada's GHG emissions and environmental impact, including: (i) reducing methane emissions in the oil and natural gas sector to 75% of 2012 levels by 2030; (ii) ceasing the export of thermal coal by 2030; (iii) imposing a cap on emissions from the oil and natural gas sector; (iv) halting direct public funding to the global fossil fuel sector by the end of 2022; and (v) committing that all new vehicles sold in the country will be zero-emission on or before 2040.

In line with Canada's pledge to impose a cap on emissions from the oil and gas sector, the federal government published a discussion paper on July 18, 2022 that outlines two potential regulatory options for such a cap. Those proposed options are either to: (i) implement a new cap-and-trade system that would set a limit on emissions from the sector; or (ii) modify the existing pollution pricing benchmark (as discussed below) to limit emissions from the sector. These options are currently under review and interested parties had the opportunity to make submissions regarding the proposed cap, ending in September 2022. The form of emissions cap on the oil and gas sector and the overall effect of such a cap remain uncertain.

The Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change in 2016, setting out a plan to meet the federal government's 2030 emissions reduction targets. On June 21, 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act (the "GGPPA"), which came into force on January 1, 2019. This regime has two parts: an output-based pricing system ("OBPS") for large industry (enabled by the Output-Based Pricing System Regulations) and a fuel charge (enabled by the Fuel Charge Regulations), both of which impose a price on CO2e emissions. This system applies in provinces and territories that request it and in those that do not have their own equivalent emissions pricing systems in place that meet the federal standards and ensure that there is a uniform price on emissions across the country. Originally under the federal plans, the price was set to escalate by $10 per year until it reached a maximum price of $50/tonne of CO2e in 2022; however, on December 11, 2020, the federal government announced its intention to continue the annual price increases beyond 2022. Commencing in 2023, the benchmark price per tonne of CO2e will increase by $15 per year until it reaches $170/tonne of CO2e in 2030. Effective January 1, 2023, the minimum price permissible under the GGPPA rose to $65/tonne of CO2e. While several provinces challenged the constitutionality of the GGPPA following its enactment, the Supreme Court of Canada confirmed its constitutional validity in a judgment released on March 25, 2021.

On April 26, 2018, the federal government passed the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Federal Methane Regulations"). The Federal Methane Regulations seek to reduce emissions of methane from the oil and natural gas sector, and came into force on January 1, 2020. By introducing a number of new control measures, the Federal Methane Regulations aim to reduce unintentional leaks and the intentional venting of methane and ensure that oil and natural gas operations use low-emission equipment and processes. Among other things, the Federal Methane Regulations limit how much methane upstream oil and natural gas facilities are permitted to vent. The federal government anticipates that these actions will reduce annual GHG emissions by about 20 megatonnes by 2030.

The federal government has enacted the Multi-Sector Air Pollutants Regulation under the authority of the Canadian Environmental Protection Act, 1999, which regulates certain industrial facilities and equipment types, including boilers and heaters used in the upstream oil and natural gas industry, to limit the emission of air pollutants such as nitrogen oxides and sulphur dioxide.

In the November 23, 2021 Speech from the Throne, the federal government restated its commitment to achieve net-zero emission by 2050. In pursuit of this objective, the government's proposed actions include: (i) moving to cap and cut oil and natural gas sector emissions; (ii) investing in public transit and mandating the sale of zero-emission vehicles; (iii) increasing the federally imposed price on pollution; (iv) investing in the production of cleaner steel, aluminum, building products, cars, and planes; (v) addressing the loss of biodiversity by continuing to strengthen partnerships with First Nations, Inuit, and Métis, to protect nature and the traditional knowledge of those groups; (vi) creating a Canada Water Agency to safeguard water as a natural resource and support Canadian farmers; (vii) strengthening action to prevent and prepare for floods, wildfires, droughts, coastline erosion, and other extreme weather worsened by climate change; and (viii) helping build back communities impacted by extreme weather events through the development of Canada's first-ever National Adaptation Strategy.

The Canadian Net-Zero Emissions Accountability Act (the "CNEAA") received royal assent on June 29, 2021, and came into force on the same day. The CNEAA binds the Government of Canada to a process intended to help Canada achieve net-zero emissions by 2050. It establishes rolling five-year emissions-reduction targets and requires the government to develop plans to reach each target and support these efforts by creating a Net-Zero Advisory Body. The CNEAA also requires the federal government to publish annual reports that describe how departments and Crown corporations are considering the financial risks and opportunities of climate change in their decision-making. A comprehensive review of the CNEAA is required every five years from the date the CNEAA came into force.

The Government of Canada introduced its 2030 Emissions Reduction Plan (the "2030 ERP") on March 29, 2022. In the 2030 ERP, the Government of Canada proposes a roadmap for Canada's reduction of GHG emissions to 40-45% below 2005 levels by 2030. As the first emissions reduction plan issued under the CNEAA, the 2030 ERP aims to reduce emissions by incentivizing electric vehicles and renewable electricity, and capping emissions from the oil and natural gas sector, among other measures.

On June 8, 2022, the Canadian Greenhouse Gas Offset Credit System Regulations were published in the Canada Gazette. The regulations establish a regulatory framework to allow certain kinds of projects to generate and sell offset credits for use in the federal OBPS through Canada's Greenhouse Gas Offset Credit System. The system enables project proponents to generate federal offset credits through projects that reduce GHG emissions under a published federal GHG offset protocol. Offset credits can then be sold to those seeking to meet limits imposed under the OBPS or those seeking to meet voluntary targets.

On June 20, 2022, the Clean Fuel Regulations came into force, establishing Canada's Clean Fuel Standard. The Clean Fuel Standard will replace the former Renewable Fuels Regulation, and aims to discourage the use of fossil fuels by increasing the price of those fuels when compared to lower-carbon alternatives. Coming into force in 2023, the Clean Fuel Standard will impose obligations on primary suppliers of transportation fuels in Canada and require fuels to contain a minimum percentage of renewable fuel content and meet emissions caps calculated over the life cycle of the fuel. The Clean Fuel Regulations also establish a market for compliance credits. Compliance credits can be generated by primary suppliers, among others, through carbon capture and storage, producing or importing low-emission fuel, or through end-use fuel switching (for example, operating an electric vehicle charging network).

The Government of Canada is also in the midst of developing a carbon capture utilization and storage ("CCUS") strategy. CCUS is a technology that captures carbon dioxide from facilities, including industrial or power applications, or directly from the atmosphere. The captured carbon dioxide is then compressed and transported for permanent storage in underground

geological formations or used to make new products such as concrete. Beginning in 2022, the federal government plans to spend $319 million over seven years to ramp up CCUS in Canada, as this will be a critical element of the plan to reach net-zero by 2050.

In December 2016, the Oil Sands Emissions Limit Act came into force, establishing an annual 100 megatonne limit for GHG emissions from all oil sands sites, but the regulations necessary to enforce the limit have not yet been developed. The delay in drafting these regulations has been inconsequential thus far, as Alberta's oil sands emit roughly 70 megatonnes of GHG emissions per year, well below the 100 megatonne limit.

In June 2019, the fuel charge element of the federal backstop program took effect in Alberta. On January 1, 2023, the carbon tax payable in Alberta increased from $50 to $65 per tonne of CO2e, and will continue to increase at a rate of $15 per year until it reaches $170 per tonne in 2030. In December 2019, the federal government approved Alberta's Technology Innovation and Emissions Reduction ("TIER") regulation, which applies to large emitters. The TIER regulation came into effect on January 1, 2020 and replaces the previous Carbon Competitiveness Incentives Regulation. The TIER regulation meets the federal benchmark stringency requirements for emissions sources covered in the regulation, but the federal backstop continues to apply to emissions sources not covered by the regulation.

The TIER regulation applies to emitters that emit more than 100,000 tonnes of CO2e per year in 2016 or any subsequent year. The initial target for most TIER-regulated facilities is to reduce emissions intensity by 10% as measured against that facility's individual benchmark, with a further 1% reduction in each subsequent year. The facility-specific benchmark does not apply to all facilities, such as those in the electricity sector, which are compared against the good-as-best-gas standard. Similarly, for facilities that have already made substantial headway in reducing their emissions, a different "high-performance" benchmark is available. Under the TIER regulation, certain facilities in high-emitting or trade exposed sectors can opt-in to the program in specified circumstances if they do not meet the 100,000 tonne threshold. The Corporation was accepted to the TIER program in December 2019, and remains a participant of the program for 2023. To encourage compliance with the emissions intensity reduction targets, TIER-regulated facilities must provide annual compliance reports. Facilities that are unable to achieve their targets may either purchase credits from other facilities, purchase carbon offsets, or pay a levy to the Government of Alberta.

The Government of Alberta aims to lower annual methane emissions by 45% by 2025. The Government of Alberta enacted the Methane Emission Reduction Regulation on January 1, 2020, and in November 2020, the Government of Canada and the Government of Alberta announced an equivalency agreement regarding the reduction of methane emissions such that the Federal Methane Regulations will not apply in Alberta.

Constitutionally mandated government-led consultation with and, if applicable, accommodation of the rights of, Indigenous groups impacted by regulated industrial activity, as well as proponent-led consultation and accommodation or benefit sharing initiatives, play an increasingly important role in the Western Canadian oil and natural gas industry. In addition, Canada is a signatory to the United Nations Declaration of the Rights of Indigenous Peoples ("UNDRIP") and the principles set forth therein may continue to influence the role of Indigenous engagement in the development of the oil and natural gas industry in Western Canada. For example, in November 2019, the Declaration on the Rights of Indigenous Peoples Act ("DRIPA") became law in British Columbia. The DRIPA aims to align British Columbia's laws with UNDRIP. In June 2021, the United Nations Declaration on the Rights of Indigenous Peoples Act ("UNDRIP Act") came into force in Canada. Similar to British Columbia's DRIPA, the UNDRIP Act requires the Government of Canada to take all measures necessary to ensure the laws of Canada are consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP's objectives. On June 21, 2022, the Minister of Justice and Attorney General issued the First Annual Progress Report on the implementation of the UNDRIP Act (the "Progress Report"). The Progress Report provides that, as of June 2022, the federal government has sought to implement the UNDRIP Act by, among other things, creating a Secretariat within the Department of Justice to support Indigenous participation in the implementation of UNDRIP, consulting with Indigenous peoples to identify their priorities, drafting an action plan to align federal laws with UNDRIP, and implementing efforts to educate federal departments on UNDRIP's principles.

uncertainty to the ability of entities operating in the Canadian oil and natural gas industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines. The Government of Canada has expressed that implementation of the UNDRIP Act has the potential to make meaningful change in how Indigenous peoples collaborate in impact assessment moving forward, but has confirmed that the current IAA already establishes a framework that aligns with UNDRIP and does not need to be changed in light of the UNDRIP Act.

On June 29, 2021, the British Columbia Supreme Court issued a judgement in Yahey v British Columbia (the "Blueberry Decision"), in which it determined that the cumulative impacts of industrial development on the traditional territory of the Blueberry River First Nation ("BRFN") in northeast British Columbia had breached the BRFN's rights guaranteed under Treaty 8. The Blueberry Decision may have significant impacts on the regulation of industrial activities in northeast British Columbia, and may lead to similar claims of cumulative effects across Canada in other areas covered by numbered treaties, as has been seen in Alberta.

On January 18, 2023, the Government of British Columbia and the BRFN signed the Blueberry River First Nations Implementation Agreement (the "BRFN Agreement"). The BRFN Agreement aims to address the cumulative effects of development on BRFN's claim area through restoration work, establishment of areas protected from industrial development, and a constraint on development activities. Such measures will remain in place while a long-term cumulative effects management regime is implemented. Specifically, the BRFN Agreement includes, among other measures, the establishment of a $200-million restoration fund by June 2025, an ecosystem-based management approach for future land-use planning in culturally important areas, limits on new petroleum and natural gas development, and a new planning regime for future oil and gas activities. The BRFN will receive $87.5 million over three years, with an opportunity for increased benefits based on petroleum and natural gas revenue sharing and provincial royalty revenue sharing in the next two fiscal years.

In July 2022, Duncan's First Nation filed a lawsuit against the Government of Alberta relying on similar arguments to those advanced successfully by the BRFN. Duncan's First Nation claims in its lawsuit that Alberta has failed to uphold its treaty obligations by authorizing development without considering the cumulative impacts on the First Nation's treaty rights. The long-term impacts of the Blueberry Decision and the Duncan's First Nation lawsuit on the Canadian oil and gas industry remain uncertain.

Obsidian Energy understands its responsibilities for reducing the environmental impacts from our operations and recognizes the interests of other land users in resource development areas and conducts our operations accordingly. Obsidian Energy is committed to mitigating the environmental impact from our operations, and to involving stakeholders throughout the exploration, development, production and abandonment process. Obsidian Energy's environmental programs encompass resource conservation, stakeholder communication and site abandonment/reclamation. Our environmental programs are monitored to ensure they comply with all government environmental regulations and with Obsidian Energy's own environmental policies. The results of these programs are reviewed with Obsidian Energy's management and operations personnel, which seeks to drive improvements and to ensure compliance with these policies.

Obsidian Energy seeks to communicate its commitment to environmental stewardship to our stakeholders, including employees, investors, contractors, landowners and local communities, in order to always be held accountable. In this regard, in December 2022 we published and posted to our website our inaugural environmental, social and governance report (the "ESG Report") for the 2021 fiscal year, which provides an overview of our approach to sustainability along with key initiatives, metrics and accomplishments. Among other things, the ESG Report provides our commitment to decrease our GHG methane emissions by 10% from 2021 levels by year-end 2023 and contains tables with performance data on material environmental, social and governance topics. The content, scope and methods used in our ESG Report are informed by the Sustainability Accounting Standards Board Oil & Gas – Processing & Exploration accounting standard, the Global Reporting Initiative GRI 11 – Oil & Gas Sector 2021 standards ("GRI Standards"), and the Task Force for Climate-related Financial Disclosure recommendations. The ESG Report includes an index that links key performance indicators and qualitative disclosures to the GRI standards, where applicable. Our inaugural ESG Report is available on our website at www.obsidianenergy.com.

Obsidian Energy maintains a program of detailed inspections, audits and field assessments to determine and quantify the environmental liabilities that will be incurred during the eventual decommissioning and reclamation of our field facilities. Obsidian Energy pursues a program of environmental impact reduction aimed at minimizing these future corporate liabilities without hampering field productivity. This program, launched in 1994, is ongoing, and includes measures to remediate

potential contaminant sources, reclaim spill sites and abandon unproductive wells and inactive facilities. For information regarding our estimated future abandonment and reclamation costs as of December 31, 2022, see "– Disclosure of Reserves Data – Total Future Net Revenue (Undiscounted) as of December 31, 2022, Forecast Prices and Costs" and "– Additional Information Concerning Abandonment and Reclamation Costs" in "Appendix A-3 – Statement of Reserves Data and Other Oil and Gas Information", which is attached hereto.

Alberta's TIER program, which came into effect January 1, 2020, requires participants to comply with ongoing reporting of emissions, and where emissions cannot be reduced to target levels or otherwise accounted for through the use of credits either generated or purchased by Obsidian Energy, financial penalties are imposed. Obsidian Energy has only minor working interests in several non-operated facilities that are considered large emitters (emissions of more than 100,000 CO2e per year) within the requirements of the Alberta GHG regulations.

Obsidian Energy has proactively opted in to the TIER program by combining our smaller facilities into an "aggregate facilities" that allows the Company to participate in the TIER program with streamlined reporting. Aggregate facilities are required to reduce their total emission intensity by 10% for 2020, but unlike large emitters, this requirement does not become more stringent over time and will be re-evaluated in 2023. Further, Obsidian believes we have several low-cost opportunities to reduce our emissions profile. As such, our financial obligations related to compliance with existing federal and provincial legislation regarding GHG emissions are not material at this time.

Because the federal and provincial programs relating to the regulation of the emission of GHGs and other air pollutants continue to be developed, Obsidian Energy is currently unable to predict the total impact of the potential regulations upon our business. Therefore, it is possible that Obsidian Energy could face increases in costs in order to comply with emissions legislation. However, in cooperation with various industry groups, Obsidian Energy continues to work cooperatively with governments to develop an approach to deal with environmental issues that protects the industry's competitiveness, limits the cost and administrative burden of compliance, and supports continued investment in the oil and natural gas sector.

Obsidian Energy is committed to meeting its responsibilities to protect the environment wherever we operate. Obsidian Energy anticipates that our expenditures, both capital and expense in nature, will continue to increase as a result of operational growth and/or the introduction of new and enhanced legislation relating to the protection of the environment. Obsidian Energy will be taking such steps as are required to ensure continued compliance with applicable environmental legislation in each jurisdiction in which we operate. Obsidian Energy believes that we are currently in compliance with applicable environmental laws and regulations in all material respects. Obsidian Energy also believes that it is likely that the trend towards heightened and additional standards in environmental legislation and regulation will continue.

