Obsidian Energy Ltd 40-F for FY2020

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

(Check One)

☐	Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

or

☒	Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2020

Commission file number 1-32895

OBSIDIAN ENERGY LTD.

(Exact name of registrant as specified in its charter)

Alberta, Canada	1311	Not applicable
(Province or other jurisdiction of<br><br><br>incorporation or organization)	(Primary Standard IndustrialClassification Code Number(if applicable))	(I.R.S. EmployerIdentification Number(if Applicable))

Suite 200, 207 – 9^th^ Avenue SW, Calgary, Alberta,Canada T2P 1K3

(403) 777-2500

(Address and Telephone Number of Registrant’s Principal Executive Offices)

DL Services Inc., Columbia Center, 701 Fifth Avenue, Suite 6100, Seattle, Washington 98104-7043

(206) 903-5448

(Name, Address (Including Zip Code) and Telephone Number

(Including Area Code) of Agent For Service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class	Trading Symbol	Name of each exchange on whichregistered

Securities registered or to be registered pursuant to Section 12(g) of the Act: Common Shares, no parvalue

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this Form:

☒ Annual Information Form	☒ Audited Annual Financial Statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 73,516,225

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.

Yes  ☒            No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).

Yes  ☒            No  ☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company	☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Yes  ☐            No  ☒

FORM 40-F

Principal Documents

The following documents, filed as Exhibits 99.1, 99.2, 99.3 and 99.4 to this Annual Report on Form 40-F, are hereby incorporated by reference into this Annual Report on Form 40-F:

(a)	Annual Information Form for the fiscal year ended December 31, 2020;
(b)	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the fiscal<br>year ended December 31, 2020;
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(c)	Audited Consolidated Financial Statements for the fiscal year ended December 31, 2020, prepared under<br>International Financial Reporting Standards as issued by the International Accounting Standards Board; and
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(d)	Supplemental Oil and Gas information.
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ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.

(a)	Certifications. See Exhibits 99.5, 99.6, 99.7 and 99.8 to this Annual Report on Form 40-F.
(b)	Disclosure Controls and Procedures. As of the end of Obsidian Energy Ltd.’s (“Obsidian<br>Energy”) fiscal year ended December 31, 2020, an evaluation of the effectiveness of Obsidian Energy’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e)<br>and 15d-15(e) under the Exchange Act) was carried out by the management of Obsidian Energy, with the participation of the Interim President and Chief Executive Officer (“CEO”) and the Chief Financial<br>Officer (“CFO”) of Obsidian Energy. Based upon that evaluation, the CEO and CFO have concluded that as of the end of that fiscal year, Obsidian Energy’s disclosure controls and procedures were effective to ensure that information<br>required to be disclosed by Obsidian Energy in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission (the<br>“Commission”) rules and forms and (ii) accumulated and communicated to the management of Obsidian Energy, including the CEO and CFO, to allow timely decisions regarding required disclosure.
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It should be noted that while the CEO and CFO believe that Obsidian Energy’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Obsidian Energy’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c)	Management’s Annual Report on Internal Control Over Financial Reporting.

Management is responsible for establishing and maintaining adequate internal control over Obsidian Energy’s financial reporting. Obsidian Energy’s internal control system was designed to provide reasonable assurance that all transactions are accurately recorded, that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that Obsidian Energy’s assets are safeguarded.

Management has assessed the effectiveness of Obsidian Energy’s internal control over financial reporting as at December 31, 2020. In making its assessment, management used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework (2013) to evaluate the effectiveness of Obsidian Energy’s internal control over financial reporting. Based on this assessment, management has concluded that Obsidian Energy’s internal control over financial reporting was effective as of December 31, 2020.

(d)	Attestation Report of the Registered Public Accounting Firm. This Annual Report on Form 40-F does not include an attestation report of Obsidian Energy’s external auditor because Obsidian Energy qualifies as a non-accelerated filer based on the aggregate<br>worldwide market value of the voting and non-voting common equity held by its non-affiliates on June 30, 2020.
(e)	Changes in Internal Control Over Financial Reporting (“ICFR”). The required disclosure is<br>included under the heading “Changes in Internal Control Over Financial Reporting” in the Company’s Management’s Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31,<br>2020, filed as Exhibit 99.2 to this Annual Report on Form 40-F.
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Notices Pursuant toRegulation BTR.

None.

AuditCommittee Financial Expert.

Obsidian Energy’s board of directors has determined that Raymond Crossley, a member of Obsidian Energy’s audit committee, qualifies as an “audit committee financial expert” (as such term is defined in Form 40-F). Mr. Crossley is “independent” as that term is defined in the rules of the New York Stock Exchange.

Code of Business Conduct.

Obsidian Energy has adopted a Code of Business Conduct and Ethics that applies to all employees, officers and directors of Obsidian Energy. This Code constitutes a “code of ethics” as defined in Form 40-F and is referred to in this Annual Report on Form 40-F as the “Code of Ethics”.

The Code of Ethics is available for viewing on Obsidian Energy’s website at www.obsidianenergy.com, is available in print to any shareholder who requests a copy, and is filed as an exhibit to this Annual Report on Form 40-F. Requests for copies of the Code of Ethics should be made by contacting: investor relations by phone at (888) 770-2633 or by e-mail to investor_relations@obsidianenergy.com.

During the year ended December 31, 2020, there have not been any amendments to, or waivers, including implicit waivers, from, any provision of the Code of Ethics.

If any amendment to the Code of Ethics is made, or if any waiver from the provisions thereof is granted, Obsidian Energy may elect to disclose the information about such amendment or waiver required by Form 40-F to be disclosed, by posting such disclosure on Obsidian Energy’s website, which may be accessed at www.obsidianenergy.com.

Principal Accountant Fees and Services.

The required disclosure is included under the heading “External Auditor Service Fees” in Obsidian Energy’s Annual Information Form for the fiscal year ended December 31, 2020, filed as Exhibit 99.1 hereto.

Pre-Approval Policies andProcedures.

(a)	The terms of the engagement of Obsidian Energy’s external auditors to provide audit services, including<br>the budgeted fees for such audit services and the representations and disclaimers 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 prior to retaining the external auditors to complete such engagement. However, the audit committee may delegate to one or more audit committee members (the “Delegate”) authority to pre-approve non-audit services, 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 audit 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 audit 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 audit committee.

(b)	Of the fees reported in this Annual Report on Form 40-F under the<br>heading “Principal Accountant Fees and Services”, none of the fees billed by Ernst & Young LLP were approved by Obsidian Energy’s audit committee pursuant to the de minimus exception provided by Section (c)(7)(i)(C) of<br>Rule 2-01 of Regulation S-X.

Off-Balance Sheet Arrangements.

Obsidian Energy has off-balance-sheet financing arrangements consisting of operating leases. The operating lease payments are summarized below in the Tabular Disclosure of Contractual Obligations.

Tabular Disclosure of Contractual Obligations.

(CDN millions)		Payment due by period
Contractual Obligations		Less than<br>1 Year		1 to 3<br>Years		3 to 5<br>Years		Morethan 5Years
Transportation	25.6		7.1		8.3		4.6		5.6
Power infrastructure	9.9		6.7		3.2		—		—
Office lease	40.8		10.0		20.0		10.8		—
Long-term debt (1)(2)	451.8		—		451.8		—		—
Lease liability	14.5		4.9		4.3		0.3		5.0
Decommissioning liability (3)	596.6		7.3		17.2		8.0		564.1
Total	1,139.2	****	36.0	****	504.8	****	23.7	****	574.7

All values are in US Dollars.

(1)	Includes $395.0 million related to the syndicated revolving credit facility and non-revolving term loan that is due for renewal in 2022 and $60.3 million of senior notes set to mature in 2022. The syndicated revolving credit facility has an initial revolving period ending on May 31,<br>2022, with a term out period until November 30, 2022. Obsidian Energy and its predecessors have successfully extended its credit facility on each renewal date since 1992.
(2)	Interest payments have not been included since future debt levels and rates are not known at this time.<br>
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(3)	These amounts represent the undiscounted future reclamation and abandonment costs that are expected to be<br>incurred over the life of the properties.
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Identification of the Audit Committee.

Obsidian Energy has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Raymond Crossley, John Brydson and Maureen Cormier Jackson.

Mine Safety Disclosure.

Not applicable.

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.	Undertaking.

Obsidian Energy undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

B.	Consent to Service of Process.

Obsidian Energy has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

Any change to the name or address of the agent for service of process of Obsidian Energy shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of Obsidian Energy.

SIGNATURES

Pursuant to the requirements of the Exchange Act, Obsidian Energy Ltd. certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 29, 2021.

Obsidian Energy Ltd.
By:	/s/ Stephen E. Loukas
Name:	Stephen E. Loukas
Title:	Interim President and Chief Executive Officer

EXHIBIT INDEX

Exhibit	Description
99.1	Annual Information Form for the fiscal year ended December 31, 2020
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2020
99.3	Consolidated Financial Statements for the fiscal year ended December 31, 2020
99.4	Supplemental Oil and Gas information
99.5	Certification of President <br>& Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
99.6	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of<br>1934
99.7	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
99.8	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
99.9	Consent of Ernst & Young LLP
99.10	Consent of Sproule Associates Limited

EX-99.1

Exhibit 99.1

OBSIDIAN ENERGY LTD.

Annual Information Form

for the year ended December 31, 2020

March 26, 2021

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS		1
CONVENTIONS		2
ABBREVIATIONS		3
OIL AND GAS INFORMATION ADVISORIES		3
CONVERSIONS		4
EFFECTIVE DATE OF INFORMATION		4
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		4
GENERAL AND ORGANIZATIONAL STRUCTURE		7
DESCRIPTION OF OUR BUSINESS		8
CAPITALIZATION OF OBSIDIAN ENERGY		14
DIRECTORS AND EXECUTIVE OFFICERS OF OBSIDIAN ENERGY		16
AUDIT COMMITTEE DISCLOSURES		21
DIVIDENDS AND DIVIDEND POLICY		23
MARKET FOR SECURITIES		23
INDUSTRY CONDITIONS		24
RISK FACTORS		38
MATERIAL CONTRACTS		60
LEGAL PROCEEDINGS AND REGULATORY ACTIONS		61
TRANSFER AGENTS AND REGISTRARS		61
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		61
INTERESTS OF EXPERTS		61
ADDITIONAL INFORMATION		62

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

GLOSSARY OF TERMS

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 March X, 2021.

“Board” or “Board of Directors” means the board of directors of Obsidian Energy.

“Common Shares” means common shares in the capital of Obsidian Energy.

“Engineering Report” means the report prepared by Sproule dated February 1, 2021 where they evaluated one hundred percent of the crude oil, natural gas and natural gas liquids reserves of Obsidian Energy and the net present value of future net revenue attributable to those reserves effective as at December 31, 2020.

“Form 40-F” means our Annual Report on Form 40-F for the fiscal year ended December 31, 2020 filed with the SEC.

“Gross” or “gross” means:

(a)	in relation to our interest in production or reserves, our “company gross reserves”, which are our<br>working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of ours;
(b)	in relation to wells, the total number of wells in which we have an interest; and
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(c)	in relation to properties, the total area of properties in which we have an interest.
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“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.

“MD&A” means management’s discussion and analysis.

“Net” or “net” means:

(a)	in relation to our interest in production or reserves, our working interest (operating or non-operating)<br>share after deduction of royalty obligations, plus our royalty interests in production or reserves;
(b)	in relation to our interest in wells, the number of wells obtained by aggregating our working interest in<br>each of our gross wells; and
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(c)	in relation to our interest in a property, the total area in which we have an interest multiplied by the<br>working interest we own.
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“NI 51-101” means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

“NYSE” means the New York Stock Exchange.

“Obsidian Energy”, the “Company”, the “Corporation”, “we”, “us” or “our” each mean 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”).

“OPEC” means the Organization of the Petroleum Exporting Countries.

“OTCQB” means the middle tier of over the counter (OTC) markets.

“OTCQX” means the top tier of the OTC markets.

“SEC” means the United States Securities and Exchange Commission.

“Senior Notes” means our guaranteed, secured senior notes consisting of US$47 million principal amount of notes, as described under the heading “Capitalization of Obsidian Energy – Debt Capital – Senior Notes”.

“Shareholders” means holders of our Common Shares.

“Sproule” means Sproule Associates Limited, independent petroleum consultants of Calgary, Alberta.

“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.

“TSX” means the Toronto Stock Exchange.

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

“United States” or “U.S.” means the United States of America.

CONVENTIONS

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 March 26, 2021, the exchange rate based on the noon rate as reported by WM/Refinitiv, was Cdn$1.00 equals US$0.7948.

All financial information herein has been presented in accordance with IFRS.

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ABBREVIATIONS

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	m^3^<br><br><br>MMbtu	cubic metres<br><br><br>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<br>oil.
WTI	West Texas Intermediate, the reference price paid in United States dollars at Cushing, Oklahoma for crude oil<br>of standard grade.
API	American Petroleum Institute.
ºAPI	the measure of the density or gravity of liquid petroleum products derived from a specific<br>gravity.
psi	pounds per square inch.
MM$	million dollars.
MW	megawatt.
MWh	megawatt hour.
CO2	carbon dioxide.

OIL AND GAS INFORMATION ADVISORIES

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 theAppendices 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 toestimate 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, 2020, filed with the SEC, Obsidian Energy has disclosedproved 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 AccountingStandards 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 crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

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CONVERSIONS

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

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

EFFECTIVE DATE OF INFORMATION

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, 2020.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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 first half 2021 capital, development and production plans; that we will continue to monitor commodity prices and adjust our development plans accordingly; the benefits in connection with the Offer; our updated syndicated credit facility and the possible reconfirmation, redetermination and term-out dates under the various scenarios; our updated senior notes maturity date; our expected 2021 full year capital program, production, and primary locations; details of our ongoing acquisition, disposition, farm-out and financing strategy; 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; 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; 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 commitment to mitigating the environmental impact from our operations and involving stakeholders throughout the exploration, development, production and abandonment process; 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 expectation that interest and other funding costs will not make the development of any of our properties uneconomic; 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; the details of our exploration and development plans in the Cardium and optimization activity in 2021; 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.

4

With respect to forward-looking statements contained or incorporated by reference in this document, we have made assumptions regarding, among other things that: the benefits to be derived by the Company and its stakeholders from the proposed acquisition of Bonterra; that the publicly available Bonterra information is correct; the Company does not dispose of additional material producing properties; the impact of the Government of Alberta production curtailment on the Company; 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; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the CEWS and ASRP) 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 notes at the newly negotiated 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 crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future capital expenditure levels and capital programs; future crude 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; 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”.

5

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; 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 (including the CEWS and ASRP) 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 pursuant to our ongoing effort to consolidate the Cardium play, including the proposed acquisition of Bonterra, on favorable terms or at all, or that the Company and its stakeholders do not realize the anticipated benefits of any such transaction that is completed (including the benefits of the proposed acquisition of Bonterra described herein); the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that the significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally that has been caused by, 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 notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew our credit facilities on acceptable terms or at all and/or finance the repayment of our senior notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or both of our credit facilities and senior notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior notes; the impact of weather conditions on seasonal demand; the impact of weather conditions on our ability to execute capital programs; the impact of the Alberta government mandated curtailment; 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 crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets and transportation restrictions, including pipeline and railway capacity constraints; 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 crude 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.

6

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.

GENERAL AND ORGANIZATIONAL STRUCTURE

General

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

Our Organizational Structure

The following diagram sets forth the organizational structure of Obsidian Energy and our material Subsidiaries as at the date hereof.

7

Notes:

(1)	The remaining 45% interest in Peace River Oil Partnership is owned by Winter Spark Resources, Inc., an<br>affiliate of China Investment Corporation.
(2)	Each of the entities identified in the diagram was incorporated, continued, formed or organized, as the case<br>may be, under the laws of the Province of Alberta.
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DESCRIPTION OF OUR BUSINESS

Overview

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, 2020, Obsidian Energy had 171 employees.

Reserves Data

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, 2020.

General Development of the Business

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

8

Year Ended December 31, 2018

Board of Directors Changes

Mr. Edward H. Kernaghan joined the Board on January 3, 2018.

Mr. Jay W. Thornton was appointed as the Chair of the Board of Directors on February 22, 2018, replacing Mr. George Brookman who had been “Acting” Chair of the Board of Directors. At the AGM on May 11, 2018, Mr. George Brookman retired from the Board and Mr. Stephen Loukas and Mr. Michael Faust joined the Board of Directors.

2018 Production Guidance and Disposition Activity

In January 2018, the Company closed an agreement to dispose of a significant portion of our non-core legacy assets located in central Alberta, in exchange for the assumption of abandonment and reclamation liabilities. Total production associated with the disposition was 2,200 boe/d. Additionally, the Company revised our average production guidance for 2018 to 29,000 to 30,000 boe/d at that time.

Additional $50 Million of Cardium Development

On June 4, 2018, the Company announced an additional $50 million of 2018 Cardium development capital was added primarily through funding by the existing credit facility, and supplemented with minor dispositions of underutilized and undeveloped acreage. The capital would be spent throughout the third and fourth quarter of 2018, with expected production beginning to come online later in the year.

2019 Outlook and Guidance

On November 15, 2018, the Company announced planned 2019 capital investment of $120 million, which included $92 million of development capital associated with drilling, well licensing, lease preparation and existing wellbore optimization; and $28 million of maintenance capital, corporate capital, operating cost reduction initiatives and decommissioning expenditures as part of the Alberta Energy Regulator’s Area-Based Closure initiative. Development capital was 80 percent weighted to the Cardium and the remaining 20 percent roughly spread evenly between optimization of existing wellbores, non-operated primary drilling and two Deep Basin wells. The Company also announced that should there be pricing improvement towards the second half of the year, the Company designed the second half program to allow for an increase of $40 million of capital spend, which would bring the 2019 total capital spend to approximately $160 million. The Company’s average production guidance for 2019 was also set at 28,000 to 29,000 boe/d. For further details, see the Company’s news release dated November 17, 2018 which is available on SEDAR at www.sedar.com.

$30 Million increase to Syndicated Credit Facility

On December 17, 2018, the Company announced an increase in our syndicated credit facility from $440 million to $470 million, primarily due to the July 2018 retirement of an outstanding Pound Sterling cross currency swap. For further details, see the Company’s news release dated December 17, 2018 which is available on SEDAR at www.sedar.com

Year Ended December 31, 2019

Updated 2019 Outlook and Guidance

On February 11, 2019, the Company announced that due to the Alberta curtailment requirements and other factors, we were revising our guidance for full year production, growth rates and operating and general and administrative costs per boe and shifting certain capital into the second half of 2019. The Company’s average production guidance for 2019 was also set at 26,750 to 27,750 boe/d. For further details, see the Company’s news release dated February 11, 2019 which is available on SEDAR at www.sedar.com.

9

Board of Directors and Management Changes

Mr. Gordon Ritchie was appointed as the Chair of the Board of Directors on February 20, 2019, replacing Mr. Jay W. Thornton who resigned his Board seat.

Mr. David French resigned as a Director, President and Chief Executive Officer effective March 29, 2019. Mr. Michael Faust, a Director of the Company, became the Interim President and Chief Executive Officer from March 29 through to December 5, 2019, at which point, Mr. Stephen Loukas, a Director of the Company, was appointed Interim President and Chief Executive Officer on December 5, 2019, and Mr. Faust returned to his Director position.

Mr. David Hendry and Mr. Andrew Sweerts tendered their resignations from the positions of Chief Financial Officer and Vice President, Business Development & Commercial, respectively, effective November 15, 2019. On December 2, 2019, the Company announced Mr. Peter Scott was appointed as Senior Vice President and Chief Financial Officer, Mr. Gary Sykes had been appointed Vice President, Commercial and Mr. Mark Hawkins was promoted to Vice President, Legal, General Counsel & Corporate Secretary.

Syndicated Credit Facility

On March 6, 2019, the Company entered into amending agreements with holders of our senior notes to temporarily amend our financial covenants for all quarters in 2019. EBITDA was reset during this period and calculated on a rolling basis starting on January 1, 2019. The maximum for both ratios was less than or equal to 4.25:1 in 2019, decreasing to 3:1 from January 1, 2020 onwards for Senior debt to EBITDA and 4:1 from January 1, 2020 onwards for Total debt to EBITDA (which were the maximum ratios required prior to entering into the amending agreements).

On August 13, 2019, the Company reached an agreement with our lenders whereby the underlying borrowing base of the syndicated credit facility and the amount available to be drawn under the syndicated credit facility remained at $550 million and $460 million, respectively. Under the agreement, an additional borrowing base redetermination was scheduled on February 28, 2020 when the revolving period ended, with the expiration of the term-out date of November 30, 2020. Additionally, there were two reconfirmation dates on November 19, 2019 and January 20, 2020 whereby the commencement of the term-out period could be accelerated on November 30, 2019 and January 30, 2020, respectively. If the facility was not extended on or prior to February 28, 2020 or reconfirmed at the before mentioned dates, the Company would not be allowed to further draw on the syndicated credit facility and the amount outstanding would be due on November 30, 2020. For further details, see the Company’s news releases dated August 13, 2019 and December 2, 2019 which are available on SEDAR at www.sedar.com.

Share Consolidation at the Annual General Meeting

To regain compliance and for other reasons set forth in the Information Circular, the Company proposed and passed a seven old common shares for one new common share consolidation as voted on by the shareholders as part of the Company’s Annual General Meeting in 2019. Subsequently, the Company regained compliance at the close of trading on July 23, 2019 since the average closing price of our common stock for the consecutive 30 trading days ended July 23, 2019 and the closing price of our common stock both exceeded US$1.00. For further details, see the Company’s news release dated July 23, 2019 which is available on SEDAR at www.sedar.com.

NYSE – Continued Listing Standard Notification

On October 1, 2019, the Company received notification from the NYSE that we were no longer in compliance with one of the NYSE’s continued listing standards applicable to us because the average closing price of our Common Shares was less than US$1.00 per share over a consecutive 30-day trading period. Under the NYSE’s rules, the Company has a period of six months from the date of the NYSE notification to regain compliance with the NYSE’s price listing standard and avoid delisting. For further details, see the Company’s news release dated October 1, 2019 which is available on SEDAR at www.sedar.com. The Company indicated in the news release that if the Company’s share price did not increase sufficiently by the deadline to meet the continued standards requirements, the Company would not take further steps to regain compliance and expected the NYSE would commence with de-listing procedures.

10

Strategic Alternatives

On September 10, 2019, the Company publicly announced that the Board had determined that it was in the best interests of the Company and our stakeholders to initiate a formal process to explore strategic alternatives. The process was intended to evaluate the Company’s strategic options and alternatives to maximize shareholder value. For further details, see the Company’s news release dated September 10, 2019 which is available on SEDAR at www.sedar.com.

2020 Outlook

On December 2, 2019, the Company announced planned first half 2020 capital expenditures of $49 million to fund the continued drilling of the remaining nine wells in our Cardium development program and other operational spending. For further details, see the Company’s news release dated December 2, 2019 which is available on SEDAR at www.sedar.com.

Year Ended December 31, 2020

Syndicated Credit Facility and Senior Notes Agreement

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:

•	The revolving period was to end on May 31, 2021 with a term-out period of November 30, 2021;<br>
•	There would be no borrowing base redetermination on May 31, 2020, the next scheduled borrowing base<br>redetermination would occur on November 30, 2020; and
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•	A re-confirmation date on June 22, 2020.
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On March 15, 2020, the Company announced that we had entered an agreement with holders of our senior unsecured notes to amend the maturity dates of the senior notes. Changes to our maturity dates were as follows:

•	the senior notes maturing on March 16, 2020, May 29, 2020 and December 2, 2020 were<br>extended to November 30, 2021;
•	the senior note maturing on November 30, 2021 would remain the same;
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•	the senior notes maturing on December 2, 2022 and December 2, 2025 would now mature on<br>November 30, 2021; and
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•	if the end date of the revolving period on the syndicated credit facility was accelerated to April 1,<br>2021, as described below, then the senior notes maturities would also be accelerated to that date.
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Additionally, on March 27, 2020, the noteholders and banking syndicate agreed to amend the Company’s financial covenants as follows:

•	for the period January 1, 2020 onwards, eliminate the Senior Debt and Total Debt to Adjusted EBITDA<br>covenants; and
•	the maximum for both the Senior Debt and Total Debt to Capitalization would be permanently increased to 75%.<br>
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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:

•	a revolving period reconfirmation date occurred on September 4, 2020, whereby the lenders could have<br>accelerated the end date of the revolving period to September 15, 2020 with the end date of the term period also concurrently accelerated to April 1, 2021; and
•	the lenders had the option to complete a borrowing base determination on September 15, 2020. If the<br>lenders elected not to complete a determination, the next scheduled borrowing base determination was to be on November 30, 2020, as previously disclosed.
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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.

Updated Office Lease Commitment

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:

•	lease payments will total $0.833 million per month, net of sub-leases, from February 2020 to January 2025 ($10<br>million on an annualized basis); and
•	the building landlord has agreed to indemnify the Company on all existing subleases.
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The execution of definitive documentation for the agreement was completed on March 27, 2020.

Updated 2020 Outlook

The Company updated our first half 2020 capital plan to $54 million which included the drilling of 10 wells in our Cardium development program, decommissioning expenditures and other operational spending. At the current low commodity price environment, the Company expected minimal capital spending in the second half of 2020, however, we would continue to monitor commodity prices and adjust our development plans accordingly.

NYSE – Delisting and OTC Listing

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.

Updated 2020 First Half Guidance

On April 23, 2020, the Company announced that due to certain production shut-in decisions and its continued and extensive focus on costs reductions and other factors, we were revising our guidance for first half 2020 production, and operating and general and administrative costs per boe. The Company’s average first half 2020 production guidance was set at 25,500 to 26,000 boe/d. For further details, see the Company’s news release dated April 23, 2020 which is available on SEDAR at www.sedar.com.

Government Assistance Programs

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.

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.

Second Half Development Program and Second Half Guidance

On July 30, 2020, the Company announced a reduced second half 2020 capital expenditure program of approximately $13 million and that we had deferred development spending and would focus activities on optimization and minor infrastructure projects. In addition, the Company provide second half and full year guidance at 24,000 to 24,500 boe/d and 25,000 to 25,500 boe/d, respectively. For further details, see the Company’s news release dated July 30, 2020 which is available on SEDAR at www.sedar.com.

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Take over Bid and Special Meeting

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.

2021 Developments

2021 Outlook and Guidance

On January 5, 2021, the Company announced planned first half 2021 capital expenditures of $35 million to fund the continued drilling of Willesden Green in the Cardium area with a planned seven well program and other operational spending in addition to $5 million of decommissioning spending. The Company’s average production guidance for the first half of 2021 was also set at 23,000 to 23,400 boe/d. For further details, see the Company’s news release dated January 5, 2021which is available on SEDAR at www.sedar.com.

Take over Bid extension

On January 25, 2021, the Company extended the Offer to purchase the Bonterra shares to March 29, 2021. For further details, see the Company’s news release dated January 25, 2021 which is available on SEDAR at www.sedar.com.

Syndicated Credit Facility and Senior Notes Agreement

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, previously January 31, 2021. For further details, see the Company’s news release dated January 28, 2021 which 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, previously February 26, 2021. For further details, see the Company’s news release dated February 24, 2021 which 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 is now set at $440 million. Additionally, the following terms were included in the amending agreement:

•	the $440 million of availability consists of a $225 million syndicated revolving credit facility and a $215<br>million non-revolving term loan;
•	the revolving period under the syndicated credit facility has been extended to May 31, 2022, with the end<br>date of the term period extended to November 30, 2022;
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•	the maturity date of the non-revolving term loan is also November 30, 2022;
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•	the next scheduled borrowing base redeterminations will occur on November 30, 2021 and May 31, 2022;<br>
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•	a revolving period reconfirmation date will occur on January 17, 2022, whereby, on or prior to such date,<br>the lenders may accelerate the end date of the revolving period to February 1, 2022. In this case, the end date of the term period would remain unchanged at November 30, 2022; and
•	the revolving credit facility will have a one-time adjustment to reduce our undrawn availability to $35<br>million at December 31, 2021. Any borrowing availability at this time in excess of that amount will be used to reduce amounts outstanding on the non-revolving term loan and senior notes.
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On March 26, 2021, the Company entered an agreement with holders of our senior unsecured notes to amend the maturity dates of the senior notes from November 30, 2021 to November 30, 2022.

Ongoing Acquisition, Disposition, Farm-Out and Financing Activities

Potential Acquisitions

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.

Potential Dispositions and Farm-Outs

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.

Potential Financings

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, and the repayment of indebtedness. 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.

Significant Acquisitions

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.

CAPITALIZATION OF OBSIDIAN ENERGY

Share Capital

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.

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Common Shares

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.

As at March 26, 2021, 73,523,122 Common Shares were issued and outstanding.

Preferred Shares

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.

As at the date hereof, no preferred shares are issued and outstanding.

Debt Capital

Obsidian Energy has issued the Senior Notes and has a syndicated credit facility. 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 Notes and credit facility, which are available on SEDAR at www.sedar.com.

SeniorNotes

Obsidian Energy has issued the Senior Notes, which consist of US$47 million principal amount of notes. The Senior Notes are guaranteed by Obsidian Energy’s material Subsidiaries, are secured and rank equally with our bank credit facilities. The following is a brief summary of certain of the material terms of each series of our Senior Notes as amended on March 26, 2021.

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Series	Currency /PrincipalAmount	InterestRate	Issue Date	Maturity Date
Series G	US$4 million	8.52%	May 29, 2008	November 30, 2022
Series S	US$10 million	7.97%	March 16, 2010	November 30, 2022
Series X	US$13 million	7.00%	December 2, 2010<br>and January 4, 2011	November 30, 2022
Series Y	US$6 million	7.10%	December 2, 2010	November 30, 2022
Series Z	US$2 million	7.35%	December 2, 2010<br>and January 4, 2011	November 30, 2022
Series EE	US$12 million	6.91%	November 30, 2011	November 30, 2022

Credit Facility

The Company has a reserve-based syndicated credit facility in place that has an amount available to be drawn totalling $440 million. The $440 million of availability consists of a $225 million revolving syndicated credit facility and a $215 million non-revolving term loan. The revolving period of the syndicated credit facility ends on May 31, 2022, with a term out period of November 30, 2022, and is subject to a semi-annual borrowing base redetermination in May and November of each year.

AdditionalInformation

For additional information regarding our Senior Notes and our credit facility, see “Description of Our Business – General Development of the Business –Year Ended December 31, 2018, Year Ended December 31, 2019, Year Ended December 31, 2020 and 2021 Developments” in this Annual Information Form, Note 7 to our audited consolidated financial statements for the year ended December 31, 2020 (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.

DIRECTORS AND EXECUTIVE OFFICERS OF OBSIDIAN ENERGY

The following table sets forth, as at March 26, 2021, 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.

Name, Province/State and Country ofResidence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five PrecedingYears
John Brydson^(1)(3)^<br><br><br>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<br>management consulting firm that he founded. Prior thereto, a Managing Director with Credit Suisse First Boston (now Credit Suisse).

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Name, Province/State and Country ofResidence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five PrecedingYears
Raymond Crossley^(1)(2)^<br><br><br>Alberta, Canada	Director since March 6, 2015	Corporate director, and serves on the boards of Alberta Securities Commission and Canada West Foundation (Chair). Mr.<br>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<br>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<br>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<br>holds the ICD.D designation from the Institute of Corporate Directors.
Michael J. Faust^(3)^<br><br><br>Alaska, USA	Director since May 11, 2018<br><br><br>Appointed Interim President and Chief Executive Officer from March 2019 to December 5, 2019	Mr. Faust is currently Chairman and CEO of SAExploration Holdings, Inc., where he was a director until he joined<br>management. He is also a director of Parker Drilling and he was the Vice President, Exploration and Land at ConocoPhillips Alaska, Inc. Mr. Faust received a Master of Arts degree in Geophysics from the University of Texas in 1984, and Bachelor of<br>Science degree in Geology from the University of Washington in 1981.
William A. Friley^(2)(3)^<br><br><br>Alberta, Canada	Director since March 12, 2015	President and CEO of Telluride Oil and Gas Ltd. and Skyeland Oils Ltd. On the board of directors of: OSUM Oil Sands Corp.,<br>Titan Energy Services, and Advanced Flow Technologies. He is also now the Chairman Emeritus to the Alberta Region board of the Nature Conservancy of Canada.
Maureen Cormier Jackson^(1)(2)^<br><br><br>Alberta, Canada	Director since March 8, 2016	Independent businesswoman with over 35 years of executive, financial and operational expertise in the oil and gas industry.<br>From 2012 and until her retirement in 2014, was Senior Vice President, Chief Process and Information Officer at Suncor Energy Inc. (“Suncor”). Her career spanned numerous roles at Suncor which provided experience in the areas of accounting<br>and financial controls, environment, health and safety, and project management. Is also a director of Enerflex Ltd. and serves on the Dean’s Advisory Board of Dean of Medicine at the University of Calgary. Is a Chartered Professional Accountant<br>and holds a Bachelor of Commerce from Memorial University. She also holds an ICD.D designation from the Institute of Corporate Directors.

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Name, Province/State and Country ofResidence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five PrecedingYears
Edward H. Kernaghan^(2)(3)^<br><br><br>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<br>& 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<br>Company, Boralex Inc., Exco Technologies Ltd. and Black Diamond Group Limited.
Stephen E. Loukas<br><br><br>New York, USA	Director since May 11, 2018<br><br><br>Appointed Interim President and Chief Executive Officer on December 5, 2019	Partner, managing member, and portfolio manager at FrontFour Capital Group LLC. Previously, Mr. Loukas was a Director at<br>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<br>& Distribution Group of Scotia Capital. He has a B.A. in Finance and Accounting from New York University.
Gordon Ritchie<br><br><br>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<br>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<br>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<br>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<br>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<br>including Iteration Energy Ltd., Rock Energy Inc., and Beau Canada Exploration Ltd. Mr. Scott began his career with Amoco Canada Petroleum Company Ltd. in 1983.

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Name, Province/State and Country ofResidence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five PrecedingYears
Aaron Smith Alberta, Canada	Senior Vice President, Development and Operations since July 9, 2018	Mr. Smith joined the Company in July 2018 and brings over 20 years of engineering expertise across a broad range of<br>technical and leadership roles. Most recently, he held the position of Vice President, Production at Sinopec Canada where he led improvement efforts on margin and uptime performance. Prior to that appointment he led Development and<br>Marketing Teams and lead Cardium-focussed asset development teams.

Notes:

(1)	Member of the Audit Committee.
(2)	Member of the Human Resources, Governance and Compensation Committee.
---	---
(3)	Member of the Operations and Reserves Committee.
---	---

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 4.6 million Common Shares, or approximately six percent of the issued and outstanding Common Shares.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

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<br>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<br>while the director or executive officer was acting in the capacity as director, Chief Executive Officer or Chief Financial Officer; or
(b)	was subject to an Order that was issued after the director or executive officer ceased to be a director,<br>Chief Executive Officer or Chief Financial Officer and which resulted from an event that occurred while that person was acting in the capacity as director, Chief Executive Officer or Chief Financial Officer.
---	---

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<br>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<br>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<br>

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(b)	has, within the ten years before the date of this Annual Information Form, become bankrupt, made a proposal<br>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,<br>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. FYI 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 is President and Chief Executive Officer of SAExploration Holdings, Inc. (“SAEX”), and a number of its subsidiaries. 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 and CEO. 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:

(a)	any penalties or sanctions imposed by a court relating to securities legislation or by a securities<br>regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or
(b)	any other penalties or sanctions imposed by a court or regulatory body that would likely be considered<br>important to a reasonable investor in making an investment decision;
---	---

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”.