The following is a summary of certain risk factors relating to Obsidian Energy and our business and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this Annual Information Form and in our other public filings. Investors should consider carefully the information contained herein and, in particular, the following risk factors. If any of these risks occur, our financial condition and results of operations could be materially adversely affected, which could result in a decline in the trading price of our Common Shares. The risks described below are not an exhaustive list of the risks that may affect Obsidian Energy and our business, nor should they be taken as a complete summary or description of all the risks associated with Obsidian Energy and our business and the oil and natural gas business generally.

Volatility in oil and natural gas prices could have a material adverse effect on our results of operations and financial condition, which in turn could negatively affect the market price of our Common Shares.

Our results of operations and financial condition are dependent upon the prices that we receive for the oil, NGLs and natural gas that we sell. Historically, the oil, NGLs and natural gas markets have been volatile and are likely to continue to be volatile in the future. Oil, NGLs and natural gas prices have fluctuated widely during recent years and are subject to fluctuations in response to changes in supply, demand, market uncertainty and other factors that are beyond our control. These factors include, but are not limited to:

 the limitations on the ability of Western Canadian energy producers to export oil, NGLs and natural gas to U.S. markets and world markets and the resulting discount that Western Canadian energy producers may receive for their products as compared to U.S. and international benchmark commodity prices;

 sanctions imposed on certain oil and natural gas producing nations (such as Russia) by other countries;

 government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business;

We make price assumptions that are used for planning purposes, and a significant portion of our cash outflows, including certain operating and capital expenditures and transportation commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outflows are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices. Our risk management arrangements will not fully mitigate the effects of price volatility.

The economics of producing from some wells may change because of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and the value of the Corporation's reserves. The Corporation might also elect not to produce from certain wells at lower prices. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

All these factors could result in a material decrease in the Corporation's expected net production revenue and a reduction in our oil and natural gas production, acquisition, development and exploration activities. Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the carrying value of our reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects, and as a result, the market price of our Common Shares.

Volatility in market conditions for the oil and natural gas industry may affect the value of the Corporation's reserves and restrict our cash flow and our ability to access capital to fund the development of our oil and natural gas assets.

Various market events and conditions existing from time to time, including global excess oil and gas supply, concerns over public health related events such as the COVID-19 pandemic and the impact that it will have on the supply of and demand for oil, NGLs and natural gas, actions taken by OPEC and non-OPEC countries (i.e. Russia) and conflicts that occasionally arise between these countries when they compete for market share, sanctions against Russia, Iran and Venezuela, slowing growth in China and emerging economies, weakened global relationships, conflict between Ukraine and Russian and the U.S. and Iran, isolationist and punitive trade policies, de-globalization, U.S. shale production, sovereign debt levels and political upheavals in various countries, including growing anti-fossil fuel sentiment, have at times caused significant volatility in commodity prices. These events and conditions have at times caused a significant reduction in the valuation of oil and natural gas companies and a decrease in confidence in the oil and natural gas industry. These difficulties have at times been exacerbated in Canada by political and other actions resulting in uncertainty surrounding potential changes to the regulatory, tax, royalty, environmental and other regulatory regimes. In addition, the difficulties encountered by midstream proponents to obtain the necessary approvals on a timely basis or at all (or if obtained, to maintain such approvals) to build pipelines, liquefied natural gas plants and other facilities to provide better access to markets for the oil and natural gas industry in western Canada have at times led to additional downward price pressure on oil and natural gas produced in western Canada. The resulting price differential between Western Canadian Select oil and Brent and West Texas Intermediate oil has at times created uncertainty and reduced confidence in the oil and natural gas industry in western Canada. See "Industry Conditions".

Lower commodity prices may also affect the volume and value of the Corporation's reserves by rendering certain reserves uneconomic. In addition, lower commodity prices restrict the Corporation's cash flow resulting in less funds from operations being available to fund the Corporation's capital expenditure budget. As a result, the Corporation may not be able to replace our production with additional reserves and both the Corporation's production and reserves could be reduced on a year over year basis. Any decrease in value of the Corporation's reserves may reduce the borrowing base under our credit facilities which, depending on the level of the Corporation's indebtedness, could result in the Corporation having to repay a portion of our indebtedness. In addition to possibly resulting in a decrease in the value of the Corporation's economically recoverable reserves, lower commodity prices may also result in a decrease in the value of the Corporation's infrastructure and facilities, all of which could also have the effect of requiring a write down of the carrying value of the Corporation's oil and natural gas assets on our balance sheet and the recognition of an impairment charge in our income statement. Given the challenging market conditions experienced by the Canadian oil and natural gas industry during the past several years, the Corporation may have difficulty raising additional funds, or if we are able to do so, it may be on unfavourable and highly dilutive terms. If these conditions return, our cash flow may not be sufficient to continue to fund our operations and satisfy our obligations when due, and our ability to continue to fund our operations and discharge our obligations may require additional equity or debt financing and/or proceeds or reduction in liabilities from asset sales. There can be no assurance that such equity or debt financing will be available on terms that are satisfactory to us or at all. Similarly, there can be no assurance that we will be able to realize any or sufficient proceeds or reduction in liabilities from asset sales to continue to fund our operations and discharge our obligations.

The onset of adverse economic conditions could negatively impact financial markets and commodity prices and thus our financial condition.

The demand for energy, including crude oil, NGLs and natural gas, is generally linked to broad-based economic activities. If there was a slowdown in economic growth, an economic downturn or recession, or other adverse economic or political developments in the U.S., Europe, or Asia, there could be a significant adverse effect on global financial markets and commodity prices. In addition, hostilities in the Middle East, Ukraine, and Taiwan and the occurrence or threat of terrorist attacks in the U.S. or other countries could adversely affect the global economy. Global or national health concerns, including the outbreak of pandemic or contagious diseases, such as COVID-19, may adversely affect us by (i) reducing global economic activity thereby resulting in lower demand for crude oil, NGLs and natural gas, (ii) impairing our supply chain, for example, by limiting the manufacturing of materials or the supply of goods and services used in our operations, and (iii) affecting the health of our workforce, rendering employees unable to work or travel. These and other factors disclosed elsewhere herein that affect the supply and demand for crude oil, NGLs and natural gas, and our business and industry, could ultimately have an adverse impact on our financial condition, financial performance, and funds flow.

Acquiring, exploring for, developing, and producing from oil and natural gas assets involves many risks. Losses resulting from the occurrence of one or more of these risks may adversely affect our business and thus the value of our Common Shares.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long‑term commercial success of Obsidian Energy depends on our ability to find, acquire,

develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, our existing reserves, and the production from them, will decline over time as we produce from such reserves. A future increase in our reserves will depend on both our ability to explore and develop our existing properties and on our ability to select and acquire suitable producing properties or prospects. There is no assurance that we will be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of Obsidian Energy may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participations uneconomic. There is also no assurance that we will discover or acquire further commercial quantities of oil and natural gas.

Future oil and natural gas exploration may involve unprofitable efforts from dry wells or from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including hydraulic fracturing), operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Adverse field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, shut‑ins of wells resulting from extreme weather conditions, insufficient storage or transportation capacity or geological and mechanical conditions. While diligent well supervision, effective maintenance operations and the development of enhanced oil recovery technologies can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

Restrictions on the availability and cost of materials and equipment may impede our exploration, development, and operating activities as crude oil and natural gas exploration, development, and operating activities are dependent on the availability and cost of specialized materials and equipment (typically leased from third parties) in the areas where such activities are conducted. The availability of such material and equipment is limited. An increase in demand or cost, or a decrease in the availability of such materials and equipment, may impede our exploration, development, and operating activities.

We utilize multi-well pad drilling where practicable. Wells drilled on a pad are typically not placed on production until all wells on the pad are drilled and completed. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production, or interruption in ongoing production. These delays or interruptions may cause volatility in our operating results.

Acquiring, exploring for, developing, and producing from oil and natural gas assets involves many risks. These risks include, but are not limited to:

 adverse weather conditions, such as wild fires, flooding and extreme cold temperatures; and

These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment and cause personal injury or threaten wildlife. In particular, we may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to us. Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations and prospects.

Although we maintain insurance in accordance with customary industry practice based on our projected cost benefit analysis of maintaining such insurance, we are not fully insured against all of these risks, not all risks are insurable, and liabilities associated with certain risks could exceed policy limits or not be covered. Like other oil and natural gas companies, we attempt to conduct our business and financial affairs so as to protect against economic risks applicable to operations in the jurisdictions where we operate, but there can be no assurance that we will be successful in so protecting our assets.

The Corporation may require additional financing from time to time to fund the acquisition, exploration and development of properties and our ability to obtain such financing in a timely fashion and on acceptable terms may be negatively impacted by economic and global market conditions.

The Corporation's cash flow from our reserves may not be sufficient to fund our ongoing activities at all times and from time to time, the Corporation may require additional financing in order to carry out our oil and natural gas acquisition, exploration and development activities. Failure to obtain suitable financing on a timely basis could cause the Corporation to forfeit our interest in certain properties, miss certain acquisition opportunities, and/or reduce our operations, or terminate our operations on one or more properties. Due to the prevailing conditions in the oil and natural gas industry and/or global economic and/or political volatility, the Corporation may from time to time have restricted access to capital and/or credit and/or increased capital raising and/or borrowing costs. Recent conditions in the oil and natural gas industry have at times negatively affected the ability of oil and natural gas companies to access additional equity and/or debt financing and/or increased the cost of such financing.

If the Corporation's revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Corporation's ability to expend the necessary capital to replace our reserves or to maintain our production. To the extent that external sources of capital and/or credit become limited, unavailable or available on onerous terms, the Corporation's ability to make capital investments and maintain existing assets may be impaired, and our assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a result. In addition, the future development of the Corporation's petroleum properties may require additional financing and there are no assurances that such financing will be available or, if available, will be available upon acceptable terms. Alternatively, any available equity financing may be highly dilutive to existing Shareholders. Failure to obtain any financing necessary for the Corporation's capital expenditure plans may result in a delay in development or production on the Corporation's properties, or may force the Corporation to divest of certain assets that we would otherwise not sell.

Modification to current or implementation of additional regulations may reduce the demand for oil and natural gas and/or increase our costs and/or delay planned operations.

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing, transportation, infrastructure and mergers and acquisitions). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes, royalties, the exportation of oil and natural gas, infrastructure projects and the transfer of assets pursuant to acquisition and divestiture activities. Amendments to these controls and regulations may occur from time to time in response to economic or political conditions.

The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for oil and natural gas and increase our costs, either of which may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder and Indigenous consultation, environmental impact assessments, and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; environmental and habitat assessments; and other commitments or obligations. Further, the ongoing third party challenges to regulatory decisions or orders has reduced the efficiency of the regulatory regime, as the implementation of the decisions and orders has been delayed resulting in uncertainty and interruption to business in the oil and natural gas industry. See "Industry Conditions".

In order to conduct oil and natural gas operations, we require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities at the municipal, provincial and federal level. There can be no assurance that we will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that we may wish to undertake. In addition, certain federal legislation such as the Competition Act and the Investment Canada Act could negatively affect our business, financial condition and the market value of our securities or our assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity. See "Industry Conditions".

Changing investor sentiment towards the oil and natural gas industry may impact our access to, and cost of, capital.

A number of factors, including the effects of the use of fossil fuels on climate change, the impact of oil and natural gas operations on the environment, environmental damage relating to spills of petroleum products during production and

transportation and Indigenous rights, have affected certain investors', lenders' and insurers' sentiments towards investing in, lending to, and insuring participants in the oil and natural gas industry. As a result of these concerns, some institutional, retail and governmental investors, lenders and insurers have announced that they no longer are willing to fund or invest in, lend to, or insure oil and natural gas properties or companies, or are reducing the amount thereof over time. In addition, certain institutional investors, lenders and insurers are requesting that issuers develop and implement more robust social, environmental and governance policies and practices and make related disclosures. Developing and implementing such policies and practices, and making such related disclosures, can involve significant costs and require a significant time commitment from our Board, management and employees. Failing to implement the policies and practices, and make the related disclosures, as requested by institutional investors, lenders and insurers, may result in such investors reducing their investment in or loan to us, or not investing in or lending to us at all, or such insurers refusing to insure us. Any reduction in the investor, lender and insurer base interested or willing to invest in, lend to and insure the oil and natural gas industry and more specifically, the Corporation, may result in limiting our access to capital or insurance, increasing the cost of capital or insurance, and decreasing the price and liquidity of our Common Shares even if our operating results, underlying asset values or prospects have not changed or have improved.

The market price of our Common Shares has been and will likely continue to be volatile.

The trading price of the securities of oil and natural gas issuers is subject to substantial volatility and is often based on factors both related and unrelated to the financial performance or prospects of the issuers involved. Factors unrelated to our performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices and/or current perceptions of the oil and natural gas market. In recent years, the volatility of commodities has increased due to, in part, the COVID-19 pandemic, the implementation of computerized trading and the decrease of discretionary commodity trading. In addition, the volatility, trading volume and market price of the securities of oil and natural gas companies has been impacted by increasing investment levels in passive funds that track major indices, as such funds only purchase securities included in such indices. Furthermore, in certain jurisdictions, institutions, including government sponsored entities, have determined to decrease their ownership in oil and natural gas entities which may impact the liquidity of certain securities and may put downward pressure on the trading price of those securities. Similarly, the market price of our Common Shares could be subject to significant fluctuations in response to variations in our operating results, financial condition, liquidity, debt levels and other internal factors. Accordingly, the price at which our Common Shares will trade cannot be accurately predicted.

Our future oil and natural gas reserves and production, and therefore our cash flow, will be highly dependent on our success in exploring and exploiting our reserves and land base and acquiring additional reserves. Without reserve additions through acquisition, exploration or development activities, our reserves and production will decline over time as our existing reserves are depleted.

Global climate issues continue to attract public and scientific attention. Numerous reports, including reports from the Intergovernmental Panel on Climate Change, have engendered concern about the impacts of human activity, especially hydrocarbon combustion, on global climate issues. In turn, increasing public, government, and investor attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide and methane from the production and use of oil, NGLs and natural gas. The majority of countries across the globe, including Canada, have agreed to reduce their carbon emissions in accordance with the Paris Agreement. See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Climate Change Regulation" for a summary of Canada's subsequent actions and pledges aimed at

reducing Canada's GHG emissions and environmental impact. As discussed below, we face both transition risks and physical risks associated with climate change and climate change policy and regulations.

Foreign and domestic governments continue to evaluate and implement policy, legislation, and regulations focused on restricting emissions commonly referred to as GHG emissions and promoting adaptation to climate change and the transition to a low-carbon economy. It is not possible to predict what measures foreign and domestic governments may implement in this regard, nor is it possible to predict the requirements that such measures may impose or when such measures may be implemented. However, international multilateral agreements, the obligations adopted thereunder and legal challenges concerning the adequacy of climate-related policy brought against foreign and domestic governments may accelerate the implementation of these measures. Given the evolving nature of climate change policy and the control of GHG emissions and resulting requirements, including carbon taxes and carbon pricing schemes implemented by varying levels of government, it is expected that current and future climate change regulations will have the effect of increasing the Corporation's operating expenses and, in the long-term, potentially reducing the demand for oil, NGLs, natural gas and related products, resulting in a decrease in the Corporation's profitability and a reduction in the value of our assets.

Claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under certain laws or that such energy companies provided misleading disclosure to the public and investors of current or future risks associated with climate change. As a result, individuals, government authorities, or other organizations may make claims against oil and natural gas companies, including the Corporation, for alleged personal injury, property damage, or other potential liabilities. While the Corporation is not a party to any such litigation or proceedings, it could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely affect the demand for and price of securities issued by the Corporation, impact our operations and have an adverse impact on our financial condition.

Given the perceived elevated long-term risks associated with policy development, regulatory changes, public and private legal challenges, or other market developments related to climate change, there have also been efforts in recent years affecting the financial community, including investment advisors, sovereign wealth funds, banks, public pension funds, universities and other institutional investors, promoting direct engagement and dialogue with companies in their portfolios on climate change action (including exercising their voting rights on matters relating to climate change) and increased capital allocation to investments in low-carbon assets and businesses while decreasing the carbon intensity of their portfolios through, among other measures, divestments of companies with high exposure to GHG-intensive operations and products. Certain stakeholders have also pressured insurance providers and commercial and investment banks to reduce or stop financing, and providing insurance coverage to oil and natural gas and related infrastructure businesses and projects. The impact of such efforts require the Corporation's management to dedicate significant time and resources to these climate change-related concerns, may adversely affect the Corporation's operations, the demand for and price of the Corporation's securities and may negatively impact the Corporation's cost of capital and access to the capital markets.

Emissions, carbon and other regulations impacting climate and climate-related matters are constantly evolving. We are committed to reporting on our sustainability performance, and consider existing standards such as the Global Reporting Initiative Sustainability Reporting Standards, the Sustainability Accounting Standards Board "Oil & Gas – Processing & Exploration" accounting standard, and recommendations issued by the Task Force for Climate Related Financial Disclosures in our ESG reporting. In addition, the Canadian Securities Administrators have published for comment Proposed National Instrument 51-107 – Disclosure of Climate Related Matters, which is intended to introduce climate-related disclosure requirements for reporting issuers in Canada with limited exceptions. If we are not able to meet future sustainability reporting requirements of regulators or current and future expectations of investors, insurance providers, or other stakeholders, our business and ability to attract and retain skilled employees, obtain regulatory permits, licences, registrations, approvals, and authorizations from various governmental authorities, and raise capital may be adversely affected. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation".

Based on the Corporation's current understanding, the potential physical risks resulting from climate change are long-term in nature and associated with a high degree of uncertainty regarding timing, scope and severity of potential impacts. We do not conduct fundamental research regarding the scientific inquiry of climate change, but do stay abreast of the scientific literature

on the subject. Many experts believe global climate change could increase extreme variability in weather patterns such as increased frequency of severe weather, rising mean temperature and sea levels, and long-term changes in precipitation patterns. Extreme hot and cold weather, heavy snowfall, heavy rainfall, and wildfires may restrict the Corporation's ability to access our properties and cause operational difficulties, including damage to equipment and infrastructure. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions. Certain of the Corporation's assets are in locations that are proximate to forests and rivers and a wildfire or flood may lead to significant downtime and/or damage to the Corporation's assets or cause disruptions to the production and transport of our products or the delivery of goods and services in our supply chain.

In March 2020, the World Health Organization declared COVID-19 a global pandemic, prompting many countries around the world to close international borders and order the closure of institutions and businesses deemed non-essential. This resulted in a swift and significant reduction in economic activity in Canada and internationally along with a sudden drop in demand for oil, NGLs and natural gas. Since 2020, oil prices have recovered from their historic lows, but price support from future demand cannot be assured as certain countries continue to experience varying degrees of virus outbreak and newly emerging virus variants. Low commodity prices resulting from reduced demand associated with the impact of COVID-19 has had, and may continue to have, a negative impact on the Corporation's operational results and financial condition. Low prices for oil, NGLs and natural gas would reduce the Corporation's funds from operations, and impact the Corporation's level of capital investment and may result in the reduction of production at certain producing properties.

The extent to which the Corporation's operational and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control such as the duration and scope of the pandemic, additional actions taken by business and government in response to any resurgence of the pandemic, and the speed and effectiveness of responses to combat any resurgence of the virus. Additionally, COVID-19 and its effect on local and global economic conditions stemming from the pandemic could also aggravate the other risk factors identified herein, the extent of which is not yet known.

We may not be able to repay all or part of our indebtedness, or alternatively, refinance all or part of our indebtedness on commercially reasonable terms. We may not be able to comply with the covenants (and in particular the financial covenants) contained in our debt instruments. The occurrence of any one of these events could have a material adverse effect on our results of operations and financial condition, which in turn could negatively affect the market price of our Common Shares.

We currently have a reserve-based syndicated credit facility in place that provides us with a $175.0 million revolving credit facility. The credit facility is subject to a semi-annual borrowing base redetermination typically in May and November of each year and currently has a revolving period to July 27, 2023 and a term out date of July 27, 2024. We have granted a floating charge security over all of our properties in favour of the lenders within our banking syndicate. As of December 31, 2022, there was $105.0 million drawn on our credit facility. In the event that our credit facility is not extended before the term out /maturity date, all outstanding indebtedness under the credit facility will be repayable at that date. There is a risk that our credit facility will not be renewed for the same principal amount or on the same terms. Any of these events could adversely affect our ability to fund our ongoing operations.

The amount authorized under the Corporation's credit facility is dependent on the borrowing base determined by our lenders. The Corporation's lenders use the Corporation's reserves, commodity prices, applicable discount rate and other factors to periodically determine the Corporation's borrowing base. Commodity prices continue to be volatile as a result of various factors, including decreased demand for commodities due to any resurgence of the COVID-19 pandemic, the advent of a recession in North America or globally, limited egress options for Western Canadian oil and natural gas producers, actions taken to limit OPEC and non-OPEC production, limited storage capacity, the impact of the ongoing war between Ukraine and Russia and related sanctions on Russia, and increased production by U.S. shale producers. A decline in commodity prices could reduce the Corporation's borrowing base, reducing the funds available to the Corporation under the credit facility. This could result in the requirement to repay a portion, or all, of the Corporation's indebtedness.

We also currently have $127.6 million principal amount of Senior Unsecured Notes outstanding, which are due on July 27, 2027. Under certain circumstances, we are required to offer to repurchase up to $63.8 million principal amount of the Senior Unsecured Notes (a "Repurchase Offer") – as of December 31, 2022, we had not repurchased any of the Senior Unsecured Notes. In the event that we are unable to repurchase, repay or refinance our Senior Unsecured Notes (or if we must refinance these debt obligations on less favourable terms) it may adversely affect our ability to fund our ongoing operations. Our Senior Unsecured Notes are rated by credit agencies and a downgrade of our rating may impact their value and/or ability to refinance them at an attractive rate or at all.

We are required to comply with covenants under our credit facilities and Senior Unsecured Notes which may either affect the availability, or price, of additional funding. In the event that we do not comply with covenants under one or more of these debt instruments, our access to capital could be restricted or repayment could be required, which could adversely affect our ability to fund our ongoing operations. Events beyond the Corporation's control may contribute to the failure of the Corporation to comply with such covenants. A failure to comply with covenants could result in default under the Corporation's credit facility and/or Senior Unsecured Notes, which could result in the Corporation being required to repay amounts owing thereunder. The acceleration of our indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross acceleration provisions.

In addition, the Corporation's credit facility and Senior Unsecured Notes may impose operating and financial restrictions on the Corporation that could include restrictions on the payment of dividends, the repurchase or making of other distributions with respect to the Corporation's securities, the incurring of additional indebtedness, the provision of guarantees, the assumption of loans, the making of capital expenditures, the entering into of amalgamations, mergers, take-over bids or acquisition or disposition of assets, among others.

If the Corporation's lenders and/or noteholders require repayment of all or a portion of the amounts outstanding under our credit facilities and/or Senior Unsecured Notes for any reason, including for a default of a covenant, the reduction of a borrowing base or the acceptance of a Repurchase Offer, there is no certainty that the Corporation would be in a position to make such repayment. Even if the Corporation is able to obtain new financing in order to make any required repayment under our credit facilities and/or Senior Unsecured Notes, it may not be on commercially reasonable terms or terms that are acceptable to the Corporation. If the Corporation is unable to repay amounts owing under our credit facilities and/or Senior Unsecured Notes, the lenders under such credit facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the credit facilities and the noteholders could seek to enforce the remedies available to them.

From time to time, we may enter into transactions to acquire assets or shares of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and gas companies of a similar size. Depending on future exploration and development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither our articles nor our by‑laws limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise, and may adversely affect the market price of our Common Shares if investors consider our debt levels to be higher than that of our peers.

Our risk management program subjects us to certain risks, including financial loss and counterparty risk.

From time to time, we may enter into physical or financial agreements to receive fixed prices on our oil and natural gas production, which is intended to mitigate the effect of commodity price volatility and support our capital budgeting and expenditure and return of capital to shareholder plans. However, to the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our risk management arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

On the other hand, failure to protect against a decline in commodity prices exposes us to reduced liquidity when prices decline. A sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which we would enter into derivative contracts on future volumes. This could make such transactions unattractive, and, as a result, some or all of our production volumes forecasted for the current fiscal year and beyond may not be protected by derivative arrangements.

Similarly, from time to time, we may enter into agreements to fix the exchange rate of Canadian to United States dollars or other currencies in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to other currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, we will not benefit from the fluctuating exchange rate.

We may not be able to achieve the anticipated benefits of acquisitions or dispositions and the integration of acquisitions may result in the loss of key employees and the disruption of on-going business relationships.

We make acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with ours. The integration of acquired businesses and assets may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters, and may also result in the loss of key employees, the disruption of on-going business, supplier, customer and employee relationships and deficiencies in internal controls or information technology controls. We continually assess the value and mix of our assets in light of our business plans and strategic objectives. In this regard, non-core assets are periodically disposed of so that we can focus our efforts and resources more efficiently. Depending on the market conditions for such non-core assets, certain of our non-core assets may realize less on disposition than their carrying value in our financial statements.

The price of oil and natural gas is affected by political events throughout the world. Any such event could result in a material decline in commodity prices and in turn result in a reduction in the market price of our Common Shares.

Political changes in North America and political instability in the Middle East and elsewhere may cause disruptions in the supply of oil and natural gas that affects the marketability and price of oil and natural gas acquired, produced or discovered by us. Conflicts, or conversely peaceful developments, arising outside of Canada (such as in Ukraine), including changes in political regimes or the parties in power, may have a significant impact on the price of oil and natural gas. Any particular event could result in a material decline in commodity prices and therefore result in a reduction of our revenues and consequently impact our operations and the market price of our Common Shares.

The Corporation’s business may be adversely affected by recent and future political and social events and decisions made in Canada, the United States, Europe and elsewhere.

The Corporation's results can be adversely impacted by political, legal or regulatory developments in Canada and elsewhere that affect local operations and local and international markets. Changes in government, government policy or regulations, changes in law or interpretation of settled law, third-party opposition to industrial activity generally or projects specifically, and duration of regulatory reviews could impact the Corporation's existing operations and planned projects. This includes actions by regulators or other political actors to delay or deny necessary licenses and permits for the Corporation's activities or restrict the operation of third-party infrastructure that the Corporation relies on. Additionally, changes in environmental regulations, assessment processes or other laws, and increasing and expanding stakeholder consultation (including Indigenous stakeholders), may increase the cost of compliance or reduce or delay available business opportunities and adversely impact the Corporation's results.

Other government and political factors that could adversely affect our financial results include increases in taxes or government royalty rates (including retroactive claims) and changes in trade policies and agreements. Further, the adoption of regulations mandating efficiency standards and mandating the sale of electric vehicles, and the use of alternative fuels or uncompetitive fuel components, could affect the demand for our products. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels, technologies or electric vehicles. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for our products.

A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and natural gas industry including the balance between economic development and environmental policy. The oil and natural gas industry has become an increasingly politically polarizing topic in Canada, which has resulted in a rise in civil disobedience surrounding oil and natural gas development, particularly with respect to infrastructure projects. Protests, blockades, demonstrations and vandalism have the potential to delay and disrupt the Corporation's activities. See "Industry Conditions – Regulatory Authorities and Environmental Regulation" and "Industry Conditions – Transportation Constraints and Market Access".

The success of our operations may be negatively impacted by factors outside of our control resulting in operational delays and cost overruns.

We manage a variety of small and large projects in the conduct of our business. Project interruptions may delay expected revenues from operations. Significant project cost over‑runs could make a project uneconomic. Our ability to execute projects and market oil and natural gas depends upon numerous factors beyond our control, including:

 the availability and proximity of transportation infrastructure, including pipeline capacity;

 the availability of, and the ability to acquire, water supplies needed for drilling, hydraulic fracturing and waterfloods, or our ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations;

 the effects of inclement and severe weather events, including fire, drought, flooding and extreme cold temperatures;

 the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

If our funds flow from operations and funds from external financing sources are not sufficient to cover our capital expenditure requirements, we may be required to reallocate available capital among our projects or modify our capital expenditure plans, which may result in delays to, or cancellation of, certain projects or deferral of certain capital expenditures. Any change to our capital expenditure plans could, in turn, have a material adverse effect on our growth objectives and our business, financial

position, and results of operations. Because of these factors, we could be unable to execute projects on time, on budget, or at all.

Changes to the demand for oil and natural gas products and the rise of petroleum alternatives may negatively affect the Corporation's financial condition, results of operations and cash flow.

Fuel conservation measures, alternative fuel requirements, electric vehicle mandates, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy generation systems could reduce the demand for oil, natural gas and other hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives (including electric vehicles), which may lessen the demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and natural gas products. The Corporation cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Corporation's business, financial condition, results of operations and cash flows by decreasing the Corporation's profitability, increasing our costs, limiting our access to capital and decreasing the value of our assets.

Implementation of new regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production volumes, which could adversely affect the Corporation's financial position. The Corporation's operations are dependent on the availability of water and our ability to dispose of produced water from drilling and production activities.

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under high pressure into tight rock formations that were previously unproductive to stimulate the production of oil, NGLs and natural gas. Concerns about seismic activity, including earthquakes, caused by hydraulic fracturing has resulted in regulatory authorities implementing additional protocols for areas that are prone to seismic activity or completely banning hydraulic fracturing in other areas. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third-party or governmental claims, and could increase the Corporation's costs of compliance and doing business, as well as delay the development of oil, liquids and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions or bans on hydraulic fracturing in the areas where we operate could reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves and resources and/or could result in us being unable to economically recover certain of our oil and natural gas reserves and resources, which in either case could result in a significant decrease in the value of our assets.

Water is an essential component of the Corporation's drilling and hydraulic fracturing processes. Limitations or restrictions on the Corporation's ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought), could materially and adversely impact our operations. Severe drought conditions can result in local water authorities taking steps to restrict the use of water in their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If the Corporation is unable to obtain water to use in our operations from local sources, it may need to be obtained from new sources and transported to drilling sites, resulting in increased costs, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

In addition, the Corporation must dispose of the fluids produced from oil, NGLs and natural gas production operations, including produced water, which we do directly or through the use of third-party vendors. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. Government authorities may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events.

Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated laws and regulations regarding waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by the Corporation or by commercial disposal well vendors that the Corporation may use from time to time to dispose of produced water. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal. Any one or more of these developments may result in the Corporation or our vendors having to limit disposal well volumes, disposal rates and pressures or locations, or require the Corporation or our vendors to shut down or curtail the injection of produced water into disposal wells, which events could have a material adverse effect on the Corporation's business, financial condition, and results of operations.

Minor earthquakes are common in certain parts of Alberta. Since 2015, the AER has introduced seismic protocols for hydraulic fracturing operators in the Seismic Protocol Regions initially in response to significant induced seismic activity in the Duvernay formation in Fox Creek. The AER may extend seismic protocols to other areas of the province if necessary, which may adversely affect our operations. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – General – Alberta".

Regulatory water use restrictions and/or limited access to water or other fluids may impact the Corporation's production volumes from our waterflood programs.

The Corporation undertakes or intends to undertake certain waterflooding programs which involve the injection of water or other liquids into an oil reservoir to increase production from the reservoir and to decrease production declines. To undertake such waterflooding activities, the Corporation needs to have access to sufficient volumes of water, or other liquids, to pump into the reservoir to increase the pressure in the reservoir. There is no certainty that the Corporation will have access to the required volumes of water. In addition, in certain areas there may be restrictions on water use for activities such as waterflooding. If the Corporation is unable to access such water we may not be able to undertake waterflooding activities, which may reduce the amount of oil and natural gas that the Corporation is ultimately able to produce from our reservoirs. In addition, the Corporation may undertake certain waterflood programs that ultimately prove unsuccessful in increasing production from the reservoir and as a result have a negative impact on the Corporation's results of operations.

Fluctuations in foreign currency exchange rates and interest rates could adversely affect our business, and adversely affect the market price of our Common Shares.

World oil and natural gas prices are predominately denominated in United States dollars and the Canadian dollar price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate, which fluctuates over time. Material increases in the value of the Canadian dollar relative to the United States dollar will negatively affect, among other things, our oil production revenues in Canadian dollars. We generally fund our cash costs in Canadian dollars. Strengthening of the Canadian dollar (excluding risk management activities) against the United States dollar negatively affects the amount of Canadian dollar funds available to us for reinvestment, and negatively affects the future value of our reserves as calculated by independent evaluators. Although a low value of the Canadian dollar relative to the United States dollar may positively affect the price we receive for our oil and natural gas production, it could also result in an increase in the price for certain goods used for our operations, which may have a negative impact on our financial results.

To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which the Corporation may contract.

An increase in interest rates could result in a significant increase in the amount we pay to service debt, resulting in a reduced amount available to fund our exploration and development activities and, if applicable, the cash available for dividends and/or Common Share repurchases, all of which could negatively impact the market price of the Common Shares.