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Conflicts of Interest

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 obtained 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.

Promoters

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.

AUDIT COMMITTEE DISCLOSURES

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.

Composition of the Audit Committee and Relevant Education and Experience

As of the date hereof, the members of the Audit Committee are Raymond Crossley (Chairman), John Brydson and Maureen Cormier Jackson, 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.

John Brydson

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, and remains on its Board.

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Maureen Cormier Jackson

Ms. Cormier Jackson is an independent businesswoman with over 35 years of executive, financial and operational expertise in the oil and gas industry. From 2012 and until her retirement in 2014, Ms. Cormier Jackson was Senior Vice President, Chief Process and Information Officer at Suncor Energy Inc. (“Suncor”). Her career spanned numerous roles at Suncor which provided experience in the areas of accounting and financial controls, environment, health and safety, and project management. Ms. Cormier Jackson is also a director of Enerflex Ltd. and serves on the Dean’s Advisory Board of Dean of Medicine at the University of Calgary. Ms. Cormier Jackson is a Chartered Professional Accountant and holds a Bachelor of Commerce from Memorial University. She also holds an ICD.D designation from the Institute of Corporate Directors.

Raymond Crossley (Chairman)

Mr. Crossley is a corporate director, and serves on the boards of Stuart Olson Ltd., the Alberta Securities Commission and Canada West Foundation. Mr. Crossley is the chair of the board of Canada West Foundation. and is chair of the Audit Committee of the Stuart Olson board. 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.

Pre-Approval Policiesand Procedures for Audit and Non-Audit Services

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.

External Auditor Service Fees

The following table summarizes the fees billed to Obsidian Energy by Ernst & Young for external audit and other services during the periods indicated.

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Year	Audit Fees(1)()	Audit-Related Fees(2)()	Tax Fees(3)()
2019
2020

All values are in US Dollars.

Notes:

(1)	The aggregate fees billed by our external auditor in each of the last two fiscal years for audit services,<br>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<br>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 auditor for assurance and<br>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)). The services comprising the fees disclosed under this category principally<br>consisted of Obsidian Energy’s portion of fees for the Peace River Oil Partnership audit and certain audit and French translation costs associated with the Bonterra Offer.
---	---
(3)	The aggregate fees billed in the applicable fiscal year by our external auditor for professional services<br>for tax compliance, tax advice and tax planning.
---	---

Reliance on Exemptions

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.

Audit Committee Oversight

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.

DIVIDENDS AND DIVIDEND POLICY

Dividend Policy

The Company has not declared a dividend in the last three financial years. The Company does not currently anticipate paying any dividends in the future but will review that policy from time to time as circumstances warrant. 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 each of the note purchase agreements governing our Senior 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 Notes is available on SEDAR at www.sedar.com. For additional information regarding our credit facility and our Senior Notes, see “Capitalization of Obsidian Energy – Debt Capital”.

MARKET FOR SECURITIES

Trading Price and Volume

The following tables set forth certain trading information for the Common Shares in 2020 as reported by the TSX and the NYSE/OTCQX.

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	TSX
	Common Shareprice ()	Common Shareprice ()
Period	High	Low	Volume
January				2,198,982
February				1,382,456
March				3,447,719
April				2,701,386
May				3,089,983
June				3,327,513
July				2,835,678
August				1,584,155
September				829,460
October				456,866
November				979,902
December				2,024,303

All values are in US Dollars.

	NYSE/OTC (1)
	Common Shareprice (US)	Common Shareprice (US)
Period	High	Low	Volume
January				4,025,053
February				1,986,670
March				11,457,263
April				3,341,329
May				3,084,407
June				3,928,286
July				5,375,210
August				3,694,654
September				3,465,463
October				822,994
November				1,828,232
December				3,085,017

All values are in US Dollars.

(1)	The Company was de-listed from the NYSE in April 2020 and began trading on the OTC (first on the OTCQB and<br>then graduating to the OTCQX).

Prior Sales

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

Escrowed Securities and Securities Subject to Contractual Restriction on Transfer

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).

INDUSTRY CONDITIONS

Companies operating in the Canadian oil and 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 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.

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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 of 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.

Pricing and Marketing in Canada

Crude Oil

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.

Since early 2020, worldwide oversupply of oil, a potential lack of available storage capacity and decreased demand due to COVID-19 have had a significant impact on the price of oil. In an effort to stabilize global oil markets, OPEC and a number of other oil producing countries announced an agreement to cut oil production by approximately 10 million bbl/d in April 2020. This agreement contributed to rebalancing global oil markets. Although the production cuts were eased to approximately 7.2 million bbl/d in January 2021, they were generally extended into April 2021 and Saudi Arabia voluntarily cut its production by a further 1 million bbl/d during February to April 2021 These ongoing production cuts together with increased worldwide economic activity and improving economic forecasts as vaccine rollouts make headway against the COVID-19 pandemic have combined to maintain balanced global oil markets**.**

Natural Gas

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, liquefied natural gas (“LNG”) and other exports from North America and other contractual terms of sale.

Natural Gas Liquids

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.

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Exports from Canada

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. ****

Transportation Constraints and Market Access

One major constraint to the export of oil, natural gas and NGLs is the deficit of transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline and other transportation and export projects are underway, many proposed projects have been cancelled or delayed due to regulatory hurdles, court challenges and economic and other 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 at times experienced low commodity pricing relative to other markets over the last several years.

Producers negotiate with pipeline operators to transport their products to market on a firm, spot 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.

Under the Canadian Constitution, 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. ****

Oil Pipelines

Specific Pipeline Updates

The Enbridge Inc. (“Enbridge”) Line 3 replacement from Hardisty, Alberta to Superior, Wisconsin, previously expected to be in-service in late 2019, has faced significant delays due to permitting difficulties in the United States. However, Minnesota regulators approved the final required permit for the project in November 2020. Certain segments of the Line 3 replacement in North Dakota and Wisconsin are currently in operation and the Canadian portion of the replaced pipeline began commercial operation in December 2019. Construction of the Line 3 replacement in Minnesota began in early December 2020. Enbridge expects the line to be in service in the fourth quarter of 2021.

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 and it is expected to be in-service in December 2022.

On March 31, 2020, TC Energy Corporation (“TC Energy”) announced it would proceed with the Keystone XL Pipeline. TC Energy also announced that the Government of Alberta had made a US $1.1 billion equity investment in the project and would guarantee a US $4.2 billion project level credit facility. While construction on the Keystone XL Pipeline started in April 2020, the project remains subject to legal and regulatory barriers in the United States, including the cancellation of a presidential permit on January 20, 2021 that permits the Keystone XL Pipeline to operate across the international border. Construction on the project was halted following the cancellation of the presidential permit.

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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, potentially forcing the lines comprising this segment of the pipeline system to be shut down by May 2021. Enbridge filed a federal complaint in late November 2020 in the Unites States District Court for the Western District of Michigan and is seeking an injunction to prevent the termination of the easement. Enbridge 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.

Marine Tankers

The Oil Tanker Moratorium Act, 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 being built to, and export terminals being located on, the portion of the British Columbia coast subject to the moratorium.

Crude Oil and Bitumen by Rail

Following two train derailments that led to fires and oil spills in Saskatchewan, the federal government announced in February 2020 that trains hauling more than 20 cars carrying dangerous goods, including oil and diluted bitumen, would be subject to reduced speed limits. The order was updated in April 2020 and replaced in November 2020. The speed limits and other requirements established in Order MO 20-10 will remain in place until permanent rule changes are approved.

Enbridge Open Season

In August 2019, Enbridge initiated an open season for the Enbridge mainline system, which has historically operated as a common carrier oil pipeline system. A common carrier pipeline must accept all products offered to it for transportation. If there is insufficient capacity to transport the volumes offered, the available capacity is pro-rated to accommodate all shippers. The changes that Enbridge intends to implement include the transition of the mainline system from a common carrier to a primarily contract carrier pipeline, wherein shippers will have to commit to reserved space in the pipeline for a fixed term, with only 10% of available capacity reserved for nominations. If the service change is approved, shippers seeking firm capacity on the Enbridge system would no longer be able to rely on the nomination process and would have to enter long-term contracts for service.

Several shippers challenged Enbridge’s open season and, in particular, Enbridge’s ability to engage in an open season without first obtaining prior regulatory approval to implement a contract carriage model. Following an expedited hearing process, the CER decided to shut down the open season. On December 19, 2019, Enbridge applied to the CER for approval of the proposed service and tolling framework. The regulatory hearing process is currently underway and a final decision from the CER is not expected until mid-2021. If Enbridge receives CER approval, it intends to hold the open season by the end of 2021.

Natural Gas and LNG

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 in the last several years has generally been depressed relative to other markets.

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. However, in September 2019, the CER approved a policy change by TC Energy on its NOVA Gas Transmission Ltd. pipeline system (the “NGTL System”) to prioritize deliveries into storage (the “Temporary Service Protocol”). The change stabilized supply and pricing, particularly during periods of maintenance on the system, however in February 2021, the CER refused a request to extend the Temporary Service Protocol. In October 2020, TC Energy received federal approval to expand the NGTL System and the expanded NGTL System is expected to be fully operational by April 2022.

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Specific Pipeline and Proposed LNG Export Terminal Updates

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 “CGLPipeline”). Pre-construction activities on the LNG Canada facility began in November 2018, with a completion target of 2025.

In late 2019, TC Energy announced that it would sell a 65% equity interest in the CGL Pipeline to investment companies KKR & Co Inc. and Alberta Investment Management Corporation while remaining the pipeline operator. The transaction closed in May 2020. Despite its 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.

In addition to LNG Canada and the CGL Pipeline projects, the following is an update on various other LNG projects that have been proposed in Canada:

•	In December 2019, the CER approved a 40-year export license for the Kitimat LNG project, a proposed joint<br>venture between Chevron Canada Limited and Woodside Energy International (Canada) Limited. However, both partners are looking to sell some or all of their interest in the project.
•	Woodfibre LNG Limited, a subsidiary of Singapore-based Pacific Oil and Gas Ltd., has proposed to build the<br>Woodfibre LNG project, a small-scale LNG processing and export facility near Squamish, British Columbia. The British Columbia Oil and Gas Commission approved a project permit for the Woodfibre LNG project in July 2019 and a formal approval of the<br>project is expected in the third quarter of 2021, with construction beginning shortly thereafter.
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•	GNL Québec Inc., the proponent of the Énergie Saguenay Project, is currently working its way<br>through a federal impact assessment process for the construction and operation of an LNG facility and export terminal located on Saguenay Fjord, an inlet which feeds into the St. Lawrence River in Québec. The Énergie Saguenay Project<br>is currently slated for completion in 2026.
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•	Pieridae Energy Ltd.’s (“Pieridae”) proposed Goldboro LNG project, located in Nova<br>Scotia, would see LNG exported from Canada to European markets. Pieridae has agreements with Shell, upstream, and with Uniper, a German utility, downstream. The federal government has issued Goldboro LNG a 20-year export licence, but Pieridae has<br>delayed its final investment decision until mid-2021.
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•	Cedar LNG Export Development Ltd.’s Cedar LNG project near Kitimat, British Columbia, is currently in the<br>environmental assessment stage, with British Columbia’s Environmental Assessment Office conducting the environmental assessment on behalf of the Impact Assessment Agency of Canada (“IA Agency”).
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Curtailment

In December 2018, the Government of Alberta announced that it would mandate a short-term and temporary curtailment of provincial crude oil and bitumen production. Curtailment first took effect on January 1, 2019. As contemplated in the CurtailmentRules, the Government of Alberta, on a monthly basis, required oil and bitumen producers producing more than 20,000 bbl/d to limit their production according to a pre-determined formula that allocates production limits proportionately amongst all operators that are subject to curtailment orders.

As of December 2020, monthly oil production limits are no longer in effect. However, the Curtailment Rules, which were set to be repealed on December 31, 2020, have been extended such that the Government of Alberta retains the ability to impose future production limits if needed.

The Corporation was subject to a curtailment order in 2019 and 2020, however, given that new wells were exempt from the CurtailmentRules, our production volumes and capital spending were not materially affected by the order.

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International Trade Agreements

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, 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 have an impact on Western Canada’s oil and gas industry at large, 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.

Land Tenure

Mineral Rights

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.

In response to COVID-19, the governments of Alberta, British Columbia and Saskatchewan announced measures to extend or continue Crown leases that may have otherwise expired in the months following the implementation of pandemic response measures.

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. Until recently, oil and natural gas activities conducted on Indian reserve lands were governed by the Indian Oil and Gas Act (the “IOGA”) and the Indian Oil and Gas Regulations, 1995. In 2009, Parliament passed An Act to Amend the Indian Oil and Gas Act, amending and modernizing the IOGA (the “Modernized IOGA”); however the amendments were delayed until the federal government was able to complete stakeholder consultations and update the accompanying Regulations (the “2019 Regulations”). The Modernized IOGA and the 2019 Regulations came into force on August 1, 2019 and further regulations are currently being developed. The Corporation does not have operations on Indian reserve lands.

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Surface Rights

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.

Royalties and Incentives

General

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.

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, the provincial governments in Western Canada create incentive programs for the oil and 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.

The federal government also creates incentives and other financial aid programs intended to assist businesses operating in the oil and gas industry. Recently, these programs, including, but not limited to, programs that provide direct financial support to companies operating in the oil and gas industry and/or targeted funding for various initiatives related to industry diversification and environmental matters, including those programs created in response to the COVID-19 pandemic, such as various short-term loan programs and the Canada Emergency Wage Subsidy (“CEWS”), for example, have been administered through federal agencies such as the Business Development Bank of Canada, Natural Resources Canada, Export Development Canada, Innovation, Science and Economic Development Canada and, in some cases, the Canada Revenue Agency. In 2020, the Company benefited from the CEWS.

Alberta

Crown Royalties

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. The Mines and Minerals Act was amended in 2014 to shorten the window during which producers can submit amendments to their royalty calculations before they become statute-barred, from four years to three.

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.

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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 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.

Freehold Royalties and Taxes

Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner.

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.

Regulatory Authorities and Environmental Regulation

General

The Canadian oil and 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 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 gas industry.

Federal

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.

On August 28, 2019, the Impact Assessment Act (the “IAA”) replaced the CanadianEnvironmental Assessment Act, 2012. The enactment of the CERA and the IAA introduced a number of important changes to the regulation of federally regulated major projects and their associated environmental assessments. The CERA separates the CER’s administrative and adjudicative functions. A board of directors and a chief executive officer manage strategic, administrative and policy considerations while adjudicative functions fall to independent commissioners. 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.

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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 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 gas industry include pipelines that require more than 75 kilometers of new right 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. The Government of Alberta has submitted a reference question to the Alberta Court of Appeal regarding the constitutionality of the IAA, but this matter remains before the courts.

Alberta

The AER is the principal regulator responsible for all energy resource development in Alberta. It derives its authority from the ResponsibleEnergy 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 andEnhancement 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 Surface Rights Board, 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 in Alberta 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.

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Liability Management Rating Program

Alberta

The AER administers a Liability Management Rating Program (the “AB LMR Program”), which is currently undergoing changes, including a name change to the “Liability Management Framework” (the “AB LMF”); however, specific details concerning this new program remain forthcoming. The AB LMR Program, as currently administered, is a liability management program governing most conventional upstream oil and natural gas wells, facilities and pipelines. It consists of three distinct programs: the Oilfield Waste Liability Program (the “AB OWL Program”), the Large Facility Liability Management Program (the “AB LFP”), and the Licensee Liability Rating Program (the “AB LLR Program”). If a licensee’s deemed liabilities in the AB LLR Program, the AB OWL Program and/or the AB LFP exceed its deemed assets in those programs, the licensee must reduce its liabilities or provide the AER with a security deposit. Failure to do so may restrict the licensee’s ability to transfer licenses. This ratio of a licensee’s assets to liabilities across the three programs is referred to as the licensee’s liability management rating (“LMR”).

Complementing 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 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 licenses subject to the AB LFP. 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.

In response to the increase in orphaned oil and gas sites and the environmental risks associated therewith, the AER amended its Directive067: Eligibility Requirements for Acquiring and Holding Energy Licenses and Approvals (“Directive 067”), which deals with licensee eligibility to operate wells and facilities, to require the provision of extensive corporate governance and shareholder information. All transfers of well, facility and pipeline licenses in the province are subject to AER approval. As a condition of transferring existing AER licenses, approvals and permits, all transfers are now assessed on a non-routine basis and the AER now requires all transferees to demonstrate that they have an LMR of 2.0 or higher immediately following the transfer, or to otherwise prove to the satisfaction of the AER that they can meet their abandonment and reclamation obligations, such as by posting security or reducing their existing obligations.

As a result of the Supreme Court of Canada’s decision in Orphan Well Association v Grant Thornton (also known as 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 license 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 will come into force on proclamation.

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Additionally, the Government of Alberta announced in July 2020 that the AB LMF will replace the AB LMR Program and its constituent programs. Among other changes under the AB LMF, the AB LMR Program will be replaced with the Licensee Capability Assessment System, which is intended to be a more comprehensive assessment of corporate health and will consider a wider variety of factors than those considered under the AB LMR Program and establish clear expectations for industry with regards to the management of liabilities throughout the entire lifecycle of oil and gas projects. Importantly, the AB LMF will also provide proactive support to distressed operators and will require mandatory annual minimum payments towards outstanding reclamation obligations in accordance with five-year rolling spending targets.

The Government of Alberta followed the announcement of the AB LMF 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.

The AER has published a draft of an amended Directive 067 to implement some of these changes (the “Draft Directive”). The changes introduced by the Draft Directive include building on the AER’s corporate and financial disclosure requirements for parties who wish to acquire, hold or transfer licenses in Alberta, and broadening the AER’s discretion to withhold or revoke licensees’ privileges if they are assessed as posing an “unreasonable risk”. The feedback that the AER receives will be considered in the determination of the final revised Directive 067, and the rollout of the AB LMF may require changes to other directives as well. As a result, the Corporation’s ongoing and future transactions may be affected in this period of transition, resulting in processing delays for license transfers and regulatory uncertainty as the criteria and requirements for licensees are subject to change.

To address abandonment and reclamation liabilities in Alberta, the AER implements, from time to time, programs intended to encourage the decommissioning, remediation and reclamation of inactive or marginal oil and natural gas infrastructure. Beginning in 2015, for example, the AER oversaw the Inactive Well Compliance Program, a five-year program intended to address the growing inventory of inactive and noncompliant wells in Alberta. More recently, the AER announced a voluntary area-based closure (“ABC”) program in 2018. The ABC program is designed to reduce the cost of abandonment and reclamation operations though industry collaboration and economies of scale. Parties seeking to participate in the program must commit to an inactive liability reduction target to be met through closure work of inactive assets. The Corporation is currently participating in the voluntary ABC program.

Federal andProvincial Support for Liability Management

As part of an announcement of federal relief for Canada’s oil and gas industry in response to COVID-19, the federal government pledged $1.72 billion to clean up orphan and inactive wells in Alberta, Saskatchewan and British Columbia. However, these funds are being administered by regulatory authorities in each province. In Alberta, the Ministry of Energy is disbursing its $1 billion share of the federally provided funds through the Site Rehabilitation Program. The Company has received $30 million of grants and allocations to-date under the program. In addition to the funds administered by the respective provincial governments, the federal government announced a $200 million loan to Alberta’s Orphan Fund.

Climate Change Regulation

Climate change regulation at each of the international, federal and provincial levels has the potential to significantly affect the future of the oil and 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.

Federal

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. Decisions about a prospective carbon market and emissions cuts have been delayed until the next climate conference, which is scheduled to take place in November 2021.

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The Government of Canada has pledged to cut its emissions by 30% from 2005 levels by 2030, but indicated in its recent Speech from the Throne (also referred to as the “Throne Speech”) that it may implement policy changes to exceed this target. Specific details have not yet been announced.

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. Under current federal plans, this price will escalate by $10 per year until it reaches a price of $50/tonne of CO2e in 2022. On December 11, 2020, however, the federal government announced its intention to continue the annual price increases beyond 2022, such that, 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. Starting April 1, 2021, the minimum price permissible under the GGPPA is $40/tonne of CO2e. In addition, on March 5, 2021, the federal government introduced for comment the Greenhouse Gas Offset Credit System Regulations (Canada) (the “Federal Offset CreditRegulations”). The proposed Federal Offset Credit Regulations are intended to establish a regulatory framework to allow certain kinds of projects to generate and sell offset credits for use in the federal OBPS. The final Federal Offset Credit Regulations are expected to be put in place before the end of 2021.

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 VolatileOrganic 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 CanadianEnvironmental Protection Act, 1999, which regulates certain industrial facilities and equipment types, including boilers and heaters used in the upstream oil and gas industry, to limit the emission of air pollutants such as nitrogen oxides and sulphur dioxide.

As part of its efforts to provide relief to Canada’s oil and gas industry in light of the COVID-19 pandemic, the federal government announced a $750 million Emissions Reduction Fund intended to support pollution reduction initiatives, including methane. Funds disbursed through this program will primarily take the form of repayable contributions to onshore and offshore oil and gas firms.

The federal government has also announced that it will implement a Clean Fuel Standard that will require producers, importers and distributors to reduce the emissions intensity of liquid fuels. It is expected that the applicable regulations will come into force in December 2022.

In the September 23, 2020 Throne Speech, the federal government has indicated that it intends to make a number of investments that will help it achieve net-zero emissions by 2050, including investments intended to: (i) improve transit options; (ii) make zero-emissions vehicles more affordable; (iii) expand electric vehicle charging infrastructure across the country; (iv) launch a fund that will help attract investments in the development of zero-emissions technology, including a corporate tax cut of 50% for companies participating in this initiative; (v) develop a Clean Power Fund that will, in part, help regions transition to cleaner sources of power generation; and (vi) support continued investment in the development and implementation of renewable and clean energy technologies. Specific program details have not yet been announced.

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On November 19, 2020, the federal government introduced the Canadian Net-ZeroEmissions Accountability Act in Parliament. If passed, this Act will bind the Government of Canada to a process intended to help Canada achieve net-zero emissions by 2050. It will also establish rolling five-year emissions-reduction targets and require the government to develop plans to reach each target and support these efforts by creating a Net-Zero Advisory Body and require 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.

Alberta

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.

In June 2019, the federal fuel charge took effect in Alberta. In accordance with the GGPPA, the fuel charge payable in Alberta will increase from $30/tonne of CO2e to $40/tonne of CO2e on April 1, 2021. 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 CarbonCompetitiveness Incentives 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 2021. To encourage compliance with the emissions intensity reduction targets, TIER-regulated facilities must provide annual compliance reports and 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 EmissionReduction Regulation on January 1, 2020, and the AER simultaneously released an updated edition of Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting. The release of the updated Directive 060 complements a previously released update to Directive 017: Measurement Requirements for Oil and Gas Operations that took effect in December 2018. Together, these directives will support Alberta in achieving its 2025 goal. 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.

Indigenous Rights

Constitutionally mandated government-led consultation with and, if applicable, accommodation 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 gas industry. In addition, Canada is a signatory to the UnitedNations 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 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 December 2020, the federal government introduced Bill C-15: An Act respecting the United Nations Declaration on the Rights of Indigenous Peoples Act (“Bill C-15”). Similar to British Columbia’s DRIPA, the intention of Bill C-15, if passed, is to establish a process whereby the Government of Canada will 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 DRIPA and Bill C-15 are expected to continue to add uncertainty to the ability of entities operating in the Canadian oil and gas industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines.

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Obsidian Energy and the Environment

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 conduct 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.

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 its 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 shut-in facilities. For information regarding our estimated future abandonment and reclamation costs as of December 31, 2020, see “– Disclosure of Reserves Data – Total Future Net Revenue (Undiscounted) as of December 31, 2020 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 facility” 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 and 1% per year until 2022, but unlike large emitters, this requirement does not become more stringent over time. 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 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.

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.

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RISK FACTORS

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. Securityholders and potential securityholders 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.

The COVID-19 pandemic may adversely affect our business, operational results, financialcondition and/or liquidity.

Pandemics, epidemics or outbreaks of an infectious disease in Canada or worldwide, including COVID-19, Middle East Respiratory Syndrome, Severe Acute Respiratory Syndrome, H1N1 influenza virus, avian flu or any other similar illnesses, could have an adverse impact on our business, operational results, financial condition and/or liquidity.

On March 11, 2020, the World Health Organization declared the outbreak of a strain of novel coronavirus disease, COVID-19, to be a global pandemic. The COVID-19 pandemic has negatively impacted the Canadian, U.S., and global economies; disrupted Canadian, U.S., and global supply chains; disrupted financial markets; contributed to a decrease in interest rates; resulted in ratings downgrades, credit deterioration and defaults in many industries; forced the closure of many businesses, led to loss of revenues, increased unemployment and bankruptcies; and necessitated the imposition of quarantines, physical distancing, business closures, travel restrictions, and sheltering-in-place requirements in Canada, the U.S., and other countries. If the pandemic is prolonged, including through subsequent waves, or if additional variants of COVID-19 emerge which are more transmissible or cause more severe disease, or if other diseases emerge with similar effects, the adverse impact on the economy could worsen. Moreover, it remains uncertain how the macroeconomic environment, and societal and business norms, will be impacted following the COVID-19 pandemic. Unexpected developments in financial markets, regulatory environments, or consumer behaviour may also have adverse impacts on our business, operational results, financial condition and/or liquidity, and these adverse impacts could persist for a substantial period of time.

Our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, and/or business plans may, in particular, and without limitation, be adversely impacted as a result of the pandemic as a result of:

•	the shut-down of facilities or the delay or suspension of work on major capital projects due to workforce<br>disruption or labour shortages caused by workers becoming infected with COVID-19, or government or health authority mandated restrictions on travel by workers or closure of facilities or worksites;
•	suppliers and third-party vendors experiencing similar workforce disruption or being ordered to cease<br>operations;
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•	reduced cash flows resulting in less funds from operations being available to fund capital expenditure<br>budgets;
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•	reduced commodity prices resulting in a reduction in the volumes and value of reserves;
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•	crude oil storage constraints resulting in the curtailment or shutting in of production;<br>
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•	counterparties being unable to fulfill their contractual obligations on a timely basis or at all;<br>
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•	the inability to deliver products to customers or otherwise get products to market caused by border<br>restrictions, road or port closures or pipeline shut-ins, including as a result of pipeline companies suffering workforce disruptions or otherwise being unable to continue to operate; and
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•	the ability to obtain additional capital including, but not limited to, debt and equity financing, being<br>adversely impacted as a result of unpredictable financial markets, decreased and volatile commodity prices and/or a change in market fundamentals.
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The COVID-19 pandemic has also created additional operational risks for us, including the need to: provide enhanced safety measures for our employees and customers; comply with rapidly changing regulatory guidance; address the risk of attempted fraudulent activity and cybersecurity threat behaviour; and protect the integrity and functionality of the Corporation’s systems, networks, and data as a larger number of employees work remotely. We are also exposed to human capital risks due to issues related to health and safety matters, and other environmental stressors as a result of measures implemented in response to the COVID-19 pandemic, as well as the potential for a significant proportion of our employees, including key executives, to be unable to work effectively, because of illness, quarantines, sheltering-in-place arrangements, government actions or other restrictions in connection with the pandemic.

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The extent to which the COVID-19 pandemic continues to impact our business, operational results, financial condition and/or liquidity will depend on future developments in Canada, the U.S. and globally, including the development and widespread availability of efficient and accurate testing options, and effective treatment options or vaccines. Despite the approval of certain vaccines by the regulatory bodies in Canada and the U.S., the ongoing evolution of the development and distribution of an effective vaccine also continues to raise uncertainty.

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 and natural gas that we sell. Historically, the oil and natural gas markets have been volatile and are likely to continue to be volatile in the future. Oil 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 impact of regional and/or global health related events, such as the ongoing COVID-19 pandemic, on economic<br>activity levels and energy demand;
•	global energy policy, including the ability of OPEC (and in particular the Kingdom of Saudi Arabia) and other<br>oil and natural gas exporting nations (and in particular Russia) to set and maintain production levels and influence prices for oil;
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•	the limitations on the ability of Western Canadian energy producers to export oil, natural gas and natural gas<br>liquids 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;
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•	the availability of transportation infrastructure, and in particular:
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•	our ability to access space on pipelines that deliver crude oil, natural gas liquids and natural gas to<br>commercial markets or alternatively contract for the delivery of our products by rail;
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•	deliverability uncertainties related to the distance of our production from existing pipeline, railway line,<br>processing and storage facility infrastructure; and
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•	operational problems affecting the pipelines, railway lines and processing and storage facilities on which we<br>rely;
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•	increased growth of shale oil and natural gas production in the U.S.;
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•	production and storage levels of oil and natural gas;
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•	existing and threatened political instability and hostilities in commodity producing regions such as the<br>Middle East, Northern Africa and elsewhere;
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•	sanctions imposed on certain oil producing nations by other countries;
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•	foreign supply of, and demand for, oil and natural gas, including liquefied natural gas;<br>
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•	weather conditions;
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•	the overall economic and political environment in Canada, the U.S., Europe, China, Russia, emerging markets<br>and globally;
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•	the overall level of energy demand;
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•	government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of<br>oil and natural gas and many other aspects of the oil and natural gas business;
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•	currency exchange rates;
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•	the effect of worldwide environmental and/or energy conservation measures;
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•	the price and availability of alternative energy supplies; and
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•	the advent of new technologies.
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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.

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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 Corporation’s 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.

Weakness and volatility in market conditions for the oil and gasindustry 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 crude 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 Iran and Venezuela, slowing growth in China and emerging economies, weakened global relationships, conflict between the U.S. and Iran, isolationist and punitive trade policies, U.S. shale production, sovereign debt levels and political upheavals in various countries, including growing anti-fossil fuel sentiment, have caused significant weakness and volatility in commodity prices. These events and conditions have 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 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 has led to additional downward price pressure on oil and gas produced in western Canada. The resulting price differential between Western Canadian Select crude oil and Brent and West Texas Intermediate crude oil has 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 current market conditions and the lack of confidence in the Canadian oil and natural gas industry, 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 persist, our cash flow may not be sufficient to continue to fund our operations and satisfy our obligations when due, and our ability to continue as a going concern and discharge our obligations will 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 discharge our obligations and continue as a going concern.

Acquiring, exploring for, developing, and producing from oil and natural gas assets involves many risks. Losses resulting from theoccurrence 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.

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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. 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.

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

•	encountering unexpected formations or pressures;
•	premature declines of reservoirs;
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•	the invasion of water into producing formations;
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•	blowouts, explosions, equipment failures and other accidents;
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•	sour gas releases;
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•	uncontrollable flows of oil, natural gas or well fluids;
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•	personal injury to staff and others;
---	---
•	adverse weather conditions, such as wild fires, flooding and extreme cold temperatures; and<br>
---	---
•	pollution and other environmental risks, such as fires and spills.
---	---

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. Particularly, 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.

Modification to current or implementation of additional regulations may reduce the demand for oil and natural gasand/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 crude 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. 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 gas industry. See “Industry Conditions”.

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In order to conduct oil and natural gas operations, we will 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 the Corporation’s 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’ sentiments towards investing in the oil and natural gas industry. As a result of these concerns, some institutional, retail and governmental investors have announced that they no longer are willing to fund or invest in oil and natural gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices and 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 the Board, management and employees of the Corporation. Failing to implement the policies and practices, or make the related disclosures, as requested by institutional investors may result in such investors reducing their investment in the Corporation or not investing in the Corporation at all. Any reduction in the investor base interested or willing to invest in the oil and natural gas industry and more specifically, the Corporation, may result in limiting the Corporation’s access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares, even if the Corporation’s operating results, underlying asset values or prospects have not changed or have improved. Additionally, these factors, as well as other related factors, may cause a decrease in the value of the Corporation’s assets which may result in an impairment charge.

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

The trading price of 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 gas market. In recent years, the volatility of commodities has increased due to, in part, the implementation of computerized trading and the decrease of discretionary commodity trading. In addition, the volatility, trading volume and share price of issuers have 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 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.

If we are unable to acquire or develop additionalreserves, the value of our Common Shares will decline.

Absent free cash flow, equity capital injections, increased debt levels and/or the efficient deployment of capital investments by us, our production levels and reserves will decline over time.

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.

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To the extent that free cash flow or external sources of capital, including the issuance of additional Common Shares, become limited or unavailable, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be impaired.

Liability management programs enacted by regulators in the western provinces may prevent or interfere with the Corporation’sability to acquire or dispose of properties or require the Corporation to make a substantial cash deposit with a regulator.

Alberta has developed a liability management program designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder is unable to satisfy its regulatory obligations. Changes to the AB LMR Program administered by the AER are currently underway. In July 2020, the Government of Alberta announced that the AB LMR Program and associated programs will be replaced by the “Liability Management Framework” (the “AB LMF Program”). Changes to the requirements of liability management programs may result in significant increases to the Corporation’s compliance obligations. The impact and consequences of the Supreme Court of Canada’s decision in the Redwater decision on the AER’s rules and policies, lending practices in the crude oil and natural gas sector and on the nature and determination of secured lenders to take enforcement proceedings are evolving as the consequences of the decision are evaluated and considered by regulators, lenders and receivers/trustees. As a result of the decision, the Government of Alberta implemented the Liabilities Management Statutes and Amendment Act, which places the financial burden of a defunct licensee’s abandonment and reclamation obligations on the working interest partners of the defunct licensee and may order the AER’s Orphan Fund to assume custody of wells or sites without a responsible owner to expedite the cleanup process.

In addition, the AB LMF Program may prevent or interfere with the Corporation’s ability to acquire or dispose of assets as both the vendor and the purchaser of oil and natural gas assets must be in compliance with the liability management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the transfer of such assets. This is of particular concern to junior oil and natural gas companies that may be disproportionately affected by price instability. See “Industry Conditions – Regulatory Authorities and Environmental Regulation – Liability Management Rating Program”.

The price of oil and natural gas is affected by political events throughout the world. Any such event couldresult 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, 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.

Our business may be adversely affected by recent and future political and social events anddecisions made in Canada, the United States, Europe and elsewhere.

In the last several years, the United States and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. During its tenure, the former American administration withdrew the United States from the Trans-Pacific Partnership and passed sweeping tax reform, which, among other things, significantly reduced U.S. corporate tax rates. This has affected the competitiveness of other jurisdictions, including Canada. The former U.S. administration also took action to reduce regulation, which affected relative competitiveness of other jurisdictions. In addition, the United States Mexico Canada Agreement, which replaced the former North American Free Trade Agreement, was ratified on July 1, 2020 and may impact our business. See “Industry Conditions”.

The newly-inaugurated Biden administration in the U.S. has indicated that it will roll-back certain policies of the former administration, and has taken action to cancel TC Energy’s Keystone X.L. pipeline permit. While it is unclear which other legislation or policies of the former Trump administration will be rolled-back and if such roll-backs will be a priority of the new administration in light of the ongoing COVID-19 pandemic, any future actions taken by the new U.S. administration could have a negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of Canadian oil and natural gas companies, including the Corporation.

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In addition to the changing political landscape in the United States, the impact of the United Kingdom’s exit from the European Union are slowly emerging and some impacts may not become apparent for some time. Some European countries have also experienced the rise of anti-establishment political parties and public protests held against open-door immigration policies, trade and globalization. Conflict and political uncertainty also continues to progress in the Middle East. To the extent that certain political actions taken in North America, Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement, it could have an adverse effect on the Corporation’s ability to market our products internationally, increase costs for goods and services required for the Corporation’s operations, reduce access to skilled labour and negatively impact the Corporation’s business, operations, financial conditions and the market value of our Common Shares.

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 gas industry, including the balance between economic development and environmental policy.

The United Conservative Party government in Alberta is supportive of the Trans Mountain Pipeline expansion project and, although there has been notable opposition from the government of British Columbia (which appears to have run its course in the courts), the federal Government remains in support of the project. Continued uncertainty and delays have led to decreased investor confidence, increased capital costs and operational delays for producers and service providers operating in western Canada. See “Industry Conditions”.

The federal Government was re-elected in 2019, but in a minority position. The ability of the minority federal government to pass legislation will be subject to whether it is able to come to agreement with, and garner the support of, the other elected parties, most of whom are opposed to the development of the oil and natural gas industry. The minority federal government will also be required to rely on the support of the other elected parties to remain in power, which provides less stability and may lead to an earlier subsequent federal election. Lack of political consensus, at both the federal and provincial level, continues to create regulatory uncertainty, the effects of which become apparent on an ongoing basis, particularly with respect to carbon pricing regimes, curtailment of crude oil production and transportation and export capacity, and may affect the business of participants in the oil and natural gas industry. See “Industry Conditions”.

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 and demonstrations have the potential to delay and disrupt our activities. See “Industry Conditions”.

Climate change may pose varied and far ranging risks to the business and operations of the Corporation, both known and unknown,that may adversely affect the Corporation’s business, financial condition, results of operations, prospects, reputation and Common Share price.

Our exploration and production facilities and other operations and activities emit greenhouse gases which may require us to comply with GHG emissions legislation at the provincial or federal level. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place to prevent climate change or mitigate its effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. Some of the Corporation’s significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions.

Climate change has been linked to long-term shifts in climate patterns, including sustained higher temperatures. As the level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns, long-term shifts in climate patterns pose the risk of exacerbating operational delays and other risks posed by seasonal weather patterns. In addition, long-term shifts in weather patterns such as water scarcity, increased frequency of storms and fires and prolonged heat waves may, among other things, require the Corporation to incur greater expenditures (time and capital) to deal with the challenges posed by such changes to its premises, operations, supply chain, transport needs, and employee safety. Specifically, in the event of water shortages or sourcing issues, the Corporation may not be able to, or will incur greater costs to, carry out hydraulic fracturing operations.

44

Climate change has been linked to extreme weather conditions. 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 machinery and facilities. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions. Certain of the Corporation’s assets are located in locations that are proximate to forests and rivers and a wildfire and/or flood may lead to significant downtime and/or damage to such assets. Moreover, extreme weather conditions may lead to disruptions in the Corporation’s ability to transport produced oil and natural gas as well as goods and services in our supply chain.

Concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation and development of fossil fuels which has influenced investors’ willingness to invest in the oil and natural gas industry. Historically, political and legal opposition to the fossil fuel industry focused on public opinion and the regulatory process. More recently, however, there has been a movement to more directly hold governments and oil and natural gas companies responsible for climate change through climate litigation. In recent years, climate change advocacy groups have attempted to bring legal action against various levels of government for climate-related harms.

Given the evolving nature of climate change policy and the control of GHG emissions and resulting requirements, 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 and natural gas production resulting in a decrease in the Corporation’s profitability and a reduction in the value of our assets or requiring asset impairments for financial statement purposes.

See “Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation”.

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

Fuel conservation measures, alternative fuel requirements, 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, 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 its costs, limiting its access to capital and decreasing the value of our assets.

We may not be able to repay all or part of our indebtedness, or alternatively, refinance all or part of ourindebtedness 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 adverseeffect 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 revolving credit facility in place that has an amount available to be drawn totalling $440 million. The $440 million of availability consists of a $225 million revolving credit facility and a $215 million non-revolving term loan. The revolving period under the syndicated credit facility ends on May 31, 2022, with the end date of the term period extended to November 30, 2022. The maturity date of the non-revolving term loan is also November 30, 2022. The next scheduled borrowing base redeterminations will occur on November 30, 2021 and May 31, 2022. As of December 31, 2020, there was $395 million drawn on our credit facility. In the event that our credit facility is not extended before the maturity date, all outstanding indebtedness under such tranche will be repayable at that date. The Company also has a borrowing base reconfirmation date on January 17, 2022 at which point the bank syndicate may end the revolving period on February 1, 2022. In addition, our revolving credit facility will have a one-time adjustment to reduce our undrawn availability to $35 million at December 31, 2021. Any borrowing availability at this time in excess of that amount will be used to reduce amounts outstanding on the non-revolving term loan and senior notes. There is also 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.

In addition, the Corporation’s credit facility 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 disposition of assets, among others.

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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 have fallen dramatically since 2014, and while prices have recently increased, they remain volatile as a result of various factors, including sharply decreased demand for crude oil due to the COVID-19 pandemic, limited egress options for Western Canadian oil and natural gas producers, actions taken to limit OPEC and non-OPEC production, limited storage capacity, and increasing production by U.S. shale producers. Depressed 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 US$47 million principal amount of Senior Notes outstanding, which are due on November 30, 2022. In the event we are unable to repay or refinance these debt obligations (or if we must refinance these debt obligations on less favourable terms) it may adversely affect our ability to fund our ongoing operations.

We are required to comply with covenants under our credit facilities and Senior Notes which may, in certain cases, include certain financial ratio tests which, from time to time, 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 Notes, which could result in the Corporation being required to repay amounts owing thereunder.

The Supreme Court of Canada’s decision in Redwater has given rise to new covenants and restrictions under the Corporation’s credit facilities, should liability management rating (or LMR) levels fall below existing agreed-upon thresholds, including further limitations on asset dispositions and acquisitions. The Corporation may also be required to provide additional reporting to our lenders regarding our existing and/or budgeted abandonment and reclamation obligations, our decommissioning expenses, our LMR and/or any notices or orders received from an energy regulator in any applicable province. The Corporation’s lenders may also be permitted to re-determine the Corporation’s borrowing base (at the sole cost of the Corporation) following a decline in its LMR below a certain threshold or if the Corporation becomes subject to an abandonment and reclamation order and our estimated cost of compliance with such order exceeds a certain threshold. See “Industry Conditions – Regulatory Authorities and Environmental Regulation – Liability Management Rating Program”.

If the Corporation’s lenders require repayment of all or a portion of the amounts outstanding under our credit facilities for any reason, including for a default of a covenant or the reduction of a borrowing base, 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, 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, the lenders under such credit facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.

Increased debt levels may impair the Corporation’s ability to borrow additional capital on a timely basis to fund opportunities asthey arise.

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.

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Our hedging program subjects us to certain risks, including financial loss andcounterparty risk.

From time to time, the Corporation may enter into agreements to receive fixed prices on our oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, to the extent that the Corporation engages in price risk management activities to protect us 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, the Corporation’s hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

•	production falls short of the hedged volumes or prices fall significantly lower than projected;<br>
•	there is a widening of price-basis differentials between delivery points for production and the delivery point<br>assumed in the hedge arrangement;
---	---
•	the counterparties to the hedging arrangements or other price risk management contracts fail to perform under<br>those arrangements; or
---	---
•	a sudden unexpected event materially impacts oil and natural gas prices.
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Similarly, from time to time the Corporation 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, the Corporation will not benefit from the fluctuating exchange rate.

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.

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate hydrocarbon (natural gas and oil) production. Hydraulic fracturing is used to produce commercial quantities of natural gas and oil from reservoirs that were previously unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delay or increased operating costs or third party or governmental claims, and could increase our cost of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Minor earthquakes have occurred in certain parts of Alberta, and are generally clustered around the municipalities of Cardston, Fox Creek, Rocky Mountain House, Brazeau and Red Deer. Since 2015, the AER has introduced seismic protocols for hydraulic fracturing operators in the Fox Creek, Red Deer and Brazeau areas (collectively, the “Seismic Protocol Regions”) – initially in response to significant induced seismic activity in the Duvernay formation in Fox Creek in February 2015. Oil and natural gas producers in each of the Seismic Protocol Regions (which includes the Corporation, as we own oil and natural gas assets in the Brazeau area) are subject to a “traffic light” reporting system that sets thresholds on the Richter scale of earthquake magnitude which vary among the three regions. The reporting requirements include an assessment of the potential for seismicity prior to conducting operations, the implementation of a response plan to address potential seismic events and the suspension of operations, depending on the magnitude of an earthquake. Orders imposed by the AER in response to seismic events remain in effect as long as the AER deems them necessary. In recent years, hydraulic fracturing has been linked to increased seismicity in the areas in which hydraulic fracturing takes place, leading to continued monitoring by the AER. The AER may extend seismic protocols to other areas of the province if necessary. See “Industry Conditions”.

Regulatory water use restrictions and/or limited access to water or other fluids may impact the Corporation’s production volumesfrom 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 its 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.

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

World oil and natural gas prices are 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 which could negatively impact the market price of the Common Shares.

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

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 of processing capacity;
•	the availability and proximity of transportation infrastructure, including pipeline capacity;<br>
---	---
•	the availability of storage capacity;
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•	the availability of, and the ability to acquire, water supplies needed for drilling, hydraulic fracturing and<br>waterfloods, or our ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations;
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•	the supply of and demand for oil and natural gas;
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•	the availability of alternative fuel sources;
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•	the effects of inclement and severe weather events, including fire, drought, flooding and extreme cold<br>temperatures;
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•	the availability of drilling and related equipment;
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•	unexpected cost increases;
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•	accidental events;
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•	currency fluctuations;
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•	changes in regulations;
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•	the availability and productivity of skilled labour; and
---	---
•	the regulation of the oil and natural gas industry by various levels of government and governmental agencies.<br>
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Because of these factors, we could be unable to execute projects on time, on budget, or at all.

A decrease in the fair market value of our hedging instruments could result in a non-cash charge against our income under applicableaccounting 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 hedging instruments. A decrease in the fair market value of the hedging 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.

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The incorrect assessment of value at the time of acquisitions could adversely affectthe 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 made by independent engineers. 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.

Actual reserves and resources will vary from reserves and resources estimates and those variationscould 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 natural gas liquid reserves and resources and future cash flows to be derived therefrom, including many factors beyond our control. The reserves and associated 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:

•	historical production from the properties;
•	estimated production decline rates;
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•	estimated ultimate recovery of reserves and resources;
---	---
•	changes in technology;
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•	timing and amount and effectiveness of future capital expenditures;
---	---
•	marketability and price of oil and natural gas;
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•	royalty rates;
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•	the assumed effects of regulation by governmental agencies; and
---	---
•	future operating costs;
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all of which may vary materially from actual results.

As a result, estimates of the economically recoverable oil 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 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, Sproule has 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 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 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 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.

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Lack of capacity and/or regulatory constraints on gathering and processing facilities,pipeline systems 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 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 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. However, in early 2020, the legal challenges to Cabinet’s approval of the Trans Mountain Pipeline expansion were dismissed, and construction on the pipeline expansion is underway. See “Industry Conditions”. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability of oil and 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. As a result, producers have turned to rail as an alternative means of transportation and competition for contracting rail capacity increased significantly prior to the COVID-19 pandemic. Prior to the onset of the COVID-19 pandemic, the volume of crude oil shipped by rail in North America had increased dramatically. 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. Announcements and actions taken by the federal government and the provincial governments of British Columbia, Alberta and Quebec relating to approval of infrastructure projects may continue to intensify, leading to increased challenges to interprovincial and international infrastructure projects moving forward. In August 2019, the Canadian Energy Regulator Act and the Impact Assessment Act came into force, resulting in changes to the federal regulation and associated environmental assessments of major projects. See “Industry Conditions – Regulatory Authorities and Environmental Regulation”. The impact of the new federal regulatory scheme on proponents, and the timing for receipt of approvals of major projects, is unclear.

In January 2021, U.S President Biden took steps to cancel the presidential permit that had allowed the Keystone XL Pipeline to operate across Canadian and American borders. It is unclear if challenges to the revocation of the permit will be successful and what the direct impact of the loss of permit will be on the Corporation.

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 ourCommon 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:

•	resources, including capital and skilled personnel;
•	the acquisition of properties with longer life reserves and exploitation and development opportunities; and<br>
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•	access to equipment, markets, transportation capacity, drilling and service rigs and storage and processing<br>facilities.
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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.

We may experience challenges adopting new technologies and our costs may increase as a result of suchadoption.

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 (including wild fires and flooding) may lead to declines in our activities and therebyadversely 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 wild fires and flooding. In the past, our production levels (and as a result our revenues) have at times been materially and adversely affected by wild fires and flooding. In addition to the loss of revenue that results from the loss of production when our operations are affected by wild fires 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, wild fires 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 wild fires and flooding that have at times plagued our operations will not occur again in the future with equal or greater severity.

Seasonal factors and unexpected weather patterns, including wild fires and flooding, 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 toenvironmental 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, among other things, the initiation and approval of new oil and natural gas projects, 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 impact activity levels. See “Industry Conditions”.

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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”.

Regulations regardingthe disposal of fluids used in the Corporation’s operations may increase its costs of compliance or subject us to regulatory penalties or litigation.

The safe disposal of the hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is subject to ongoing regulatory review by the federal and provincial governments, including its effect on fresh water supplies and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that may be enacted in response to such review, the implementation of stricter regulations may increase the Corporation’s costs of compliance.

Changes to royalty regimes may have a material and adverse impact on our financial condition.

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”.

We may not be able to achieve theanticipated 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.

Ourproperties 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 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 the 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.

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In addition, the Corporation’s oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Corporation’s properties, wells or facilities are the subject of a terrorist attack it may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. The Corporation does not have insurance to protect against the risk from terrorism.

Our ability tomake 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:

•	the overall state of the capital markets;
•	the Corporation’s credit rating (if applicable);
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•	commodity prices;
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•	interest rates;
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•	royalty rates;
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•	tax burden due to current and future tax laws; and
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•	investor appetite for investments in the energy industry and the Corporation’s securities in particular.<br>
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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.

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

The Corporation’s cash flow from its 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 or terminate our operations. Due to the conditions in the oil and natural gas industry and/or global economic and political volatility, the Corporation may from time to time have restricted access to capital and increased borrowing costs. The current conditions in the oil and natural gas industry have negatively impacted the ability of oil and natural gas companies to access additional 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 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 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.

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In the normal course of our operations, we are exposed to litigation, which ifdetermined adversely, could have a material and adverse impact on us.

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), and contract disputes. 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 onour 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 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. 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, poor credit conditions in the industry generally and of our joint venture partners in particular 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. 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 the Corporation being unable to collect all or a portion of any money owing from such parties. Any of these factors could materially adversely affect our financial and operational results.

Restrictions on the availability and cost of materials and equipment may impede the Corporation’s exploration, development andoperating activities.

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 the Corporation’s exploration, development and operating activities.

We rely on third parties to operate some of our assets.

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 current low and volatile commodity price environment, many 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.

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A portion of the Corporation’s revenues from royalty payers and certain of ouroperations 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 current low and volatile commodity price environment, many companies, including companies that may have a working interest in the lands 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, weak commodity prices and/or curtailment of the production of crude oil and bitumen mandated by the Government of Alberta 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.

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 or dividends or capital gains, may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders. Furthermore, tax authorities having jurisdiction over us or our Shareholders may disagree with how we calculate our income for tax purposes or could change administrative practises to our detriment 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.

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Indigenous claims may affect the Corporation.

Indigenous peoples have claimed Indigenous rights and title in portions of western Canada. The Corporation is not aware that any material claims have been made in respect of our properties and assets. However, if a material claim arose and was successful, such claim may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays in the construction of infrastructure systems and facilities which could have a material adverse effect on the Corporation’s business and financial results.

Taxes on carbon emissions affect the demand for oil and naturalgas, the Corporation’s operating expenses and may impair the Corporation’s ability to compete.

The majority of countries across the globe have agreed to reduce their carbon emissions in accordance with the Paris Agreement. In Canada, the federal government implemented legislation aimed at incentivizing the use of alternative fuels and in turn reducing carbon emissions. The federal system applies in provinces and territories that request it to be implemented or are without their own system that meets federal standards. While several provinces challenged the constitutionality of the legislation implementing the federal system following its enactment, the Supreme Court of Canada confirmed its constitutional validity in a judgment released on March 25, 2021. See “Industry Conditions”. Any taxes placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas products and at the same time, increasing the Corporation’s operating expenses, each of which may have a material adverse effect on the Corporation’s profitability and financial condition. Further, the imposition of carbon taxes puts the Corporation at a disadvantage with its competitors who operate in jurisdictions where there are less costly carbon regulations.

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, or the insolvency of the insurer of such event, could have a material adverse effect on our financial condition, results of operations or prospects.

An inability torecruit 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, a decline in market conditions has led increasing numbers of skilled personnel to seek employment in other industries. 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 workforce. 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.

Future acquisitions, financings or other transactions and the issuance of securities pursuant to our treasury-based equity incentiveplans 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.

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Lower oil and gas prices and higher costs increase the risk of write-downs of our oiland 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 inbusiness 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.

An unforeseen defect in the chain of title to our oil and natural gas producing properties may arise to defeat our claim, which couldhave 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 its properties, and our rights to produce and sell the oil and natural gas therefrom, may accordingly 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. There may be valid legal challenges to title 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 ofcompanies 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, 2020 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.

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The ability of residents of the United States to enforce civil remedies against us andour 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 oflicenses 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 pay dividends and there is no assurance that we will do so in the future.

The Corporation has not paid any dividends on the Common Shares since 2015. 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, the Corporation’s debt levels and constraints on paying dividends imposed by our lenders and noteholders, and other considerations as the Board considers relevant.

Our directors and management may have conflicts of interestthat may create incentives for them to act contrary to or in competition with the interests of our Shareholders.

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”.

Expanding the Corporation’s business exposes us to new risks and uncertainties.

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.

58

The Corporation relies on its reputation to continue our operations and to attract andretain 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 and increased costs and/or cost overruns. 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 its 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, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares.

Our information assets and critical infrastructure may be subject to destruction, theft, cyber-attacks or misuse by unauthorizedparties .

We are increasingly 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 and third-parties.

As a result, we are subject to a variety of information technology and/or system risks as a part of our 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, and credit card details (and money) by disguising 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 ongoing COVID-19 pandemic has contributed to the increase of cyber-attacks against us, as increased malicious activities are creating more threats for cyberattacks, including COVID-19 phishing emails, malware-embedded mobile apps that purport to track infection rates, and targeting of vulnerabilities in remote access platforms as many companies continue to operate with work from home arrangements.

59

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, and any damages sustained may not be adequately covered by the Corporation’s current insurance coverage, or at all. 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.

There might not always be an active trading market inthe 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 OTCQX) 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 andsupervisory 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 restricts the social media access of our employees and periodically reviews, supervises, retains and maintains the ability to retrieve social media content. 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.

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.

Forward-looking information may prove inaccurate.

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, assumption and uncertainties are found under the heading “Special Note Regarding Forward-LookingStatements” in this Annual Information Form.

MATERIAL CONTRACTS

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:

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(a)	the amended and restated credit agreement dated May 18, 2017 (as amended on May 10,<br>2018, December 14, 2018, March 21, 2019, May 31, 2019, June 28, 2019, August 12, 2019, February 28, 2020, March 4, 2020, March 13, 2020, March 27,<br>2020, June 22, 2020, September 3, 2020, October 29, 2020, January 27, 2021, February 24, 2021 and March 26, 2021) among Obsidian Energy and certain lenders and other parties in respect of<br>Obsidian Energy’s reserve-based loan syndicated credit facility, which agreement is described under “Capitalization of Obsidian Energy – Debt Capital – Credit Facility”; and
(b)	the note purchase agreement dated March 26, 2021 among Obsidian Energy and the holders of our Series G,<br>S, X, Y, Z and EE Senior Notes, which agreement is described under “Capitalization of Obsidian Energy – Debt Capital – Senior Notes”.
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Economic Dependence

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.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

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.

RegulatoryActions

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.

TRANSFER AGENTS AND REGISTRARS

The transfer agent and registrar for the Common Shares in Canada is AST Trust Company (Canada) 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.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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.

INTERESTS OF EXPERTS

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 Sproule, our independent engineering evaluator (the “Expert”), and Ernst & Young LLP (“EY”), our auditors.

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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 InformationForm) 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.

EY are the auditors of Obsidian Energy and have confirmed that they are independent with respect to Obsidian Energy in the context of the Rules of Professional Conduct of the Institute of Chartered Professional Accountants of Alberta and in compliance with Rule 3520 of the Public Company Accounting Oversight Board.

No director, officer or employee of the Expert or EY 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

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).

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APPENDIX A-1

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

(Form 51-101F3)

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, 2020, 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:

(a)	reviewed Obsidian Energy’s procedures for providing information to the independent qualified reserves<br>evaluator;
(b)	met with the independent qualified reserves evaluator to determine whether any restrictions affected the<br>ability of the independent qualified reserves evaluator to report without reservation; and
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(c)	reviewed the reserves data with management and the independent qualified reserves evaluator.<br>
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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:

(a)	the content and filing with securities regulatory authorities of Form<br>51-101F1 containing reserves data and other oil and natural gas information;
(b)	the filing of Form 51-101F2 which is the report of the independent<br>qualified reserves evaluator on the reserves data; and
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(c)	the content and filing of this report.
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Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

(signed) “Stephen Loukas”	(signed) “Peter Scott”
Interim President and Chief Executive Officer	Senior Vice President and Chief Financial Officer
(signed) “William Friley”	(signed) “Michael Faust”
Director and Chair of the Operations and Reserves Committee	Member of the Operations and Reserves Committee
March 26, 2021

APPENDIX A-2

REPORT ON RESERVES DATA

(Form 51-101F2)

To the Board of Directors of Obsidian Energy Ltd. (“Obsidian Energy”):

1.	We have evaluated Obsidian Energy’s reserves data as at December 31, 2020. The reserves data are<br>estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2020, estimated using forecast prices and costs.
2.	The reserves data are the responsibility of Obsidian Energy’s management. Our responsibility is to<br>express an opinion on the reserves data based on our evaluation.
---	---
3.	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation<br>Handbook as amended from time to time (the “COGE Handbook”), maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
---	---
4.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether<br>the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
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5.	The following table sets forth the net present value of future net revenue (before deduction of income<br>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,<br>2020, 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:
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Independent Qualified<br>Reserves Evaluator or<br><br><br>Auditor	Description and Preparation Date<br>of<br>Evaluation Report	Location<br>of<br>Reserves<br>(Country)			Net Present Value of Future Net Revenue<br>(millions before income taxes, 10% discount rate)
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
				Audited			Evaluated			Reviewed		Total
Sproule Associates Limited	Evaluation of the P&NG<br><br><br>Reserves of Obsidian Energy<br> <br>Ltd.<br>(As of December 31, 2020)<br> <br><br> <br>February 1,<br>2021		Canada			nil		$	1,189,110		nil		$	1,189,110
6.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been<br>determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
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7.	We have no responsibility to update our report referred to in paragraph 5 for events and circumstances<br>occurring after the preparation date.
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8.	Because the reserves data are based on judgements regarding future events, actual results will vary and the<br>variations may be material.
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Executed as to our report referred to above:

(signed) “Sproule Associates Limited”<br><br><br>Sproule Associates Limited<br><br><br>Calgary, Alberta, Canada<br><br><br>February 1, 2021

A2-1

APPENDIX A-3

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Our statement of reserves data and other oil and natural gas information dated March 26, 2021 is set forth below (the “Statement”). The effective date of the Statement is December 31, 2020 and the preparation date of the Statement is March 26, 2021. The Report of Management and Directors on Reserves Data and Other Information on Form 51-101F3 and the Report on Reserves Data by Sproule on Form 51-101F2 are attached as Appendices A-1 and A-2, respectively, to this Annual Information Form.

Disclosure of Reserves Data

The reserves data set forth below is based upon an evaluation prepared by Sproule with an effective date of December 31, 2020 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 Sproule to evaluate all of our proved and proved plus probable reserves. See also “Notes to Reserves Data Tables” below.

As at December 31, 2020, the vast 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 thereserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein areestimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.

BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalencyconversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from theenergy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Formore information as to the risks involved, see “ Risk Factors ”.

SUMMARY OF OIL AND GAS RESERVES

AS OF DECEMBER 31, 2020

FORECAST PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM<br>CRUDE OIL				HEAVY CRUDE OIL AND<br>BITUMEN
RESERVES CATEGORY	Gross<br>(MMbbl)		Net<br>(MMbbl)		Gross<br>(MMbbl)		Net<br>(MMbbl)
PROVED
Developed Producing		31		29		3		3
Developed Non-Producing		—		—		—		—
Undeveloped		20		19		1		—
TOTAL PROVED		51		48		4		4
PROBABLE		16		14		3		3
TOTAL PROVED PLUS PROBABLE		67		62		7		7

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	RESERVES
	CONVENTIONAL<br>NATURAL GAS				NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross<br>(Bcf)		Net<br>(Bcf)		Gross<br>(MMbbl)		Net<br>(MMbbl)
PROVED
Developed Producing		127		121		6		5
Developed Non-Producing		3		3		—		—
Undeveloped		56		52		3		2
TOTAL PROVED		185		176		8		7
PROBABLE		68		65		3		3
TOTAL PROVED PLUS PROBABLE		253		241		12		10
	RESERVES
---	---	---	---	---
	TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross<br>(MMboe)		Net<br>(MMboe)
PROVED
Developed Producing		61		57
Developed Non-Producing		1		1
Undeveloped		33		30
TOTAL PROVED		95		89
PROBABLE		33		30
TOTAL PROVED PLUS PROBABLE		128		119

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2020

BEFORE INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

						Unit Value Before IncomeTax Discounted at10%/year(1)
RESERVES CATEGORY	0%(MM)	5%(MM)	10%(MM)	15%(MM)	20%(MM)	(/boe)	(/Mcfe)
PROVED
Developed Producing
Developed Non-Producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE

All values are in US Dollars.

Note:

(1)	The unit values are based on net reserve volumes.

A3-2

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2020

AFTER INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

RESERVES CATEGORY	0%(MM)	5%(MM)	10%(MM)	15%(MM)	20%(MM)
PROVED
Developed Producing
Developed Non-Producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE

All values are in US Dollars.

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

AS OF DECEMBER 31, 2020

FORECAST PRICES AND COSTS

RESERVES CATEGORY	REVENUE(MM)	ROYALTIES(MM)	OPERATINGCOSTS(MM)	DEVELOPMENTCOSTS(MM)	ABANDONMENTANDRECLAMATIONCOSTS(MM)	FUTURENETREVENUEBEFOREFUTUREINCOMETAXES(MM)	FUTUREINCOMETAXES(MM)	FUTURENETREVENUEAFTERFUTUREINCOMETAXES(MM)
Proved Reserves
Proved Plus Probable Reserves

All values are in US Dollars.

FUTURE NET REVENUE

BY PRODUCTION TYPE

AS OF DECEMBER 31, 2020

FORECAST PRICES AND COSTS

		FUTURENETREVENUEBEFOREINCOMETAXES(discounted at	UNIT VALUE(3)
		10%/year)
RESERVES CATEGORY	PRODUCTION TYPE	(MM)	(/bbl)	(/Mcf)
Proved Reserves	Light and Medium Crude Oil^(1)^
	Heavy Crude Oil and Bitumen^(1)^
	Conventional Natural Gas^(2)^
	Non-Conventional Oil and Gas Activities^(1)^
	TOTAL
Proved Plus Probable	Light and Medium Crude Oil^(1)^
Reserves	Heavy Crude Oil and Bitumen^(1)^
	Conventional Natural Gas^(2)^
	Non-Conventional Oil and Gas Activities^(1)^
	TOTAL

All values are in US Dollars.

A3-3

Notes:

(1)	Including solution gas and other by-products.
(2)	Including by-products but excluding solution gas and by-products from oil wells and non-conventional<br>oil & gas activities.
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(3)	The unit values are based on net reserve volumes.
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Notes to Reserves Data Tables

1.	Columns may not add due to rounding.
2.	The crude oil, natural gas liquids and natural gas reserves estimates presented in the Engineering Report<br>are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”). A summary of those definitions are set forth below:
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Reserves Categories

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:

(a)	analysis of drilling, geological, geophysical and engineering data;
(b)	the use of established technology; and
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(c)	specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.<br>
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Reserves are classified according to the degree of certainty associated with the estimates.

(d)	Proved reserves are those reserves that can be estimated with a high degree of certainty to be<br>recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(e)	Probable reserves are those additional reserves that are less certain to be recovered than proved<br>reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
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Other criteria that must also be met for the classification of reserves are provided in the COGE Handbook.

Development and Production Status

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

(a)	Developed reserves are those reserves that are expected to be recovered from existing wells and<br>installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into<br>producing and non-producing.

A3-4

(i)	Developed producing reserves are those reserves that are expected to be recovered from completion<br>intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.<br>
(ii)	Developed non-producing reserves are those reserves that either have not been on production, or have<br>previously been on production, but are shut-in, and the date of resumption of production is unknown.
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(b)	Undeveloped reserves are those reserves expected to be recovered from known accumulations where a<br>significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable) to which they are assigned.<br>
---	---

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.

Levels of Certainty for Reported Reserves

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)	at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated<br>proved reserves; and
(b)	at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the<br>estimated proved plus probable reserves.
---	---

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.

3.	Forecast prices and costs

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 crude 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 (Sproule, GLJ Petroleum Consultants, McDaniel & Associates Consultants and Deloitte Resource Evaluation & Advisory).

A3-5

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

AS OF DECEMBER 31, 2020

FORECAST PRICES AND COSTS

			OIL				GAS		EDMONTON LIQUIDS PRICES
Year	WTICushingOklahoma(US/bbl)		CanadianLight OilSweetPrice40ºAPI(Cdn/bbl)		WesternCanadaSelect20.5ºAPI(Cdn/bbl)		NATURALGASAECO(Cdn/MMbtu)		Propane(Cdn/bbl)		Butane(Cdn/bbl)		Condensates(Cdn/bbl)		INFLATION<br>RATES^(1)^<br>%/year		EXCHANGERATE(2)(US/Cdn)
Forecast
2021																0.00
2022																1.00
2023																2.00
2024																2.00
2025																2.00
2026																2.00
2027																2.00
2028																2.00
2029																2.00
2030																2.00
2031																2.00
Thereafter		%		%		%		%		%		%		%		+2.0

All values are in US Dollars.

(1)	Inflation rates are used for forecasting prices and costs
(2)	Exchange rates used to generate the benchmark reference prices in this table.
---	---

Weighted average actual prices realized, including hedging activities, for the year ended December 31, 2020 were $2.32/Mcf for natural gas, $50.08/bbl for light and medium crude oil, $22.56/bbl for heavy crude oil and $20.13/bbl for natural gas liquids.

4.	Future Development Costs

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

	Forecast Prices and Costs
Year	Proved Reserves(MM)	Proved Plus ProbableReserves (MM)
2021
2022
2023
2024
2025
2026 and subsequent
Total: Undiscounted for all years

All values are in US Dollars.

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.

A3-6

5.	Estimated future abandonment and reclamation costs related to reserve wells and active pipelines and<br>facilities have been taken into account by Sproule in determining the aggregate future net revenue therefrom.
6.	The forecast price and cost assumptions assume the continuance of current laws and regulations.<br>
---	---
7.	All factual data supplied to Sproule was accepted as represented. No field inspection was conducted.<br>
---	---
8.	The estimates of future net revenue presented in the tables above do not represent fair market value.<br>
---	---

Reconciliations of Changes in Reserves

The following table sets forth the reconciliation of our gross reserves as at December 31, 2020, using forecast price and cost estimates derived from the Engineering Report.

RECONCILIATION OF

COMPANY GROSS RESERVES

BY PRODUCT TYPE

FORECAST PRICES AND COSTS

	LIGHT AND MEDIUM CRUDE<br>OIL^(1)^									HEAVY CRUDE OIL AND<br>BITUMEN^(1)^									CONVENTIONAL<br>NATURAL GAS^(1)^
FACTORS	Gross<br>Proved<br>(MMbbl)			Gross<br>Probable<br>(MMbbl)			Gross<br>Proved<br>Plus<br>Probable<br>(MMbbl)			Gross<br>Proved<br>(MMbbl)			Gross<br>Probable<br>(MMbbl)			Gross<br>Proved<br>Plus<br>Probable<br>(MMbbl)			Gross<br>Proved<br>(Bcf)			Gross<br>Probable<br>(Bcf)			Gross<br>Proved<br>Plus<br>Probable<br>(Bcf)
December 31, 2019		51			16			67			6			3			9			173			63			236
Extensions		0			0			0			0			0			0			0			0			0
Infill drilling		3			3			6			0			0			0			8			10			18
Improved Recovery		0			0			0			0			0			0			0			0			0
Technical Revisions		4			(3	)		0			0			(0	)		(0	)		31			(4	)		27
Discoveries		0			0			0			0			0			0			0			0			0
Acquisitions		0			0			0			0			0			0			0			0			0
Dispositions		(0	)		(0	)		(0	)		0			0			0			(0	)		(0	)		(0	)
Economic Factors		(2	)		0			(2	)		(1	)		0			(1	)		(8	)		(0	)		(8	)
Production		(4	)		0			(4	)		(1	)		0			(1	)		(19	)		0			(19	)
December 31, 2020		51			16			67			4			3			7			185			68			253

A3-7

	NATURAL GAS LIQUIDS^(1)^									TOTAL OIL EQUIVALENT^(1)^
FACTORS	Gross<br>Proved<br>(MMbbl)			Gross<br>Probable<br>(MMbbl)			Gross<br>Proved<br>Plus<br>Probable<br>(MMbbl)			Gross<br>Proved<br>(MMboe)			Gross<br>Probable<br>(MMboe)			Gross<br>Proved<br>Plus<br>Probable<br>(MMboe)
December 31, 2019		8			3			11			94			32			126
Extensions		0			0			0			0			0			0
Infill drilling		0			0			1			5			5			10
Improved Recovery		0			0			0			0			0			0
Technical Revisions		1			(0	)		1			10			(5	)		5
Discoveries		0			0			0			0			0			0
Acquisitions		0			0			0			0			0			0
Dispositions		(0	)		(0	)		(0	)		(0	)		(0	)		(0	)
Economic Factors		(0	)		(0	)		(0	)		(5	)		1			(4	)
Production		(1	)		0			(1	)		(9	)		0			(9	)
December 31, 2020		8			3			12			95			33			128

Note:

(1)	Columns may not add due to rounding.

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped reserves are attributed by Sproule 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 the all of the proved undeveloped reserves over the next five years. Obsidian Energy plans to develop approximately two-fifths 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).

Proved Undeveloped Reserves

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.

A3-8

Year	Light and Medium Crude<br>Oil<br>(MMbbl)				Heavy Crude Oil and<br>Bitumen<br>(MMbbl)						Conventional Natural Gas<br>(Bcf)		NGLs<br>(MMbbl)
	First<br>Attributed		Cumulative<br>at Year End		First<br>Attributed		Cumulative<br>at Year End		First<br>Attributed		Cumulative at Year End		First<br>Attributed		Cumulative<br>at Year End
2018		3		14		—		1		13		41		1		2
2019		5		17		—		1		14		47		1		2
2020		2		20		—		1		4		56		0		3

Sproule has assigned 33 MMboe of proved undeveloped reserves in the Engineering Report under forecast prices and costs, together with $476 million of associated undiscounted future capital expenditures. Proved undeveloped capital spending in the first two forecast years of the Engineering Report accounts for $183 million, or 38 percent, of the total forecast undiscounted capital expenditures for proved undeveloped reserves. These figures increase to $476 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.

Probable Undeveloped Reserves

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.