Actual reserves and resources will vary from reserves and resources estimates and those variations could be material and negatively affect the market price of our Common Shares.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and resources and future net revenues to be derived therefrom, including many factors beyond our control. The reserves and associated net revenue information set forth herein represents estimates only. In general, estimates of economically recoverable oil and natural gas reserves and resources (including the breakdown of reserves and resources by product type) and the future net revenue therefrom are based upon a number of variable factors and assumptions, such as:

As a result, estimates of the economically recoverable oil, NGL and natural gas reserves or estimates of resources attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues, taxes and development and operating expenditures will vary from reserve and resource estimates thereof and such variations could be material.

Estimates of proved and probable reserves that may be developed and produced in the future are sometimes based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are often estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, GLJ have used forecast price and cost estimates in calculating the reserve quantities and future net revenue disclosed herein. Actual future net revenue will be affected by other factors including but not limited to actual production levels, supply and demand for oil, NGLs and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and net revenue derived from the Corporation's reserves will vary from the reserve estimates contained in the Engineering Report summarized herein, and such variations could be material. The Engineering Report summarized herein is based in part on the assumption that certain activities will be undertaken by us in future years and the further assumption that such activities will be successful. The reserves and estimated net revenue to be derived therefrom contained in the Engineering Report summarized herein will be reduced in future years to the extent that such activities are not undertaken or, if undertaken, do not achieve the level of success assumed in the Engineering Report summarized herein. The Engineering Report described herein is effective as of a specific date and, except as otherwise noted, has not been updated and thus does not reflect changes in our reserves since that date.

A decrease in the fair market value of our risk management financial instruments could result in a non-cash charge against our income under applicable accounting standards.

Under IFRS, accounting for financial instruments may result in non-cash charges against income as a result of reductions in the fair market value of such instruments. A decrease in the fair market value of the financial instruments as a result of fluctuations in commodity prices and/or foreign exchange rates may result in a non-cash charge against income, which may be viewed unfavourably in the market.

The incorrect assessment of value at the time of acquisitions could adversely affect the value of our Common Shares.

Acquisitions of oil and natural gas properties or companies will be based in large part on engineering and economic assessments. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geological and engineering uncertainty that could result in lower production and reserves than anticipated. If actual reserves or production are less than we expect, our revenues and consequently the value of our Common Shares could be negatively affected.

Lack of capacity and/or regulatory constraints on gathering and processing facilities, pipeline systems, trucking and railway lines may have a negative impact on our ability to produce and sell our oil and natural gas.

We deliver our products through gathering and processing facilities, pipeline systems and, in certain circumstances, by truck and railway systems. The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities, pipeline systems, trucks and railway lines. The lack of firm pipeline capacity, production limits and limits on availability of capacity in gathering and processing facilities, pipeline systems or railway lines continues to affect the oil and natural gas industry and limits the ability to transport produced oil and natural gas to market. In addition, the pro-rationing of capacity on inter-provincial pipeline systems from time to time affects the ability of oil and natural gas companies to export oil and natural gas, and could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Unexpected shut downs or curtailment of capacity of pipelines for maintenance or integrity work or because of actions taken by regulators could also affect the Corporation's production, operations and financial results. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities (or uncertainty regarding whether such construction will proceed), could harm our business and, in turn, our financial condition, results of operations and cash flows.

Federal and various provincial governments have been active in recent years in their support for and opposition to major infrastructure projects in Canada leading to increased awareness of and challenges to interprovincial and international infrastructure projects. In 2019, with the passing of Bill C-69, the Canadian Energy Regulator Act and the Impact Assessment Act came into force and the National Energy Board Act and the Canadian Environmental Assessment Act, 2012 were repealed. In addition, the Impact Assessment Agency of Canada replaced the Canadian Environmental Assessment Agency. The impact of the new federal regulatory scheme on proponents, and the timing for receipt of approvals, of major projects is unclear.

A portion of our production may, from time to time, be processed through facilities owned by third parties that we do not control. From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could materially adversely affect our ability to process our production and to deliver the same to market. Midstream and pipeline companies may take actions to maximize their return on investment, which may in turn adversely affect producers and shippers, especially when combined with a regulatory framework that may not always align with the interests of particular shippers.

We may be unable to successfully compete with other companies in our industry, which could negatively affect the market price of our Common Shares.

There is strong competition relating to all aspects of the oil and natural gas industry. We compete with numerous other companies, many of whom have substantially greater financial and operational resources, staff and facilities than those of the Corporation in connection with our oil and natural gas exploration, development, production and marketing activities. Among other things, we compete for:

 the acquisition of properties with longer life reserves and exploitation and development opportunities; and

 access to equipment, markets, transportation capacity, drilling and service rigs and storage and processing facilities.

Some of the companies with whom we compete not only explore for, develop and produce oil and natural gas, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than the Corporation.

Our ability to make future capital expenditures may depend on our ability to access third party financing.

The Corporation anticipates making substantial capital expenditures for the exploration, development, acquisition and production of oil and natural gas reserves in the future. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, the Corporation's ability to do so is dependent on, among other factors:

Further, if the Corporation's revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future drilling programs. The conditions in, or affecting, the oil and natural gas industry have negatively impacted the ability of oil and natural gas companies, including the Corporation, to access additional financing and/or the cost thereof. There can be no assurance that debt or equity financing, or cash generated by operations, will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. The Corporation may be required to seek additional equity financing on terms that are highly dilutive to existing Shareholders. The inability of the Corporation to access sufficient capital for our operations could have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

There can be no assurance that the federal government and the provincial governments of the western provinces will not adopt a new, or modify the existing, royalty regimes in one or more of such provinces, which in each case may have an impact on the economics of our projects or the profitability of our operations. An increase in royalties would reduce our earnings and could make future capital investments, or our operations, less economic. See "Industry Conditions".

Opposition by Indigenous groups to the conduct of our operations, development or exploratory activities in any of the jurisdictions in which the Corporation conducts business may negatively impact it in terms of public perception, diversion of management's time and resources, legal and other advisory expenses, and could adversely impact the Corporation's progress and ability to explore and develop properties.

Some Indigenous groups have established or asserted Indigenous treaty, title and rights to portions of Canada. Although there are no Indigenous and treaty rights claims on lands where the Corporation operates, no certainty exists that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims. Such claims, if successful, could have a material adverse impact on our operations or pace of growth.

The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of litigation. The fulfillment of the duty to consult Indigenous people and any associated accommodations may adversely affect the Corporation's ability to, or increase the timeline to, obtain or renew, permits, leases, licences and other approvals, or to meet the terms and conditions of those approvals. For example, regulatory authorities in British Columbia ceased granting approvals, and, in some cases, revoked existing approvals, for, among other things crude oil and natural gas activities relating to drilling, completions, testing, production, and transportation infrastructure following a June 2021 British Columbia Supreme Court decision that the cumulative impacts of government-sanctioned industrial development on the traditional territories of a First Nations group in northeast British Columbia breached that group's treaty rights. While a settlement between the British Columbia government and the First Nations group has recently been announced and the regulatory authorities have resumed granting certain approvals for crude oil and natural gas activities, the long-term impacts of, and associated risks with, the decision on the Canadian oil and natural gas industry and the Corporation remain uncertain.

In addition, Canada is a signatory to the UNDRIP and the principles set forth therein may continue to influence the role of Indigenous engagement in the development of the oil and natural gas industry in Western Canada. In November 2019, the DRIPA became law in British Columbia. The DRIPA aims to align British Columbia's laws with UNDRIP. In June 2021, the UNDRIP Act came into force in Canada. Similar to British Columbia's DRIPA, the UNDRIP Act requires the Government of Canada to take all measures necessary to ensure the laws of Canada are consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP's objectives. Continued development of common law precedent regarding existing laws relating to Indigenous consultation and accommodation as well as the adoption of new laws such as the DRIPA and the UNDRIP Act are expected to continue to add uncertainty to the ability of entities operating in the Canadian oil and natural gas industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines. See "Industry Conditions – Indigenous Rights".

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. Other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to implement and benefit from technological advantages now and in the future. There can be no assurance that we will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If the Corporation does implement such technologies, there is no assurance that the Corporation will do so successfully. One or more of the technologies currently utilized by us or implemented in the future may become obsolete. If we are unable to utilize the most advanced commercially available technology, or we are unsuccessful in implementing certain technologies, our business, financial condition and results of operations could be materially adversely affected.

Seasonal factors and extreme weather conditions may lead to declines in our activities and thereby adversely affect our business and the market price of our Common Shares.

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable, which prevents, delays or makes operations more difficult. Consequently, municipalities and provincial transportation departments may enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Road bans and other restrictions generally result in a reduction of drilling and exploratory activities and may also result in the shut-in of some of the Corporation's production if not otherwise tied-in. Also, certain of our oil and natural gas producing areas may be located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of impassable muskeg (swampy terrain). In addition, extreme cold weather, heavy snowfall and heavy rainfall may restrict the Corporation's ability to access our properties and cause operational difficulties, including damage to machinery, or contribute to personnel injury because of dangerous working conditions.

Our operations are susceptible to the impacts of wildfires and flooding. In the past, our production levels (and as a result our revenues) have at times been materially and adversely affected by wildfires and flooding. In addition to the loss of revenue that results from the loss of production when our operations are affected by wildfires and/or flooding, we incur expenses responding to such events, repairing damaged equipment, and resuming operations. Although our insurance policies may compensate us for part of our losses, they will not compensate us for all of our losses. In addition, wildfires and/or flooding consume both financial resources and management and employee time that would otherwise be directed towards the development of our business and the pursuit of our business strategy. We can offer no assurance that the severe wildfires and flooding that have at times affected our operations will not occur again in the future with equal or greater severity.

Seasonal factors and unexpected weather patterns, including wildfires, flooding and/or extreme temperatures, may lead to material declines in our exploration, development and production activities and may consume material amounts of our financial and human resources, and thereby materially and adversely affect our results of operations and financial condition.

Our operation of oil and natural gas wells, and our participation in oil and natural gas wells operated by others, could subject us to environmental claims and liability and/or increased compliance costs, all of which could affect the market price of our Common Shares.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for and regulates, among other things, the initiation and approval of new oil and natural gas projects and restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. In addition, such legislation sets out requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. New environmental legislation enacted at the federal and provincial levels of government may increase uncertainty among oil and natural gas industry participants as the new laws are implemented and the effects of the new laws and related regulations are experienced by such participants, which may adversely affect activity levels. See "Industry Conditions".

Compliance with environmental legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and legal liability, and potentially increased capital expenditures and operating

costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. Although we believe that we are in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects. See “Industry Conditions”.

Our properties may be subject to action by non-governmental organizations or terrorist attack.

The oil and natural gas exploration, development and operating activities conducted by the Corporation may, at times, be subject to public opposition. Such public opposition could expose the Corporation to the risk of higher costs, delays or even project cancellations due to increased pressure on governments and regulators by special interest groups including Indigenous groups, landowners, environmental interest groups (including those opposed to oil and natural gas production operations) and other non-governmental organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support from the federal, provincial or municipal governments, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses and direct legal challenges, including the possibility of climate-related litigation. See "Industry Conditions". There is no guarantee that the Corporation will be able to satisfy the concerns of such special interest groups and non-governmental organizations and attempting to address such concerns may require the Corporation to incur significant and unanticipated capital and operating expenditures.

In addition, the Corporation's oil and natural gas properties, wells and facilities could be the subject of vandalism, sabotage, or a terrorist attack. If any of the Corporation's properties, wells or facilities are the subject of vandalism, sabotage, or a terrorist attack it may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

In the normal course of our operations, we may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, relating to personal injuries (including resulting from exposure to hazardous substances), property damage, property taxes, land and access rights, environmental issues (including claims relating to contamination or natural resource damages), securities law matters (such as our public disclosures), contract disputes and employment matters. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and as a result, could have a material adverse effect on our assets, liabilities, business, financial condition and results of operations. Even if we prevail in any such legal proceedings, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from business operations, which could have an adverse affect on our financial condition.

The failure of third parties to meet their contractual obligations to us may have a material adverse effect on our financial condition.

We may be exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production, counterparties to our derivative risk management contracts, and other parties. In addition, we may be exposed to third party credit risk from operators of properties in which we have a working or royalty interest and from purchasers of assets from us for various liabilities, including well abandonment and reclamation obligations assumed by the purchasers. In the event such entities fail to meet their contractual obligations to us, such failures may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, from time to time there may be poor credit conditions in the industry generally and/or of one or more of our joint venture partners in particular, which may affect a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until we find a suitable alternative partner. The use of derivative risk management contracts involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We are unable to predict changes in a counterparty's creditworthiness or ability to perform. Even if we accurately predict such changes, our ability to negate this risk may be limited depending upon market conditions and the contractual terms of the agreements. During periods of declining commodity prices, our derivative receivable positions may increase, which would increase our counterparty credit exposure. To the extent that any of such third parties go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in us

A failure to secure the services and equipment necessary to the Corporation's operations for the expected price, on the expected timeline, or at all, may have an adverse effect on the Corporation's financial performance and cash flows.

The Corporation's operating costs could escalate and become uncompetitive due to supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, and additional government intervention through stimulus spending or additional regulations. The Corporation's inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on our financial performance and cash flows.

The cost or availability of oil and natural gas field equipment may adversely affect the Corporation's ability to undertake exploration, development and construction projects. The oil and natural gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including drilling rigs, geological and geophysical services, engineering and construction services, major equipment items for infrastructure projects and construction materials generally. These materials and services may not be available when required at reasonable prices. A failure to secure the services and equipment necessary to the Corporation's operations for the expected price, on the expected timeline, or at all, may have an adverse effect on the Corporation's financial performance and cash flows.

An inability to recruit and retain a skilled workforce and key personnel may negatively impact the Corporation.

The operations and management of the Corporation require the recruitment and retention of a skilled workforce, including engineers, technical personnel and other professionals. The loss of key members of such workforce, or a substantial portion of the workforce as a whole, whether for a limited period of time arising from an event such as the ongoing COVID-19 pandemic or permanently, could result in the failure to implement the Corporation's business plans which could have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract and retain all personnel necessary for the development and operation of our business. In addition, the decline in market conditions in recent years resulted in a significant number of skilled personnel exiting the oil and natural gas industry and fewer young people entering the industry. The Corporation does not have any key personnel insurance in effect. Contributions of the existing management team to the immediate and near term operations of the Corporation are likely to be of central importance. In addition, certain of the Corporation's current employees are senior and have significant institutional knowledge that must be transferred to other employees prior to their departure from the Corporation. If the Corporation is unable to: (i) retain current employees; (ii) successfully complete effective knowledge transfers; and/or (iii) recruit new employees with the requisite knowledge and experience; the Corporation could be negatively impacted. In addition, the Corporation could experience increased costs to retain and recruit these professionals.

Other companies operate some of the assets in which the Corporation has an interest. The Corporation has limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Corporation's financial performance. The Corporation's return on assets operated by others depends upon a number of factors that may be outside of the Corporation's control, including, but not limited to, the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology, and risk management practices.

In addition, due to the volatility of commodity prices, from time to time some companies, including companies that may operate some of the assets in which the Corporation has an interest, may be in financial difficulty, which could impact their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner, and satisfy regulatory requirements with respect to abandonment and reclamation obligations. If companies that operate some of the assets in which the Corporation has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations, the Corporation may be required to satisfy such obligations and to seek reimbursement from such companies. To the extent that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in such assets being shut-in, the Corporation potentially becoming subject to additional liabilities relating to such assets, and the Corporation having difficulty collecting revenue due from such operators or recovering

amounts owing to the Corporation from such operators for their share of abandonment and reclamation obligations. Any of these factors could have a material adverse affect on the Corporation's financial and operational results.

A portion of the Corporation's revenues from royalty payers and certain of our operations are dependent on the financial and operational capacity of third-party working interest owners to develop and produce from the Corporation's properties, over which we have limited influence.

The Corporation relies on other companies drilling and producing from lands in which the Corporation has a royalty interest. The Corporation has limited ability to exercise influence over the decision of other companies to drill and produce from such lands. The Corporation's return on lands in which we have a royalty interest depends upon a number of factors that may be outside of the Corporation's control, including, but not limited to, the capital expenditure budgets and financial resources of the operators who have a working interest in such lands, the operator's ability to efficiently produce the resources from such lands, and commodity prices.

In addition, due to the volatility of commodity prices, from time to time some companies, including companies that may operate some of the assets in which the Corporation has a royalty interest, may be in financial difficulty, which could affect their ability to fund and pursue capital expenditures on such lands. Furthermore, any reoccurrence of weak commodity prices may result in companies choosing to defer capital spending or shutting-in existing production. Any reduction in drilling and production from lands in which the Corporation has a royalty interest will negatively affect the Corporation's cash flows and financial results.