Year	Light and Medium Crude<br>Oil<br>(MMbbl)				Heavy Crude Oil and<br>Bitumen<br>(MMbbl)				Conventional Natural Gas<br>(Bcf)				NGLs<br>(MMbbl)
	First<br>Attributed		Cumulative<br>at Year End		First<br>Attributed		Cumulative<br>at Year End		First<br>Attributed		Cumulative<br>at Year End		First<br>Attributed		Cumulative<br>at Year End
2018		1		9		—		1		5		21		—		1
2019		1		9		—		1		7		33		—		2
2020		2		9		—		2		6		38		—		2

Sproule has assigned 52 MMboe of probable undeveloped reserves in the Engineering Report under forecast prices and costs, together with $635 million of associated undiscounted future capital expenditures. Probable undeveloped capital spending in the first two forecast years of the Engineering Report accounts for $233 million, or 37 percent, of the total forecast undiscounted future capital expenditures for probable undeveloped reserves. These figures increase to $635 million, or 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.

Significant Factors or Uncertainties Affecting Reserves Data

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.

A3-9

Additional Information Concerning Abandonment and Reclamation Costs

Abandonment and reclamation costs in respect of surface leases, wells, facilities and pipelines (collectively, “A&RCosts”) 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 active wells, facilities, and pipelines have been included in the Engineering Report as part of future net revenue calculations. The total uninflated, undiscounted A&R costs included in reserves is $281 million. Inflated at 2% per year and discounted at 10% this value is $26 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, 2020, we expect to incur future A&R Costs in respect of approximately 4,522 net well bores, 520 facilities and 6,140 kilometres of pipelines. On an undiscounted, inflated basis, approximately 73 percent of A&R Costs relate to well bores, 24 percent to facilities and 3 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:

Period	Abandonment and ReclamationCosts Escalated at 2%Undiscounted (MM)	Abandonment and ReclamationCosts Escalated at 2%Discounted at 10% (MM)
Total liability as at December 31, 2020
Anticipated to be paid in 2021
Anticipated to be paid in 2022
Anticipated to be paid in 2023
Total anticipated to be paid in 2021, 2022 and 2023

All values are in US Dollars.

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 $730 million, and escalated at two percent and discounted at 10 percent, these A&R Costs were $9 million. On an undiscounted, uninflated basis total A&R costs are $533 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 Sproule.

OTHER OIL AND GAS INFORMATION

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

Introduction

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, 2020 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, 2020, the majority of our proved plus probable reserves are located in Alberta, Canada.

Major Operating Regions

Our production and reserves are attributed to approximately 24 producing properties. The Company’s Willesden Green property accounts for 37 percent of our proved plus probable reserves; no other property is above 25 percent. Obsidian Energy’s capital investments are currently focused on light-oil development.

A3-10

The following map illustrates Obsidian Energy’s major operating regions as at December 31, 2020.

The following is a description of our principal oil and natural gas properties and related operations and activities as at December 31, 2020. Information in respect of gross and net acres and well counts are as of December 31, 2020 and information in respect of production is for the year ended December 31, 2020, except where indicated otherwise. For information on the Company’s disposition activity in 2020 see “Description of Our Business – General Development of the Business – 2020 Developments”. 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.

A3-11

Cardium Development Area

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 465 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 2020 capital expenditures were $55 million, excluding decommissioning expenditures, resulting in 10 (10 net) operated wells drilled and completed, optimization activities and minor infrastructure spend. In 2021, planned Cardium activity will continue in the Willesden Green area of the play and focus on primary development. Refer to the 2021 Capital Budget section below for further details.

Peace River Development Area

The Peace River development area is a heavy oil play located in Northwestern Alberta. In 2010, Obsidian Energy entered the Peace River Oil Partnership where it holds a 55 percent working interest and operatorship. At December 31, 2020, Obsidian Energy had approximately 234 net sections of developed and undeveloped land in the area. In 2020, minimal capital was spent in the area given the low commodity price environment and the Company focused activity in the Cardium.

Viking Development Area

The Viking development area is located in Eastern Alberta along the Alberta/Saskatchewan border. At December 31, 2020, Obsidian Energy had approximately 155 net sections of developed and undeveloped land in the play. As a result of strong economics in the Company’s Cardium play, no capital activity occurred in the area in 2020.

Optimization activity

In 2021, 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 totals $8 million in 2021 across several individual projects to either increase production by reactivating and/or recompleting existing well bores or reduce operating costs through facilities optimization projects.

Additional Information

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.

2021 Capital Budget

The Board has approved a $125—$130 million 2021 capital plan to fund the continued drilling of Willesden Green and others areas in the Cardium as well as various optimization activities and other operational spending. A total of 32 gross wells are planned under this program and the Company anticipates average production of 23,300 to 23,800 boe/d for 2021. Additionally, the Company continues to focus on various abandonment activities and plans to spend approximately $8 million of decommissioning expenditures in 2021. Combined with ASRP funding, the Company expects to have approximately $18 million of decommissioning activities carried out on our inactive properties in 2021

The primary components of our programs are described above under theheading “ Major Operating Regions ”. See also “ Description of our Business – General Development of the Business –2021 Developments – Full Year 2021 Outlook and Guidance “. ****

A3-12

Oil and Gas Wells

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2020.

	Producing								Non-Producing				Total
	Oil				Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Alberta		1,576		1,222		384		253		3,884		3,029		5,844		4,505
Northwest Territories		—		—		—		—		41		6		41		6
Saskatchewan		—		—		—		—		4		1		4		1
USA		—		—		—		—		25		9		25		9
Total		1,576		1,222		384		253		3,954		3,046		5,914		4,522

Note:

(1)	Total well counts differ from the well count provided under the Abandonment and Reclamation Costs as the<br>table excludes water disposal, water source and injector wells.

Properties with no Attributed Reserves

The following table sets out the unproved properties in which we had an interest as at December 31, 2020.

	Unproved Properties<br>(thousands of acres)
	Gross		Net
Alberta		222		222
Northwest Territories		11		4
Total		233		226

We currently have no material work commitments on these lands. The primary lease or extension term on approximately 43,200 net acres of unproved property is scheduled to expire by December 31, 2021. 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.

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

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.

Tax Horizon

The most important variables that will determine the level of cash taxes incurred by us in a given year will be the price of crude 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 the foreseeable future. However, if crude 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.

A3-13

Capital Expenditures

The following table summarizes capital expenditures related to our activities for the year ended December 31, 2020, irrespective of whether such costs were capitalized or charged to expense when incurred.

	2020MM
Property Acquisition<br>Costs^(1)^
Proved Properties
Unproved Properties
Exploration Costs^(1)^
Development Costs^(1)^
Corporate Costs
Total Capital Expenditures
Corporate Acquisitions
Total Expenditures

All values are in US Dollars.

Note:

(1)	“Property Acquisition Costs”, “Proved Properties”, “Unproved Properties”,<br>“Exploration Costs” and “Development Costs” have the meanings ascribed thereto in the COGE Handbook.

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells that we participated in during the year ended December 31, 2020.

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net
Oil		—		—		13.0		10.7
Gas and condensate		—		—		—		—
Injectors/Stratigraphic test		—		—		1.0		0.1
Total		—		—		14.0		10.8

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2021 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.

	Light and Medium<br>Crude Oil				Heavy Crude Oil<br>and Bitumen				Conventional<br>Natural Gas				Natural Gas<br>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		8,579		8,122		2,333		2,292		41,496		39,471		1,799		1,387		19,627		18,380
Proved Developed Non- Producing		85		81		3		3		496		482		24		17		195		181
Proved Undeveloped		1,912		1,813		—		0		5,208		4,942		225		213		3,004		2,850
Total Proved		10,577		10,016		2,335		2,295		47,200		44,896		2,047		1,618		22,826		21,412
Total Probable		979		909		99		97		3,370		3,195		144		131		1,783		1,669
Total Proved Plus Probable		11,556		10,925		2,434		2,392		50,570		48,090		2,191		1,748		24,609		23,081

A3-14

The Company notes that our Willesden Green property (located in the Cardium development area) accounts for approximately 50% of the estimated production on a proved plus probable basis in 2021. No other field (being a defined geographical area consisting of one or more pools) accounts for more than 10 percent of the estimated production on a 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”.

Production History

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:

												Year Ended<br>December 31,<br>2020
			June 30			September 30			December 31
Share of Average Gross Daily Production
Light and Medium Crude Oil (bbl/d)	12,512			12,800			10,952			10,055			11,574
Heavy Crude Oil (bbl/d)	3,644			1,966			2,823			2,895			2,832
Conventional Natural Gas (Mcf/d)	52,181			52,962			54,070			51,645			52,715
NGLs (bbl/d)	2,239			2,278			2,244			2,087			2,212
Combined (boe/d)	27,092			25,872			25,031			23,644			25,404
Average Net Production Prices Received
Light and Medium Crude Oil (/bbl)	50.59			29.20			50.84			50.76			44.81
Heavy Crude Oil (/bbl)	20.07			5.98			29.54			30.00			22.56
Conventional Natural Gas (/Mcf)	2.20			2.14			2.40			2.81			2.39
NGLs (/bbl)	22.52			11.65			22.11			24.61			20.13
Combined (/boe)	32.17			20.30			32.74			33.57			29.63
Royalties Paid
Light and Medium Crude Oil (/bbl)	4.60			1.37			2.58			2.72			2.82
Heavy Crude Oil (/bbl)	0.71			0.09			0.42			0.45			0.46
Conventional Natural Gas (/Mcf)	0.09			(0.06	)		0.12			0.04			0.05
NGLs (/bbl)	(1.91	)		2.35			(0.22	)		1.25			0.36
Combined (/boe)	2.23			0.76			1.42			1.42			1.47
Production<br>Costs(1)(2)
Light and Medium Crude Oil (/bbl)	16.83			12.67			20.07			24.16			18.06
Heavy Crude Oil (/bbl)	18.87			11.28			5.94			1.49			9.85
Conventional Natural Gas (/Mcf)	0.91			0.68			0.89			1.06			0.89
NGLs (/bbl)	(0.15	)		(0.16	)		(0.16	)		(0.21	)		(0.17	)
Combined (/boe)	12.04			8.51			11.36			12.77			11.15
Transportation
Light and Medium Crude Oil (/bbl)	3.65			0.57			2.41			1.34			2.00
Heavy Crude Oil (/bbl)	4.15			6.05			5.96			5.20			5.20
Conventional Natural Gas (/Mcf)	0.22			0.22			0.19			0.18			0.20
NGLs (/bbl)	0.00			0.00			0.00			0.00			0.00
Combined (/boe)	2.68			1.18			2.13			1.60			1.91
Risk Management Contracts Loss (Gain)
Light and Medium Crude Oil (/bbl)	(9.51	)		(10.05	)		0.00			0.24			(5.27	)
Heavy Crude Oil (/bbl)	0.00			0.00			0.00			0.00			0.00
Conventional Natural Gas (/Mcf)	(0.04	)		0.11			0.19			0.02			0.07
NGLs (/bbl)	0.00			0.00			0.00			0.00			0.00
Combined (/boe)	(4.47	)		(4.75	)		0.42			0.14			(2.25	)
Netback Received(3)
Light and Medium Crude Oil (/bbl)	35.02			24.64			25.78			22.30			27.20
Heavy Crude Oil (/bbl)	(3.66	)		(11.44	)		17.22			22.86			7.05
Conventional Natural Gas (/Mcf)	1.02			1.19			1.01			1.51			1.18
NGLs (/bbl)	24.58			9.46			22.49			23.57			19.94
Combined (/boe)	19.69			14.60			17.41			17.64			17.35

All values are in US Dollars.

A3-15

Notes:

(1)	Net operating expenses are comprised of direct costs incurred to operate both oil and gas wells and include<br>processing fees and road use recoveries. A number of assumptions are required to allocate these costs between crude oil, conventional natural gas and natural gas liquids production.
(2)	Operating overhead recoveries associated with operated properties are charged to operating costs and<br>accounted for as a reduction to general and administrative costs.
---	---
(3)	Netbacks are calculated by subtracting royalties, net operating expenses, transportation costs and<br>losses/gains on commodity and foreign exchange contracts from revenues.
---	---

During the year ended December 31, 2020, Obsidian Energy produced 9 MMboe, comprised of 4 MMbbl of light and medium crude oil, 1 MMbbl of heavy crude oil, 19 Bcf of conventional natural gas and 1 MMbbl of natural gas liquids.

Marketing Arrangements

Our marketing approach incorporates the following primary objectives:

•	Ensure security of market and avoid production shut-ins due to marketing constraints by dealing with end-users<br>or regionally strategic counterparties wherever possible.
•	Ensure competitive pricing by managing pricing exposures through a portfolio of various terms and geographic<br>basis.
---	---
•	Ensure optimization of netbacks through careful management of transportation obligations, facility utilization<br>levels, blending opportunities and emulsion handling.
---	---
•	Ensure protection of our receivables by, whenever possible, dealing only with credit worthy counterparties who<br>have been subjected to regular credit reviews.
---	---

Oil and Liquids Marketing

Of our liquids production in 2020, approximately 70% percent was light and medium oil, 17% percent was conventional heavy crude oil and 13% percent was NGLs. In regard specifically to crude oil, our average quality was 30 degrees API, which was comprised of an average quality for our light and medium crude oil of 38 degrees API and an average quality for our conventional heavy crude oil of 11 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.

A3-16

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

	2020		2019		2018
	Light andMediumCrude Oil andNGLs	Heavy Crude<br>Oil	Light andMedium Crude<br>Oil and NGLs	Heavy CrudeOil	Light andMedium CrudeOil and NGLs	Heavy CrudeOil
Quarter Ended	(/bbl)	(/bbl)	(/bbl)	(/bbl)	(/bbl)	(/bbl)
March 31
June 30
September 30
December 31

All values are in US Dollars.

Natural Gas Marketing

In 2020, we received an average price from the sale of conventional natural gas, before adjustments for hedging activities, of $2.39 per mcf compared to $1.79 per mcf realized in 2019. 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.

Forward Contracts

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, we may, from time to time, manage these risks through the use of swaps, collars or other financial instruments. Commodity price risk may be hedged up to a maximum of 50 percent of forecast sales volumes, net of royalties, for the balance of any current year and one year following and up to 25 percent of forecast sales volumes, net of royalties, for one additional year thereafter. Subject to the Board’s approval, our hedging limits may be increased above the maximum limits. This policy is reviewed by management and our Board of Directors from time to time and amended as necessary. For the first half of 2021, the Board of Directors has approved an increase to the maximum percentage of production that may be hedged as follows: i) gas volumes, net of royalties may be hedged up to a maximum of 65 percent and ii) crude oil volumes, net of royalties, may be hedged up to a maximum of 65 percent for the following month, otherwise hedges must follow the standard terms and conditions of the program. Additionally, for the second half of 2021, the Board of Directors has approved that gas volumes, net of royalties, may be hedged up to a maximum of 60 percent.

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, 2020, 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 10 to our audited consolidated financial statements as at and for the year ended December 31, 2020 which have been filed on SEDAR at www.sedar.com.

Our transportation obligations and commitments for future physical deliveries of crude 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.

A3-17

APPENDIX B

MANDATE OF THE AUDIT COMMITTEE

1.	PURPOSE

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.

The objectives of the Committee are as follows:

(a)	To assist the Board in meeting its responsibilities (especially for accountability) in respect of the<br>preparation and disclosure of the consolidated financial statements of Obsidian Energy and related matters;
(b)	To provide an open avenue of communication between directors, management and independent auditors;<br>
---	---
(c)	To assist the Board in meeting its responsibilities regarding the oversight of the independent<br>auditor’s qualifications and independence;
---	---
(d)	To assist the Board in meeting its responsibilities regarding the oversight of the credibility, integrity<br>and objectivity of financial reports;
---	---
(e)	To strengthen the role of the non-management directors by facilitating discussions between directors on the<br>Committee, management and independent auditors;
---	---
(f)	To assist the Board in meeting its responsibilities regarding the oversight of the performance of Obsidian<br>Energy’s independent auditors and internal audit function (if any);
---	---
(g)	To assist the Board in meeting its responsibilities regarding the oversight of Obsidian Energy’s<br>compliance with legal and regulatory requirements; and
---	---
(h)	To assist the Board by monitoring the effectiveness and integrity of the Corporation’s financial<br>reporting systems, management information systems and internal control systems.
---	---
2.	SPECIFIC DUTIES AND RESPONSIBILITIES
---	---

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

(a)	Satisfy itself on behalf of the Board that the Company’s internal control systems are sufficient to<br>reasonably ensure that:
(i)	controllable, material business risks are identified, monitored and mitigated where it is determined cost<br>effective to do so;
---	---
(ii)	internal controls over financial reporting are sufficient to meet the requirements under National Instrument<br>52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings and the United States Securities Exchange Act of 1934, as amended, and
---	---
(iii)	there is compliance with legal, ethical and regulatory requirements.
---	---
(b)	Review the annual and interim financial statements of the Company prior to their submission to the Board for<br>approval. The process should include, but not be limited to:
---	---

B-1

(i)	review of changes in accounting principles, or in their application, which may have a material impact on the<br>current or future years’ financial statements;
(ii)	review of significant accruals, reserves or other estimates such as the ceiling test calculation;<br>
---	---
(iii)	review of accounting treatment of unusual or non-recurring transactions;
---	---
(iv)	review of compliance with covenants under loan agreements;
---	---
(v)	review of asset retirement obligations recommended by the Health, Safety, Environment and Regulatory<br>Committee;
---	---
(vi)	review of disclosure requirements for commitments and contingencies;
---	---
(vii)	review of adjustments raised by the independent auditors, whether or not included in the financial<br>statements;
---	---
(viii)	review of unresolved differences between management and the independent auditors, if any;<br>
---	---
(ix)	review of reasonable explanations of significant variances with comparative reporting periods; and<br>
---	---
(x)	determination through inquiry if there are any related party transactions and ensure the nature and extent<br>of such transactions are properly disclosed.
---	---
(c)	Review, discuss and recommend for approval by the Board the annual and interim financial statements and<br>related information included in prospectuses, management discussion and analysis, information circular-proxy statements and annual information forms, prior to recommending Board approval.
---	---
(d)	Discuss Obsidian Energy’s interim results press releases, as well as financial information and earnings<br>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<br>disclosed to the public).
---	---
(e)	With respect to the appointment of independent auditors by the Board, the Committee shall:<br>
---	---
(i)	on an annual basis, review and discuss with the auditors all relationships the auditors have with Obsidian<br>Energy to 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<br>itself;
---	---
(ii)	be directly responsible for overseeing the work of the independent auditors engaged for the purpose of<br>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<br>auditors shall report directly to the Committee;
---	---
(iii)	review and evaluate the performance of the lead partner of the independent auditors;
---	---
(iv)	review the basis of management’s recommendation for the appointment of independent auditors and<br>recommend to the Board appointment of independent auditors and their compensation;
---	---
(v)	review the terms of engagement and the overall audit plan (including the materiality levels to be applied)<br>of the independent auditors, including the appropriateness and reasonableness of the auditors’ fees;
---	---
(vi)	when there is to be a change in auditors, review the issues related to the change and the information to be<br>included in the required notice to securities regulators of such change; and
---	---

B-2

(vii)	review and pre-approve any audit and permitted non-audit services to be provided by the independent<br>auditors’ firm and consider the impact on the independence of the auditors.
(f)	The Committee may delegate to one or more Committee members (the “Delegate”) authority to<br>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<br>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 fee for such non-audit services shall not exceed $50,000 either individually or in the aggregate,<br>for a particular financial year without the approval of the Committee of the Company.
---	---
(g)	At least annually, obtain and review the report by the independent auditors describing the independent<br>auditors’ internal quality control procedures, any material issues raised by the most recent interim quality-control review, or peer review, of the independent auditors, or by any inquiry or investigation by governmental or professional<br>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<br>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<br>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<br>accounting policies and practices used by Obsidian Energy, (ii) all alternative accounting treatments of financial information within generally accepted accounting principles related to material items that have been discussed with management,<br>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<br>Energy.
---	---
(j)	Obtain assurance from the independent auditors that disclosure to the Committee is not required pursuant to<br>the provisions of the United States Securities Exchange Act of 1934, as amended, regarding the discovery by the independent auditors of illegal acts.
---	---
(k)	Review, set and approve hiring policies relating to current and former staff of current and former<br>independent auditors.
---	---
(l)	Review all public disclosure containing financial information before release (provided that the Committee is<br>not required to review investor presentations that do not contain financial information or earnings guidance that has not previously been generally disclosed to the public).
---	---
(m)	Review all pending significant litigation to ensure disclosures are sufficient and appropriate.<br>
---	---
(n)	Satisfy itself that adequate procedures are in place for the review of Obsidian Energy’s public<br>disclosure of financial information from Obsidian Energy’s financial statements and periodically assess the adequacy of those procedures.
---	---
(o)	Review and discuss major financial risk exposures and the steps management has taken to monitor and control<br>such exposures.
---	---
(p)	Establish procedures independent of management for:
---	---
(i)	the receipt, retention and treatment of complaints received by Obsidian Energy regarding accounting,<br>internal accounting controls, or auditing matters; and
---	---
(ii)	the confidential, anonymous submission by employees of Obsidian Energy of concerns regarding questionable<br>accounting or auditing matters.
---	---
(q)	Review any other matters required by law, regulation or stock exchange requirement, or that the Committee<br>feels are important to its mandate or that the Board chooses to delegate to it.
---	---

B-3

(r)	Establish, review and update periodically a Code of Business and ensure that management has established<br>systems to enforce these codes.
(s)	Review management’s monitoring of Obsidian Energy’s compliance with the organization’s Code<br>of Business Conduct.
---	---
(t)	Review and discuss with the Chief Executive Officer, the Chief Financial Officer and the independent<br>auditors, the matters required to be reviewed with those persons in connection with any certificates required by applicable laws, regulations or stock exchange requirements to be provided by the Chief Executive Officer and the Chief Financial<br>Officer.
---	---
(u)	Review and discuss major issues regarding accounting principles and financial statement presentations,<br>including any significant changes in Obsidian Energy’s selection or application of accounting principles.
---	---
(v)	Review and discuss major issues as to the adequacy of Obsidian Energy’s internal controls and any<br>special audit steps adopted in light of material control deficiencies.
---	---
(w)	Review and discuss analyses prepared by management and/or the independent auditors setting forth significant<br>financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the effects of alternative generally accepted accounting principles methods on the financial statements.<br>
---	---
(x)	Review and discuss the effect of regulatory and accounting initiatives, as well as off-balance sheet<br>structures, on Obsidian Energy’s financial statements.
---	---
(y)	Review and discuss the type and presentation of information to be included in earnings press releases,<br>paying particular attention to any use of “pro forma” or “adjusted” non-GAAP information.
---	---
(z)	Annually review the Committee’s Mandate and the Committee Chair’s Terms of Reference and recommend<br>any proposed changes to the Board for consideration.
---	---
(aa)	Review and/or approve any other matters specifically delegated to the Committee by the Board.<br>
---	---
3.	KNOWLEDGE & EDUCATION
---	---

Committee members shall be “financially literate” within the meaning of National Instrument 52-110 AuditCommittees (“NI 52-110”), and 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.

4.	COMPOSITION
(a)	Committee members shall be appointed and removed by the Board and the Committee shall be composed of three<br>directors of Obsidian Energy or such greater number as the Board may from time to time determine.
---	---
(b)	Provided the Board Chair is an “independent” director as contemplated in subparagraph 4(c) below<br>and “financially literate” as contemplated in subparagraph (d) below, the Board Chair shall be a non-voting ex officio member of the Committee, subject to subparagraph 5(e) below.
---	---
(c)	Each member of the Committee shall be an “independent” director in accordance with the definition<br>of “independent” in (a) NI 52-110 and (b) Section 303A.02 and 303A.07 of the New York Stock Exchange Listed Company Manual, and in accordance with all other applicable securities laws or rules of any stock exchange on which<br>Obsidian Energy’s securities are listed for trading.
---	---
(d)	All of the members must be “financially literate” within the meaning of NI 52-110 and<br>Section 303A.07 (a) of the New York Stock Exchange Listed Company Manual unless the Board has determined to rely on an exemption in NI 52-110. Being “financially literate” means members have the ability to read and understand a<br>set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Obsidian Energy’s financial<br>statements. In addition, at least one member of the Committee must have accounting or related financial management expertise, as the Board interprets such qualification in its business judgment.
---	---

B-4

(e)	In connection with the appointment of the members of the Committee, the Board will determine whether any<br>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<br>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<br>management proxy circular and annual report on Form 40-F filed with the United States Securities and Exchange Commission.
(f)	The Board shall appoint the Chair of the Committee from among the Committee members.
---	---
5.	MEETINGS
---	---
(a)	The Committee shall meet at least four times per year at the call of the Committee Chair. The Committee<br>Chair may call additional meetings as required. In addition, a meeting may be called by the Board Chair, the Chief Executive Officer, the Chief Financial Officer or any member of the Committee.
---	---
(b)	As part of its job to foster open communication, the Committee shall meet at least annually with management,<br>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<br>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<br>financial statements and the management’s discussion and analysis of financial conditions and results of operations.
---	---
(c)	Notice of the time and place of every meeting may be given orally, in writing, by facsimile or by other<br>electronic means of communication to each member of the Committee at least 48 hours prior to the time fixed for such meeting. A member may, in any manner, waive notice of the meeting. Attendance of a member at a meeting shall constitute waiver of<br>notice.
---	---
(d)	Agendas, with input from management and the Committee Chair, shall be circulated by the Committee Secretary<br>to Committee members and relevant members of management along with appropriate meeting materials and background reading on a timely basis prior to Committee meetings.
---	---
(e)	A quorum shall be a majority of the members of the Committee present in person or by telephone or video<br>conference or by other electronic or communication medium or by a combination thereof. If an independent ex officio non-voting member’s presence is required to attain a quorum, then such member shall be a voting member of the Committee for such<br>meeting.
---	---
(f)	The Committee Chair shall be a full voting member of the Committee. If the Committee Chair is unavailable or<br>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<br>of the Committee present at such meeting. The Chair of any Committee meeting 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<br>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,<br>independent directors, including the Board Chair, shall always have the right to be present. As part of each Committee meeting the Committee members will also meet “in-camera” without any members of management present, and in the<br>Committee’s discretion, without any other members of the Board who are not Committee members present.
---	---
(h)	The secretary to the Committee (the “Committee Secretary”) will be either the Corporate<br>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<br>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<br>Committee shall be available for examination by any Director.
---	---

B-5

6.	RESOURCES
(a)	The Committee may retain special legal, accounting, financial or other consultants or advisors to advise the<br>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, subject to review by the Board, and<br>at the expense of the Company.
---	---
(b)	The Committee shall have access to Obsidian Energy’s senior management and documents as required to<br>fulfill its responsibilities and shall be provided with the resources necessary to carry out its responsibilities.
---	---
(c)	The Committee shall have the authority to investigate any financial activity of Obsidian Energy and to<br>communicate directly with the internal auditors (if any) and independent auditors. All employees are to cooperate as requested by the Committee.
---	---
7.	DELEGATION
---	---

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

8.	STANDARDS OF LIABILITY
(a)	Nothing contained in this Mandate is intended to expand applicable standards of liability under statutory,<br>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<br>procedures and standards as it deems necessary from time to time to fulfill its responsibilities, subject to applicable statutory, regulatory and other legal requirements.
---	---
(b)	The duties and responsibilities of a member of the Committee are in addition to those duties set out for a<br>member of the Board.
---	---

B-6

EX-99.2

Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the year ended December 31, 2020

This management’s discussion and analysis of financial condition and results of operations (“MD&A”) of Obsidian Energy Ltd. (“Obsidian Energy”, the “Company”, “we”, “us”, “our”) should be read in conjunction with the Company’s audited consolidated financial statements (“audited consolidated Financial Statements”) for the year ended December 31, 2020. The date of this MD&A is March 26, 2021. All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise.

For additional information, including Obsidian Energy’s audited consolidated Financial Statements and Annual Information Form, please go to the Company’s website at www.obsidianenergy.com, in Canada to the SEDAR website at www.sedar.com or in the United States to the EDGAR website at www.sec.gov.

Certain financial measures such as funds flow from operations, funds flow from operations per share-basic, funds flow from operations per share-diluted, free cash flow, netback, net operating costs, gross revenues and net debt included in this MD&A do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered non-GAAP measures; accordingly, they may not be comparable to similar measures provided by other issuers. This MD&A also contains oil and gas information and forward-looking statements. Please see the Company’s disclosure under the headings “Non-GAAP Measures”, “Oil and Gas Information”, and “Forward-Looking Statements” included at the end of this MD&A.

All per share figures included in this MD&A reflect the 7:1 common share consolidation that was effective June 5, 2019. Additionally, within this MD&A the Company has updated the presentation of our financial figures to disclose dollar figures rounded to the nearest hundred thousand. This may result in immaterial differences in the comparative figures

Annual Financial Summary

	Year ended December 31
(millions, except per share amounts)	2020			2019			2018
Production revenues	$	275.4	****	$	409.3		$	420.6
Cash flow from operations	****	79.4	****		76.8			98.2
Basic and Diluted per share	****	1.08	****		1.05			1.36
Funds flow from operations	****	117.8	****		159.1			92.5
Basic and Diluted per share	****	1.61	****		2.18			1.28
Net loss	****	(771.7	)		(788.3	)		(303.9	)
Basic and Diluted per share	****	(10.53	)		(10.82	)		(4.20	)
Capital expenditures	****	57.2	****		103.2			166.8
Property acquisitions (dispositions), net	****	(0.1	)		(10.7	)		(12.7	)
Debt ^(1)^	****	455.3	****		460.5			418.7
Total assets	$	964.1	****	$	1,904.8		$	2,648.5
(1)	Includes drawings under the Company’s syndicated credit facility and outstanding senior notes.<br>
---	---

Starting in 2018, the Company’s development activities have been focused on our significant drilling inventory within the Cardium. In conjunction with this, the Company’s operations have become more focused which resulted in minor asset disposition activity outside of our Cardium lands and the completion of our Legacy shut-in program in early 2019 which removed several negative cash flow properties from our portfolio. This resulted in lower production, which contributed to reduced production revenues in 2019 and 2020 compared to 2018. Additionally, in 2020, the low commodity price environment, mainly due to the COVID-19 pandemic and related supply and demand implications, reduced production revenues and impacted cash flow from operations and funds flow from operations. The effect of lower oil prices and production was more than offset by the Company’s lower cost structure and improvement in our working capital position due to reduced capital expenditures, which resulted in an improvement in cash flow from operations compared to 2019.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 1

The net losses in 2020 and 2019 were mainly due to non-cash property, plant and equipment (“PP&E”) impairment charges as a result of lower forecasted commodity prices, various economic factors and classifying our interest in the Peace River Oil Partnership (“PROP”) as held for sale in 2019. In 2018, realized risk management losses related to the Company’s outstanding hedges, non-cash PP&E impairments and reduced revenues late in 2018 from widening oil differentials contributed to the net loss in that period.

In 2020, capital expenditures were reduced, beginning in the second quarter, because of uncertainty regarding oil prices due to the COVID-19 pandemic. Since 2019, the Company has focused on spending within funds flow from operations and, as a result, capital expenditures were lower than 2018. The Company’s Willesden Green assets in the Cardium have been the primary area of development since mid-2018.

Quarterly Financial Summary

(millions, except per share and production amounts) (unaudited)

Three months ended	Dec. 312020		Sep. 30<br>2020			June 30<br>2020			Mar. 31<br>2020			Dec. 31<br>2019			Sep. 30<br>2019			June 30<br>2019			Mar. 31<br>2019
Production revenues	$	72.8	$	75.4		$	48.2		$	79.0		$	111.6		$	90.1		$	107.8		$	99.8
Cash flow from operations	****	11.1		34.8			2.1			31.4			49.5			32.0			(2.7	)		(2.0	)
Basic per share	****	0.15		0.47			0.03			0.43			0.68			0.44			(0.04	)		(0.03	)
Diluted per share	****	0.15		0.47			0.03			0.43			0.68			0.44			(0.04	)		(0.03	)
Funds flow from operations ^(1)^	****	26.4		30.4			24.7			36.3			54.2			28.4			41.5			35.0
Basic per share	****	0.36		0.41			0.34			0.50			0.74			0.39			0.57			0.48
Diluted per share	****	0.36		0.41			0.34			0.50			0.74			0.39			0.57			0.48
Net income (loss)^^	****	0.2		(3.2	)		(21.1	)		(747.6	)		(543.2	)		(28.9	)		(159.6	)		(56.6	)
Basic per share	****	0.01		(0.04	)		(0.29	)		(10.24	)		(7.44	)		(0.40	)		(2.19	)		(0.78	)
Diluted per share	$	0.01	$	(0.04	)	$	(0.29	)	$	(10.24	)	$	(7.44	)	$	(0.40	)	$	(2.19	)	$	(0.78	)
Production
Light oil (bbls/d)	****	10,055		10,952			12,800			12,512			12,246			10,802			12,453			12,376
Heavy oil (bbls/d)	****	2,895		2,823			1,966			3,644			3,718			3,991			4,059			4,096
NGLs (bbls/d)	****	2,087		2,244			2,278			2,239			2,095			2,192			2,201			2,122
Natural gas (mmcf/d)	****	52		54			53			52			52			51			55			54
Total (boe/d)	****	23,644		25,031			25,872			27,092			26,639			25,505			27,835			27,651
(1)	Please refer to our prior quarterly filings for reconciliations of cash flow from operations to funds flow<br>from operations.
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OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 2
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Cash flow from Operations and Funds Flow from Operations

	Year ended December 31
(millions, except per share amounts)^^	2020			2019
Cash flow from operating activities	$	79.4	****	$	76.8
Change in non-cash working capital	****	6.6	****		39.6
Decommissioning expenditures	****	11.1	****		14.4
Onerous office lease settlements	****	9.7	****		2.2
Deferred financing costs	****	(2.8	)		—
Financing fees paid	****	5.6	****		—
Realized foreign exchange loss – debt maturities	****	—	****		2.6
Restructuring charges ^(1)^	****	0.6	****		3.6
Transaction costs	****	3.5	****		—
Other expenses ^(2)^	****	4.1	****		19.9
Funds flow from operations	$	117.8	****	$	159.1
Per share – funds flow from operations
Basic and Diluted per share	$	1.61	****	$	2.18
(1)	In 2019 and 2020, excludes the non-cash portion of restructuring.<br>
---	---
(2)	In 2019, mainly includes legal fees related to claims against former Penn West Petroleum Ltd. (“Penn<br>West”) employees related to the Company’s 2014 restatement of certain financial results.
---	---

In 2020, funds flow from operations was lower than 2019, primarily due to lower oil prices (particularly in the second quarter of 2020), as a result of the impact of the COVID-19 pandemic and related supply and demand implications. Lower production volumes due to our deferred capital program also contributed to the decrease, which were partially offset by our lower cost structure.

Cash flow from operations increased in 2020 from 2019 primarily due to the impact of working capital changes and the Company’s lower cost structure.

Business Strategy

We believe our plan to focus on our industry leading Cardium position in addition to our goal of becoming a consolidating entity within the Cardium, offers a predictable, liquids weighted, production profile that is capable of generating sustainable value for all stakeholders. Our priorities are clear from both an operational and strategic perspective as we actively pursue Cardium consolidation while continuing to unlock value through our development program.

In September 2020, the Company formally launched an offer (the “Offer”) to purchase all issued and outstanding common shares (“Bonterra Share”) of Bonterra Energy Corp. (“Bonterra”) for consideration of two common shares of Obsidian Energy for each Bonterra Share. The Company believes that the combination of the two companies will create the Cardium Champion allowing for the realization of material synergies that have the combined effect of generating increased cash flow, reducing debt levels, further lowering our breakeven $US WTI/barrel costs and ultimately allowing us to return money back to shareholders.

The Offer is subject to certain conditions, including that the Bonterra Shares validly deposited to the Offer and not withdrawn represent more than 50% of the outstanding Bonterra Shares and certain regulatory and third-party approvals have been obtained and other customary conditions. The Offer is open for acceptance until 5:00pm (Mountain Daylight Time) on March 29, 2021, unless extended, accelerated or withdrawn. Please refer to our Take-Over Bid circular dated September 21, 2020 and our subsequent notices of extension, variation and change for further details. The Company will provide updates on the Offer as required.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 3

With oil prices becoming more constructive and less volatile as 2020 progressed, the Company recommenced drilling in our Willesden Green Cardium asset in late 2020 where we have a significant inventory of high netback drilling opportunities. This activity started our 2021 development program which we expected to total $125—$130 million of capital expenditures.

In 2020, the Company has continued to focus on cost savings initiatives as well as implementing temporary cost saving measures due to COVID-19 induced oil price reductions. These successful efforts, combined with lower production volumes, led to a $28 million or 21 percent reduction in operating costs and a $6 million or 30 percent reduction in general & administrative (“G&A”) costs compared to 2019. In 2021, the Company plans to continue this operational momentum and further cost reduction initiatives to improve our base business.

COVID-19 pandemic impact

In March 2020, the World Health Organization declared COVID-19 a global pandemic. Since that time, the oil and gas industry has experienced significant volatility with commodity prices, and in particular oil prices, as a result of a decline in economic activity and lower demand for commodities in both Canada and around the world. In the second half of 2020 and into 2021, oil prices have partially recovered from the lows that occurred in the second quarter of 2020 as restrictions eased and vaccines started to be administered. In early 2021, full demand recovery remains uncertain as countries are at various stages of rolling-out vaccines while virus outbreaks continue to occur, mainly due to new variants which has resulted in activity restrictions.

At the time oil prices began to fall in March, we had completed the majority of our drilling program for the first half of 2020, which totaled $49 million including drilling 10 horizontal wells, optimization spending and decommissioning expenditures. In response to the low oil price environment at the time, the Company deferred our second half 2020 development program. For the remainder of the year, minimal capital spending occurred with activities focused on highly capital efficient, optimization projects.

The Company actively reviewed our portfolio beginning in March in 2020, considering the commodity price outlook at the time, which resulted in the shut-in of production deemed uneconomic. This reduced average production in the second quarter of 2020 by approximately 2,100 boe per day. This reduction was primarily comprised of heavy oil and associated gas production in the Peace River and Viking areas and certain light-oil properties in the Cardium area. As oil prices began to improve in May and June, the Company restarted the majority of the shut-in production and currently there is approximately 250 boe per day of production that remains offline, mostly consisting of heavy oil properties. The Company will continue to evaluate and, if required, adjust our production base as appropriate based on expected realized commodity prices.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 4

In 2020, the Company applied to applicable government relief programs. During the year, we benefited from the Canadian Emergency Wage Subsidy (“CEWS”) and received funds totaling approximately $3.5 million. The CEWS allows eligible companies to receive a subsidy of employee wages, subject to a cap. The program has been extended into 2021 and we will continue to evaluate our eligibility to participate in the amended CEWS program. Additionally, under the Alberta Site Rehabilitation program (“ASRP”) the Company has successfully been awarded grants, on a gross basis, totaling $20 million and an additional $10 million in allocation eligibility as an Area Based Closure program (“ABC” program) participant. These awards will allow the Company to expand our abandonment activities for wells, pipelines, facilities and related site reclamation. We began utilizing the grants during the fourth quarter of 2020, which resulted in $2.4 million of grant usage, ($2.2 million on a net basis) resulting in 99 wells being abandoned. We will continue to be actively engaged with the Government of Alberta on further ASRP developments, and other provincial and federal programs, as they are announced.

Business Environment

The following table outlines quarterly averages for benchmark prices and Obsidian Energy’s realized prices for the previous eight quarters.

			Q3 2020			Q2 2020			Q1 2020			Q4 2019			Q3 2019			Q2 2019			Q1 2019
Benchmark prices
WTI oil (US/bbl)	42.66	****	$	40.93		$	27.85		$	46.17		$	56.96		$	56.45		$	59.81		$	54.90
Edm mixed sweet par price (CAD/bbl)	50.29	****		49.83			29.55			51.62			67.99			68.40			73.81			66.52
Western Canada Select (CAD/bbl)	43.46	****		42.41			22.42			34.11			54.29			58.39			65.72			56.73
NYMEX Henry Hub (US/mmbtu)	2.53	****		2.00			1.72			1.95			2.50			2.32			2.47			2.85
AECO Index (CAD/mcf)	2.77	****		2.24			1.99			2.22			2.48			0.92			1.08			2.66
Foreign exchange rate (CAD/US)	1.303	****		1.332			1.386			1.345			1.320			1.321			1.338			1.329
Benchmark differentials
WTI – Edm Light Sweet (US/bbl)	(4.07	)		(3.51	)		(6.14	)		(7.58	)		(5.37	)		(4.66	)		(4.63	)		(4.85	)
WTI – WCS Heavy (US/bbl)	(9.31	)		(9.08	)		(11.47	)		(20.53	)		(15.83	)		(12.24	)		(10.68	)		(12.22	)
Average sales price (1)
Light oil (CAD/bbl)	50.76	****		50.84			29.20			50.59			70.57			68.14			72.20			64.88
Heavy oil (CAD/bbl)	30.00	****		29.54			5.98			20.07			41.80			40.44			42.63			30.62
NGLs (CAD/bbl)	24.61	****		22.11			11.65			22.52			31.42			15.75			14.95			21.44
Total liquids (CAD/bbl)	43.14	****		43.06			24.18			41.13			60.10			54.87			59.05			52.37
Natural gas (CAD/mcf)	2.81	****	$	2.40		$	2.14		$	2.20		$	2.55		$	1.05		$	1.18		$	2.41

All values are in US Dollars.

(1)	Excludes the impact of realized hedging gains or losses.

Oil

In 2020, WTI prices averaged US$39.40 per barrel compared to US$57.03 per barrel in 2019. Oil prices started 2020 above WTI US$60 per barrel due to the escalating conflict between the US and Iran. This conflict eventually subsided, and the focus shifted to the potential outlook for worldwide oil demand in response to the impact of the COVID-19 pandemic and concerns over additional supply as OPEC restrictions stopped at the end of March and both Saudi Arabia and Russia signaled potential production increases. This resulted in oil prices decreasing into the WTI US$20 per barrel range in March. In the second quarter of 2020, OPEC, Russia and others agreed to a 10-million-barrel per day production cut, however, the negative demand impact of the COVID-19 pandemic and the lack of oil storage was the main focus, which led to WTI moving below US$20 per barrel. In the second half of 2020 oil prices steadily improved, mainly due to OPEC extending their production cuts, demand being partially restored as some COVID-19 restrictions were eased and the roll-out of several COVID-19 vaccines in late 2020. In early 2021, oil prices have continued to rise to above US$60 per barrel primarily due to increased demand projections as the COVID-19 vaccine distribution continues to increase.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 5

Differentials were relatively consistent year-over-year with Mixed Sweet Blend (“MSW”) averaging US$5.33 per barrel in 2020 compared to US$4.88 per barrel in 2019 and Western Canadian Select Heavy (“WCS”) averaging $12.58 per barrel in 2020 compared to US$12.75 per barrel in 2019. In early 2020, oil differentials were volatile because of increasing storage levels in Western Canada. Subsequent to the first quarter of 2020, differentials began to narrow largely due to refining capacity increasing as demand improved in addition to significant production shut-ins in Western Canada.

The Company has the following oil contracts in place on a weighted average basis:

Term	Notional<br>volume		Pricing
January 2021		6,150 bbl/d	$	59.84/bbl
February 2021		6,250 bbl/d	$	64.33/bbl
March 2021		6,800 bbl/d	$	68.80/bbl
April 2021		4,750 bbl/d	$	77.74/bbl
May 2021		1,125 bbl/d	$	81.50/bbl

Additionally, the Company has the following physical contracts in place:

		Term		Pricing
Physical Oil Contracts<br>(1)
WTI	542 bbl/d		Jan – Mar 2021
WTI	571 bbl/d		Apr – Jun 2021
Light Oil Differential (2)<br>(3)
		Apr – Jun 2021		5.51/bbl
		Jul – Sep 2021		5.82/bbl
Light Oil Differential – <br>(2)
		Apr – Jun 2021		US4.00/bbl
		Jul – Sep 2021		US4.42/bbl
Heavy Oil Differential<br>(4)
		Jul – Sep 2021		14.85/bbl

All values are in US Dollars.

(1)	WTI, differentials and foreign exchange hedged to lock-in positive<br>net operating income on certain heavy oil properties.
(2)	Differentials completed on a WTI—MSW basis.
---	---
(3)	USD transactions completed on a US$ WTI—US$ MSW basis and converted to Canadian dollars using a fixed<br>foreign exchange ratio of CAD/USD $1.281 in the second quarter of 2021 and $1.279 in the third quarter of 2021.
---	---
(4)	Differentials completed on a WTI—WCS basis.
---	---

Natural Gas

In 2020, NYMEX Henry Hub gas prices averaged US$2.03 per MMbtu compared to US$2.53 per MMbtu in 2019 with the decline in 2020 mostly attributed to milder weather conditions across much of North America in the early part of the year. In Alberta, AECO 5A prices increased in 2020 and averaged $2.38 per mcf compared to $1.76 per mcf in 2019, with access to storage injection in the summer and winter weather conditions in Western Canada contributing to the increase.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 6

The Company has the following natural gas hedges in place on a weighted average basis:

Term	Notional<br>volume		Pricing
January 2021		23,700 mcf/d	$	2.94/mcf
February 2021		23,700 mcf/d	$	2.94/mcf
March 2021		26,100 mcf/d	$	2.96/mcf
April 2021		26,100 mcf/d	$	2.83/mcf
May 2021		21,300 mcf/d	$	2.68/mcf
June 2021		21,300 mcf/d	$	2.67/mcf
July 2021		4,700 mcf/d	$	2.28/mcf
August 2021		4,700 mcf/d	$	2.28/mcf
September 2021		4,700 mcf/d	$	2.28/mcf
October 2021		4,700 mcf/d	$	2.28/mcf

Average Sales Prices

	Year ended December 31
	2020			2019			% change
Light oil (per bbl)	$	44.81	****	$	68.99			(35	)
Heavy oil (per bbl)	****	22.56	****		38.82			(42	)
NGLs (per bbl)	****	20.13	****		20.77			(3	)
Total liquids (per bbl)	****	37.73	****		56.63			(33	)
Risk management (loss) gain (per bbl)^^	****	3.67	****		(0.98	)		n/a
Total liquids price, net (per bbl)	****	41.40	****		55.65			(26	)
Natural gas (per mcf)	****	2.39	****		1.79			34
Risk management (loss) gain (per mcf)^^	****	(0.07	)		—			n/a
Natural gas net (per mcf)	****	2.32	****		1.79			30
Weighted average (per boe)	****	29.63	****		41.60			(29	)
Risk management (loss) gain (per boe)^^	****	2.25	****		(0.66	)		n/a
Weighted average net (per boe)	$	31.88	****	$	40.94			(22	)

Performance Indicators

Obsidian Energy monitors performance based on the following three key focus areas using several qualitative and quantitative factors:

•	Values – Execution of our field, health, safety, environmental and regulatory programs and our focus on<br>operational excellence;
•	Delivery – Key performance metrics include obtaining a leading cost structure within the industry and a<br>focus on free cash flow generation; and
---	---
•	Sustainability – Management of the Company’s asset portfolio, financial stewardship and the goal of<br>sustaining production and reserves and long-term competitive return on investment for our shareholders.
---	---
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 7
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Values

At Obsidian Energy, the health, safety and wellness of our employees, contractors and stakeholders living within our areas of operation is paramount. Safety policies, procedures and programs developed by Obsidian Energy shall meet or exceed legislative requirements and all injuries and serious incidents are reported and investigated accordingly. Additionally, the Company is committed to minimizing the environmental impacts of our operations with our programs focusing on stakeholder communication, impact minimization, resource conservation and site abandonment and reclamation. Throughout our operations, Obsidian Energy requires a high standard of professional conduct and supports a culture that ensures all individuals act with integrity and respect. These principles form the operational standards for the Company.

Delivery

The Company met all key performance targets in 2020 as we continued to emphasize operational execution and focus on cost reduction initiatives as we adjusted our operations and development plans in response to the low oil price environment due to the impact of the COVID-19 pandemic.

•	The Company’s average annual production of 25,404 boe per day was within recently upwardly revised<br>production guidance of 25,300 to 25,500 boe per day;
•	Capital expenditures were $57.2 million compared to revised guidance of $56 million and<br>decommissioning expenditures were $11.1 million compared to revised guidance of $11 million;
---	---
•	Net operating costs per boe were $11.15 per boe, consistent with the Company’s recently improved revised<br>guidance of $11.00—$11.20 per boe; and
---	---
•	G&A costs per boe were $1.51, consistent with the Company’s recently improved revised guidance of<br>$1.45—$1.55 per boe.
---	---

In 2021, the Company will continue to target capital expenditures within funds flow from operations. For 2021 targets, please refer to the “Outlook” section below.

Sustainability

In early 2020, Obsidian Energy continued to focus on development of the Willesden Green play in the Cardium. Production results from these wells in addition to the results from wells drilled in the play since we concentrated our development activities on the area in 2018 continue to outperform our expectations. In response to the low and volatile oil price environment beginning in March 2020, the Company suspended all development activities until pricing improved later in the year. Capital activities were re-started in December 2020 as part of our first half 2021 development program. This program will continue to focus on Willesden Green with five of the nine wells drilled expected to be on production by the end of March 2021. For 2021, the Company is anticipating capital expenditures of $125—$130 million which includes development activity, the continuation of our highly capital efficient optimization program and minor infrastructure expenditures. The Company will continue to monitor commodity prices and has the operational flexibility to modify our capital program in response to commodity prices and potentially increase the pace of development with our significant drilling inventory across our asset portfolio.

RESULTS OF OPERATIONS

Production

	Year ended December 31
Daily production	2020		2019		% change
Light oil (bbls/d)	****	11,574		11,966		(3	)
Heavy oil (bbls/d)	****	2,832		3,965		(29	)
NGLs (bbls/d)	****	2,212		2,153		3
Natural gas (mmcf/d)	****	53		53		—
Total production (boe/d)	****	25,404		26,901		(6	)
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 8
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During 2020, the Company reduced development activity, particularly in mid-2020, in response to the COVID-19 pandemic and the low commodity price environment, which led to a minor decrease in production due to base declines.

Additionally, as a result of the lower oil pricing environment, the Company shut-in production deemed temporarily uneconomic which reduced average production by approximately 2,100 boe per day during the second quarter of 2020, mostly related to heavy oil properties in the Peace River area. This contributed to the decrease from the comparable period. Currently there is approximately 250 boe per day of production that remains offline, mostly consisting of heavy oil properties. The Company will continue to evaluate and, if required, adjust our production base as appropriate based on expected realized commodity prices.

As a result of our continued focus on development within the Willesden Green area, Cardium production has increased over last year’s levels. This was partially offset by our decision to defer development spending for the majority of 2020, beginning in March, in response to the low and volatile commodity price environment due to the COVID-19 pandemic. Heavy oil production declines have reduced our total Company production due to restricted capital spending, our decision to temporarily shut-in certain heavy oil production and our decision to defer the repair of certain failed wells that were uneconomic.

Average production within the Company’s key development areas and within the Company’s Legacy asset area was as follows:

	Year ended December 31
Daily production (boe/d)<br>^(1)^	2020		2019		% change
Cardium	****	21,003		20,706		1
Peace River	****	3,136		4,452		(30	)
Viking	****	860		987		(13	)
Legacy	****	405		756		(46	)
Total	****	25,404		26,901		(6	)
(1)	Refer to “Supplemental Production Disclosure” for details by product type.
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Netbacks

	Year ended December 31
							2020			2019
		Liquids			Natural Gas		****	Combined	****		Combined
	(bbl)			(mcf)			(boe)			(boe)
Operating netback:
Sales price ^(1)^	$	37.73		$	2.39		$	29.63	****	$	41.60
Risk management (loss) gain ^(2)^		3.67			(0.07	)	****	2.25	****		(0.66	)
Royalties		(2.09	)		(0.05	)	****	(1.47	)		(3.11	)
Transportation		(2.28	)		(0.20	)	****	(1.91	)		(2.76	)
Net operating costs		(14.23	)		(0.89	)	****	(11.15	)		(13.42	)
Netback	$	22.80		$	1.18		$	17.35		$	21.65
		(bbls/d	)		(mmcf/d	)	****	(boe/d	)		(boe/d	)
Production		16,618			53		****	25,404	****		26,901
(1)	Includes the impact of commodities purchased and sold to/from third parties—$0.2 million (2019<br>– ($0.4 million)).
---	---
(2)	Realized risk management gains and losses on commodity contracts.
---	---
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 9
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For 2020, netbacks were lower than the comparable period as the impact of the COVID-19 pandemic and resultant supply and demand implications resulted in lower realized prices in 2020. This was partially offset by lower net operating costs as a result of several successful cost saving initiatives, reduced royalty rates due to lower oil prices and higher realized risk management gains on oil hedges, particularly during the first half of 2020.

Production Revenues

A reconciliation from production revenues to gross revenues is as follows:

	Year ended December 31
(millions)	2020			2019
Production revenues	$	275.4	****	$	409.3
Realized risk management (loss) gain<br>^(1)^	****	20.9	****		(7.2	)
Sales of commodities purchased	****	4.8	****		2.9
Less: Commodities purchased	****	(4.6	)		(3.3	)
Gross revenues	$	296.5	****	$	401.7
(1)	Relates to realized risk management gains and losses on commodity contracts
---	---

Production revenues and gross revenues were both lower than 2019 as a result of lower oil prices due to the COVID-19 pandemic, lower production volumes as a result of the Company temporarily shutting-in volumes deemed uneconomic during the second quarter of 2020 and deferred development capital spending. This was partially offset by oil hedging gains and higher natural gas prices in 2020 compared to 2019.

Change in GrossRevenues

(millions)
Gross revenues – January 1 – December 31, 2019	$	401.7
Decrease in liquids production		(22.4	)
Decrease in liquids prices ^(1)^		(92.9	)
Increase in natural gas prices ^(1)^		10.1
Gross revenues – January 1 – December 31, 2020 ^(2)^	$	296.5
(1)	Includes realized risk management gains and losses on commodity contracts.
---	---
(2)	Excludes processing fees and other income.
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Royalties

	Year ended December 31
	2020			2019
Royalties (millions)	$	13.7	****	$	30.6
Average royalty rate ^(1)^	****	5	%		8	%
$/boe	$	1.47	****	$	3.11
(1)	Excludes effects of risk management activities and other income.
---	---

For 2020, royalties decreased from the comparable period largely due to lower oil prices.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 10

Expenses

	Year ended December 31
(millions)	2020		2019
Net Operating	$	103.7	$	131.7
Transportation	****	17.7		27.1
Financing	****	37.2		40.6
Share-based compensation	$	3.4	$	4.6
	Year ended December 31
---	---	---	---	---
(per boe)	2020		2019
Net Operating	$	11.15	$	13.42
Transportation	****	1.91		2.76
Financing	****	3.99		4.13
Share-based compensation	$	0.36	$	0.47

Operating

A reconciliation of operating costs to net operating costs is as follows:

	Year ended December 31
(millions)	2020			2019
Operating costs	$	115.4	****	$	145.4
Less processing fees	****	(6.3	)		(7.7	)
Less road use recoveries	****	(5.4	)		(6.0	)
Net Operating costs	$	103.7	****	$	131.7

In 2020, the Company continued to progress on several cost saving initiatives and also quickly responded to the lower commodity price environment arising from the COVID-19 pandemic, which resulted in the Company temporally shutting-in production deemed uneconomic. This decision reduced operating costs beginning in the second quarter and partially in the third quarter of 2020, as most shut-in production was restored with oil prices improving. Additionally, the Company benefited from the CEWS program which reduced operating costs by $2.2 million and had a $0.24 per boe impact on operating expenses in 2020. The Company further lowered operating costs by temporarily reducing field staff salaries effective May 1, 2020. Salaries were fully restored to their previous levels effective February 1, 2021.

The results for 2020 also include the full impact of the Company’s Legacy asset shut-in program of negative cash flow properties which was completed in 2019.

Transportation

The Company continues to utilize multiple sales points in the Peace River area to increase realized prices. The increase in realized prices is partially offset by additional transportation costs.

In 2020, the Company temporarily shut-in various heavy oil properties located in Peace River beginning in the second quarter and for part of the third quarter, which led to a reduction in transportation costs from the comparable period.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 11

Financing

Financing expense consists of the following:

	Year ended December 31
(millions)	2020		2019
Interest on bank debt and senior notes	$	22.8	$	28.3
Advisor fees	****	10.1		4.1
Deferred financing costs	****	2.8		0.7
Unwinding of discount on lease liabilities	****	1.5		7.5
Financing	$	37.2	$	40.6

Obsidian Energy’s debt structure includes short-term borrowings under our syndicated credit facility and term financing through our senior notes. Financing charges decreased from the comparable period mainly due to lower interest rates under the Company’s syndicated credit facility, which was partially offset by recent bank extension fees and various bank-related advisor fees.

The interest rates on the Company’s syndicated credit facility are subject to fluctuations in short-term money market rates as advances on the syndicated credit facility are generally made under short-term instruments. As at December 31, 2020, 87 percent (2019 – 87 percent) of the Company’s outstanding debt instruments were exposed to changes in short-term interest rates.

The Company has a reserve-based syndicated credit facility which is subject to a semi-annual borrowing base redetermination typically in May and November of each year. Subsequent to December 31, 2020, 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 is now set at $440 million. The $440 million of availability consists of a $225 million revolving syndicated credit facility and a $215 million non-revolving term loan.

Additionally, the following terms were included in the amending agreement:

•	the revolving period under the syndicated credit facility has been extended to May 31, 2022, with the end<br>date of the term period extended to November 30, 2022;
•	the maturity date of the non-revolving term loan is also<br>November 30, 2022;
---	---
•	the next scheduled borrowing base redeterminations will occur on November 30, 2021 and May 31, 2022;<br>
---	---
•	a revolving period reconfirmation date will occur on January 17, 2022, whereby, on or prior to such date,<br>the lenders may accelerate the end date of the revolving period to February 1, 2022. In this case, the end date of the term period would remain unchanged at November 30, 2022; and
---	---
•	the Company’s revolving credit facility will have a one-time<br>adjustment to reduce our undrawn availability to $35 million at December 31, 2021. Any borrowing availability at this time in excess of that amount will be used to reduce amounts outstanding on the<br>non-revolving term loan and senior notes.
---	---

Additionally, subsequent to December 31, 2020, the Company agreed with holders of our senior notes to extend the maturity dates of the notes due on November 30, 2021 to November 30, 2022 and to increase the interest rate on each series of our notes by approximately 2.1 percent.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 12

At December 31, 2020, the carrying value of the Company’s US dollar denominated senior notes was $60.3 million (2019 – $61.5 million). The decrease in carrying value is the result of a stronger Canadian dollar against the US dollar at the comparable balance sheet dates. Summary information on the Company’s senior notes outstanding as at December 31, 2020 is as follows:

	Issue date	Amount (millions)	Initial<br><br><br>Term	Average<br><br><br>interest<br> <br>rate	Weighted<br><br><br>average<br> <br>remaining<br><br><br>term ^(1)^
2008 Notes	May 29, 2008	US$4.0	8 –12 years	6.40%	0.9
2010 Q1 Notes	March 16, 2010	US$9.8	5 –15 years	5.85%	0.9
2010 Q4 Notes	December 2, 2010	US$21.2	5 –15 years	4.94%	0.9
2011 Notes	November 30, 2011	US$12.3	5 –10 years	4.79%	0.9
(1)	Subsequent to December 31, 2020, the Company entered into an agreement with noteholders to extend the<br>maturity dates from November 30, 2021 to November 20, 2022.
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Share-Based Compensation

Share-based compensation expense relates to the Company’s Stock Option Plan (the “Option Plan”), restricted shares units (“RSUs”) granted under the Restricted and Performance Share Unit Plan (“RPSU plan”), Deferred Share Unit Plan (“DSU plan”) and performance share units (“PSUs”) granted under the RPSU plan.

Share-based compensation expense consisted of the following:

	Year ended December 31
(millions)	2020		2019
RSU grants	$	2.0	$	4.5
DSU plan	****	1.2		0.1
PSU grants	****	0.1		—
Options	****	0.1		—
Share-based compensation	$	3.4	$	4.6

The share price used in the fair value calculation of the RPSU and DSU plan obligations at December 31, 2020 was $0.87 per share (2019 – $0.93).

General and Administrative Expenses

	Year ended December 31
(millions, except per boe amounts)	2020		2019
Gross	$	23.9	$	36.3
Per boe	****	2.57		3.63
Net	****	13.9		20.0
Per boe	$	1.51	$	2.03

In 2019, the Company focused our development operations on the Cardium which led to staff reductions, information technology savings and associated lower head office costs. The full effect of these changes has been realized in 2020, which led to decreases in both gross and net costs from 2019.

In 2020, the Company benefited from the CEWS program which reduced net G&A expenses by approximately $0.7 million or $0.07 on a per boe basis for 2020. Additionally, in response to the low commodity price environment due to the COVID-19 pandemic, the Company further reduced G&A expenses by temporarily reducing all head office staff salaries, suspending the Company’s matching component under the employee retirement savings plan and reducing Board of Directors retainer fees by 10 percent, until further notice. Salaries were fully reinstated effective February 1, 2021.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 13

Restructuring and other expenses

	Year ended December 31
(millions, except per boe amounts)	2020		2019
Restructuring	$	0.6	$	3.6
Per boe	****	0.07		0.37
Other	****	6.2		23.5
Per boe	$	0.67	$	2.41

The amounts included in restructuring primarily related to severance costs as the Company reduced staff with more streamlined operations.

In 2018, the Company fully utilized available insurance coverage relating to ongoing claims against former Penn West employees arising from the Company’s 2014 restatement of certain financial results when we were known as Penn West. A claim brought by the United States Securities and Exchange Commission (“SEC”) against Penn West was previously settled. The Company had been indemnifying two former employees pursuant to indemnity agreements in connection with the claims brought by the SEC arising out of the same restatement. In 2020, the SEC reached a settlement with the two former employees.

In 2019, the Company notified and commenced legal proceedings against the two former employees that the Company did not believe that the former employees met the criteria for indemnification, that the amounts invoiced on account of indemnification to date were in any event unreasonable, and that the Company would not be making any further advancements on account of indemnification. The preliminary application Judge ruled in favour of the two former employees. The Company appealed the preliminary application decision and was notified in late 2020 that the appeal was ruled in favour of the two former employees as well.

The Company continued to accrue for, but not pay, defense costs incurred on behalf of the two former employees and recently agreed to a settlement to pay $6.4 million of the defense costs equally over a 30-month period beginning in April 2021. As a result of the settlement, the Company will be recording a recovery of costs previously accrued in the first quarter of 2021.

Transaction costs

	Year ended December 31
(millions, except per boe amounts)	2020		2019
Transaction costs	$	3.5	$	—
Per boe	$	0.37	$	—

In September 2020, the Company formally launched an Offer to purchase all of the Bonterra Shares for consideration consisting of two common shares of Obsidian Energy for each Bonterra Share. This resulted in recording certain transaction related costs during the third and fourth quarter of 2020.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 14

Depletion, Depreciation, Impairment and Accretion

	Year ended December 31
(millions, except per boe amounts)	2020		2019
Depletion and depreciation (“D&D”)	$	128.4	$	245.8
D&D expense per boe	****	13.81		25.03
PP&E Impairment	****	766.2		657.7
PP&E Impairment per boe	****	82.40		66.99
Accretion	****	8.3		9.5
Accretion expense per boe	$	0.89	$	0.97

The Company’s D&D expense has decreased from the comparable period, primarily due to non-cash impairment charges recorded in both the first quarter of 2020 and the fourth quarter of 2019. These impairment charges were recorded mainly due to lower forecast commodity prices and higher discount rates due to continued commodity price and market value volatility within the oil and gas industry.

At December 31, 2020, given higher commodity prices, the Company completed an assessment across our Cardium and Peace River cash generating units (“CGU’s”) to determine if a reversal of prior period impairments was required, which resulted in a $18.0 million impairment reversal for our Peace River CGU. For our Legacy CGU, as a result of revisions to our decommissioning spending profile, the Company completed an impairment test and recorded a $21.8 million impairment. The Company plans to accelerate decommissioning spending in the area as we focus on reducing our inactive well liability, which led to the impairment.

During the first quarter of 2020, the Company completed impairment tests across all of our CGU’s as a result of the low commodity price environment, primarily due to the impact of the COVID-19 pandemic and concerns regarding potential supply and demand implications. This led to the Company recording $762.8 million of non-cash impairments, which included $701.8 million within our Cardium CGU, $58.1 million within our Peace River CGU and $18.7 million within our corporate assets. Additionally, a $15.8 million impairment recovery was recorded within our Legacy CGU as a result of the Company increasing our discount rate used in our decommissioning liability due to then current market conditions. Impairment losses related to PP&E may be reversed in future periods if commodity price forecasts materially improve.

At December 31, 2019, the Company completed an assessment to determine if indicators of impairment or an impairment reversal were present. As a result of the Company’s net asset value being higher than its market capitalization the Company concluded that an impairment indicator was present resulting in impairment tests being completed across all our CGUs (Cardium, Peace River, Viking and Legacy). As a result of completing the tests, the Company recorded a $450.0 million non-cash, PP&E impairment in our Cardium CGU mainly due to lower forecast commodity prices and continued volatility within the oil and gas industry which caused us to increase the discount rate we applied in the test. Additionally, a $77.8 million impairment was recorded within our non-Cardium CGU’s, primarily in the Legacy CGU, as the Company is directing no capital to this area.

In the second quarter of 2019, the Company classified our interest in our PROP asset as held for sale as we were working through a formal process to dispose of the asset. As the book value exceeded the estimated fair value to be received through a sales process, a non-cash impairment charge of $129.7 million was recorded.

Taxes

As at December 31, 2020, the Company was in a net unrecognized deferred tax asset position of approximately $448.6 million (2019—$270.5 million). Since the Company has not recognized the benefit of deductible timing differences in excess of taxable timing differences, deferred tax expense (recovery) for the quarter is nil.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 15

Tax Pools

	As at December 31
(millions)	2020		2019
Non-capital losses	$	2,194.9	$	2,150.8
Undepreciated capital cost (UCC)	****	226.6		282.9
Canadian development expense (CDE)	****	95.7		105.5
Canadian exploration expense (CEE)	****	2.2		2.3
Other	****	5.4		9.7
Total	$	2,524.8	$	2,551.2

The total tax pool balance decreased as capital expenditures in 2020 were lower in relation to taxable income.

Foreign Exchange

Obsidian Energy records unrealized foreign exchange gains or losses to translate U.S. denominated senior notes and the related accrued interest to Canadian dollars using the exchange rates in effect on the balance sheet date. Realized foreign exchange gains or losses are recorded upon repayment of the senior notes.

The split between realized and unrealized foreign exchange gains or losses is as follows:

	Year ended December 31
(millions)	2020		2019
Realized foreign exchange loss	$	—	$	(2.6	)
Unrealized foreign exchange gain	****	1.4		5.8
Foreign exchange gain	$	1.4	$	3.2

In the comparable period in 2019, the Company repaid senior notes in the amount of US$12.6 million and recorded a $2.6 million realized foreign exchange loss.

Net Loss

	Year ended December 31
(millions, except per share amounts)	2020			2019
Net loss	$	(771.7	)	$	(788.3	)
Basic and Diluted per share	$	(10.53	)	$	(10.82	)

In 2020, the net loss was mainly due to non-cash, PP&E impairment charges as a result of lower forecasted commodity prices due to the impact of the COVID-19 pandemic and potential supply and demand implications.

The net loss in 2019 was attributed to non-cash, PP&E impairment charges as a result of classifying the PROP asset as held for sale during the second quarter which resulted in an impairment charge. Additionally, impairment charges were recorded in the Cardium and Legacy CGUs as part of the impairment tests completed on December 31, 2019.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 16

Capital Expenditures

	Year ended December 31
(millions)	2020			2019
Drilling and completions	$	39.6	****	$	74.3
Well equipping and facilities	****	17.1	****		28.2
Land and geological/geophysical	****	0.3	****		0.2
Corporate	****	0.2	****		0.5
Capital expenditures	****	57.2	****		103.2
Property dispositions, net	****	(0.1	)		(10.7	)
Total capital expenditures	$	57.1	****	$	92.5

As a result of the low commodity price environment due to the COVID-19 pandemic, the Company had minimal capital spending beginning in March 2020 onwards.

In early 2020, the Company continued with our development focus in the Cardium, specifically in the Willesden Green area. All wells were drilled in the first quarter and were brought on production from March through May of 2020. Late in the fourth quarter of 2020, the Company re-started development activity within the Cardium and drilled and rig released one well in December 2020.

Drilling

	Year ended December 31
	2020					2019
(number of wells)	Gross		Net			Gross		Net
Oil	****	13	****	10.7	****		23		18.7
Injectors, stratigraphic and service	****	1	****	0.1	****		3		0.4
Total	****	14	****	10.8	****		26		19.1
Success rate ^(1)^			****	100	%				100	%
(1)	Success rate is calculated excluding stratigraphic and service wells.
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Environmental and Climate Change

The oil and gas industry has a number of environmental risks and hazards and is subject to regulation by all levels of government. Environmental legislation includes, but is not limited to, operational controls, site restoration requirements and restrictions on emissions of various substances produced in association with oil and natural gas operations. Compliance with such legislation could require additional expenditures and a failure to comply may result in fines and penalties which could, in the aggregate and under certain assumptions, become material.

Obsidian Energy is dedicated to managing the environmental impact from our operations through our environmental programs which include resource conservation, water management and site abandonment/reclamation/remediation. Obsidian Energy has voluntarily entered into the Government of Alberta’s ABC program which has allowed the Company to accelerate abandonment activities, specifically on inactive properties, in a more cost-effective manner. The Company is committed to remaining in the ABC program for at least 2021 and 2022. The Alberta Government announced the suspension of spending requirements for the ABC program for 2020 and the $9 million incurred by the Company in 2020 will be applied to our 2021 program target. Additionally, operations are continuously monitored to minimize both environmental and climate change impacts and allocate sufficient capital to reclamation and other activities to mitigate the impact on the areas in which the Company operates.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 17

The Company has received ASRP grants to date totaling $20 million on a gross basis and an additional $10 million in allocation eligibility as an ABC program participant. These awards will allow the Company to expand our abandonment activities for wells, pipelines, facilities, and related site reclamation which started in the fourth quarter of 2020 and thus reduce our decommissioning liability.

Liquidity and Capital Resources

Net Debt

Net debt is the total of long-term debt and working capital deficiency as follows:

	Year ended December 31
(millions)	2020			2019
Long-term debt
Syndicated credit facility	$	395.0	****	$	399.0
Senior secured notes	****	60.3	****		61.5
Deferred financing costs	****	(3.5	)		—
Total	****	451.8	****		460.5
Working capital deficiency^(1)^
Cash	****	(8.1	)		(3.0	)
Restricted cash	****	—	****		(2.4	)
Accounts receivable	****	(40.8	)		(65.6	)
Prepaid expenses and other	****	(9.2	)		(12.3	)
Accounts payable and accrued liabilities	****	74.1	****		117.0
Total	****	16.0	****		33.7
Net debt	$	467.8	****	$	494.2
(1)	Includes amounts classified as held for sale in 2019.
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Net debt decreased compared to December 31, 2019, as commodity price decreases due to the impact of COVID-19, which lowered revenues, were more than offset by realized hedging gains, the Company’s lower cost structure (specifically within operating costs and G&A expense) and lower capital expenditures.