The financial difficulty of any companies who have assets in which the Corporation has a royalty interest may affect the Corporation's ability to collect royalty payments, particularly if such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency.

A decrease in, or restriction in access to, diluent supply may increase the Corporation's operating costs.

Heavy oil and bitumen are characterized by high specific gravity or weight and high viscosity or resistance to flow. Diluent is required to facilitate the transportation of heavy oil and bitumen. A shortfall in the supply of diluent, or a restriction in access to diluent, may cause its price to increase, increasing the cost to transport heavy oil and bitumen to market. An increase to the cost of bringing heavy oil and bitumen to market may increase the Corporation's overall operating cost and/or transportation cost and result in decreased cash flows, negatively impacting the overall profitability of the Corporation's heavy oil and bitumen projects.

Changes in Canadian income tax legislation and other laws may adversely affect us and our Shareholders.

Income tax laws, or other laws or government incentive programs relating to the oil and natural gas industry, such as the treatment of resource taxation, dividends, share repurchases or capital gains, may in the future be changed or interpreted in a manner that adversely affects us and/or our Shareholders. Furthermore, tax authorities having jurisdiction over us and/or our Shareholders may disagree with how we calculate our income for tax purposes or could change administrative practises to our detriment and/or the detriment of our Shareholders.

We file all required income tax returns and believe that we are in compliance with the provisions of the Tax Act and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of Obsidian Energy, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable.

Unauthorized use of intellectual property may cause us to engage in or be the subject of litigation.

Due to the rapid development of oil and natural gas technology, in the normal course of our operations, we may become involved in, named as a party to, or be the subject of, various legal proceedings in which it is alleged that we have infringed the intellectual property rights of others or which we initiate against others that we believe are infringing upon our intellectual property rights. The Corporation's involvement in intellectual property litigation could result in significant expense, adversely affecting the development of our assets or intellectual property or diverting the efforts of our technical and management personnel, whether or not such litigation is resolved in the Corporation's favour. In the event of an adverse outcome as a

defendant in any such litigation, the Corporation may, among other things, be required to: (a) pay substantial damages and/or cease the development, use, sale or importation of processes that infringe upon other patented intellectual property; (b) expend significant resources to develop or acquire non-infringing intellectual property; (c) discontinue processes incorporating infringing technology; or (d) obtain licences to the infringing intellectual property. However, the Corporation may not be successful in such development or acquisition or such licences may not be available on reasonable terms. Any such development, acquisition or licence could require the expenditure of substantial time and other resources and could have a material adverse effect on the Corporation's business and financial results.

We are exposed to potential liabilities that may not be covered, in part or in whole, by insurance.

Our involvement in the exploration for and development of oil and natural gas properties could subject us to liability for pollution, blowouts, leaks of sour natural gas, property damage, personal injury or other hazards. Although the Corporation maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, certain risks may not, in all circumstances, be insurable or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to us. The occurrence of a significant event that we are not fully insured against, our inability to obtain insurance coverage against one or more risks at acceptable premium rates or at all, or the insolvency of the insurer of such event, could have a material adverse effect on our financial condition, results of operations or prospects.

Our insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, policy limits and/or deductibles for certain insurance policies can vary substantially. In some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Significantly increased costs could lead us to decide to reduce or possibly eliminate coverage. In addition, insurance is purchased from a number of third-party insurers, often in layered insurance arrangements, some of whom may discontinue providing insurance coverage for their own policy or strategic reasons. Should any of these insurers refuse to continue to provide insurance coverage, our overall risk exposure could be increased and we could incur significant costs.

Future acquisitions, financings or other transactions and the issuance of securities pursuant to our treasury-based equity incentive plans may result in Shareholder dilution.

We may make future acquisitions or enter into financings or other transactions involving the issuance of our securities, which may be dilutive to Shareholders. Shareholder dilution may also result from the issuance of Common Shares pursuant to our stock option plan and our restricted and performance share unit plan. For more information regarding these compensation plans, see our most recent Information Circular and Proxy Statement, financial statements and related MD&A filed on SEDAR at www.sedar.com.

We may be subject to growth related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base. Our inability to deal with this growth may have a material adverse effect on our business, financial condition, results of operations and prospects.

Lower oil and gas prices and higher costs increase the risk of write-downs of our oil and gas property assets and goodwill (if any).

Under IFRS, when indicators of impairment exist, the carrying value of our "Property, plant and equipment" ("PP&E") and "Goodwill" (if any) is compared to its recoverable amount. The recoverable amount is defined as the higher of the fair value less cost to sell or value in use. A decline in oil and natural gas prices may be an indicator of impairment and may result in a write-down of the value of our assets. While these write-downs would not affect cash flow from operations, the charge to earnings may be viewed unfavourably by investors and could adversely impact the market price of our Common Shares and the calculation of our compliance with the financial covenants contained in our debt instruments. PP&E asset write-downs may also be reversed to earnings in future periods should the conditions that caused impairment reverse.

We may not be able to maintain the confidentiality of sensitive information in business dealings with third parties, and our remedies for breaches of confidentiality may not fully compensate us for our losses.

While discussing potential business relationships or other transactions with third parties, we may disclose confidential information relating to our business, operations or affairs. Although confidentiality agreements are generally signed by third parties prior to the disclosure of any confidential information, a breach could put us at competitive risk and may cause significant damage to our business. The harm to our business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, we will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to our business that such a breach of confidentiality may cause.

We are dependent upon the availability, capacity, reliability and security of our information technology infrastructure, and our ability to expand and continually update this infrastructure, to conduct daily operations. We depend on various information technology systems to estimate reserve quantities, process and record financial data, manage our land base, manage financial resources, analyze seismic information, administer our contracts with our operators and lessees and communicate with employees, consultants, securityholders and other stakeholders, regulators and other third-parties.

As a result, we are subject to a variety of information technology and/or system risks as a part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of our information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations, or disruption to our business activities or our competitive position. In addition, cyber phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, credit card and banking details (and money), or approval of wire transfer requests, by disguising themselves as a trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years. If the Corporation becomes a victim to a cyber phishing attack it could result in a loss or theft of the Corporation's financial resources or critical data and information or could result in a loss of control of the Corporation's technological infrastructure or financial resources. The Corporation's employees are often the targets of such cyber phishing attacks, as they are and will continue to be targeted by parties using fraudulent "spoof" emails to misappropriate information or to introduce viruses or other malware through "Trojan horse" programs to the Corporation's computers. These emails appear to be legitimate emails, but direct recipients to fake websites operated by the sender of the email or request recipients to send a password or other confidential information through email or to download malware.

The Corporation maintains policies and procedures that address and implement employee protocols with respect to electronic communications and electronic devices and conducts annual cyber-security risk assessments. The Corporation also employs encryption protection of its confidential information, all computers and other electronic devices. Despite the Corporation's efforts to mitigate such cyber phishing attacks through education and training, cyber phishing activities remain a serious problem that may damage our information technology infrastructure. The Corporation applies technical and process controls in line with industry-accepted standards to protect our information assets and systems, including a response plan for responding to a cyber-security incident. However, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on our performance and earnings, as well as on our reputation. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Corporation’s business, financial condition and results of operations.

An unforeseen defect in the chain of title to our oil and natural gas producing properties may arise to defeat our claim, which could have an adverse effect on the market price of our Common Shares.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise. The actual title to and interest of the Corporation in our properties, and our rights to produce and sell the oil and natural gas therefrom, may vary from the Corporation's records. If a defect does exist in the chain of title or in the Corporation's right to

produce, or a legal challenge or legislative change does arise, it is possible that the Corporation may lose all or a portion of the properties to which the title defect relates and/or our right to produce hydrocarbons from such properties, which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. In addition, there may be valid legal challenges or legislative changes which affect the Corporation's title to and right to produce from the oil and natural gas properties the Corporation controls that could impair the Corporation's activities on them and result in a reduction of the revenue received by the Corporation.

Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States.

In this Annual Information Form, we report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51‑101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by United States companies. Nevertheless, as part of Obsidian Energy's Form 40-F for the year ended December 31, 2022 filed with the SEC, Obsidian Energy has disclosed proved reserves quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves determined in accordance with the U.S. Financial Accounting Standards Board, "Disclosures About Oil and Gas Producing Activities", which disclosure complies with the SEC's rules for disclosing oil and natural gas reserves.

The ability of residents of the United States to enforce civil remedies against us and our directors, officers and experts may be limited.

Obsidian Energy is organized under the laws of Alberta, Canada and our principal places of business are in Canada. Most of our directors and officers and the experts named herein are residents of Canada, and all or a substantial portion of our assets and all or a substantial portion of the assets of most of such persons are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon those directors, officers and experts who are not residents of the United States or to enforce against them judgments of United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as to the enforceability in Canada against us or against any of our directors, officers or experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts, of liabilities based solely upon the United States federal securities laws or the securities laws of any state within the United States.

The termination or expiration of licenses and leases through which we or our industry partners hold our interests in petroleum and natural gas substances could adversely affect the market price of our Common Shares.

Our properties are held in the form of licenses and leases and working interests in licenses and leases. If we or the holder of the license or lease fail to meet the specific requirement of a license or lease, the license or lease may terminate or expire. There can be no assurance that all of the obligations required to maintain each license or lease will be met. The termination or expiration of a license or lease or the working interest relating to a license or lease and the associated abandonment and reclamation obligations may have a material adverse effect on our results of operations and business.

The Corporation does not currently pay dividends on our Common Shares. The payment of dividends in the future will be dependent on, among other things, the cash flow, results of operations and financial condition of the Corporation, the need for funds to finance ongoing operations and debt repayments, the Corporation's debt levels and constraints on paying dividends imposed by our lenders and noteholders, and other considerations as the Board considers relevant.

Certain directors and officers of Obsidian Energy are engaged in, and will continue to engage in, other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of Obsidian Energy may become subject to conflicts of interest. The ABCA provides that in the event that a director or officer of the Corporation is a party to a material contract or material transaction or proposed material contract or proposed material transaction with the Corporation,

or is a director or an officer of or has a material interest in any person who is a party to a material contract or material transaction or proposed material contract or proposed material transaction with the Corporation, the director or officer must disclose the nature and extent of his or her interest and, if a director, must refrain from voting on any resolution to approve the contract or transaction unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA and our Code of Business Conduct and Ethics. See "Directors and Executive Officers of Obsidian Energy – Conflicts of Interest".

The Corporation's operations and drilling activity is vulnerable to risks associated with operating in a limited geographic area.

The Corporation's producing properties are geographically concentrated in the Province of Alberta. As a result, to the extent demand for and costs of personnel, equipment, power, services, and resources in Alberta are high, it could result in a delay or inability to secure such personnel, equipment, power, services and resources. Any delay or inability to secure personnel, equipment, power, services, and resources could result in oil, NGLs and natural gas production volumes being below the Corporation's forecasted production volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on the Corporation's financial conditions, results of operations, cash flow and profitability.

The operations and expertise of the Corporation's management are currently focused primarily on oil and natural gas production, exploration and development in the Western Canada Sedimentary Basin. In the future, the Corporation may acquire or move into new industry related activities or new geographical areas and may acquire different energy-related assets; as a result, the Corporation may face unexpected risks or, alternatively, its exposure to one or more existing risk factors may be significantly increased, which may in turn result in the Corporation's future operational and financial conditions being adversely affected.

The Corporation relies on our reputation to continue our operations and to attract and retain investors and employees.

The Corporation's business, operations or financial condition may be negatively impacted as a result of any negative public opinion towards the Corporation or as a result of any negative sentiment toward or in respect of the Corporation's reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups' negative portrayal of the industry in which the Corporation operates as well as their opposition to certain oil and natural gas projects. Potential impacts of negative public opinion or reputational issues may include delays or interruptions in operations, legal or regulatory actions or challenges, blockades, increased regulatory oversight, reduced support for, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses, increased costs and/or cost overruns, and reduced access to (or an increase in the cost of) capital, credit and/or insurance coverage. The Corporation's reputation and public opinion could also be impacted by the actions and activities of other companies operating in the oil and natural gas industry, particularly other producers, over which the Corporation has no control.

Similarly, the Corporation's reputation could be impacted by negative publicity related to loss of life, injury or damage to property and environmental damage caused by the Corporation's operations. In addition, if the Corporation develops a reputation of having an unsafe work site, it may impact the ability of the Corporation to attract and retain the necessary skilled employees and consultants to operate our business. Opposition from special interest groups opposed to oil and natural gas development and the possibility of climate related litigation against governments and fossil fuel companies may impact the Corporation's reputation.

Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and legal risks, among others, must all be managed effectively to safeguard the Corporation's reputation. Damage to the Corporation's reputation could result in negative investor sentiment towards the Corporation, which may result in limiting the Corporation's access to capital, credit and/or insurance coverage, increasing the cost of capital, credit and/or insurance coverage, and decreasing the price and liquidity of the Common Shares.

There might not always be an active trading market in the United States and/or Canada for our Common Shares.

While there is currently an active trading market for our Common Shares in both the United States (on the NYSE American) and Canada (on the TSX), we cannot guarantee that an active trading market will be sustained in either country. If an active trading market in our Common Shares is not sustained, the trading liquidity of our Common Shares will be limited, and the market value of our Common Shares may be reduced.

The Corporation faces compliance and supervisory challenges in respect of the use of social media as a means of communicating with industry partners, stakeholders and the general public.

Increasingly, social media is used as a vehicle to carry out cyber phishing attacks. Information posted on social media sites, for business or personal purposes, may be used by attackers to gain entry into the Corporation's systems and obtain confidential information. The Corporation decrypts and applies malware filtering to all social media platform access of our employees. Periodic evaluations and browsing oversight occurs through firewall report reviews, and the Corporation retains the ability to modify access and control social media access. Despite these efforts, as social media continues to grow in influence and access to social media platforms becomes increasingly prevalent, there are significant risks that the Corporation may not be able to properly regulate social media use and preserve adequate records of business activities and third-party communications conducted through the use of social media platforms.

Shareholders and prospective investors are cautioned not to place undue reliance on the Corporation's forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Additional information on the risks, assumptions and uncertainties are found under the heading "Special Note Regarding Forward-Looking Statements" in this Annual Information Form.

Except for contracts entered into in the ordinary course of business, the only contracts that are material to us and that were entered into by us or one of our Subsidiaries within the most recently completed financial year or before the most recently completed financial year but which are still material and are still in effect, are the following:

We are not currently a party to any contract on which our business is substantially dependent, including any contract to sell the major part of our products or to purchase the major part of our requirements for goods, services or raw materials, or any franchise or license or other agreement to use a patent, formula, trade secret, process or trade name on which our business depends.

Other than as has been disclosed, there are no legal proceedings that Obsidian Energy is or was a party to, or that any of Obsidian Energy's property is or was the subject of, during the most recently completed financial year, that were or are material to Obsidian Energy, and there are no such material legal proceedings that Obsidian Energy knows to be contemplated. For the purposes of the foregoing, a legal proceeding is not considered to be "material" by us if it involves a claim for damages and the amount involved, exclusive of interest and costs, does not exceed 10 percent of our current assets, provided that if any proceeding presents in large degree the same legal and factual issues as other proceedings pending or known to be contemplated, we have included the amount involved in the other proceedings in computing the percentage.

Other than as has been disclosed, there were no: (i) penalties or sanctions imposed against Obsidian Energy by a court relating to securities legislation or by a security regulatory authority during our most recently completed financial year; (ii) any other penalties or sanctions imposed by a court or regulatory body against Obsidian Energy that would likely be considered important to a reasonable investor in making an investment decision; or (iii) settlement agreements Obsidian Energy entered into before a court relating to securities legislation or with a securities regulatory authority during Obsidian Energy's most recently completed financial year.

The transfer agent and registrar for the Common Shares in Canada is TSX Trust Company at its principal offices in Calgary, Alberta and Toronto, Ontario. The co-transfer agent and registrar for the Common Shares in the United States is Computershare Shareowner Services at its principal offices in Jersey City, New Jersey.

There were no material interests, direct or indirect, of any director or executive officer of Obsidian Energy, any person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10 percent of the outstanding Common Shares, or any known associate or affiliate of any such person, in any transaction within Obsidian Energy's three most recently completed financial years or during our current financial year that has materially affected or is reasonably expected to materially affect Obsidian Energy.

There is no person or company whose profession or business gives authority to a report, valuation, statement or opinion made by such person or company and who is named as having prepared or certified a report, valuation, statement or opinion described or included in a filing, or referred to in a filing, made under National Instrument 51-102 Continuous Disclosure Obligations by us during, or related to, our most recently completed financial year, other than GLJ, our independent engineering evaluator (the "Expert"), and KPMG, our auditors.