At December 31, 2020, the term out period of the credit facility was November 30, 2021. As this was within one year of the balance sheet date, this resulted in the outstanding amount of the syndicated credit facility being presented as a current liability. This treatment was also consistent at December 31, 2019 as the term out period at that time was also within one year of the balance sheet date. Subsequent to December 31, 2020, the Company re-negotiated its syndicated credit facility which results in an extension of the term-out period to November 30, 2022.

Additionally, subsequent to December 31, 2020, the Company agreed with the holders of our senior notes to extend the maturity dates from November 30, 2021 to November 30, 2022.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 18

Liquidity

The Company has a reserve-based syndicated credit facility with a borrowing limit of $440.0 million. For further details on the Company’s debt instruments and our recent bank amendment, please refer to the “Financing” section of this MD&A.

The Company actively manages our debt portfolio and considers opportunities to reduce or diversify our debt capital structure. Management contemplates both operating and financial risks and takes action as appropriate to limit the Company’s exposure to certain risks. Management maintains close relationships with the Company’s lenders and agents to monitor credit market developments. These actions and plans aim to increase the likelihood of maintaining the Company’s financial flexibility and appropriate capital program, supporting the Company’s ongoing operations and ability to execute longer-term business strategies.

In the first quarter of 2020, the Company entered into amending agreements with holders of our senior notes and our bank syndicate to update our financial covenants as follows:

•	for the period from January 1, 2020 onward both the Senior Debt and Total Debt to Adjusted<br>EBITDA covenants have been eliminated; and
•	the maximum for both the Senior Debt and Total Debt to Capitalization ratios were permanently increased to<br>75 percent.
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On December 31, 2020, the Company was in compliance with all of our financial covenants which consisted of the following:

	Limit			December 31, 2020
Senior debt to capitalization		Less than 75	%		59	%
Total debt to capitalization		Less than 75	%		59	%

Financial Instruments

Obsidian Energy had the following financial instruments outstanding as at December 31, 2020. Fair values are determined using external counterparty information, which is compared to observable market data. The Company limits our credit risk by executing counterparty risk procedures which include transacting only with institutions within our syndicated credit facility or companies with high credit ratings and by obtaining financial security in certain circumstances.

	Notional<br>volume		Remaining<br>term		Pricing		Fair value(millions)
Oil
WTI Swaps		5,750 bbl/d		January 2021	$	59.62/bbl	$	(0.5	)
WTI Swaps		2,500 bbl/d		February 2021	$	60.34/bbl		(0.1	)
WTI Swaps		750 bbl/d		March 2021	$	61.58/bbl		—
AECO Swaps
AECO Swaps		23,700 mcf/d		Jan –Mar 2021	$	2.94/mcf		0.8
Total							$	0.2	****
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 19
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Refer to the Business Environment section above for a full list of hedges currently outstanding including trades that were entered into subsequent to December 31, 2020.

Based on commodity prices and contracts in place at December 31, 2020, a $1.00 change in the price per barrel of liquids of WTI would change pre-tax unrealized risk management by $0.4 million and a $0.50 change in the price per mcf of natural gas would change pre-tax unrealized risk management by $1.1 million.

The components of risk management on the Consolidated Statements of Income (Loss) are as follows:

	Year ended December 31
(millions)	2020		2019
Realized
Settlement of commodity contracts	$	20.9	$	(7.2	)
Total realized risk management gain (loss)	$	20.9	$	(7.2	)
Unrealized
Commodity contracts	$	0.8	$	(8.6	)
Total unrealized risk management gain (loss)	****	0.8		(8.6	)
Risk management gain (loss)	$	21.7	$	(15.8	)

Additionally, the Company had the following physical contracts outstanding at December 31, 2020:

	Notional<br>volume		Term		Pricing
Physical Oil Contracts^(1)^
WTI		542 bbl/d		Jan –<br>Mar 2021	$	55.54/bbl
WTI		571 bbl/d		Apr –<br>Jun 2021	$	59.04/bbl
(1)	WTI, differentials and foreign exchange hedged to lock-in positive<br>net operating income on certain heavy oil properties.
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Refer to the Business Environment section above for a full list of physical hedges currently outstanding including trades that were entered into subsequent to December 31, 2020.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 20

Outlook

The Company’s capital spending in 2021 will predominately focus on further development within the Willesden Green play of the Cardium. A 32 well program is planned and builds on the 2020 program where Obsidian Energy experienced strong production results. In the first half of 2021, the Company anticipates drilling nine wells assuming continued supportive ground conditions, five of which are expected to be on production by the end of the first quarter. With our syndicated credit facility and senior note extensions now in place and stronger financial position, the Company is replacing our first half 2021 guidance issued on January 5, 2021 with full year 2021 guidance. We will no longer be updating first half 2021 guidance. Key metrics are as follows:

Metric			H1 2021<br>Guidance Range		2021<br>Guidance Range
Average Production^(1)^		boe per day		23,000 – 23,400		23,300 – 23,800
Capital Expenditures	$	millions	$	35	$	125 – $130
Decommissioning Expenditures ^(2)^	$	millions	$	5	$	8
Net Operating expense	$	/boe	$	12.20 – $12.60	$	12.70 – $13.10
G&A	$	/boe	$	1.75 – $1.85	$	1.65 – $1.85
Funds flow from operations ^(3)^	$	millions		n/a	$	160 – $195
Funds flow from operations ^(3)^		Per share		n/a	$	2.18 – $2.65
Free cash flow ^(3)^	$	millions		n/a	$	25 – $60
(1)	Mid-point of guidance range:2021—10,600 bbl/d light oil, 2,800<br>bbl/d heavy oil, 1,950 bbl/d NGLs and 49.2 mmcf/d natural gas, H1/21—10,225 bbl/d light oil, 2,775 bbl/d heavy oil, 1,950 bbl/d NGLs and 49.5 mmcf/d natural gas
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(2)	Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the<br>Alberta Site Rehabilitation program.
---	---
(3)	Midpoint of guidance based on US$60 WTI/bbl, C$2.79/mcf AECO price deck and 1.27x CAD/USD foreign exchange.<br>Ranges for funds flow from operations and free cash flow calculated based on mid-point of guidance for production and costs using WTl prices between US$55/bbl – US$65/bbl.
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This outlook section is included to provide shareholders with information about Obsidian Energy’s expectations as at March 26, 2021 for average production, capital expenditures, decommissioning expenditures, net operating expense and G&A expenses for the first half and fiscal 2021 and funds flow from operations and free cash flow for 2021 and readers are cautioned that the information may not be appropriate for any other purpose. This information constitutes forward-looking information. Readers should note the assumptions, risks and discussion under “Forward-Looking Statements” and are cautioned that numerous factors could potentially impact the Company and our ability to meet our guidance, including fluctuations in commodity prices, any decision we make to shut-in additional production or resume production from shut-in properties, the impact of the COVID-19 pandemic on supply and demand for commodities, particularly oil, our ability to qualify for and receive payments under government assistance programs, and acquisition and disposition activity.

All press releases are available on Obsidian Energy’s website at www.obsidianenergy.com, on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.

Sensitivity Analysis

Estimated sensitivities to selected key assumptions on funds flow from operations for the 12 months subsequent to the date of this MD&A, including risk management contracts entered into to date, are based on forecasted results as discussed in the Outlook above.

Change of:	Change		/share
Price per barrel of liquids		WTI US1.00
Liquids production		1,000 bbls/day
Price per mcf of natural gas		AECO 0.10
Natural gas production		10 mmcf/day
Effective interest rate		1%
Exchange rate ($US per $CAD)	$	0.01

All values are in US Dollars.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 21

Contractual Obligations and Commitments

Obsidian Energy is committed to certain payments over the next five calendar years and thereafter as follows:

	2021		2022		2023		2024		2025		Thereafter		Total
Long-term debt ^(1)^	$	—	$	451.8	$	—	$	—	$	—	$	—	$	451.8
Transportation	****	7.1		5.4		2.9		2.5		2.1		5.6		25.6
Power infrastructure	****	6.7		3.2		—		—		—		—		9.9
Interest obligations	****	30.0		28.1		—		—		—		—		58.1
Office lease	****	10.0		10.0		10.0		10.0		0.8		—		40.8
Lease liability	****	4.9		3.5		0.8		0.2		0.1		5.0		14.5
Decommissioning liability ^(2)^	****	7.3		12.4		3.5		3.3		3.1		40.9		70.5
Total	$	66.0	$	514.4	$	17.2	$	16.0	$	6.1	$	51.5	$	671.2
(1)	Based on agreements signed subsequent to December 31, 2020, the 2022 figure includes<br>$395.0 million related to the syndicated credit facility and non-revolving term loan that is due for renewal in 2022 and $60.3 million of senior notes set to mature in 2022; refer to the Financing<br>section above for further details. Historically, the Company has successfully renewed its syndicated credit facility.
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(2)	These amounts represent the inflated, discounted future reclamation and abandonment costs that are expected<br>to be incurred over the life of the Company’s properties.
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Subsequent to December 31, 2020, the Company entered into agreements extending the revolving period of our syndicated credit facility to May 31, 2022, with an additional term out period to November 30, 2022, provided that if the lenders do not reconfirm the revolving period on January 17, 2022 the revolving period will accelerate to February 1, 2022 and the end date of the term period will continue to be November 30, 2022. In addition, the Company has an aggregate of US$47 million in senior notes maturing in 2022. If the Company is unsuccessful in renewing or replacing the syndicated credit facility or obtaining alternate funding for some or all of the maturing amounts of the senior notes, it is possible that we could be required to seek to obtain other sources of financing, including other forms of debt or equity arrangements if available.

The Company is involved in various litigation and claims in the normal course of business and records provisions for claims as required.

Equity Instruments

Common shares issued:
As at December 31, 2020	73,516,225
Issuances under RPSU plan	6,897
As at March 26, 2021	73,523,122
Options outstanding:
As at December 31, 2020 and March 26, 2021	961,954
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 22
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Fourth Quarter Highlights

Key financial and operational results for the fourth quarter were as follows:

	Three months ended December 31
	2020			2019			% change
Financial (millions, except per share or per boe amounts)
Production revenues	$	72.8	****	$	111.6			(35	)
Cash flow from operations	****	11.1	****		49.5			(78	)
Basic and Diluted per share	****	0.15	****		0.68			(78	)
Funds flow from operations	****	26.4	****		54.2			(51	)
Basic and Diluted per share	****	0.36	****		0.74			(51	)
Net income (loss)	****	0.2	****		(543.2	)		n/a
Basic and Diluted per share	****	0.01	****		(7.44	)		n/a
Capital expenditures	****	11.6	****		34.6			(66	)
Decommissioning expenditures	****	2.3	****		6.4			(64	)
G&A per boe	$	1.63	****	$	1.68			(3	)
Operations
Daily production
Light oil (bbls/d)	****	10,055	****		12,246			(18	)
Heavy oil (bbls/d)	****	2,895	****		3,718			(22	)
NGLs (bbls/d)	****	2,087	****		2,095			—
Natural gas (mmcf/d)	****	52	****		52			—
Total production (boe/d)	****	23,644	****		26,639			(11	)
Corporate netback per boe
Sales price	$	33.57	****	$	45.67			(26	)
Risk management gain (loss)	****	(0.14	)		0.66			n/a
Net sales price	****	33.43	****		46.33			(28	)
Royalties	****	(1.42	)		(3.79	)		(63	)
Net operating expenses	****	(12.77	)		(12.75	)		—
Transportation	****	(1.60	)		(2.56	)		(38	)
Netback	$	17.64	****	$	27.23			(35	)
Liquids netback per bbl
Sales price	$	43.14	****	$	60.10			(28	)
Risk management gain (loss)	****	(0.16	)		0.97			n/a
Net sales price	****	42.98	****		61.07			(30	)
Royalties	****	(2.08	)		(4.97	)		(58	)
Net operating expenses	****	(16.42	)		(16.83	)		(2	)
Transportation	****	(1.90	)		(3.06	)		(38	)
Netback	$	22.58	****	$	36.21			(38	)
Natural gas netback per mcf
Sales price	$	2.81	****	$	2.55			10
Risk management gain (loss)	****	(0.02	)		—			n/a
Net sales price	****	2.79	****		2.55			9
Royalties	****	(0.04	)		(0.22	)		(82	)
Net operating expenses	****	(1.06	)		(0.69	)		54
Transportation	****	(0.18	)		(0.25	)		(28	)
Netback	$	1.51	****	$	1.39			9
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 23
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Financial

Production revenues, cash flow from operations and funds flow from operations decreased in the fourth quarter of 2020 compared to 2019 mainly due to decreased production and lower realized commodity prices.

Net income in the fourth quarter of 2020 was impacted by a non-cash, PP&E impairment charge within our Legacy CGU as a result of the Company accelerating decommissioning spending in the area. This was largely offset by a non-cash, PP&E impairment recovery in our Peace River CGU.

In 2019, the net loss is mainly due to depletion costs and non-cash PP&E impairment charges within our Cardium and Legacy CGU’s.

Operations

Capital activities during the fourth quarter of 2020 were focused on the Company’s optimization program as well as the restart of our development activity in December as we began work on our first half 2021 drilling program.

Production in the fourth quarter of 2020 declined from the comparable period due to restricted development activity as a result of commodity price volatility due to the impact of the COVID-19 pandemic. During the fourth quarter of 2020, average production within the Company’s key development areas was as follows:

	Three months ended December 31
Daily production (boe/d)<br>^(1)^	2020		2019		% change
Cardium	****	19,180		20,950		(8	)
Peace River	****	3,175		4,230		(25	)
Viking	****	906		849		7
Legacy	****	383		610		(37	)
Total	****	23,644		26,639		(11	)
(1)	Refer to “Supplemental Production Disclosure” for details by product type.
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Netbacks

Corporate and liquids netbacks decreased from the comparative quarter mainly due to lower realized prices and realized risk management losses related to hedging activities, which were partially offset by lower royalty and transportation costs.

In the fourth quarter of 2020, WTI prices averaged US$42.66 per barrel compared to US$56.96 per barrel for the same period in 2019. WTI prices increased significantly throughout the fourth quarter of 2020 settling at US$47.07 per barrel in December. The increase in pricing was mainly due to the anticipated positive impact on demand from the approvals of COVID-19 vaccines and OPEC extending their production cuts into 2021. Oil differentials widened slightly in the fourth quarter of 2020 with MSW averaging US$4.07 per barrel (2019—US$5.37 per barrel) and WCS averaged US$9.07 per barrel (2019—US$15.83 per barrel). Although these differentials remain relatively narrow, the widening was related to production being restored in Western Canada after extended downtime and the Alberta Government ceasing to impose monthly oil production limits under its curtailment rules.

NYMEX Henry Hub gas prices started the fourth quarter of 2020 at US$1.60 per Mmbtu and then increased to a high of US$3.14 per Mmbtu in late October due to cold weather and temporarily shut in production related to Hurricane Zeta. Throughout the balance of the fourth quarter, warmer temperatures led to price declines and resulted in an average of US$2.53 per Mmbtu. In Alberta, AECO 5A prices followed a similar pattern resulting in an average price of $2.77 per mcf.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 24

Supplemental Production Disclosure

Outlined below is production by product type for each area for the three and twelve months ended December 31, 2020 and December 31, 2019.

	Three months ended December 31
Daily production (boe/d)	2020		2019
Cardium
Light oil (bbls/d)	****	9,788		11,782
Heavy oil (bbls/d)	****	45		28
NGLs (bbls/d)	****	2,011		2,041
Natural gas (mmcf/d)	****	44		43
Total production (boe/d)	****	19,180		20,950
Peace River
Light oil (bbls/d)	****	—		70
Heavy oil (bbls/d)	****	2,702		3,487
NGLs (bbls/d)	****	4		4
Natural gas (mmcf/d)	****	3		4
Total production (boe/d)	****	3,175		4,230
Viking
Light oil (bbls/d)	****	196		205
Heavy oil (bbls/d)	****	106		45
NGLs (bbls/d)	****	42		27
Natural gas (mmcf/d)	****	4		3
Total production (boe/d)	****	906		849
Legacy
Light oil (bbls/d)	****	71		189
Heavy oil (bbls/d)	****	42		158
NGLs (bbls/d)	****	30		24
Natural gas (mmcf/d)	****	1		1
Total production (boe/d)	****	383		610
Total
Light oil (bbls/d)	****	10,055		12,246
Heavy oil (bbls/d)	****	2,895		3,718
NGLs (bbls/d)	****	2,087		2,095
Natural gas (mmcf/d)	****	52		52
Total production (boe/d)	****	23,644		26,639
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 25
---	---
	Year ended December 31
---	---	---	---	---
Daily production (boe/d)	2020		2019
Cardium
Light oil (bbls/d)	****	11,290		11,452
Heavy oil (bbls/d)	****	40		38
NGLs (bbls/d)	****	2,140		2,055
Natural gas (mmcf/d)	****	45		43
Total production (boe/d)	****	21,003		20,706
Peace River
Light oil (bbls/d)	****	—		87
Heavy oil (bbls/d)	****	2,660		3,699
NGLs (bbls/d)	****	3		5
Natural gas (mmcf/d)	****	3		4
Total production (boe/d)	****	3,136		4,452
Viking
Light oil (bbls/d)	****	210		292
Heavy oil (bbls/d)	****	62		49
NGLs (bbls/d)	****	39		38
Natural gas (mmcf/d)	****	4		4
Total production (boe/d)	****	860		987
Legacy
Light oil (bbls/d)	****	75		134
Heavy oil (bbls/d)	****	70		179
NGLs (bbls/d)	****	30		55
Natural gas (mmcf/d)	****	1		2
Total production (boe/d)	****	405		756
Total
Light oil (bbls/d)	****	11,574		11,966
Heavy oil (bbls/d)	****	2,832		3,965
NGLs (bbls/d)	****	2,212		2,153
Natural gas (mmcf/d)	****	53		53
Total production (boe/d)	****	25,404		26,901
OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 26
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Evaluation of Disclosure Controls and Procedures

The Company’s disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company in our annual filings, interim filings or other reports filed or submitted by us under securities legislation is recorded, processed, summarized and reported within the time periods specified in such securities legislation. They include controls and procedures designed to ensure that information required to be disclosed by the Company in our annual filings, interim filings or other reports that we file or submit under applicable securities legislation is accumulated and communicated to the Company’s management, including our Interim Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

An internal evaluation was carried out by management under the supervision and with the participation of the Company’s Interim Chief Executive Officer and Chief Financial Officer of the effectiveness of Obsidian Energy’s disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 (the “Exchange Act”) and as defined in Canada by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”) as at December 31, 2020. Based on that evaluation, the Interim Chief Executive Officer and the Chief Financial Officer concluded that as at December 31, 2020 the disclosure controls and procedures were effective.

Management’s Report on Internal Control over Financial Reporting

Internal control over financial reporting (“ICFR”) is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. Obsidian Energy’s management, including our Interim Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate ICFR, as such term is defined in Rule 13a-15 under the Exchange Act and as defined in Canada by NI 52-109. A material weakness in the Company’s ICFR exists if a deficiency, or a combination of deficiencies, in our ICFR is such that there is a reasonable possibility that a material misstatement of our annual financial statements or interim financial reports will not be prevented or detected on a timely basis.

An internal evaluation was carried out by management under the supervision and with the participation of the Company’s Interim Chief Executive Officer and Chief Financial Officer of the effectiveness of the Company’s ICFR as at December 31, 2020. The assessment was based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, the Interim Chief Executive Officer and the Chief Financial Officer concluded that as at December 31, 2020 the Company’s ICFR was effective.

Changes in Internal Control Over Financial Reporting

Obsidian Energy’s senior management has evaluated whether there were any changes in the Company’s ICFR that occurred during the period beginning on October 1, 2020 and ending on December 31, 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR. No changes to the Company’s ICFR were made during the quarter.

Off-Balance-Sheet Financing

Obsidian Energy has off-balance-sheet financing arrangements consisting of operating leases. The operating lease payments are summarized in the Contractual Obligations and Commitments section.

Critical Accounting Estimates

Obsidian Energy’s significant accounting policies are detailed in Note 3 to our audited consolidated Financial Statements. In the determination of financial results, Obsidian Energy must make certain critical accounting estimates as follows:

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 27

COVID-19 pandemic

In March 2020, the World Health Organization declared COVID-19 a global pandemic. Since that time, the impact of the COVID-19 pandemic and resultant supply and demand implications for oil has resulted in significant commodity price volatility. This market volatility has increased the complexity of certain judgements and estimates when preparing our year-end 2020 financial information, particularly within the measurement uncertainty of the inputs used in the Company’s assessment of the recoverability of asset carrying values, assessing counterparty credit risk as well as the credit risk-adjusted discount rate used within our decommissioning liability and office lease provision.

Decommissioning Liability

The decommissioning liability is the present value of the Company’s future statutory, contractual, legal or constructive obligations to retire long-lived assets including wells, facilities and pipelines. The liability is recorded on the balance sheet with a corresponding increase to the carrying amount of the related asset. The recorded liability increases over time to its future liability amount through accretion charges to income. Revisions to the estimated amount or timing of the obligations are reflected as increases or decreases to the recorded decommissioning liability. Actual decommissioning expenditures are charged to the liability to the extent of the then-recorded liability. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset. Note 9 to Obsidian Energy’s audited consolidated Financial Statements details the impact of these accounting standards.

Deferred Tax

Deferred taxes are recorded based on the liability method of accounting whereby temporary differences are calculated assuming financial assets and liabilities will be settled at their carrying amount. Deferred taxes are computed on temporary differences using substantively enacted income tax rates expected to apply when future income tax assets and liabilities are realized or settled.

Depletion and Impairments

Costs of developing oil and natural gas reserves are capitalized and depleted against associated oil and natural gas production using the unit-of-production method based on the estimated proved plus probable reserves with forecast commodity pricing.

All the Company’s reserves were evaluated by Sproule Associates Limited (“SAL”), an independent, qualified reserve evaluation engineering firm. Obsidian Energy’s reserves are determined in compliance with National Instrument 51-101. The evaluation of oil and natural gas reserves is, by its nature, based on complex extrapolations and models as well as other significant engineering, reservoir, capital, pricing and cost assumptions. Reserve estimates are a key component in the calculation of depletion and are an important component in determining the recoverable amount in impairment tests. The determination of the recoverable amount involves estimating the higher of an asset’s fair value less costs to sell or its value-in-use, the latter of which is based on its discounted future cash flows using an applicable discount rate. To the extent that the recoverable amount, which could be based in part on its reserves, is less than the carrying amount of property, plant and equipment, a write-down against income is recorded.

Financial Instruments

Financial instruments included in the balance sheets consist of accounts receivable, fair values of derivative financial instruments, current liabilities and long-term debt. Except for the senior notes, the fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments, the mark-to-market values recorded for the financial instruments and the market rate of interest applicable to the bank debt. The estimated fair value of the senior notes is disclosed in Note 7 to the Company’s audited consolidated Financial Statements.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 28

Obsidian Energy’s revenues from the sale of oil, natural gas liquids and natural gas are directly impacted by changes to the underlying commodity prices. To manage our planned capital program to within funds flows from operations, financial instruments including swaps and collars may be utilized from time to time.

Substantially all the Company’s accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. Obsidian Energy may, from time to time, use various types of financial instruments to reduce its exposure to fluctuating oil and natural gas prices, electricity costs, exchange rates and interest rates. The use of these financial instruments exposes us to credit risks associated with the possible non-performance of counterparties to the derivative contracts. The Company limits this risk by executing counterparty risk procedures which include transacting only with financial institutions who are members of its credit facility or those with high credit ratings as well as obtaining security in certain circumstances.

Office Lease Provision

The office lease liability is the net present value of future lease payments Obsidian Energy is obligated to make under non-cancellable lease contracts. The liability is recognized on the balance sheet with the corresponding change charged to income. The recorded liability increases over time to its future amount through accretion charges to income. Revisions to the estimated amount or timing of the obligations are reflected prospectively as increases or decreases to the recorded liability. Actual lease payments are charged to the liability as the costs are incurred. Note 9 to Obsidian Energy’s audited consolidated Financial Statements details the impact of these accounting standards.

Non-GAAP Measures

Certain financial measures including funds flow from operations, funds flow from operations per share-basic, funds flow from operations per share-diluted, free cash flow, netback, net operating costs, gross revenues and net debt, included in this MD&A do not have a standardized meaning prescribed by IFRS and therefore are considered non-GAAP measures; accordingly, they may not be comparable to similar measures provided by other issuers. Funds flow from operations is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, onerous office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments, restructuring charges, transaction costs and certain other expenses and is representative of cash related to continuing operations. Funds flow from operations is used to assess the Company’s ability to fund our planned capital programs. See “Cash flow from Operations and Funds Flow from Operations” above for a reconciliation of funds flow from operations to cash flow from operating activities, being our nearest measure prescribed by IFRS. Free cash flow is funds flow from operations less both capital and decommissioning expenditures. Netback is the per unit of production amount of revenue less royalties, operating expenses, transportation expenses and realized risk management gains and losses, and is used in capital allocation decisions and to economically rank projects. See “Results of Operations – Netbacks” and “Fourth Quarter Highlights—Operations” above for a calculation of the Company’s 2020 annual and 2020 fourth quarter netbacks. Net operating costs are calculated by deducting processing income and road use recoveries from operating costs and is used to assess the Company’s cost position. Processing fees are primarily generated by processing third party volumes at the Company’s facilities. In situations where the Company has excess capacity at a facility, it may agree with third parties to process their volumes as a means to reduce the cost of operating/owning the facility. Road use recoveries are a cost recovery for the Company as we operate and maintain roads that are also used by third parties. See “Expenses – Operating” above for a reconciliation of operating costs to net operating costs. Gross revenues are production revenues including realized risk management gains and losses on commodity contracts and adjusted for commodities purchased and sales of commodities purchased and is used to assess the cash realizations on commodity sales. See “Production Revenues” above for a reconciliation of gross revenues to production revenues, being our nearest measure prescribed by IFRS. Net debt is the total of long-term debt and working capital deficiency and is used by the Company to assess our liquidity. See “Liquidity and Capital Resources – Net Debt” above for a calculation of the Company’s net debt.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 29

Oil and Gas Information

Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of 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.

Forward-Looking Statements

Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our belief that our plan to focus on our industry leading Cardium position in addition to our goal of becoming a consolidating entity within the Cardium, offers a predictable, liquids weighted, production profile that is capable of generating sustainable value for all stakeholders; the benefits and synergies attributable to the offer to purchase all the Bonterra Shares; the terms and conditions of the Bonterra Offer; our expected 2021 development program and capital expenditure; that the Company will continue to economically evaluate and, if required, adjust our production base as appropriate based on the expected realized commodity prices; that the Company continues to monitor all applicable government relief programs to determine if we qualify to participate in them and will continue to evaluate our eligibility to participate in the amended CEWS program as further details become available; how the ASRP will allow the Company to expand the abandonment activities, the timing thereof and staying actively engage in these types of programs; our hedging program; that the compliance with certain environmental legislation could require additional expenditures and a failure to comply may result in fines and penalties which could, in the aggregate and under certain assumptions, become material; that we are dedicated to managing the environmental impact from our operations through the environmental programs which include resource conservation, water management and site abandonment / reclamation / remediation; that the Company will continue to target capital expenditures within funds flow from operations in 2021; the expected re-confirmation and term out dates, as applicable, in connection with our reserve-based syndicated credit facility, the lender option date to complete a borrowing base redetermination on the credit facility, the available revolving capacity at the end of year depending on the amount drawn under the credit facility, and the maturity dates and interest rates on the senior notes; amounts and timing of payments in connection with settlement of former officer defense costs and the resulting recovery of costs on the income statement; our decommissioning spending plans on certain inactive wells; the financial covenant amendments and time frames that are applicable in connection with the amending agreements; that the impairment losses related to PP&E can be reversed in future periods if commodity price forecasts materially improve; that we will remain in the ABC program for 2020 and 2021; that the ABC program remains suspended in 2020 and amounts spent in 2020 under the program can be applied to our 2021 target; that the Company continuously monitors operations to minimize environmental impact and allocate sufficient capital to reclamation and other activities to mitigate the impact on the areas in which the Company operates; that management contemplates both operating and financial risks and takes action as appropriate to limit the Company’s exposure to certain risks and that management maintains close relationships with the Company’s lenders and agents to monitor credit market developments, and these actions and plans aim to increase the likelihood of maintaining the Company’s financial flexibility and capital program, supporting the Company’s ongoing operations and ability to execute longer-term business strategies; our financial outlook including our first half and full year 2021 guidance including average production range, capital expenditures and decommissioning expenditures, net operating and G&A expense ranges, FFO and FFO per share, and free cash flow; and the sensitivity analysis and contractual obligations and commitments moving forward.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 30

With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: the benefits to be derived by the Company and its stakeholders from the proposed acquisition of Bonterra; that the publicly available Bonterra information is correct; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than as stated herein (provided that, except where otherwise stated, the forward-looking statements contained herein (including our guidance set out under “Outlook”) do not assume the completion of the proposed acquisition of Bonterra); 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; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the CEWS and ASRP) or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to execute our plans as described herein and in our other disclosure documents and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future operating costs and G&A costs; future oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in additional production due to a deterioration of commodity prices and our expectations regarding when commodity prices will improve such that any remaining shut-in properties can be returned to production; future exchange rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, wild fires, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability to renew or replace our syndicated bank facility and our ability to finance the repayment of our senior notes on maturity; and our ability to add production and reserves through our development and exploitation activities.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 31

Although the Company believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued pursuant to our ongoing effort to consolidate the Cardium play, including the proposed acquisition of Bonterra, on favorable terms or at all, or that the Company and its stakeholders do not realize the anticipated benefits of any such transaction that is completed (including the benefits of the proposed acquisition of Bonterra described herein); the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that the significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally that has been caused by, 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 notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew our credit facilities on acceptable terms or at all and/or finance the repayment of our senior notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or both of our credit facilities and senior notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior notes; the possibility that we are forced to shut-in additional production or continue existing production shut-ins longer than anticipated, whether due to commodity prices decreasing or the Alberta government reactivating its curtailment program; the risk that OPEC, Russia and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of oil, natural gas liquids and natural gas, price differentials for oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company’s ability to obtain financing and/or insurance on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments, financial institutions and consumers to the ongoing COVID-19 pandemic; and the other factors described under “Risk Factors” in our Annual Information Form and described in our public filings, available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, the Company does not undertake any obligation to publicly update any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement

Additional Information

Additional information relating to Obsidian Energy, including Obsidian Energy’s Annual Information Form, is available on the Company’s website at www.obsidianenergy.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

OBSIDIAN ENERGY 2020	MANAGEMENT’S DISCUSSION AND ANALYSIS 32

EX-99.3

Exhibit 99.3

Report of Independent Registered Public Accounting Firm

To the shareholders and the board of directors of Obsidian Energy Ltd.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Obsidian Energy Ltd. (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income (loss), changes in shareholders’ equity and cash flows, for each of the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years then ended, in conformity with International Financial Reporting Standards (IFRSs) as issued by the International Accounting Standards Board.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

OBSIDIAN ENERGY 2020	ANNUAL CONSOLIDATED FINANCIAL STATEMENTS  1
Critical Audit Matter	Valuation of Property, Plant & Equipment (“PP&E”) in the Cardium and Peace River Cash Generating Units (“CGU”)
---	---
Description of the Matter	As at December 31, 2020, the carrying value of PP&E was $905.2 million. For the year ended December 31, 2020, a net<br>impairment expense of $766.2 million was recorded with respect to PP&E. Refer to Note 3 Significant accounting policies of the consolidated financial statements for a description of the Company’s impairment of non-financial assets accounting policy. Refer to Note 6 Property, plant and equipment of the consolidated financial statements for the Company’s PP&E impairment disclosures. PP&E is tested for<br>impairment only when circumstances indicate that the carrying value of a CGU to which the PP&E relates, may exceed the recoverable amount. Impairment is determined by estimating a CGU’s respective recoverable amount. The recoverable amount<br>of the Peace River CGU was determined by using the fair value less costs to dispose method, whereby the net cash flows are estimated using the external reserve report, a discount rate applied and the resulting fair value is cross checked to market<br>metrics. The recoverable amount of the Cardium CGU was determined by using the value-in-use method, whereby the net cash flows are estimated using budgets approved by<br>management and a discount rate applied.<br> <br><br> <br>Auditing the Company’s estimated<br>recoverable amount for the Peace River and Cardium CGUs was complex due to the subjective nature of the various management inputs and assumptions and for the Peace River CGU, the continued volatility in commodity prices, transaction markets and the<br>equity markets which impact the fair value less costs to dispose. In both cases, the recoverable amounts were determined using the proven plus probable reserves from the Company’s external reserves evaluator. The estimation of future cash flows<br>from proven plus probable oil and gas reserves are sensitive to assumptions in future oil and gas prices, production volumes, royalties, operating expenditures, and planned capital expenditures. The estimation of the discount rates used also<br>required management estimation and are sensitive to changes in cash-flow specific risk premiums. For the Cardium CGU, the Company’s ability to fund the capital expenditures is subject to judgment regarding liquidity and future debt levels.<br>
How We Addressed the Matter in Our Audit	To test the Company’s estimated recoverable amounts for the Peace River and Cardium CGUs, our procedures included, among others<br>involving our internal valuation specialists to assess the methodology applied, and the various inputs utilized in determining the discount rates by referencing current industry, economic, and comparable company information, as well as company and<br>cash-flow specific risk premiums. We compared commodity price forecasts to third party published commodity forecasts. We compared forecasted production against historically realized production. We compared forecasted price differentials against<br>historically realized differentials and third-party reserve engineer data. We assessed forecasted royalty, operating cost, general and administrative expenses and capital expenditures estimates by comparing it to historical performance.<br><br><br><br> <br>To test the Company’s reserves inputs, we assessed the competence and objectivity<br>of the Company’s external reserves evaluator. We also tested the completeness and accuracy of the external reserve report by agreeing current year production, revenue, royalty, operating cost, and capital cost data to the Company’s<br>accounting records.
OBSIDIAN ENERGY 2020	ANNUAL CONSOLIDATED FINANCIAL STATEMENTS  2
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For the Cardium CGU, we reviewed and evaluated management’s assessment of the Company’s ability to fund the development of its PP&E as a whole by assessing the assumptions used in the cash flow forecasts and the debt<br>capacity compared to the capital expenditures required to develop the assets. As part of our procedures, we also evaluated the adequacy of the disclosures included in Note 6 of the accompanying financial statements in relation to this<br>matter.
---

“signed” Ernst & Young LLP

Chartered Professional Accountants

We have served as the Company’s auditor since 2015.

Calgary, Canada

March 26, 2021

OBSIDIAN ENERGY 2020	ANNUAL CONSOLIDATED FINANCIAL STATEMENTS  3

Obsidian Energy Ltd.

Consolidated Balance Sheets

			As at December 31
(CAD millions)	Note		2020			2019
Assets
Current
Cash			$	8.1	****	$	1.0
Restricted cash			****	0	****		2.4
Accounts receivable		10	****	40.8	****		61.7
Risk management		10	****	0.8	****		0.4
Prepaid expenses and other			****	9.2	****		12.3
Lease receivable		4	****	0	****		8.8
Assets held for sale		5	****	0	****		82.9
			****	58.9	****		169.5
Non-current
Lease receivable		4		0			30.7
Property, plant and equipment		6		905.2			1,704.6
			****	905.2	****		1,735.3
Total assets			$	964.1	****	$	1,904.8
Liabilities and Shareholders’ Equity
Current
Accounts payable and accrued liabilities			$	74.1	****	$	111.0
Current portion of long-term debt		7	****	451.8	****		434.2
Current portion of lease liabilities		8	****	4.8	****		28.8
Current portion of provisions		9	****	16.3	****		16.2
Risk management		10	****	0.6	****		1.0
Liabilities related to assets held for sale		5	****	0	****		13.0
			****	547.6	****		604.2
Non-current
Long-term debt		7	****	0	****		26.3
Lease liabilities		8	****	5.6	****		85.0
Provisions		9	****	87.7	****		96.6
Other non-current liabilities		14	****	0.1	****		—
			****	641.0	****		812.1
Shareholders’ equity
Shareholders’ capital		13	****	2,187.0	****		2,186.7
Other reserves		13	****	103.6	****		101.8
Deficit			****	(1,967.5	)		(1,195.8	)
			****	323.1	****		1,092.7
Total liabilities and shareholders’ equity			$	964.1	****	$	1,904.8

Subsequent events (Notes 7, 10 and 18)

Commitments and contingencies (Note 18)

See accompanying notes to the consolidated financial statements.

Approved on behalf of the Board of Directors of Obsidian Energy Ltd.:

“signed”	“signed”
Gordon M. Ritchie<br> <br>Chairman	Raymond D. Crossley<br> <br>Director
OBSIDIAN ENERGY 2020	ANNUAL CONSOLIDATED FINANCIAL STATEMENTS  4
---	---

Obsidian Energy Ltd.

Consolidated Statements of Income (Loss)

	Year ended December 31
(CAD millions, except per share amounts)	Note		2020			2019
Production revenues		11	$	275.4	****	$	409.3
Processing fees		11	****	6.3	****		7.7
Royalties			****	(13.7	)		(30.6	)
Sales of commodities purchased from third parties			****	4.8	****		2.9
			****	272.8	****		389.3
Other income		11	****	13.0	****		8.5
Government decommissioning assistance		21	****	2.2	****		—
Risk management gain (loss)		10	****	21.7	****		(15.8	)
			****	309.7	****		382.0
Expenses
Operating		20	****	115.4	****		145.4
Transportation			****	17.7	****		27.1
Commodities purchased from third parties			****	4.6	****		3.3
General and administrative		20	****	13.9	****		20.0
Restructuring			****	0.6	****		3.6
Share-based compensation		14	****	3.4	****		4.6
Depletion, depreciation, impairment and accretion		6,9	****	902.9	****		913.0
Loss on dispositions		6	****	0	****		1.2
Provisions		9	****	(22.6	)		(8.8	)
Foreign exchange gain		7	****	(1.4	)		(3.2	)
Financing		7	****	37.2	****		40.6
Transaction costs		22	****	3.5	****		—
Other		18	****	6.2	****		23.5
			****	1,081.4	****		1,170.3
Loss before taxes			****	(771.7	)		(788.3	)
Deferred tax recovery		12	****	0	****		—
Net and comprehensive loss			$	(771.7	)	$	(788.3	)
Net loss per share
Basic		15	$	(10.53	)	$	(10.82	)
Diluted		15	$	(10.53	)	$	(10.82	)
Weighted average shares outstanding (millions)
Basic		15	****	73.3	****		72.9
Diluted		15	****	73.3	****		72.9

See accompanying notes to the consolidated financial statements.

OBSIDIAN ENERGY 2020	ANNUAL CONSOLIDATED FINANCIAL STATEMENTS  5

Obsidian Energy Ltd.

Consolidated Statements of Cash Flows

	Year ended December 31
(CAD millions)	Note		2020			2019
Operating activities
Net income (loss)			$	(771.7	)	$	(788.3	)
Government decommissioning assistance			****	(2.2	)		—
Other income		4	****	(0.3	)		(2.5	)
Depletion, depreciation, impairment and accretion		6,9	****	902.9	****		913.0
Loss on dispositions		6	****	0	****		1.2
Provisions		9	****	(22.6	)		(8.8	)
Financing		7,9	****	1.5	****		7.5
Share-based compensation		14	****	2.1	****		4.5
Unrealized risk management loss (gain)		10	****	(0.8	)		8.6
Unrealized foreign exchange gain		7	****	(1.4	)		(5.8	)
Other			****	2.1	****		3.6
Decommissioning expenditures		9	****	(11.1	)		(14.4	)
Onerous office lease settlements		9	****	(9.7	)		(2.2	)
Deferred financing costs		7	****	2.8	****		—
Financing fees paid		7	****	(5.6	)		—
Change in non-cash working capital		16	****	(6.6	)		(39.6	)
			****	79.4	****	****	76.8	****
Investing activities
Capital expenditures			****	(57.2	)		(103.2	)
Property dispositions, net		6	****	0.1	****		10.7
Change in non-cash working capital		16	****	(9.1	)		(8.6	)
			****	(66.2	)		(101.1	)
Financing activities
Lease receivable receipts		4	****	2.2	****		9.1
Lease liabilities settlements		8	****	(6.3	)		(29.9	)
Increase (decrease) in long-term debt		7	****	(4.0	)		62.0
Repayments of senior notes		7	****	0	****		(16.9	)
Realized foreign exchange loss on repayments		7	****	0	****		2.6
			****	(8.1	)		26.9
Change in cash and cash equivalents			****	5.1	****		2.6
Cash and cash equivalents, beginning of year			****	3.0	****		0.4
Cash and cash equivalents, end of year			$	8.1	****	$	3.0

See accompanying notes to the consolidated financial statements.

OBSIDIAN ENERGY 2020	ANNUAL CONSOLIDATED FINANCIAL STATEMENTS  6

Obsidian Energy Ltd.

Statements of Changes in Shareholders’ Equity

(CAD millions)	Note		Shareholders’<br>Capital		Other<br>Reserves			Deficit			Total
Balance at January 1, 2020			$	2,186.7	$	101.8		$	(1,195.8	)	$	1,092.7
Net and comprehensive loss				0		0			(771.7	)		(771.7	)
Share-based compensation		14		0		2.1			0			2.1
Issued on exercise of equity compensation plans		13		0.3		(0.3	)		0			0
Balance at December 31, 2020			$	2,187.0	$	103.6	****	$	(1,967.5	)	$	323.1	****
(CAD millions)	Note		Shareholders’<br>Capital		Other<br>Reserves			Deficit			Total
---	---	---	---	---	---	---	---	---	---	---	---	---	---
Balance at January 1, 2019			$	2,184.9	$	99.1		$	(407.5	)	$	1,876.5
Net and comprehensive loss				—		—			(788.3	)		(788.3	)
Share-based compensation		14		—		4.5			—			4.5
Issued on exercise of equity compensation plans		13		1.8		(1.8	)		—			—
Balance at December 31, 2019			$	2,186.7	$	101.8	****	$	(1,195.8	)	$	1,092.7	****

See accompanying notes to the consolidated financial statements.

OBSIDIAN ENERGY 2020	ANNUAL CONSOLIDATED FINANCIAL STATEMENTS  7

Notes to the Consolidated Financial Statements

(All tabular amounts are in CAD millions except numbers of common shares, per share amounts,

percentages and various figures in Note 10)

1. Structure of Obsidian Energy

Obsidian Energy Ltd. (“Obsidian Energy”, the “Company”, “we”, “us” or “our”) is an exploration and production company and is governed by the laws of the Province of Alberta, Canada. The Company operates in one segment, to explore for, develop and hold interests in oil and natural gas properties and related production infrastructure in the Western Canada Sedimentary Basin directly and through investments in securities of subsidiaries holding such interests. Obsidian Energy’s portfolio of assets is managed at an enterprise level, rather than by separate operating segments or business units. The Company assesses our financial performance at the enterprise level and resource allocation decisions are made on a project basis across our portfolio of assets, without regard to the geographic location of projects*.* Obsidian Energy owns the petroleum and natural gas assets or 100 percent of the equity, directly or indirectly, of the entities that carry on the remainder of the oil and natural gas business of Obsidian Energy, except for an unincorporated joint arrangement (the “Peace River Oil Partnership”) in which Obsidian Energy’s wholly owned subsidiaries hold a 55 percent interest.

2. Basis of presentation and statement of compliance

a) Basis of Presentation

The annual consolidated financial statements include the accounts of Obsidian Energy, its wholly owned subsidiaries and its proportionate interest in partnerships. Results from acquired properties are included in Obsidian Energy’s reported results subsequent to the closing date and results from properties sold are included until the closing date.

All intercompany balances, transactions, income and expenses are eliminated on consolidation.

Certain comparative figures have been reclassified to correspond with current period presentation. Additionally, within these financial statements the Company has updated the presentation of our financial figures to disclose dollar figures rounded to the nearest hundred thousand. This may result in immaterial differences in the comparative figures.

b) Statement of Compliance

These annual consolidated financial statements are prepared in compliance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board.

The annual consolidated financial statements have been prepared on a historical cost basis, except risk management assets and liabilities which are recorded at fair value as discussed in Note 10.

These annual consolidated financial statements of the Company for the year ended December 31, 2020 were approved for issuance by the Board of Directors on March 26, 2021.

3. Significant accounting policies

a) Critical accounting judgments and key estimates

The preparation of the consolidated financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the recorded amounts of assets and liabilities, disclosure of any contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the period. These and other estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in these estimates could be material.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  8

Management also makes judgments while applying accounting policies that could affect amounts recorded in its consolidated financial statements. Significant judgments include the identification of cash generating units (“CGUs”) for impairment testing purposes and determining whether a CGU has an impairment indicator. Additionally, management has performed an assessment of the Company’s ability to comply with liquidity requirements for the 12-month period ending December 31, 2021. This assessment includes judgements relating to future production volumes, forward commodity pricing, future costs including capital, operating and general and administrative, forward foreign exchange rates, interest rates, and income taxes, all of which are subject to measurement uncertainty.

The following are the estimates that management has made in applying the Company’s accounting policies that have the most significant effect on the amounts recognized in the consolidated financial statements.

i) Reserve and resource estimates

Commercial petroleum reserves are determined based on estimates of petroleum-in-place, recovery factors and future oil and natural gas prices and costs. Obsidian Energy engages an independent qualified reserve evaluator to evaluate all of the Company’s oil and natural gas reserves at each year-end.

Reserve adjustments are made annually based on actual oil and natural gas volumes produced, the results from capital programs, revisions to previous estimates, new discoveries and acquisitions and dispositions made during the year and the effect of changes in forecast future oil and natural gas prices. There are a number of estimates and assumptions that affect the process of evaluating reserves.

Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids determined to be economically recoverable under existing economic and operating conditions with a high degree of certainty (at least 90 percent) those quantities will be exceeded. Proved plus probable reserves are the estimated quantities of oil, natural gas and natural gas liquids determined to be economically recoverable under existing economic and operating conditions with a 50 percent degree of certainty those quantities will be exceeded. Obsidian Energy reports production and reserve quantities in accordance with Canadian practices and specifically in accordance with “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”).

The estimate of proved plus probable reserves is an essential part of the depletion calculation and the impairment test and hence the recorded amount of oil and gas assets.

Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, operational, political and regulatory matters or a lack of markets. The estimate of contingent resources may be included as part of the recoverable amount in the impairment test.

Obsidian Energy cautions users of this information that the process of estimating oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on current and forecast economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include commodity prices, new technology, changing economic conditions, future reservoir performance and forecast development activity.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  9

ii) Recoverability of asset carrying values

Obsidian Energy assesses our property, plant and equipment (“PP&E”) for impairment by comparing the carrying amount to the recoverable amount of the underlying assets. The determination of the recoverable amount involves estimating the higher of an asset’s fair value less costs of disposal or its value-in-use, the latter of which is based on its discounted future cash flows using an applicable discount rate. Future cash flows are calculated based on estimates of future commodity prices and inflation and are discounted based on management’s current assessment of market conditions.

iii)Decommissioning liability

Obsidian Energy recognizes a provision for future abandonment activities in the consolidated financial statements at the net present value of the estimated future expenditures required to settle the estimated obligation at the balance sheet date. The measurement of the decommissioning liability involves the use of estimates and assumptions including the discount rate, the amount and expected timing of future abandonment costs and the inflation rate related thereto. The estimates were made by management and external consultants considering current costs, technology and enacted legislation.

iv) Office lease liability

Obsidian Energy recognizes a provision for certain onerous office lease commitments in the consolidated financial statements at the net present value of future lease payments the Company is obligated to make under non-cancellable lease contracts. The office lease liability relates to the non-lease component that does not qualify as a lease component under IFRS 16. The measurement of the office lease liability involves the use of assumptions including the discount rate and actual settlement amounts. Actual costs and cash outflows may differ from the estimates as a result of the changes in the noted assumptions.

v) Fair value calculation on share-based payments

The fair value of share-based payments is calculated using a Black-Scholes model. There are a number of estimates used in the calculation such as the expected future forfeiture rate, the expected period the share-based compensation is outstanding and the future price volatility of the underlying security all of which can vary from expectations. The factors applied in the calculation are management’s estimates based on historical information and future forecasts.

vi) Fair value of risk management contracts

Obsidian Energy records risk management contracts at fair value with changes in fair value recognized in income. The fair values are determined using external counterparty information which is compared to observable market data.

vii) Taxation ****

The calculation of deferred income taxes is based on a number of assumptions including estimating the future periods in which temporary differences and other tax credits will reverse and the general assumption that substantively enacted future tax rates at the balance sheet date will be in effect when differences reverse.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  10

viii) Litigation

Obsidian Energy records provisions related to legal matters if it is probable that the Company will not be successful in defending the claim and if an amount can be reasonably estimated. Determining the probability of a claim being defended is subject to considerable judgment. Additionally, the potential claim is generally a wide range of figures and a single estimate must be made when recording a provision. The assessment of contingencies involves significant judgment and estimates of the potential outcome of future events.

b) Business combinations

Obsidian Energy uses the acquisition method to account for business combinations. The net identifiable assets and liabilities acquired in transactions are generally measured at their fair value on the acquisition date. The acquisition date is the closing date of the business combination. Acquisition costs incurred by Obsidian Energy to complete a business combination are expensed in the period incurred except for costs related to the issue of any debt or equity securities, which are recognized based on the nature of the related financing instrument.

Revisions may be made to the initial recognized amounts determined during the measurement period, which shall not exceed one year after the closing date of the acquisition.

c) Revenue

Obsidian Energy generally recognizes oil, natural gas and natural gas liquids (“NGLs”) revenue when title passes from Obsidian Energy to the purchaser or, in the case of services, as contracted services are performed. Production revenues are determined pursuant to the terms outlined in contractual agreements and are based on fixed or variable price components. The transaction price for oil, natural gas and NGLs is based on the commodity price in the month of production, adjusted for various factors including product quality and location. Commodity prices are based on monthly or daily market indices.

Performance obligations in the contract are fulfilled on the last day of the month with payment typically on the 25^th^ day of the following month. All of the Company’s significant revenue streams are located in Alberta.

Obsidian Energy may purchase commodity products from third parties to utilize in blending activities and then subsequently sell these products to its customers. These transactions are presented as separate revenue and expense items in the Consolidated Statements of Income (Loss).

The Company enters into road use agreements with our partners which allows them to use roads that are operated by the Company. Under these road use agreements, the Company charges a fee which assists the Company in maintaining the roads. These fees received from partners are recorded within road use recoveries within Other income.

d) Joint arrangements

The consolidated financial statements include Obsidian Energy’s proportionate interest of jointly controlled assets and liabilities and our proportionate interest of the revenue, royalties and operating expenses. A significant portion of Obsidian Energy’s exploration and development activities are conducted jointly with others and involve joint operations. Under such arrangements, Obsidian Energy has the exclusive rights to our proportionate interest in the assets and the economic benefits generated from our share of the assets. Income from the sale or use of Obsidian Energy’s interest in joint operations and our share of expenses is recognized when it is probable that the economic benefits associated with the transactions will flow to/from Obsidian Energy and the amounts can be reliably measured.

The Peace River Oil Partnership is a joint operation and Obsidian Energy records our 55 percent interest of revenues, expenses, assets and liabilities.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  11

e) Transportation expense

Transportation costs are paid by Obsidian Energy for the shipping of natural gas, oil and natural gas liquids from the wellhead to the point where title transfers to buyers. These costs are recognized as services are received.

f) Foreign currency translation

Obsidian Energy and each of our subsidiaries use the Canadian dollar as their functional currency. Monetary items, such as accounts receivable and long-term debt, are translated to Canadian dollars at the rate of exchange in effect at the balance sheet date. Non-monetary items, such as PP&E, are translated to Canadian dollars at the rate of exchange in effect when the associated transactions occurred. Revenues and expenses denominated in foreign currencies are translated at the exchange rate on the date of the transaction. Foreign exchange gains or losses on translation are included in income.

g) PP&E

i) Measurement and recognition

Oil and gas properties are included in PP&E at cost, less accumulated depletion and depreciation and any impairment losses. The cost of PP&E includes costs incurred initially to acquire or construct the item and betterment costs. ****

Capital expenditures are recognized as PP&E when it is probable that future economic benefits associated with the investment will flow to Obsidian Energy and the cost can be reliably measured. PP&E includes capital expenditures incurred in the development phases, acquisition and disposition of PP&E and additions to the decommissioning liability.

ii) Depletion and Depreciation

Except for components with a useful life shorter than the reserve life of the associated property, resource properties are depleted using the unit-of-production method based on production volumes before royalties in relation to total proved plus probable reserves. Natural gas volumes are converted to equivalent oil volumes based upon the relative energy content of six thousand cubic feet of natural gas to one barrel of oil. In determining its depletion base, Obsidian Energy includes estimated future costs to develop proved plus probable reserves and excludes estimated equipment salvage values. Changes to reserve estimates are included in the depletion calculation prospectively.

Components of PP&E that are not depleted using the unit-of-production method are depreciated on a straight-line basis over their useful life. The turnaround component has an estimated useful life of three to five years and the corporate asset component has an estimated useful life of 10 years.

iii)Derecognition

The carrying amount of an item of PP&E is derecognized when no future economic benefits are expected from its use or upon sale to a third party. The gain or loss arising from derecognition is included in income and is measured as the difference between the net proceeds, if any, and the carrying amount of the asset.

iv) Major maintenance and repairs

Ongoing costs to maintain properties are generally expensed as incurred. These costs include the cost of labour, consumables and small parts. The costs of material replacement parts, turnarounds and major inspections are capitalized provided it is probable that future economic benefits in excess of cost will be realized and such benefits are expected to extend beyond the current operating period. The carrying amount of a replaced part is derecognized in accordance with Obsidian Energy’s derecognition policies.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  12

v) Impairment of oil and natural gas properties

Obsidian Energy reviews oil and gas properties for circumstances that indicate our assets may be impaired at the end of each reporting period. These indicators can be internal (i.e. reserve changes) or external (i.e. market conditions) in nature. If an indication of impairment exists, Obsidian Energy completes an impairment test, which compares the estimated recoverable amount to the carrying value. The estimated recoverable amount is defined under IAS 36 (“Impairment of Assets”) as the higher of an asset’s or CGU’s fair value less costs of disposal and its value-in-use.

Where the recoverable amount is less than the carrying amount, the CGU is considered to be impaired. Impairment losses identified for a CGU are allocated on a pro rata basis to the asset categories within the CGU. The impairment loss is recognized as an expense in income.

Value-in-use is computed as the present value of future cash flows expected to be derived from production. Present values are calculated using an after-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Under the fair value less cost of disposal method the recoverable amount is determined using various factors, which can include external factors such as observable market conditions and comparable transactions and internal factors such as discounted cash flows related to reserve and resource studies and future development plans.

The fair value less costs of disposal values used to determine the recoverable amounts of the Company’s CGUs are classified as Level 3 fair value measures as certain key assumptions are not based on observable market data but rather management’s best estimates.

Impairment losses related to PP&E can be reversed in future periods if the estimated recoverable amount of the asset exceeds the carrying value. The impairment recovery is limited to a maximum of the estimated depleted historical cost if the impairment had not been recognized. The reversal of an impairment loss is recognized in depletion, depreciation and impairment.

vi) Other Property, Plant and Equipment

Obsidian Energy’s corporate assets include computer hardware and software, office furniture, buildings and leasehold improvements and are depreciated on a straight-line basis over their useful lives. Corporate assets are tested for impairment separately from oil and gas assets. ****

h) Share-based payments

The fair value of units granted under the Restricted and Performance Share Unit Plan (“RPSU” plan) follows the equity method and recognizes compensation expense with a corresponding increase to other reserves in shareholders’ equity over the term of the units based on a graded vesting schedule. Obsidian Energy measures the fair value of units granted under this plan at the grant date using the share price from the Toronto Stock Exchange (“TSX”). The fair value is based on market prices and considers the terms and conditions of the units granted.

The fair value of options granted under the Stock Option Plan (the “Option Plan”) is recognized as compensation expense with a corresponding increase to other reserves in shareholders’ equity over the term of the options based on a graded vesting schedule. Obsidian Energy measures the fair value of options granted under these plans at the grant date using the Black-Scholes option-pricing model. The fair value is based on market prices and considers the terms and conditions of the share options granted.

The fair value of awards granted under the Deferred Share Unit Plan (“DSU”) and performance share units granted under the RPSU plan follow the liability method and are based on a fair value calculation on each reporting date using the awards and performance share units outstanding and Obsidian Energy’s share price from the TSX on each balance sheet date. The fair value of the awards and performance share units is expensed over the vesting period based on a graded vesting schedule. Subsequent increases and decreases in the underlying share price result in increases and decreases, respectively, to the accrued obligation until the related instruments are settled.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  13

i) Provisions

i) General

Provisions are recognized based on an estimate of expenditures required to settle present obligations at the end of the reporting period. The provision is risk adjusted to take into account any uncertainties. When the effect of the time value of money is material, the amount of a provision is calculated as the present value of the future expenditures required to settle the obligations. The discount rate reflects the current assessment of the time value of money and risks specific to the liability when those risks have not already been reflected as an adjustment to future cash flows.

ii) Decommissioning liability

The decommissioning liability is the present value of Obsidian Energy’s future costs of obligations for property, facility and pipeline abandonment and site restoration. The liability is recognized on the balance sheet with a corresponding increase to the carrying amount of the related asset. The recorded liability increases over time to its future amount through accretion charges to income. Revisions to the estimated amount or timing of the obligations are reflected prospectively as increases or decreases to the recorded liability and the related asset. Actual decommissioning expenditures, up to the recorded amount of the liability at the time, are charged to the liability as the costs are incurred. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset.

iii) Office lease provision

The office lease provision is the net present value of future lease payments that the Company is obligated to make under non-cancellable lease contracts. The office lease provision relates to the non-lease component that does not qualify as a lease component under IFRS 16. The liability is recognized on the balance sheet with the corresponding change charged to income. The recorded liability increases over time to its future amount through accretion charges to income. Revisions to the estimated amount or timing of the obligations are reflected prospectively as increases or decreases to the recorded liability. Actual lease payments are charged to the liability as the costs are incurred.

j) Leases

At the inception of entering into a contract, the Company assesses whether a contract is, or contains, a lease. A contract is or contains a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Company considers the following:

•	the contract involves the use of an identified asset;
•	the Company has the right to obtain substantially all of the economic benefits from the use of the asset<br>throughout the period of use; and
---	---
•	the Company has the right to direct the use of the asset, which occurs if either;
---	---
•	the Company has the right to operate the asset; or
---	---
•	the Company designed the asset in a way that predetermines how and for what purpose it will be used.<br>
---	---

Obsidian Energy recognizes a right-of-use asset and a lease liability at the commencement date of the lease. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date.

The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. The estimated useful life of right-of-use assets are determined based on the length of the lease.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  14

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the Company’s incremental borrowing rate. The consideration used to measure the lease liability includes all fixed payments and variable lease payments that depend on an index or rate under the arrangement. Subsequently, the lease liability is measured at amortized cost using the effective interest method and is re-measured when there is a change in the future lease payments.

In-scope leases

Upon adoption of IFRS 16, the Company identified certain office leases, transportation commitments, vehicle leases and surface leases in-scope under the standard.

•	Office lease commitments pertain to total leased office space;
•	Transportation commitments related to costs for future pipeline access;
---	---
•	Vehicle leases relate to commitments for usage of vehicles; and
---	---
•	Surface leases allow access to land at a natural gas or oil treatment facility and beyond.<br>
---	---

Obsidian Energy has elected not to recognize right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less and leases of low-value assets, which include information technology equipment and field equipment. The Company recognizes the lease payments associated with these leases as an expense on a straight-line basis over the lease term.

k) Share capital

Common shares are classified as equity. Share issue costs are recorded in shareholder’s equity, net of applicable taxes. Dividends, if paid, are at the discretion of the Board of Directors and are deducted from retained earnings.

If issued, preferred shares would be classified as equity and could be issued in one or more series.

l) Earnings per share

Earnings per share is calculated by dividing net income or loss attributable to the shareholders by the weighted average number of common shares outstanding during the period. Obsidian Energy computes the dilutive impact of equity instruments other than common shares assuming the proceeds received from the exercise of in-the-money share options are used to purchase common shares at average market prices. Anti-dilutive shares are excluded from the diluted earnings per share calculation.

m) Taxation

Income taxes are based on taxable income in a taxation year. Taxable income normally differs from income reported in the Consolidated Statements of Income (Loss) as it excludes items of income or expense that are taxable or deductible in other years or are not taxable or deductible for income tax purposes.

Obsidian Energy uses the liability method of accounting for deferred income taxes. Temporary differences are calculated assuming that the financial assets and liabilities will be settled at their carrying amount. Deferred income taxes are computed on temporary differences using substantively enacted income tax rates expected to apply when deferred income tax assets and liabilities are realized or settled.

A deferred income tax asset is recognized to the extent that it is probable that future taxable income will be available against which the deductible temporary differences can be utilized. Deferred income tax assets are reviewed at each reporting date and are not recognized until such time that it is probable that the related tax benefit will be realized.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  15

n) Financial instruments

Obsidian Energy recognizes financial assets and financial liabilities, including derivatives, on the Consolidated Balance Sheets when the Company becomes a party to the contract. Financial assets are derecognized when the rights to receive cash flows from the assets have expired or when the Company has transferred substantially all risks and rewards of ownership. Financial liabilities are derecognized from the consolidated financial statements when the liability is extinguished either through settlement of or release from the obligation of the underlying liability.

Classification and Measurement of Financial Instruments

The classification of financial assets is determined by their context in Obsidian Energy’s operations and by the characteristics of the financial asset’s contractual cash flows.

Financial assets and financial liabilities are measured at fair value on initial recognition, which is typically the transaction price unless a financial instrument contains a significant financing component. Subsequent measurement is dependent on the financial instrument’s classification, as described below:

•	Cash and cash equivalents (which includes cash and bank overdrafts), accounts receivable, accounts payable and<br>accrued liabilities and long-term debt are measured at amortized cost.
•	Risk management contracts, all of which are derivatives, are measured initially at fair value through profit<br>or loss and are subsequently measured at fair value with changes in fair value immediately charged to the Consolidated Statements of Income (Loss).
---	---

Financial assets and liabilities are offset and the net amount is reported on the balance sheet when there is a legally enforceable right to offset the recognized amounts, and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

Impairment of Financial Assets

Financial assets are assessed using an expected credit loss (“ECL”) model. The ECL model applies to financial assets measured at amortized cost, a lease receivable, a contract asset or a loan commitment and a financial guarantee.

o) Embedded derivatives

An embedded derivative is a component of a contract that affects the terms of another factor, for example, rent costs that fluctuate with oil prices. These “hybrid” contracts are considered to consist of a “host” contract plus an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative if the following conditions are met:

•	The economic characteristics and risks of the embedded derivative are not closely related to the economic<br>characteristics and risks of the host contract;
•	The embedded item, itself, meets the definition of a derivative; and
---	---
•	The hybrid contract is not measured at fair value or designated as held for trading.
---	---

p) Classification of debt or equity

Obsidian Energy classifies financial liabilities and equity instruments in accordance with the substance of the contractual arrangement and the definitions of a financial liability or an equity instrument.

Obsidian Energy’s debt instruments currently have requirements to deliver cash at the end of the term thus are classified as liabilities.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  16

q) Government Grants

Obsidian Energy recognizes government grants as they are received or if there is reasonable assurance that the Company is in compliance with all associated conditions. The grant is recognized within the Consolidated Statements of Income (Loss) in the period in which the income is earned or the related expenditures are incurred. If the grant relates to an asset, it is recognized as a reduction to the carrying value of the asset and amortized into income over the expected useful life of the asset through lower depletion and depreciation.

4. Lease receivable

Lease receivable relates to the lease component of sub-leased office space. Total lease receivable included in the Consolidated Balance Sheets is as follows:

	Year ended December 31
	2020			2019
Balance, beginning of year	$	39.5	****	$	42.4
Additions (terminations)	****	(37.6	)		3.7
Finance income	****	0.3	****		2.5
Lease payments received	****	(2.2	)		(9.1	)
Balance, end of year	$	0	****	$	39.5
Current portion	$	0	****	$	8.8
Long-term portion	$	0	****	$	30.7

In the first quarter of 2020, the Company entered into an amending agreement with our building landlord which resulted in renewed lease terms for our Calgary office space. Under the revised agreement, the amounts received from subtenants no longer meet the criteria to be classified as a finance lease and thus the lease receivable has been removed. The office lease provision referenced in Notes 8 and 9 has been updated to reflect the accounting treatment under the revised terms.

5.Assets and liabilities held for sale

Assets and liabilities classified as held for sale consisted of the following:

	As at December 31
	2020		2019
Assets held for sale
Cash	$	0	$	2.0
Accounts receivable	****	0		3.9
Property, plant and equipment	****	0		77.0
	$	0	$	82.9
Liabilities related to assets held for sale
Accounts payable and accrued liabilities	$	0	$	6.0
Decommissioning liability	****	0		7.0
	$	0	$	13.0

In the prior year, at December 31, 2019, the Company was continuing to progress through a sales process for our interest in the Peace River Oil Partnership. As a result of commodity price volatility, primarily due to the COVID-19 pandemic, the sales process was discontinued, thus the Company has no longer classified this asset as held for sale.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  17

6. Property, plant and equipment

Oil and Gas assets/Facilities, Corporate assets

Cost

	Oil and gas<br>assets/Facilities			Corporate<br>assets		Total
Balance at January 1, 2019	$	10,600.8		$	175.1	$	10,775.9
Capital expenditures		102.7			0.5		103.2
Dispositions		(53.3	)		—		(53.3	)
Transfer to assets held for sale		(423.0	)		—		(423.0	)
Net decommissioning dispositions ^(1)^		(15.6	)		—		(15.6	)
Balance at December 31, 2019	$	10,211.6	****	$	175.6	$	10,387.2	****
Capital expenditures	****	57.0	****	****	0.2	****	57.2	****
Dispositions	****	(0.1	)	****	0	****	(0.1	)
Transfer from assets held for sale	****	423.0	****	****	0	****	423.0	****
Net decommissioning dispositions<br>^(1)^	****	(29.0	)	****	0	****	(29.0	)
Balance at December 31, 2020	$	10,662.5	****	$	175.8	$	10,838.3	****
(1)	Includes additions from drilling activity, facility capital spending and disposals from net property<br>dispositions.
---	---

Accumulated depletion, depreciation and impairment

	Oil and gas<br>assets/Facilities			Corporate<br>Assets		Total
Balance at January 1, 2019	$	8,066.2		$	135.8	$	8,202.0
Depletion and depreciation		221.7			14.3		236.0
Impairments		657.7			—		657.7
Transfers to assets held for sale		(346.0	)		—		(346.0	)
Dispositions		(41.4	)		—		(41.4	)
Balance at December 31, 2019	$	8,558.2	****	$	150.1	$	8,708.3	****
Depletion and depreciation	****	115.1	****	****	7.0	****	122.1	****
Impairments	****	747.5	****	****	18.7	****	766.2	****
Transfers from assets held for sale	****	346.0	****	****	0	****	346.0	****
Balance at December 31, 2020	$	9,766.8	****	$	175.8	$	9,942.6	****

Net book value

	As at December 31
	2020		2019
Total	$	895.7	$	1,678.9

At December 31, 2020, future development costs of $636.1 million were included within the depletable base in the depletion and depreciation calculation (2019 – $563.7 million).

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  18

Right-of-use assets

The following table includes a break-down of the categories for right-of-use assets.

Cost	Office			Transportation			Vehicle		Surface			Total
Balance, January 1, 2019	$	15.0		$	16.7		$	2.9	$	2.2		$	36.8
Additions (Terminations)		(2.4	)		—			1.2		(0.1	)		(1.3	)
Balance, December 31, 2019	$	12.6		$	16.7		$	4.1	$	2.1		$	35.5
Additions (Terminations)		(12.6	)		(1.8	)		1.6		—			(12.8	)
Balance, December 31, 2020	$	0	****	$	14.9	****	$	5.7	$	2.1	****	$	22.7	****
Accumulated amortization	Office			Transportation		Vehicle		Surface		Total
---	---	---	---	---	---	---	---	---	---	---	---	---
Balance, January 1, 2019	$	—		$	—	$	—	$	—	$	—
Amortization		2.4			6.0		1.3		0.1		9.8
Balance, December 31, 2019	$	2.4		$	6.0	$	1.3	$	0.1	$	9.8
Amortization		0.5			4.5		1.3		—		6.3
Termination		(2.9	)		—		—		—		(2.9	)
Balance, December 31, 2020	$	0	****	$	10.5	$	2.6	$	0.1	$	13.2	****
	As at December 31
---	---	---	---	---
	2020		2019
Total	$	9.5	$	25.7

In the first quarter of 2020, the Company entered into an amending agreement with our building landlord which resulted in renewed lease terms for our Calgary office space. Under the revised agreement, the office lease no longer meets the criteria to be classified as a right-of-use asset. The office lease provision referenced in Notes 8 and 9 has been updated to reflect the accounting treatment under the revised terms.

Total PP&E

Total PP&E including Oil and Gas assets, Facilities, Corporate assets and Right-of-use assets is as follows:

	As at December 31
PP&E	2020		2019
Oil and Gas assets, Facilities, Corporate assets	$	895.7	$	1,678.9
Right-of-use<br>assets	****	9.5		25.7
Total	$	905.2	$	1,704.6
OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  19
---	---

The Company recorded non-cash impairments of $766.2 million in 2020 compared to $657.7 million in 2019.

At March 31, 2020, the Company completed impairment tests across all of our CGU’s as a result of the low commodity price environment, primarily due to the impact of the COVID-19 pandemic and concerns regarding potential lack of storage forcing production shut-ins. This led to the Company recording $762.8 million of non-cash impairments, which included $701.8 million within our Cardium CGU, $58.1 million within our Peace River CGU and $18.7 million within our corporate assets. Additionally, a $15.8 million impairment recovery was recorded within our Legacy CGU as a result of the Company increasing our discount rate used in our decommissioning liability due to current market conditions.

At December 31, 2020, the Company completed an assessment to determine if indicators of impairment or an impairment reversal were present. As a result of recent improvements in near term commodity prices and positive reserve revisions, the Company concluded that an impairment reversal indicator was present resulting in impairment tests being completed within our Cardium and Peace River CGUs. The Company followed the value-in use method for our Cardium CGU and the fair value less costs of disposal method for our Peace River CGU using proved plus probable reserves. Additionally, the Company identified an indicator of impairment for our Legacy CGU as a result of the planned acceleration of decommissioning spending in the area. This led to an impairment test being completed following the fair value less costs of disposal method. The after-tax discount rates applied within the tests were between 9.5 – 15 percent. No indicator of impairment was noted for our Viking CGU; thus, no test was performed.