There were no registered or beneficial interests, direct or indirect, in any securities or other property of Obsidian Energy or of one of our associates or affiliates: (i) held by the Expert or by the "designated professionals" (as defined in Form 51‑102F2 – Annual Information Form) of the Expert, when the Expert prepared the relevant report, valuation, statement or opinion; (ii) received by the Expert or by the "designated professionals" of the Expert, after the preparation of the relevant report, valuation, statement or opinion; or (iii) to be received by the Expert or by the "designated professionals" of the Expert; except with respect to the ownership of our Common Shares, in which case the person's or company's interest in our Common Shares represents less than one percent of our outstanding Common Shares. The foregoing does not include registered or beneficial interests, direct or indirect, held through mutual funds.

KPMG are the auditors of the Company and have confirmed that they are independent with respect to the Company within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and also that they are independent accountants with respect to the Company under all relevant U.S. professional and regulatory standards.

No director, officer or employee of the Expert or KPMG is or is expected to be elected, appointed or employed as a director, officer or employee of Obsidian Energy or of any associate or affiliate of Obsidian Energy.

Additional information relating to Obsidian Energy may be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Obsidian Energy's securities and securities authorized for issuance under equity compensation plans, is contained in Obsidian Energy's Information Circular for our most recent annual meeting of securityholders that involved the election of directors. Additional financial information is provided in Obsidian Energy's financial statements and MD&A for our most recently completed financial year.

Any document referred to in this Annual Information Form and described as being filed on SEDAR at www.sedar.com and on EDGAR at www.sec.gov (including those documents referred to as being incorporated by reference in this Annual Information Form) may be obtained free of charge from us by contacting our Investor Relations Department by telephone (toll free: 1-888-770-2633) or by email (investor_relations@obsidianenergy.com).

Management of Obsidian Energy Ltd. ("Obsidian Energy") is responsible for the preparation and disclosure of information with respect to Obsidian Energy's oil and natural gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2022, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated Obsidian Energy's reserves data. The report of the independent qualified reserves evaluator is presented below.

The Operations and Reserves Committee of the Board of Directors of Obsidian Energy has:

The Operations and Reserves Committee of the Board of Directors has reviewed Obsidian Energy's procedures for assembling and reporting other information associated with oil and natural gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Operations and Reserves Committee, approved:

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

The following table sets forth the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of Obsidian Energy evaluated by us for the year ended December 31, 2022, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to Obsidian Energy's management and Board of Directors:

Our statement of reserves data and other oil and natural gas information dated January 20, 2023 is set forth below (the "Statement"). The effective date of the Statement is December 31, 2022 and the preparation date of the Statement is January 20, 2023. The Report of Management and Directors on Reserves Data and Other Information on Form 51-101F3 and the Report on Reserves Data by GLJ on Form 51-101F2 are attached as Appendices A-1 and A-2, respectively, to this Annual Information Form.

The reserves data set forth below is based upon an evaluation prepared by GLJ with an effective date of December 31, 2022 contained in the Engineering Report. The reserves data summarizes our oil, natural gas liquids and natural gas reserves and the net present values of future net revenue from these reserves using forecast prices and costs, not including the impact of any hedging activities. The reserves data conforms to the requirements of NI 51‑101. We engaged GLJ to evaluate all of our proved and proved plus probable reserves. See also "Notes to Reserves Data Tables" below.

As at December 31, 2022, the majority of our proved plus probable reserves are located in Alberta, Canada.

It should not be assumed that the estimates of future net revenues presented in the tables below 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 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 oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.

BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl 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 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.

SUMMARY OF OIL AND GAS RESERVES
AS OF DECEMBER 31, 2022
FORECAST PRICES AND COSTS

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2022
BEFORE INCOME TAXES DISCOUNTED AT (%/year)

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2022
AFTER INCOME TAXES DISCOUNTED AT (%/year)

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF DECEMBER 31, 2022
FORECAST PRICES AND COSTS

FUTURE NET REVENUE
BY PRODUCTION TYPE
AS OF DECEMBER 31, 2022
FORECAST PRICES AND COSTS

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:

Reserves are classified according to the degree of certainty associated with the estimates.

Other criteria that must also be met for the classification of reserves are provided in the COGE Handbook.

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

The qualitative certainty levels referred to in the definitions above are applicable to "individual reserves entities", which refers to the lowest level at which reserves calculations are performed, and to "reported reserves", which refers to the highest level sum of individual entity estimates for which reserves estimates are presented. Reported reserves should target the following levels of certainty under a specific set of economic conditions:

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative

measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

NI 51-101 defines "forecast prices and costs" as future prices and costs that are: (i) generally acceptable as being a reasonable outlook of the future; and (ii) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which we are legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in subparagraph (i).

The forecast cost and price assumptions include increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. The oil, natural gas and natural gas liquids benchmark reference pricing, inflation rates and exchange rates utilized in the Engineering Report are set forth below. The price assumptions set forth below were based on an average of four independent reserve evaluators’ forecasts (GLJ, Sproule Associates Ltd., McDaniel & Associates Consultants and Deloitte Resource Evaluation & Advisory).

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
AS OF DECEMBER 31, 2022
FORECAST PRICES AND COSTS

Weighted average actual prices realized, including hedging activities, for the year ended December 31, 2022 were $5.57/Mcf for natural gas, $115.91/bbl for light and medium oil, $83.84/bbl for heavy oil and $71.02/bbl for natural gas liquids.

The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserve categories noted below.

We currently expect to fund the development costs of our reserves primarily through internally-generated funds flow from operations. There can be no guarantee that funds will be available to develop all of our reserves or that we will allocate funding to develop all of the reserves attributed in the Engineering Report. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to our reserves. The interest and other costs of any external funding are not included in our reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized. We do not currently expect that interest or other funding costs could make development of any of our properties uneconomic.

The following table sets forth the reconciliation of our gross reserves as at December 31, 2022, using forecast price and cost estimates derived from the Engineering Report.

RECONCILIATION OF
COMPANY GROSS RESERVES
BY PRODUCT TYPE
FORECAST PRICES AND COSTS

Undeveloped reserves are attributed by GLJ in accordance with standards and procedures contained in the COGE Handbook. 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. Undeveloped reserves must fully meet the requirements of the reserves category (proved or probable) to which they are assigned.

In some cases, it will take longer than two years to develop Obsidian Energy's undeveloped reserves. Obsidian Energy plans to develop approximately two-fifths of the proved undeveloped reserves in the Engineering Report over the next two years and all of the proved undeveloped reserves over the next five years. Obsidian Energy plans to develop approximately one-third of the probable undeveloped reserves in the Engineering Report over the next two years and all of the probable undeveloped reserves over the next five years. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing and/or operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals).

The following table discloses, for each product type, the gross volumes of proved undeveloped reserves that were first attributed in each of the most recent three financial years.

GLJ has assigned 50 MMboe of proved undeveloped reserves in the Engineering Report under forecast prices and costs, together with $966 million of associated undiscounted future capital expenditures. Proved undeveloped capital spending in the first two forecast years of the Engineering Report accounts for $367 million, or 38 percent, of the total forecast undiscounted capital expenditures for proved undeveloped reserves. These figures increase to $966 million, or 100 percent, during the first five years of the Engineering Report. The majority of our proved undeveloped reserves evaluated in the Engineering Report are attributable to future oil development from known pools and enhanced oil recovery projects.

The following table discloses, for each product type, the gross volumes of probable undeveloped reserves that were first attributed in each of the most recent three financial years.

GLJ has assigned 31 MMboe of probable undeveloped reserves in the Engineering Report under forecast prices and costs, together with $275 million of associated undiscounted future capital expenditures. Probable undeveloped capital spending in the first two forecast years of the Engineering Report accounts for $87 million, or 32 percent, of the total forecast undiscounted future capital expenditures for probable undeveloped reserves. These figures increase to $274 million, or approximately 100 percent, during the first five years of the Engineering Report. The probable undeveloped reserves evaluated in the Engineering Report are primarily associated with proved undeveloped reserve assignments but have a less likely probability of being recovered than such associated proved undeveloped reserve assignments.

The development schedule for our undeveloped reserves is based on forecast price assumptions for the determination of economic projects. The actual market prices for oil and natural gas may be significantly lower or higher resulting in some projects being delayed or accelerated, as the case may be. See "Risk Factors".

We do not anticipate that any significant economic factors or other significant uncertainties will affect any particular components of our reserves data. However, our reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs, royalty regimes and well performance that are beyond our control.

Abandonment and reclamation costs in respect of surface leases, wells, facilities and pipelines (collectively, "A&R Costs") are primarily comprised of abandonment, decommissioning, remediation and reclamation costs. A&R Costs are estimated using guidance from the Alberta Energy Regulatory for abandonment and reclamation costs for wells and facilities. Pipeline abandonment and reclamation costs have been estimated based on Obsidian Energy experience decommissioning pipelines in recent years. Obsidian Energy A&R costs associated with existing active and future wells, to which reserves have been included within the evaluation, as well as active facilities, and pipelines have been included in the Engineering Report as part of future net revenue calculations. The total proved plus probable uninflated, undiscounted A&R costs included in reserves is $335 million.

Obsidian Energy reviews our suspended or standing well bores for reactivation, recompletion or sale opportunities. Wellbores that do not meet this criterion become part of our overall wellbore abandonment program. A portion of our A&R Costs are retired every year and facilities are generally decommissioned subsequent to the time when all the wells producing to them have been abandoned. All of our liability reduction programs take into account seasonal access, high priority and stakeholder issues, and where possible, opportunities for multi-location programs and continuous operations to reduce costs.

As of December 31, 2022, we expect to incur future A&R Costs in respect of approximately 4,265 net well bores, 558 facilities and 4,559 kilometres of pipelines. On an undiscounted, inflated basis, approximately 73 percent of A&R Costs relate to well bores, 24 percent to facilities and three percent to pipelines. The total amount of A&R Costs we expect to incur, including wells that extend beyond the 50‑year limit in the Engineering Report, are summarized in the following table:

The above table includes certain A&R Costs not included in the Engineering Report and not deducted in estimating future net revenue as disclosed above. Escalated at two percent and undiscounted, the A&R Costs deducted were $745 million, and escalated at two percent and discounted at 10 percent, these A&R Costs were $28 million. On an undiscounted, uninflated basis total A&R costs are $272 million, net of estimated salvage values.

The net present value of future net revenue attributable to reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures and well abandonment costs for only those wells assigned reserves by GLJ.

Description of Our Properties, Operations and Activities in Our Major Operating Regions

Obsidian Energy participates in the exploration for, and the development and production of, oil and natural gas principally in western Canada. Our portfolio of properties as at December 31, 2022, includes both unitized and non-unitized light oil, heavy oil and natural gas production. In general, the properties contain long-life, low-decline-rate reserves and include interests in several major oil and gas fields. As at December 31, 2022, the majority of our proved plus probable reserves are located in Alberta, Canada.

Our production and reserves are attributed to approximately 57 producing properties. The Company’s Willesden Green property accounts for 36 percent of our total proved plus probable Company Interest reserves; no other property is above 15 percent. Obsidian Energy’s capital investments are currently focused on light-oil development in the Cardium and Viking and heavy-oil development in Peace River.

The following map illustrates Obsidian Energy’s major operating regions as at December 31, 2022.

The following is a description of our principal oil and natural gas properties and related operations and activities as at December 31, 2022. Information in respect of gross and net acres and well counts are as of December 31, 2022 and information in respect of production is for the year ended December 31, 2022, except where indicated otherwise. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

The Cardium development play is located in West Central Alberta and extends over 300 kilometers from Calgary to Grande Prairie, Alberta. Obsidian Energy is the largest land owner in the Cardium play, holding approximately 455 net sections of developed and undeveloped land with Cardium rights. The Company’s holdings in the area include significant interests within the core of the play, particularly in the Willesden Green and Pembina areas. Total 2022 capital expenditures were approximately $199.6 million, excluding decommissioning expenditures, resulting in 34 (32.5 net) operated wells drilled and completed, optimization activities and minor infrastructure spend. In 2023, Cardium activity will continue in the Willesden Green and Pembina areas of the play and focus on primary development with 19 operated wells planned. Refer to the 2023 Capital Budget section below for further details.

The Peace River development area is a heavy oil play located in Northwestern Alberta. At December 31, 2022, Obsidian Energy had approximately 500 net sections of developed and undeveloped land in the area. In 2022, the Company completed a development activity in the area with 17 operated Bluesky wells drilled and two operated wells in the Clearwater which resulted in approximately $90.7 million of capital expenditures. In 2023, the Company is further expanding activity in the area with 16 operated wells planned, including four wells in the emerging Clearwater play.

The Viking development area is located in Eastern Alberta along the Alberta/Saskatchewan border. At December 31, 2022, Obsidian Energy had approximately 144 net sections of developed and undeveloped land in the play. Total 2022 capital expenditures were approximately $17.0 million resulting in 8 (8 net) operated wells drilled and completed. For 2023, the Company will build on our strong 2022 results in the area and anticipates drilling 11 operated wells.

In 2023, Obsidian Energy plans to continue to leverage our existing infrastructure and land base and focus on optimization of existing well bores and facilities within the Company’s portfolio. Allocated capital to these activities in 2023 are across several individual projects to either increase production by reactivating and/or recompleting existing well bores or reduce operating costs through facilities optimization projects.

None of our important properties, plants, facilities or installations are subject to any material statutory or other mandatory relinquishments, surrenders, back-ins or changes in ownership.

We do not have any important properties to which reserves have been attributed and which are capable of producing but which are not producing.

The Board has approved a $260 to $270 million 2023 capital plan to fund the continued drilling in the Cardium, Peace River and Viking as well as various optimization activities and other operational spending. A total of 46 gross wells are planned under this program and the Company anticipates average production of 32,000 to 33,500 boe/d for 2022. Additionally, the Company continues to focus on various abandonment activities and plans to spend approximately $26 to $28 million of decommissioning expenditures in 2023.

The primary components of our programs are described above under the heading “Major Operating Regions”. See also “Description of our Business – General Development of the Business –2023 Developments – 2023 Outlook and Guidance”.

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2022.

The following table sets out the unproved properties in which we had an interest as at December 31, 2022.

We currently have no material work commitments on these lands. The primary lease or extension term on approximately 8,000 net acres of unproved property is scheduled to expire by December 31, 2023. The right to explore, develop and exploit these leases will be surrendered unless we qualify them for continuation based on production, drilling or technical mapping.

The development of properties with no attributed reserves can be affected by a number of factors including, but not limited to, project economics, forecasted price assumptions, cost estimates, well type expectations and access to infrastructure. These and other factors could lead to the delay or the acceleration of projects related to these properties.

The most important variables that will determine the level of cash taxes incurred by us in a given year will be the price of oil and natural gas, our capital spending levels, the nature and extent of acquisition and disposition activities and the amount of tax pools available to us. We currently estimate that we will not be required to pay income taxes for at least 10 years. However, if oil and natural gas prices were to strengthen beyond the levels anticipated by the current forward market, our tax pools would be utilized more quickly and we may experience higher than expected cash taxes or payment of such taxes in an earlier time period. However, we emphasize that it is difficult to give guidance on future taxability as we operate within an industry where various factors constantly change our outlook, including factors such as acquisitions, divestments, capital spending levels, operating cost levels and commodity price changes.

The following table summarizes capital expenditures related to our activities for the year ended December 31, 2022, irrespective of whether such costs were capitalized or charged to expense when incurred.

The following table sets forth the gross and net exploratory and development wells that we participated in during the year ended December 31, 2022.

The following table sets out the volume of our production estimated for the year ended December 31, 2022, which is reflected in the estimates of gross proved reserves and gross probable reserves disclosed in the tables contained under “Disclosure of Reserves Data” above.

The Company notes that our Willesden Green property (located in the Cardium development area) accounts for approximately 37% of the estimated Company Interest production on a total proved plus probable basis in 2023. No other field (being a

defined geographical area consisting of one or more pools) accounts for more than 15 percent of the estimated Company Interest production on a total proved plus probable basis disclosed above. For more information, see "Other Oil and Gas Information – Description of Our Properties, Operations and Activities in Our Major Operating Regions".

The following table summarizes certain information in respect of our share of average gross daily production volumes, average net product prices received, royalties paid, production costs, transportation costs, risk management contracts loss (gain), and resulting netbacks for the periods indicated below:

(1)

Production costs or Net operating costs are comprised of direct costs incurred to operate both oil and gas wells and include processing fees and road use recoveries. A number of assumptions are required to allocate these costs between oil, conventional natural gas and natural gas liquids production. Note that the Light and Medium Oil category include costs associated with NGL’s as well as associated natural gas costs which can be a by-product on our Light and Medium oil wells.

During the year ended December 31, 2022, Obsidian Energy produced 11 MMboe, comprised of 4 MMbbl of light and medium oil, 2 MMbbl of heavy oil, 23 Bcf of conventional natural gas and 1 MMbbl of natural gas liquids.

Of our liquids production in 2022, approximately 58% percent was light and medium oil, 30% percent was conventional heavy oil and 12% percent was NGLs. In regard specifically to oil, our average quality was 28 degrees API, which was comprised of an average quality for our light and medium oil of 39 degrees API and an average quality for our conventional heavy oil of 10 degrees API. To reduce risk, we market the majority of our production to large credit-worthy counterparties or end-users on varying term contracts. Where possible we aggregate our oil on pipelines and sell on a stream basis to maximize flexibility and reduce incremental costs. We actively manage our heavy oil sales by finding opportunities to optimize netbacks through ongoing evaluation of both pipeline and rail sales opportunities based on market conditions.

The following table summarizes the net product price received for our production of conventional light and medium oil (including NGLs) and our conventional heavy oil, before adjustments for hedging activities, for the periods indicated:

In 2022, we received an average price from the sale of conventional natural gas, before adjustments for hedging activities, of $5.84 per mcf compared to $3.88 per mcf realized in 2021. We continue to maintain a significant weighting to the Alberta market which is one of the largest and most liquid market hubs in North America.

We continue to conservatively manage our transportation costs. Transportation on all pipelines is closely balanced to supply, and market commitments.

We are exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. In accordance with policies approved by our Board of Directors, the Company may, from time to time, manage these risks through the use of swaps or other financial instruments up to a maximum of 50 percent of forecast sales volumes, net of royalties, for the balance of any current year plus one additional year forward and up to a maximum of 25 percent, net of royalties, for one additional year thereafter. In the prompt three months, the Company can hedge up to a maximum of 80% of production, net of royalties. Risk management limits included in Obsidian Energy’s policies may be exceeded with specific approval from the Board of Directors.

The Board of Directors has recently approved the following changes to our hedging policy as follows:

We are also exposed to losses in the event of default by the counterparties to these derivative instruments. We manage this risk by diversifying our hedging portfolio among a number of counterparties, primarily parties within our banking syndicate, whom we consider to be financially sound.

As at December 31, 2022, we were not bound by any agreement (including a transportation agreement), directly or through an aggregator, under which we may be precluded from fully realizing, or may be protected from the full effect of, future market prices for oil or natural gas, except for agreements disclosed by us in Note 8 to our audited consolidated financial statements as at and for the year ended December 31, 2022 which have been filed on SEDAR at www.sedar.com.

Our transportation obligations and commitments for future physical deliveries of oil and conventional natural gas do not exceed our expected related future production from our proved reserves, estimated using forecast prices and costs, as disclosed herein.

The purpose of the Audit Committee (the "Committee") of the board of directors (the "Board") of Obsidian Energy Ltd. ("Obsidian Energy" or the “Company”) is to assist the Board in fulfilling its responsibility for oversight of the integrity of Obsidian Energy's consolidated financial statements, Obsidian Energy's compliance with legal and regulatory requirements, the qualifications and independence of Obsidian Energy's independent auditors, and the performance of Obsidian Energy's internal audit function, if any.

Subject to the powers and duties of the Board, the Committee will perform the following duties:

(d)

Discuss Obsidian Energy's interim results press releases, as well as financial information and earnings guidance provided to analysts and rating agencies (provided that the Committee is not required to review and discuss investor presentations that do not contain financial information or earnings guidance that has not previously been generally disclosed to the public).

(i)

on an annual basis, receive from the auditors, and review and discuss with the auditors a formal written statement delineating all relationships the auditors have with Obsidian Energy consistent with PCAOB Rule 3526; discuss with the auditors any disclosed relationships or services that may impact the objectivity and independence of the auditors; take, or recommend that the Board take, appropriate action to oversee the independence of the auditors; determine the auditors’ independence, ensure the rotation of partners on the audit engagement team in accordance with applicable law; and, in order to ensure continuing auditor independence, consider the rotation of the audit firm itself;

(ii)

in its capacity as a committee of the Board, be directly responsible for the appointment, compensation, retention and oversight of the work of the independent auditors engaged for the purpose of preparing or issuing an auditors' report or performing other audit, review or attest services for Obsidian Energy, including the resolution of disagreements between management and the independent auditor regarding financial reporting, and the independent auditors shall report directly to the Committee;

(f)

The Committee may delegate to one or more Committee members (the "Delegate") authority to pre-approve non-audit services in satisfaction of 2(e)(vii) above, subject to the fee restriction below. If such delegation occurs, the pre-approval of non-audit services by the Delegate, must be presented to the Committee at its first scheduled meeting following such pre-approval and the member(s) comply with such other procedures as may be established by the Committee from time to time. The fees for such non-audit services shall not exceed $50,000, either individually or in the aggregate, for a particular financial year without the approval of the Committee.

(g)

At least annually, obtain and review the report by the independent auditors describing the independent auditors' internal quality control procedures, any material issues raised by the most recent internal quality-control review, or peer review, of the independent auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the independent auditors, and any steps taken to deal with any such issues.

(h)

Review with the independent auditors (and internal auditors, if any) their assessment of the internal controls of the Company, their written reports containing recommendations for improvement, and management's response and follow-up to any identified weaknesses. The Committee shall also review annually with the independent auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of Obsidian Energy and its subsidiaries.

(i)

At least annually, obtain and review a report by the independent auditors describing (i) all critical accounting policies and practices used by Obsidian Energy, (ii) all alternative accounting treatments of financial information within IFRS related to material items that have been discussed with management, including the ramifications of the use of such alternative treatments and disclosures and the treatment preferred by the accounting firm, and (iii) other material written communications between the accounting firm and management of Obsidian Energy.

Committee members shall be "financially literate" within the meaning of National Instrument 52-110 Audit Committees ("NI 52-110"), and at least one member shall be “financially sophisticated” within the meaning of Section 803(B)(2)(a)(iii) of the NYSE American Company Guide. The Committee members should have or obtain sufficient knowledge of Obsidian Energy's financial and audit policies and procedures to assist in providing advice and counsel on related matters. Members shall be encouraged as appropriate to attend relevant educational opportunities at the expense of Obsidian Energy.

(a)

Committee members shall be appointed and removed by the Board and the Committee shall be composed of three directors of Obsidian Energy or such greater number as the Board may from time to time determine. Provided the Board Chair is an "independent" director as contemplated in subparagraph 4(b) below, the Board Chair shall be a non-voting ex officio member of the Committee, subject to subparagraph 5(e) below.

(b)

Each member of the Committee shall be an "independent" director in accordance with the definition of "independent" in (a) NI 52-110 Audit Committees, (b) Sections 803(A) and 803(B)(2) of the NYSE American Company Guide and (c) Rule 10A-3 under the United States Securities Exchange Act of 1934, as amended, and in accordance with all other applicable securities laws or rules of any stock exchange on which Obsidian Energy’s securities are listed for trading.

(c)

All of the members of the Committee must be "financially literate" within the meaning of NI 52-110 (unless the Board has determined to rely on an applicable exemption therefrom), and each member of the Committee shall be able to read and understand fundamental financial statements, including a company’s balance sheet, income statement, and cash flow statement. In addition, at least one member of the Committee shall be “financially sophisticated” within the meaning of Section 803(B)(2)(a)(iii) of the NYSE American Company Guide.

(d)

In connection with the appointment of the members of the Committee, the Board will determine whether any proposed nominee for the Committee serves on the audit committees of more than three public companies. To the extent that any proposed nominee for membership on the Committee serves on the audit committees of more than three public companies, the Board will make a determination as to whether such simultaneous services would impair the ability of such member to effectively serve on the Company's Audit Committee and will disclose such determination in Obsidian Energy's annual management proxy circular and annual report on Form 40-F filed with the United States Securities and Exchange Commission.

(b)

As part of its job to foster open communication, the Committee shall meet at least annually with management, internal auditors (if any) and the independent auditors in separate executive sessions to discuss any matters that the Committee or each of these groups believe should be discussed privately. In addition, the Committee shall meet with the independent auditors and management quarterly to review Obsidian Energy’s interim financials. The Committee shall also meet with management and independent auditors on an annual basis to review and discuss Obsidian Energy's annual financial statements and the management's discussion and analysis of financial conditions and results of operations.

(f)

The Committee Chair shall be a full voting member of the Committee. If the Committee Chair is unavailable or unable to attend a meeting of the Committee, the Committee Chair shall ask another member to chair the meeting, failing which a member of the Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting. The Chair of any Committee meeting (including, without limitation, any Chair selected in accordance with the foregoing) shall have a casting vote in the event of a tie on any matter upon which the Committee votes during such meeting.

(g)

Members of the Company's management and such other Company staff as are appropriate to provide information to the Committee shall be available to attend meetings upon invitation by the Committee. The Committee shall have the right to determine who shall and who shall not be present at any time during a meeting of the Committee; however, independent directors, including the Board Chair, shall always have the right to be present. As part of each Committee

(h)

The secretary to the Committee (the "Committee Secretary") will be either the Corporate Secretary of Obsidian Energy or his/her designate. The Committee Secretary shall record minutes of the meetings of the Committee, which shall be reviewed and approved by the Committee and maintained with Obsidian Energy's records by the Committee Secretary. The Committee shall report its activities and proceedings to the Board by oral or written report at the next Board meeting and by distributing the minutes of its meetings. Supporting schedules and information reviewed by the Committee shall be available for examination by any Director.

(a)

The Committee may retain special independent legal, accounting, financial or other consultants or advisors as it determines necessary to carry out its duties, to advise the Committee at the Company's expense and shall have sole authority to retain and terminate any such consultants or advisors and to approve any such consultant's or advisor's fees and retention terms, and at the expense of the Company.

(d)

Obsidian Energy shall provide for appropriate funding, as determined by the Committee, in its capacity as a committee of the Board, for payment of: (i) compensation to any auditor engaged for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for Obsidian Energy; (ii) compensation to any advisors employed by the Committee under paragraph 6(a) above; and (iii) ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties

The Committee may delegate from to time to any person or committee of persons any of the Committee's responsibilities that are permitted to be delegated to such person or committee in accordance with applicable laws, regulations and stock exchange requirements.

(a)

Nothing contained in this Mandate is intended to expand applicable standards of liability under statutory, regulatory or other legal requirements for the Board or members of the Committee. The purposes and responsibilities outlined in this Mandate are meant to serve as guidelines rather than inflexible rules and the Committee may adopt such additional procedures and standards as it deems necessary from time to time to fulfill its responsibilities, subject to applicable statutory, regulatory and other legal requirements.


	Page
GLOSSARY OF TERMS	2
CONVENTIONS	3
ABBREVIATIONS	4
OIL AND GAS INFORMATION ADVISORIES	4
CONVERSIONS	5
EFFECTIVE DATE OF INFORMATION	5
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	5
GENERAL AND ORGANIZATIONAL STRUCTURE	8
DESCRIPTION OF OUR BUSINESS	9
CAPITALIZATION OF OBSIDIAN ENERGY	15
DIRECTORS AND EXECUTIVE OFFICERS OF OBSIDIAN ENERGY	17
AUDIT COMMITTEE DISCLOSURES	22
DIVIDENDS AND DIVIDEND POLICY	24
MARKET FOR SECURITIES	24
INDUSTRY CONDITIONS	25
RISK FACTORS	38
MATERIAL CONTRACTS	62
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	63
TRANSFER AGENTS AND REGISTRARS	63
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	63
INTERESTS OF EXPERTS	63
ADDITIONAL INFORMATION	64


Oil and Natural Gas Liquids			Natural Gas

bbl		barrel or barrels	GJ	Gigajoule
bbl/d		barrels per day	GJ/d	gigajoules per day
Mbbl		thousand barrels	Mcf	thousand cubic feet
MMbbl		million barrels	MMcf	million cubic feet
NGLs		natural gas liquids	Bcf	billion cubic feet
MMboe		million barrels of oil equivalent	Mcf/d	thousand cubic feet per day
Mboe		thousand barrels of oil equivalent	MMcf/d	million cubic feet per day
boe/d		barrels of oil equivalent per day	m3 MMbtu	cubic metres million British thermal units

Other
AECO	the Alberta benchmark price for natural gas.
BOE or boe	barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one barrel of oil.
WTI	West Texas Intermediate, the reference price paid in United States dollars at Cushing, Oklahoma for oil of standard grade.
API	American Petroleum Institute.
API	the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
psi	pounds per square inch.
MM$	million dollars.
MW	megawatt.
MWh	megawatt hour.
CO2	carbon dioxide.


To Convert From	To	Multiply By

Mcf	cubic metres	28.174
cubic metres	cubic feet	35.494
Bbl	cubic metres	0.159
cubic metres	Bbl	6.293
Feet	metres	0.305
Metres	Feet	3.281
Miles	kilometres	1.609
Kilometres	miles	0.621
Acres	hectares	0.405
Hectares	acres	2.500
gigajoules (at standard)	mmbtu	0.948
mmbtu (at standard)	gigajoules	1.055
gigajoules (at standard)	Mcf	1.055


Name, Province/State and Country of Residence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five Preceding Years

Shani Bosman(3) British Columbia, Canada	Director since May 4, 2022	From 2011 to 2021, held various positions at Husky Energy Inc. including Vice President, Corporate Strategy, Performance, Planning & Investor Relations from 2019 to 2021. She also held Director roles in Technical Operations & Business and Asset Development at Husky Energy Inc. In 2021, she founded a boutique independent consulting firm called BINGWA Inc.
John Brydson(1)(2)(3) Connecticut, United States	Director since June 4, 2014	Private investor since 2012. From 2010 until the end of 2012, Chairman of Hestan Consulting Group, a full-service management consulting firm that he founded. Prior thereto, a Managing Director with Credit Suisse First Boston (now Credit Suisse).
Raymond Crossley(1)(2) Alberta, Canada	Director since March 6, 2015	Corporate director who serves on the board of the Alberta Securities Commission and departed the Canada West Foundation board in April 2022. Mr. Crossley is also the Chief Financial Officer of the Calgary Health Foundation. In March 2015, Mr. Crossley retired from the global professional services firm, PwC LLP, after more than 33 years. During his career at PwC he served as a member of the firm’s management, as Managing Partner, Western Canada from 2011-2013 and Managing Partner of PwC’s Calgary office from 2005-2011. Prior to becoming the Calgary Managing Partner, Mr. Crossley served as an elected member of the firm’s Partnership Board from 2001-2005. Mr. Crossley also served as the audit partner for several of PwC’s largest audit clients. Mr. Crossley graduated from the University of Western Ontario, is a Chartered Professional Accountant in Alberta and holds the ICD.D designation from the Institute of Corporate Directors.
Michael J. Faust(2)(3) Alaska, USA	Director since May 11, 2018 Appointed Interim President and Chief Executive Officer from March 2019 to December 5, 2019	Mr. Faust is currently a board member of SAExploration Holdings, Inc., where he was also the President and CEO until December 31, 2021 and also previously served as the Chair of the Board. He is also a director of Parker Drilling and he was the Vice President, Exploration and Land at ConocoPhillips Alaska, Inc. Mr. Faust received


Name, Province/State and Country of Residence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five Preceding Years
		a Master of Arts degree in Geophysics from the University of Texas in 1984, and Bachelor of Science degree in Geology from the University of Washington in 1981.
Edward H. Kernaghan(2)(3) Ontario, Canada	Director since January 3, 2018	Mr. Kernaghan holds a Master of Science Degree from the University of Toronto. He is Senior Investment Advisor of Kernaghan & Partners Ltd., a brokerage firm. Mr. Kernaghan is also President of Principia Research Inc., a research and investment company, and of Kernwood Ltd., an investment holding company. He also sits on the board of directors of Waterloo Brewing Company, Exco Technologies Ltd., Black Diamond Group Limited and Velan Inc.
Stephen E. Loukas New York, USA	Director since May 11, 2018 Appointed Interim President and Chief Executive Officer on December 5, 2019 and subsequently President and Chief Executive Officer on February 22, 2023	Partner, managing member, and portfolio manager at FrontFour Capital Group LLC. Previously, Mr. Loukas was a Director at Credit Suisse Securities where he was a Portfolio Manager and Head of Investment Research of the Multi-Product Event Proprietary Trading Group, and at Pirate Capital where he was a senior investment analyst and worked within the Corporate Finance & Distribution Group of Scotia Capital. He has a B.S. in Finance and Accounting from New York University.
Gordon Ritchie(1) Alberta, Canada	Chairman of the Board and Director since December 1, 2017	Retired as Vice Chairman of RBC Capital Markets April 1, 2016 after 37 years with RBC. Previously, Mr. Ritchie served as Managing Director and Head of RBC’s Global E&P Energy Group, from 2000 to 2005; spent six years in New York where he served as President and Chief Executive Officer of RBC’s U.S. Broker/Dealer, RBC Dominion Securities Corporation, from 1993 to 1999; served as Managing Director of RBC’s International Corporate Finance Group based in London, England, from 1989 to 1993; and worked as Investment Banker and Energy Research Analyst in Calgary, from 1979 through 1988. Mr. Ritchie also sits on the boards of Coril Holdings Ltd. and Pipestone Energy Corp.
Peter Scott Alberta, Canada	Senior Vice President and Chief Financial Officer since December 2, 2019	Chief Financial Officer of Obsidian Energy since December 2019. Mr. Scott previously held the role of Senior Vice President and Chief Financial Officer at Ridgeback Resources Inc., previously Lightstream Resources Ltd., for seven years. Before joining Lightstream, Mr. Scott held Vice President Finance and Chief Financial Officer roles at several oil and gas companies including Iteration Energy Ltd., Rock Energy Inc., and Beau Canada Exploration Ltd. Mr. Scott began his


Year	Audit Fees (1) ($)	Audit-Related Fees (2) ($)	Tax Fees (3) ($)	Other fees (4) ($)
2022	695,500	37,450	-	96,300
2021 (KPMG)	642,000	64,200	-	37,450
2021 (EY)	59,335	40,280	-	159,000


	TSX
	Common Share price ($)	Common Share price ($)
Period	High	Low	Volume

January	9.48	5.35	13,431,415
February	11.09	8.56	11,182,965
March	11.77	8.65	12,852,440
April	12.38	9.52	9,940,710
May	12.74	8.68	14,131,135
June	15.67	9.45	12,683,612
July	10.95	8.00	7,645,970
August	13.36	9.76	9,266,884
September	11.72	8.91	6,272,749
October	12.48	10.23	4,749,365
November	13.94	9.63	7,019,419
December	10.43	4.95	9,352,074


	OTC
	Common Share price ($US)	Common Share price ($US)
Period	High	Low	Volume

January (1-30)	7.33	4.00	8,392,887


	NYSE AMERICAN
	Common Share price ($US)	Common Share price ($US)
Period	High	Low	Volume

January (31)	8.58	7.25	436,694
February	8.80	6.73	11,047,297
March	9.49	6.74	18,324,993


(signed) "Stephen Loukas"	(signed) "Peter Scott"
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer
(signed) "Michael Faust"	(signed) "John Brydson"
Director and Chair of the Operations and Reserves Committee	Member of the Operations and Reserves Committee
February 22, 2023


Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)	Net Present Value of Future Net Revenue (millions before income taxes, 10% discount rate)
Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)				Audited	Evaluated	Reviewed	Total
GLJ Ltd.	Reserves Assessment and Evaluation of Canadian Oil and Gas Properties of Obsidian Energy Ltd. (As of December 31, 2022) January 20, 2023	Canada	nil	2,794	nil	2,794


	RESERVES
	LIGHT AND MEDIUM OIL		HEAVY OIL AND BITUMEN
RESERVES CATEGORY	Gross (MMbbl)	Net (MMbbl)	Gross (MMbbl)		Net (MMbbl)

PROVED
Developed Producing	31	27	8	7
Developed Non-Producing	-	-	-	-
Undeveloped	25	21	2	2
TOTAL PROVED	57	49	10	9

PROBABLE	23	19	5	4
TOTAL PROVED PLUS PROBABLE	80	68	15	13


	RESERVES
	CONVENTIONAL NATURAL GAS		COAL BED METHANE		NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross (Bcf)	Net (Bcf)	Gross (Bcf)	Net (Bcf)	Gross (MMbbl)	Net (MMbbl)

PROVED
Developed Producing	175	165	-	-	7	6
Developed Non-Producing	2	2	-	-	-	-
Undeveloped	107	98	-	-	5	4
TOTAL PROVED	285	265	-	-	12	10

PROBABLE	124	112	-	-	5	4
TOTAL PROVED PLUS PROBABLE	409	377	-	1	17	14


	RESERVES
	TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (MMboe)	Net (MMboe)

PROVED
Developed Producing	76	68
Developed Non-Producing	1	1
Undeveloped	50	43
TOTAL PROVED	127	112

PROBABLE	54	46
TOTAL PROVED PLUS PROBABLE	181	158


						Unit Value Before Income Tax Discounted at 10%/year(1)
RESERVES CATEGORY	0% (MM$)	5% (MM$)	10% (MM$)	15% (MM$)	20% (MM$)	($/boe)	($/Mcfe)

PROVED
Developed Producing	1,994	1,881	1,579	1,354	1,193	23.15	3.86
Developed Non-Producing	22	17	14	11	10	18.28	3.05
Undeveloped	1,321	828	549	379	267	12.83	2.14
TOTAL PROVED	3,338	2,726	2,142	1,745	1,470	19.16	3.19

PROBABLE	1,991	1,046	653	451	333	14.25	2.38

TOTAL PROVED PLUS PROBABLE	5,328	3,772	2,794	2,196	1,803	17.74	2.96


	NYSE AMERICAN
	Common Share price ($US)	Common Share price ($US)
Period	High	Low	Volume

April	9.84	7.45	12,207,907
May	10.05	6.69	17,372,987
June	12.52	7.26	23,658,681
July	8.55	6.07	13,195,938
August	10.30	7.54	20,884,645
September	8.98	6.47	15,290,935
October	9.21	7.49	11,420,560
November	10.33	7.14	15,191,590
December	7.77	6.25	14,624,286


	OIL	GAS	EDMONTON LIQUIDS PRICES
Year	WTI Cushing Oklahoma ($US/bbl)	Canadian Light Oil Sweet Price 40ºAPI ($Cdn/bbl)	Western Canada Select 20.5ºAPI ($Cdn/bbl)	NATURAL GAS AECO ($Cdn/MMbtu)	Propane ($Cdn/bbl)	Butane ($Cdn/bbl)	Condensates ($Cdn/bbl)	INFLATION RATES(1) %/year	EXCHANGE RATE(2) ($US/$Cdn)
Forecast
2023	80.25	103.16	75.98	4.44	41.25	54.35	105.00	-	0.74
2024	78.19	97.34	77.20	4.54	40.16	52.73	100.05	2.5	0.76
2025	76.10	94.21	76.55	4.37	40.04	51.08	96.97	2.0	0.76
2026	76.96	94.90	78.80	4.44	40.35	51.47	98.35	2.0	0.77
2027	78.50	96.48	80.54	4.52	41.02	52.32	99.98	2.0	0.77
2028	80.07	98.41	82.53	4.61	41.84	53.37	101.99	2.0	0.77
2029	81.67	100.38	84.20	4.70	42.67	54.43	104.03	2.0	0.77
2030	83.31	102.38	85.88	4.79	43.52	55.51	106.10	2.0	0.77
2031	84.97	104.43	87.60	4.88	44.39	56.63	108.22	2.0	0.77
2032	86.68	106.16	89.46	4.98	45.11	57.54	110.39	2.0	0.77
2033	88.40	108.28	91.24	5.08	46.02	58.69	112.60	2.0	0.77
Thereafter	+2%	+2%	+2%	+2%	+2%	+2%	+2%


	Producing				Non-Producing		Total
	Oil		Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net

Alberta	1,630	1,326	337	239	3,374	2,685	5,341	4,250
Northwest Territories	-	-	-	-	41	6	41	6
USA	-	-	-	-	25	9	25	9
Total	1,630	1,326	337	229	3,440	2,700	5,407	4,265


	Unproved Properties (thousands of acres)
	Gross	Net

Alberta	223	223
Northwest Territories	11	4
Total	234	227


RESERVES CATEGORY	REVENUE (MM$)	ROYALTIES (MM$)	OPERATING COSTS (MM$)	DEVELOPMENT COSTS (MM$)	ABANDONMENT AND RECLAMATION COSTS (MM$)	FUTURE NET REVENUE BEFORE FUTURE INCOME TAXES (MM$)	FUTURE INCOME TAXES (MM$)	FUTURE NET REVENUE AFTER FUTURE INCOME TAXES (MM$)

Proved Reserves	8,837	1,170	2,629	980	720	3,338	275	3,062

Proved Plus Probable Reserves	13,057	1,889	3,840	1,255	745	5,328	689	4,639


		FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at	UNIT VALUE(3)
RESERVES CATEGORY	PRODUCTION TYPE	10%/year) (MM$)	($/bbl)	($/Mcf)

Proved Reserves	Light and Medium Oil(1)	1,688	21.15	3.53
	Heavy Oil and Bitumen(1)	238	22.52	3.75
	Conventional Natural Gas(2)	215	10.09	1.68
	Non-Conventional Oil and Gas Activities(1)	1	8.91	1.49
	TOTAL	2,142	19.16	3.19

Proved Plus Probable	Light and Medium Oil(1)	2,210	19.50	3.26
Reserves	Heavy Oil and Bitumen(1)	317	20.14	3.36
	Conventional Natural Gas(2)	267	9.40	1.57
	Non-Conventional Oil and Gas Activities(1)	1	8.30	1.39
	TOTAL	2,794	17.74	2.96


	Forecast Prices and Costs
Year	Proved Reserves (MM$)	Proved Plus Probable Reserves (MM$)

2023	173	202
2024	197	256
2025	245	261
2026	183	267
2027	173	260
2028 and subsequent	9	9
Total: Undiscounted for all years	980	1,255


	LIGHT AND MEDIUM OIL(1)			HEAVY OIL AND BITUMEN(1)			CONVENTIONAL NATURAL GAS(1)
FACTORS	Gross Proved (MMbbl)	Gross Probable (MMbbl)	Gross Proved Plus Probable (MMbbl)	Gross Proved (MMbbl)	Gross Probable (MMbbl)	Gross Proved Plus Probable (MMbbl)	Gross Proved (Bcf)	Gross Probable (Bcf)	Gross Proved Plus Probable (Bcf)

December 31, 2021	55	14	70	11	5	16	224	73	298

Discoveries	-	-	-	-	-	-	-	-	-
Extensions (2)	7	7	14	1	1	2	47	23	70
Infill drilling (3)	1	2	2	-	-	-	1	4	5
Improved Recovery	-	-	-	-	-	-	-	-	-
Technical Revisions(4)	(4)	-	(4)	(1)	(1)	(1)	25	20	45
Acquisitions (5)	-	-	-	-	-	-	2	1	3
Dispositions	-	-	-	-	-	-	-	-	(1)
Economic Factors (6)	2	-	2	1	-	1	8	2	11
Production (7)	(4)	-	(4)	(2)	-	(2)	(23)	-	(23)

December 31, 2022	57	23	80	10	5	16	285	124	409


	NATURAL GAS LIQUIDS(1)			TOTAL OIL EQUIVALENT(1)
FACTORS	Gross Proved (MMbbl)	Gross Probable (MMbbl)	Gross Proved Plus Probable (MMbbl)	Gross Proved (MMboe)	Gross Probable (MMboe)	Gross Proved Plus Probable (MMboe)


December 31, 2021	10	3	13	114	34	148

Discoveries	-	-	-	-	-	-
Extensions (2)	2	1	2	18	12	30
Infill drilling (3)	-	-	-	1	3	4
Improved Recovery	-	-	-	-	-	-
Technical Revisions (4)	1	1	2	-	4	4
Acquisitions (5)	-	-	-	-	-	1
Dispositions	-	-	-	-	-	-
Economic Factors (6)	-	-	-	4	1	5
Production (7)	(1)	-	(1)	(11)	-	(11)

December 31, 2022	12	5	17	127	54	181


Year	Light and Medium Oil (MMbbl)		Heavy Oil and Bitumen (MMbbl)		Conventional Natural Gas (Bcf)		NGLs (MMbbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End

2020	2	20	0	1	4	56	0	3
2021	1	22	1	3	22	75	1	3
2022	13	25	1	2	50	107	2	5


Period	Abandonment and Reclamation Costs Escalated at 2% Undiscounted (MM$)	Abandonment and Reclamation Costs Escalated at 2% Discounted at 10% (MM$)
Total liability as at December 31, 2022	1,324	181
Anticipated to be paid in 2023	26	26
Anticipated to be paid in 2024	27	24
Anticipated to be paid in 2025	27	22
Total anticipated to be paid in 2023, 2024 and 2025	80	72


	2022 MM$

Property Acquisition Costs
Proved Properties	4.6
Unproved Properties	18.9
Exploration Costs	-
Development Costs	295.0
Corporate Costs	0.9
Total Capital Expenditures	319.4
Corporate Acquisitions	-
Total Expenditures	319.4


	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	-	-	70	60
Gas and condensate	-	-	2	2
Injectors/Stratigraphic test	-	-	2	1
Total	-	-	74	63


	Light and Medium Oil		Heavy Oil and Bitumen		Total Natural Gas			Natural Gas Liquids		Total Oil Equivalent
	(bbl/d)		(bbl/d)		(Mcf/d)			(bbl/d)		(boe/d)
	Gross	Net	Gross	Net		Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	11,305	9,391	5,326	4,243		69,008	64,123	2,757	2,052	30,889	26,372
Proved Developed Non- Producing	132	122	-	-		629	591	30	25	267	245
Proved Undeveloped	1,952	1,829	592	672		6,341	6,025	243	230	3,844	3,734
Total Proved	13,390	11,342	5,918	4,915		75,978	70,740	3,030	2,306	35,000	30,352
Total Probable	824	700	756	714		3,377	3,176	91	72	2,235	2,016
Total Proved Plus Probable	14,214	12,042	6,674	5,628		79,355	73,916	3,122	2,378	37,325	32,367


	Quarter Ended 2022				Year Ended
	March 31	June 30	September 30	December 31	December 31, 2022
Share of Average Gross Daily Production
Light and Medium Oil (bbl/d)	11,113	12,261	11,062	12,105	11,636
Heavy Oil (bbl/d)	5,790	6,174	5,854	5,983	5,950
Conventional Natural Gas (Mcf/d)	60,426	64,409	64,134	66,813	63,964
NGLs (bbl/d)	2,432	2,406	2,379	2,520	2,434
Combined (boe/d)	29,407	31,575	29,985	31,742	30,682

Average Net Production Prices Received
Light and Medium Oil ($/bbl)	117.96	139.88	118.66	110.45	121.92
Heavy Oil ($/bbl)	84.77	106.18	81.78	62.19	83.84
Conventional Natural Gas ($/Mcf)	4.96	7.38	5.31	5.66	5.84
NGLs ($/bbl)	68.09	82.93	69.12	64.33	71.02
Combined ($/boe)	77.10	96.44	76.58	70.87	80.31

Royalties Paid
Light and Medium Oil ($/bbl)	15.92	23.99	23.55	19.45	20.79
Heavy Oil ($/bbl)	16.20	20.40	17.97	10.75	16.35
Conventional Natural Gas ($/Mcf)	0.40	0.67	0.42	0.57	0.52
NGLs ($/bbl)	16.01	11.33	12.13	16.32	13.98
Combined ($/boe)	11.35	15.53	14.06	11.93	13.25

Production Costs(1)(2)
Light and Medium Oil ($/bbl)	25.83	24.70	26.67	25.51	25.66
Heavy Oil ($/bbl)	14.65	14.72	13.91	16.06	14.85
Conventional Natural Gas ($/Mcf)	0.63	0.76	0.94	0.90	0.81
NGLs ($/bbl)	0.00	0.00	0.00	0.00	0.00
Combined ($/boe)	13.93	14.02	14.57	14.63	14.30

Transportation
Light and Medium Oil ($/bbl)	1.81	1.80	1.74	1.84	1.80
Heavy Oil ($/bbl)	7.12	8.84	8.40	9.16	8.40
Conventional Natural Gas ($/Mcf)	0.16	0.18	0.16	0.18	0.17
NGLs ($/bbl)	4.15	6.41	7.10	5.91	5.89
Combined ($/boe)	2.76	3.29	3.18	3.28	3.14

Risk Management Contracts Loss (Gain)
Light and Medium Oil ($/bbl)	17.52	8.56	(0.94)	(0.52)	6.01
Heavy Oil ($/bbl)	0.00	0.00	0.00	0.00	0.00
Conventional Natural Gas ($/Mcf)	(0.02)	0.65	0.44	0.01	0.27
NGLs ($/bbl)	0.00	0.00	0.00	0.00	0.00
Combined ($/boe)	6.58	4.66	0.59	(0.18)	2.85