Upon completion of the impairment tests, an $18.0 million impairment reversal was recorded within our Peace River CGU and no reversal was recorded within our Cardium CGU. Within our Legacy CGU, as a result of revisions to our decommissioning spending profile the Company recorded a $21.8 million impairment. The Company plans to accelerate decommissioning spending in the area as we focus on reducing our inactive well liability, which led to the impairment.

The following table outlines benchmark prices and assumptions, based on an average of four independent reserve evaluators’ forecasts (Sproule Associates Limited, GLJ Petroleum Consultants, McDaniel & Associates Consultants and Deloitte Resource Evaluation & Advisory), used in completing the impairment tests as at December 31, 2020.

	WTI(US/bbl)		AECO(CAD/MMbtu)		Exchange rate(US equals 1CAD)	Inflation rate
2021							0	%
2022							1.5	%
2023							2.0	%
2024							2.0	%
2025							2.0	%
2026 – 2030							2.0	%
Thereafter (inflation percentage)		%		%			2.0	%

All values are in US Dollars.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  20

The following table outlines the sensitivity on possible changes to the estimated recoverable amounts on the Company’s CGUs that had impairment tests completed on December 31, 2020.

	Recoverable<br>amount		Impairment/<br>(Impairment<br>reversal)			1% change in<br>discount rate		5% change in<br>cash flows
Cardium	$	849.2	$	Nil		$	66.9	$	66.2
Peace River		28.5		(18.0	)		1.3		2.8
Legacy	$	Nil	$	21.8		$	Nil	$	Nil

At December 31, 2019, the Company completed impairment tests as a result of continued market and commodity price volatility in the oil and gas industry which resulted in an increase of our discount rates used in the calculation. This led to the Company recording $527.8 million of non-cash impairments, which included $450.0 million within our Cardium CGU and $77.8 million with our Legacy CGU.

At June 30, 2019, as a result of continuing to progress through a sales process for our interest in the Peace River Oil Partnership, these assets were recorded at the lower of fair value less costs of disposal and their carrying amount, resulting in a PP&E impairment loss of $129.7 million.

Impairments and impairment reversals have been recorded as Depletion, depreciation, impairment and accretion expense on the Consolidated Statements of Income (Loss).

7. Long-term debt

			2019
Syndicated credit facility	395.0	****	$	399.0
Senior secured notes – 2008 Notes6.40%, US4.0 million, maturing November 30,<br>2021	5.2			5.3
Senior secured notes – 2010 Q1 Notes5.85%, US9.8 million, maturing<br>November 30, 2021	12.4			12.7
Senior secured notes – 2010 Q4 Notes4.88%, US13.3 million, maturing<br>November 30, 2021	16.9			17.2
4.98%, US5.8 million, maturing November 30, 2021	7.4			7.5
5.23%, US2.1 million, maturing November 30, 2021	2.7			2.8
Senior secured notes – 2011 Q4 Notes4.79%, US12.3 million, maturing<br>November 30, 2021	15.7	****		16.0
Total credit facility and senior secured notes	455.3	****	$	460.5
Deferred financing costs	(3.5	)		—
Total long-term debt	451.8	****		460.5
Current portion	451.8	****	$	434.2
Long-term portion	0	****	$	26.3

All values are in US Dollars.

At December 31, 2020, the revolving period of the syndicated credit facility was set at January 29, 2021, with the end date of the term out period on November 30, 2021. As the term-out date was within one year of the balance sheet date, this resulted in the outstanding amount of the syndicated credit facility being presented as a current liability. This treatment was also consistent at December 31, 2019 as the term out period at that time was also within one year of the balance sheet date. Subsequent to December 31, 2020, the Company re-negotiated its syndicated credit facility, which resulted in an extension of the term-out period to November 30, 2022.

There were no senior note issuances in either 2020 or 2019.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  21

Additional information on Obsidian Energy’s senior secured notes was as follows:

	As at December 31
	2020			2019
Weighted average remaining life (years)	****	0.9	****		1.5
Weighted average interest rate	****	5.2	%		5.7	%

The estimated fair values of the principal and interest obligations of the outstanding senior secured notes were as follows:

	As at December 31
	2020		2019
2008 Notes	$	4.3	$	5.3
2010 Q1 Notes	****	10.2		12.6
2010 Q4 Notes	****	22.0		25.7
2011 Notes	****	12.8		14.8
Total	$	49.3	$	58.4

The Company has a reserve-based syndicated credit facility which is subject to a semi-annual borrowing base redetermination typically in May and November of each year. Subsequent to December 31, 2020, 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 is now set at $440 million. The $440 million of availability consists of a $225 million revolving syndicated credit facility and a $215 million non-revolving term loan.

Additionally, the following terms were included in the amending agreement:

•	the revolving period under the syndicated credit facility has been extended to May 31, 2022, with the end<br>date of the term period extended to November 30, 2022;
•	the maturity date of the non-revolving term loan is also November 30, 2022;
---	---
•	the next scheduled borrowing base redeterminations will occur on November 30, 2021 and May 31, 2022;<br>
---	---
•	a revolving period reconfirmation date will occur on January 17, 2022, whereby, on or prior to such date,<br>the lenders may accelerate the end date of the revolving period to February 1, 2022. In this case, the end date of the term period would remain unchanged at November 30, 2022; and
---	---
•	the Company’s revolving credit facility will have a one-time adjustment to reduce our undrawn<br>availability to $35 million at December 31, 2021. Any borrowing availability at this time in excess of that amount will be used to reduce amounts outstanding on the non-revolving term loan and senior notes.
---	---

Additionally, subsequent to December 31, 2020, the Company agreed with holders of our senior notes to extend the maturity dates of the notes due on November 30, 2021 to November 30, 2022 and to increase the interest rate on each series of our notes by approximately 2.1 percent.

Drawings on the Company’s syndicated credit facility are subject to fluctuations in short-term money market rates as they are generally held as short-term borrowings. As at December 31, 2020, 87 percent (2019 – 87 percent) of Obsidian Energy’s long-term debt instruments were exposed to changes in short-term interest rates.

At December 31, 2020, letters of credit totaling $5.0 million were outstanding (2019 – $7.7 million) that reduce the amount otherwise available to be drawn on the syndicated credit facility.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  22

The aggregate amount available under our syndicated credit facility is scheduled for review on a semi-annual basis and is based on our lender’s assessment of the Company’s reserves, forecasted commodity prices and other factors. In the event that a decrease in the borrowing base occurs, this could result in a reduction to the available amount under the syndicated credit facility. In a situation where the amount available is below the amount drawn on the syndicated credit facility, the Company has 30 days to eliminate any shortfall by repaying amounts in excess of the new re-determined borrowing base.

Financing expense consists of the following:

	As at December 31
	2020		2019
Interest on bank debt and senior notes	$	22.8	$	28.3
Advisor fees	****	10.1		4.1
Deferred financing costs	****	2.8		0.7
Unwinding discount on lease liabilities	****	1.5		7.5
Financing	$	37.2	$	40.6

Obsidian Energy records unrealized foreign exchange gains or losses on our senior notes as amounts are translated into Canadian dollars at the rate of exchange in effect at the balance sheet date. Realized foreign exchange gains or losses are recorded upon actual repayment of senior notes. The split between realized and unrealized foreign exchange is as follows:

	As at December 31
	2020		2019
Realized foreign exchange loss	$	0	$	(2.6	)
Unrealized foreign exchange gain	****	1.4		5.8
Foreign exchange gain	$	1.4	$	3.2

The Company is subject to Senior debt and Total debt to Capitalization financial covenants with a maximum ratio of 75 percent, as more specifically defined in the applicable lending agreements. At December 31, 2020, the Company was in compliance with our financial covenants under such lending agreements.

In 2015, as part of entering into amending agreements with its lenders and noteholders, the Company agreed to grant floating charge security over all of its property in favour of the lenders and the noteholders on a pari passu basis, which security will be fully released on such date when both (a) no default or event of default is continuing under the Company’s syndicated bank facility or senior notes and (b) the Company has achieved both (i) a Senior Debt to EBITDA ratio of 3:1 or less for four consecutive quarters, and (ii) an investment grade rating on its senior secured debt. The security remained in place at December 31, 2020.

8. Lease liabilities

Total lease liabilities included in the Consolidated Balance Sheets are as follows:

	Year ended December 31
	2020			2019
Balance, beginning of year	$	113.8	****	$	135.2
Additions (terminations)	****	(98.6	)		1.0
Unwinding of discount on lease liabilities	****	1.5	****		7.5
Lease payments	****	(6.3	)		(29.9	)
Balance, end of year	$	10.4	****	$	113.8
Current portion	$	4.8	****	$	28.8
Long-term portion	$	5.6	****	$	85.0
OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  23
---	---

In the first quarter of 2020, the Company entered into an amending agreement with our building landlord which resulted in renewed lease terms for our Calgary office space. The revised agreement no longer meets the criteria to be classified as a lease liability, thus the office lease portion has been removed. The office lease provision referenced in Note 9 has been adjusted to reflect the revised appropriate accounting treatment.

The following table sets out a maturity analysis of lease payments, disclosing the undiscounted balance after December 31, 2020:

	2021		2022		2023		2024		2025		Thereafter		Total
Transportation	$	3.4	$	2.2	$	—	$	—	$	—	$	—	$	5.6
Vehicle	****	1.4		1.2		0.7		0.1		—		—		3.4
Surface	****	0.1		0.1		0.1		0.1		0.1		5.0		5.5
Total	$	4.9	$	3.5	$	0.8	$	0.2	$	0.1	$	5.0	$	14.5

Amounts recognized in Consolidated Statements of Income (Loss) and Consolidated Statements of Cash Flows

The Company recorded $0.3 million of income from sub-leases related to our right-of-use assets. Expenses related to short-term leases and leases of low-value assets were insignificant during the year.

9. Provisions

	As at December 31
	2020		2019
Decommissioning liability	$	70.5	$	100.1
Office lease provision	****	33.5		12.7
Total	$	104.0	$	112.8
Current portion	$	16.3	$	16.2
Long-term portion	****	87.7		96.6
Total	$	104.0	$	112.8

Decommissioning liability

The decommissioning liability is based on the present value of Obsidian Energy’s net share of estimated future costs of obligations to abandon and reclaim all our wells, facilities and pipelines. These estimates were made by management using information obtained from government estimates, internal analysis and external consultants assuming current costs, technology and enacted legislation.

At December 31, 2020, the decommissioning liability was determined by applying an inflation factor of 2.0 percent (2019 – 2.0 percent) and the inflated amount was discounted using a credit-adjusted rate of 9.0 percent (2019 – 7.0 percent) over the expected useful life of the underlying assets, currently extending over 50 years into the future. At December 31, 2020, the total decommissioning liability on an undiscounted, uninflated basis was $596.6 million (2019 – $621.2 million).

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  24

Changes to the decommissioning liability were as follows:

	Year ended December 31
	2020			2019
Balance, beginning of year	$	100.1	****	$	129.1
Net liabilities added (disposed)<br>^(1)^	****	(0.4	)		(6.2	)
Increase (decrease) due to changes in estimates	****	(28.6	)		(9.4	)
Liabilities settled	****	(11.1	)		(14.4	)
Government decommissioning assistance	****	(2.2	)		—
Transfers (to) from liabilities for assets held for sale	****	7.0	****		(7.0	)
Accretion charges	****	5.7	****		8.0
Balance, end of year	$	70.5	****	$	100.1
Current portion	$	7.3	****	$	13.0
Long-term portion	$	63.2	****	$	87.1
(1)	Includes additions from drilling activity, facility capital spending and disposals related to net property<br>dispositions.
---	---

Office lease provision

The office lease provision represents the net present value of non-lease components on future office lease payments. The office lease provision was determined by applying an asset specific credit-adjusted discount rate of 6.5 percent (2019 – 6.0 percent) over the remaining life of the lease contracts, extending into 2025.

Changes to the office lease provision were as follows:

	Year ended December 31
	2020			2019
Balance, beginning of year	$	12.7	****	$	21.3
Net additions (dispositions)	****	27.0	****		(5.6	)
Increase (decrease) due to changes in estimates	****	1.0	****		(1.9	)
Settlements	****	(9.7	)		(2.2	)
Accretion charges	****	2.5	****		1.1
Balance, end of year	$	33.5	****	$	12.7
Current portion	$	9.0	****	$	3.2
Long-term portion	$	24.5	****	$	9.5

In the first quarter of 2020, the Company entered into an amending agreement with our building landlord which resulted in renewed lease terms for our Calgary office space. Under the terms of the amending agreement our annual net rent payable will be a maximum of $0.8 million per month ($10.0 million per annum) for the period from February 1, 2020 through January 31, 2025, when the lease expires. Additionally, the building landlord has agreed to indemnify the Company on all existing subleases. Based on the revised terms, all costs associated with the agreement now meet the criteria to be classified as an onerous lease.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  25

10. Risk management

Financial instruments consist of cash and cash equivalents, accounts receivable, fair values of derivative financial instruments, accounts payable and accrued liabilities and long-term debt. At December 31, 2020, except for the senior notes described in Note 7 with a carrying value of $60.3 million (2019 – $61.5 million) and a fair value of $49.3 million (2019 – $58.4 million), the fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments.

The fair values of all outstanding financial and commodity contracts are reflected on the Consolidated Balance Sheets with the changes during the period recorded in income as unrealized gains or losses.

At December 31, 2020 and 2019, the only asset or liability measured at fair value on a recurring basis was the risk management asset and liability, which was valued based on “Level 2 inputs” being quoted prices in markets that are not active or based on prices that are observable for the asset or liability.

The following table reconciles the changes in the fair value of financial instruments outstanding:

	Year ended December 31
Risk management asset (liability)	2020			2019
Balance, beginning of year	$	(0.6	)	$	8.0
Unrealized gain (loss) on financial instruments:
Commodity collars and swaps	****	0.8	****		(8.6	)
Total fair value, end of year	$	0.2	****	$	(0.6	)
Current portion	$	0.2	****	$	(0.6	)
Long-term portion	$	0	****	$	—

Obsidian Energy records our risk management assets and liabilities on a net basis in the Consolidated Balance Sheets. At December 31, 2020 and 2019, there were no differences between the gross and net amounts.

Obsidian Energy had the following financial instruments outstanding as at December 31, 2020. Fair values are determined using external counterparty information, which is compared to observable market data. The Company limits our credit risk by executing counterparty risk procedures which include transacting only with institutions within our syndicated credit facility or companies with high credit ratings and by obtaining financial security in certain circumstances.

	Notionalvolume		Remaining<br>term		Pricing		Fair value(millions)
Oil
WTI Swaps		5,750 bbl/d		January 2021	$	59.62/bbl	$	(0.5	)
WTI Swaps		2,500 bbl/d		February 2021	$	60.34/bbl		(0.1	)
WTI Swaps		750 bbl/d		March 2021	$	61.58/bbl		0
AECO Swaps
AECO Swaps		23,700 mcf/d		Jan –Mar 2021	$	2.94/mcf		0.8
Total							$	0.2	****
OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  26
---	---

Subsequent to December 31, 2020, the Company entered into the following additional financial hedges:****

Reference price	Notionalvolume		Term		Pricing
Oil
WTI Swaps		400 bbl/d		January 2021	$	63.09/bbl
WTI Swaps		3,750 bbl/d		February 2021	$	67.00/bbl
WTI Swaps		6,050 bbl/d		March 2021	$	69.70/bbl
WTI Swaps		4,750 bbl/d		April 2021	$	77.74/bbl
WTI Swaps		1,125 bbl/d		May 2021	$	81.50/bbl
AECO Swaps
AECO Swaps		2,370 mcf/d		March 2021	$	3.17/mcf
AECO Swaps		26,100 mcf/d		April 2021	$	2.83/mcf
AECO Swaps		21,300 mcf/d		May 2021	$	2.68/mcf
AECO Swaps		21,300 mcf/d		June 2021	$	2.67/mcf
AECO Swaps		4,700 mcf/d		July 2021	$	2.28/mcf
AECO Swaps		4,700 mcf/d		August 2021	$	2.28/mcf
AECO Swaps		4,700 mcf/d		September 2021	$	2.28/mcf
AECO Swaps		4,700 mcf/d		October 2021	$	2.28/mcf

Based on commodity prices and contracts in place at December 31, 2020, a $1.00 change in the price per barrel of liquids of WTI would change pre-tax unrealized risk management by $0.4 million and a $0.50 change in the price per mcf of natural gas would change pre-tax unrealized risk management by $1.1 million.

The components of risk management on the Consolidated Statements of Income (Loss) are as follows:

	Year ended December 31
	2020		2019
Realized
Settlement of commodity contracts	$	20.9	$	(7.2	)
Total realized risk management gain (loss)	$	20.9	$	(7.2	)
Unrealized
Commodity contracts	$	0.8	$	(8.6	)
Total unrealized risk management gain (loss)	****	0.8		(8.6	)
Risk management gain (loss)	$	21.7	$	(15.8	)

Additionally, the Company had the following physical contracts outstanding at December 31, 2020.

	Notionalvolume		Term		Pricing
Physical Oil Contracts^(1)^
WTI		542 bbl/d		Jan – Mar 2021	$	55.54/bbl
WTI		571 bbl/d		Apr – Jun 2021	$	59.04/bbl
(1)	WTI, differentials and foreign exchange hedged to lock-in positive net operating income on certain heavy oil<br>properties.
---	---
OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  27
---	---

Subsequent to December 31, 2020 the Company entered into the following physical contracts:

		Term		Pricing
Light Oil Differential<br>(1)(2)
	1,245 bbl/d		Apr – Jun 2021	$	5.51/bbl
	1,230 bbl/d		Jul – Sep 2021	$	5.82/bbl
Light Oil Differential – <br>(1)
	1,556 bbl/d		Apr – Jun 2021	US$	4.00/bbl
	1,539 bbl/d		Jul – Sep 2021	US$	4.42/bbl
Heavy Oil Differential<br>(3)
	564 bbl/d		Jul – Sep 2021	$	14.85/bbl

All values are in US Dollars.

(1)	Differentials completed on a WTI - MSW basis.
(2)	USD transactions completed on a US$ WTI - US$ MSW basis and converted to Canadian dollars using a fixed foreign<br>exchange ratio of CAD/USD $1.281 in the second quarter of 2021 and $1.279 in the third quarter of 2021.
---	---
(3)	Differentials completed on a WTI - WCS basis.
---	---

COVID-19 Pandemic Risk

In March 2020, the World Health Organization declared COVID-19 a global pandemic. Since that time, the oil and gas industry has experienced significant volatility with commodity prices, and in particular oil prices, as a result of a decline in economic activity and lower demand for commodities in both Canada and around the world. In the second half of 2020 and into 2021, oil prices have largely recovered from the lows that occurred in the second quarter of 2020 as restrictions eased and vaccines started to be administered. In early 2021, full demand recovery remains uncertain as countries are at various stages of rolling-out vaccines while virus outbreaks continue to occur, mainly due to new variants, which has resulted in activity restrictions. This market volatility has not only impacted oil and gas sales but has increased the complexity of certain judgements and estimates when preparing our year-end 2020 financial information, particularly within the measurement uncertainty of the inputs used in the Company’s assessment of the recoverability of asset carrying values, assessing counterparty credit risk as well as the credit risk-adjusted discount rate used within our decommissioning liability and office lease provision.

Market Risks

Obsidian Energy is exposed to normal market risks inherent in the oil and natural gas business, including, but not limited to, commodity price risk, foreign currency rate risk, credit risk, interest rate risk and liquidity risk. The Company seeks to mitigate these risks through various business processes and management controls and from time to time by using financial instruments.

CommodityPrice Risk

Commodity price fluctuations are among the Company’s most significant exposures. Oil prices are influenced by worldwide factors, including, but not limited to, OPEC actions, world supply and demand fundamentals, pipeline capacity availability and geopolitical events. Natural gas prices are influenced by, including, but not limited to, the price of alternative fuel sources such as oil or coal and by North American natural gas supply and demand fundamentals including the levels of industrial activity, weather, storage levels and liquefied natural gas activity. In accordance with policies approved by Obsidian Energy’s 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. Risk management limits included in Obsidian Energy’s policies may be exceeded with specific approval from the Board of Directors.

For the first half of 2021, the Board of Directors has approved an increase to the maximum percentage of production that may be hedged as follows: i) gas volumes, net of royalties may be hedged up to a maximum of 65 percent and ii) oil volumes, net of royalties may be hedged up to a maximum of 65 percent for the following month, otherwise hedges must follow the standard terms and conditions of the program. Additionally, for the second half of 2021, the Board of Directors has approved that gas volumes, net of royalties, may be hedged up to a maximum of 60 percent.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  28

Foreign Currency Rate Risk

Prices received for oil are referenced in US dollars, thus Obsidian Energy’s realized oil prices are impacted by Canadian dollar to US dollar exchange rates. A portion of the Company’s debt is denominated in US dollars, thus the principal and interest payments in Canadian dollar terms are also impacted by exchange rates. When considered appropriate, the Company may use financial instruments to fix or collar future exchange rates to fix the Canadian dollar equivalent of oil revenues or to fix US denominated long-term debt principal repayments.

Credit Risk

Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. As at December 31, 2020, the Company’s maximum exposure to credit risk was $41.6 million (2019 – $66.0 million) which was comprised of $40.8 million (2019 – $65.6 million) being the carrying value of the accounts receivable and $0.8 million (2019 – $0.4 million) related to the fair value of the derivative financial assets.

The Company’s accounts receivable are principally with customers in the oil and natural gas industry and are generally subject to normal industry credit risk, which includes the ability to recover unpaid receivables by retaining the partner’s share of production when Obsidian Energy is the operator or the potential to net offsetting payables to mitigate exposure. Obsidian Energy continuously monitors credit risk and maintains credit policies to ensure collection risk is limited. For oil and natural gas sales and financial derivatives, a counterparty risk procedure is followed whereby each counterparty is reviewed on a regular basis for the purpose of assigning a credit limit and may be requested to provide security if determined to be prudent. For financial derivatives, the Company normally transacts with counterparties who are members of our banking syndicate or counterparties that have investment grade bond ratings. Credit events related to all counterparties are monitored and credit exposures are reassessed on a regular basis.

At December 31, 2020, $5.7 million of accounts receivable are past due (90+ days) but are considered to be collectible (2019 – $8.7 million). The lifetime ECL allowances related to Obsidian Energy’s commodity product sales receivables and joint venture receivables recognized in accounts receivable was nominal as at and for the years ended December 31, 2020 and 2019.

As at December 31, the following accounts receivable amounts were outstanding:

	Current		30-90 days		90+ days		Total ^(1)^
2020	$	29.5	$	5.6	$	5.7	$	40.8
2019	$	47.5	$	9.4	$	8.7	$	65.6
(1)	In 2020, $nil of accounts receivable is related to assets classified as held for sale (2019 – $3.9<br>million).
---	---

Interest Rate Risk

A portion of the Company’s debt capital can be held in floating-rate bank facilities, which results in exposure to fluctuations in short-term interest rates, which remain at lower levels than longer-term rates. From time to time, Obsidian Energy may increase the certainty of our future interest rates by entering fixed interest rate debt instruments or by using financial instruments to swap floating interest rates for fixed rates or to collar interest rates. As at December 31, 2020, 87 percent of the Company’s long-term debt instruments were exposed to changes in short-term interest rates (2019 – 87 percent).

As at December 31, 2020, a total of $60.3 million (2019 – $61.5 million) of fixed interest rate debt instruments was outstanding with an average remaining term of 0.9 years (2019 – 1.5 years) and an average interest rate of 5.2 percent (2019 – 5.7 percent).

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  29

Liquidity Risk

Liquidity risk is the risk that the Company will be unable to meet its financial liabilities as they come due. Management utilizes short and long-term financial and capital forecasting programs to ensure credit facilities are sufficient relative to forecast debt levels and capital program levels are appropriate, and that financial covenants will be met. Management also regularly reviews capital markets to identify opportunities to optimize the debt capital structure on a cost-effective basis. In the short term, liquidity is managed through daily cash management activities, short-term financing strategies and the use of swaps and other financial instruments to increase the predictability of cash flow from operating activities.

The following table outlines estimated future obligations for non-derivative financial liabilities as at December 31, 2020:

	Long-term debt ^(1)^		Accounts payable<br>& accrued<br>liabilities		Share-based<br>compensation<br>accrual		Total
2021	$	451.8	$	72.2	$	1.9	$	525.9
2022		0		0		0.1	****	0.1
2023		0		0		0	****	0
2024		0		0		0	****	0
2025		0		0		0	****	0
Thereafter	$	0	$	0	$	0	$	0
(1)	The 2021 figure includes $395.0 million related to the syndicated credit facility, which at the balance<br>sheet date was due for renewal in 2021. Subsequent to December 31, 2020, the Company entered into an agreement with members of our banking syndicate to extend the term-out period of the syndicated credit<br>facility to November 30, 2022. Additionally, the Company also entered into agreements with holders of our senior notes to extend their maturity dates, previously due on November 30, 2021, to November 30, 2022. Refer to Note 7 for<br>additional details.
---	---

11. Revenue and Other Income

The Company’s significant revenue streams consist of the following:

	Year ended December 31
	2020		2019
Oil	$	213.1	$	357.9
NGLs	****	16.3		16.3
Natural gas	****	46.0		35.1
Production revenues	****	275.4		409.3
Processing fees	****	6.3		7.7
Oil and natural gas sales	****	281.7		417.0
Other income	****	13.0		8.5
Oil and natural gas sales and other income	$	294.7	$	425.5

In 2020, Other income includes $5.4 million in road use recoveries (2019 – $6.0 million), while the remainder primarily relates to curtailment sales, whereby the Company sold unused production limit capacity under the Alberta Government Curtailment production limits.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  30

12. Income taxes

The provision for income taxes is as follows:

	As at December 31
	2020		2019
Deferred tax recovery	$	0	$	—

The provision for income taxes reflects an effective tax rate that differs from the combined federal and provincial statutory tax rate as follows:

	Year ended December 31
	2020			2019
Loss before taxes	$	(771.7	)	$	(788.3	)
Combined statutory tax rate ^(1)^	****	24.0	%		26.5	%
Computed income tax recovery	$	(185.2	)	$	(208.9	)
Increase (decrease) resulting from:
Share-based compensation	****	0.5	****		1.2
Non-taxable foreign exchange (gain) loss	****	(0.3	)		(0.9	)
Unrecognized deferred tax asset	****	178.2	****		176.5
Adjustments related to prior years	****	(0.9	)		(4.8	)
Tax rate reductions	****	7.6	****		34.2
Other	****	0.1	****		2.7
Deferred tax recovery	$	0	****	$	—
(1)	The tax rate represents the combined federal and provincial statutory tax rates for the Company and our<br>subsidiaries for the years ended December 31, 2020 and December 31, 2019. Effective July 1, 2020, the Alberta corporate income tax rate was reduced from 10% to 8%. This resulted in a combined statutory tax rate of 24.0% for the year.<br>
---	---

The net deferred income tax liability is comprised of the following:

	Balance<br>January 1,<br>2020			Provision<br>(Recovery)<br>in Income			Balance<br>December 31,2020
Deferred tax liabilities (assets)
PP&E	$	282.5		$	(196.0	)	$	86.5	****
Leases		(20.0	)		9.9		****	(10.1	)
Decommissioning liability		(24.6	)		8.0		****	(16.6	)
Share-based compensation		(0.2	)		(0.2	)	****	(0.4	)
Non-capital losses		(237.7	)		178.3		****	(59.4	)
Net deferred tax liability	$	0		$	0		$	0	****
	Balance<br>January 1,<br>2019			Provision<br>(Recovery)<br>in Income			Balance<br>December 31,<br>2019
---	---	---	---	---	---	---	---	---	---
Deferred tax liabilities (assets)
PP&E	$	525.9		$	(243.4	)	$	282.5
Risk management		2.2			(2.2	)		—
Leases		(22.7	)		2.7			(20.0	)
Decommissioning liability		(34.9	)		10.3			(24.6	)
Share-based compensation		(0.2	)		—			(0.2	)
Non-capital losses		(470.3	)		232.6			(237.7	)
Net deferred tax liability	$	—		$	—		$	—
OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  31
---	---

As at December 31, 2020, Obsidian Energy had approximately $2.5 billion (2019 – $2.6 billion) in total tax pools, including non-capital losses of $2.2 billion (2019 – $2.2 billion). The non-capital losses are available for immediate deduction against future taxable income and expire in the years 2026 through 2041. A deferred tax asset has not been recognized in respect of non-capital losses of $1,950.4 million (2019 – $1,175.4 million) as there is not sufficient certainty regarding future utilization.

At December 31, 2020, Obsidian Energy had realized and unrealized net capital losses of $595.0 million (2019 – $592.0 million). A deferred tax asset has not been recognized in respect of these losses as they may only be applied against future capital gains.

The Company has income tax filings that are subject to audit by taxation authorities, which may impact our deferred income tax position or amount. The Company does not anticipate adjustments arising from these audits and believes we have adequately provided for income taxes based on available information, however, adjustments that arise could be material.

13. Shareholders’ equity

Effective June 5, 2019, the Company consolidated its common shares on the basis of seven old common shares outstanding for one new common share. All figures in the annual consolidated financial statements have been updated to reflect the 7:1 consolidation. Additionally, the number of units or options and the per unit or option prices under the RPSU plan, Option Plan and DSU plan have been updated accordingly.

a) Authorized

i) An unlimited number of Common Shares.

ii) 90,000,000 preferred shares issuable in one or more series.

If issued, preferred shares of each series would rank on parity with the preferred shares of other series with respect to accumulated dividends and return on capital. Preferred shares would have priority over the common shares with respect to the payment of dividends or the distribution of assets.

b) Issued

Shareholders’ capital	Common Shares		Amount
Balance, December 31, 2018		72,473,719	$	2,184.9
Issued on exercise of equity compensation plans<br>^(1)^		537,769		1.8
Balance, December 31, 2019	****	73,011,488	$	2,186.7
Issued on exercise of equity compensation plans<br>^(1)^	****	504,737	****	0.3
Balance, December 31, 2020	****	73,516,225	$	2,187.0
(1)	Upon vesting or exercise of equity awards, the net benefit is recorded as a reduction of other reserves and an<br>increase to shareholders’ capital.
---	---
OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  32
---	---
	Year ended December 31
---	---	---	---	---	---	---
Other Reserves	2020			2019
Balance, beginning of year	$	101.8	****	$	99.1
Share-based compensation expense	****	2.1	****		4.5
Net benefit on options exercised^(1)^	****	(0.3	)		(1.8	)
Balance, end of year	$	103.6	****	$	101.8
(1)	Upon exercise of awards, the net benefit is recorded as a reduction of other reserves and an increase to<br>shareholders’ capital.
---	---

Preferred Shares

No Preferred Shares were issued or outstanding.

14.Share-based compensation

Restricted and Performance Share Unit plan (“RPSU plan”)

Restricted Share unit (“RSU”) grants under the RPSU plan

Obsidian Energy awards RSU grants under the RPSU plan whereby employees receive consideration that fluctuates based on the Company’s share price on the TSX. Consideration can be in the form of cash or shares purchased on the open market or issued from treasury.

	Year ended December 31
RSUs<br><br><br>(number of shares equivalent)	2020			2019
Outstanding, beginning of year	****	1,100,278	****		1,235,202
Granted	****	1,818,840	****		971,916
Vested	****	(510,738	)		(574,706	)
Forfeited	****	(52,972	)		(532,134	)
Outstanding, end of year	****	2,355,408	****		1,100,278

The fair value and weighted average assumptions of the RSUs granted during the year were as follows:

	Year ended December 31
	2020		2019
Average fair value of units granted (per unit)	$	0.55	$	2.77
Expected life of units (years)	****	3.0		3.0
Expected forfeiture rate	****	0.6%		1.0%

Performance Share Unit (“PSU”) grants under the RPSU plan

The RPSU plan allows Obsidian Energy to grant PSUs to employees of the Company. Members of the Board of Directors are not eligible for the RPSU plan. The PSU obligation is classified as a liability due to the cash settlement feature and could be settled in cash or shares purchased on the open market or issued from treasury.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  33
	Year ended December 31
---	---	---	---	---	---	---
PSUs (number of shares equivalent)	2020			2019
Outstanding, beginning of year	****	92,424	****		163,129
Granted	****	376,310	****		144,211
Vested	****	(10,716	)		(22,929	)
Forfeited	****	(4,173	)		(191,987	)
Outstanding, end of year	****	453,845	****		92,424

The liability associated with the PSU’s under the RPSU plan was insignificant at both December 31, 2020 and 2019.

Stock Option Plan

Obsidian Energy has an Option Plan that allows the Company to issue options to acquire common shares to officers, employees, directors and other service providers.

	Year ended December 31
	2020					2019
Options	Number of<br>Options			WeightedAverage<br>Exercise Price		Number of<br>Options			Weighted<br>Average<br>Exercise Price
Outstanding, beginning of year	****	89,178	****	$	10.41		287,996		$	25.34
Granted	****	917,490	****	****	0.56		—			—
Forfeited	****	(44,714	)	****	12.06		(198,818	)		32.04
Outstanding, end of year	****	961,954	****	$	0.94		89,178		$	10.41
Exercisable, end of year	****	44,464	****	$	8.74		77,066		$	10.67

The fair value and weighted average assumptions of the options granted during the year were as follows:

	Year ended December 31
	2020		2019
Average fair value of options granted (per option)	$	0.29	$	—
Expected volatility	****	83.6%		—
Expected life of options (years)	****	3.25		—
Expected forfeiture rate	****	0.6%		—

Deferred Share Unit (“DSU”) plan

The DSU plan allows the Company to grant DSUs in lieu of cash fees to non-employee directors providing a right to receive, upon retirement, a cash payment based on the volume-weighted-average trading price of the common shares on the TSX. At December 31, 2020, 2,087,580 DSUs (2019 – 847,100) were outstanding and $1.9 million was recorded as a current liability (2019 – $0.7 million).

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  34

Share-based compensation

Share-based compensation consisted of the following:

	Year ended December 31
	2020		2019
RSU grants	$	2.0	$	4.5
DSU plan	****	1.2		0.1
PSU grants	****	0.1		—
Options	****	0.1		—
Share-based compensation	$	3.4	$	4.6

The share price used in the fair value calculation of the DSU and RPSU plan obligations at December 31, 2020 was $0.87 per share (2019 – $0.93).

Employee retirement savings plan

Obsidian Energy has an employee retirement savings plan (the “savings plan”) for the benefit of all employees. Under the savings plan, employees may elect to contribute up to 10 percent of their salary and Obsidian Energy matches these contributions at a rate of $1.00 for each $1.00 of employee contribution. Both the employee’s and Obsidian Energy’s contributions are used to acquire Obsidian Energy common shares or are placed in low-risk investments. Shares are purchased in the open market at prevailing market prices.

Effective May 1, 2020, due to the low commodity price environment, the Company temporarily suspended the employer match portion of the savings plan, until further notice.

15. Per share amounts

The number of incremental shares included in diluted earnings per share is computed using the average volume-weighted market price of shares for the period. In addition, contracts that could be settled in cash or shares are assumed to be settled in shares if share settlement is more dilutive.

	Year ended December 31
	2020			2019
Net loss – basic and diluted	$	(771.7	)	$	(788.3	)

The weighted average number of shares used to calculate per share amounts is as follows:

	Year ended December 31
	2020		2019
Basic and Diluted	****	73,258,648		72,882,619

For 2020, 1.0 million shares (2019 – 0.1 million) that could be issued under the Option Plan were excluded in calculating the weighted average number of diluted shares outstanding as they were considered anti-dilutive.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  35

16. Changes in non-cash working capital increase (decrease)

	Year ended December 31
	2020			2019
Restricted cash	$	2.4	****	$	(2.4	)
Accounts receivable ^(1)^	****	22.6	****		(15.8	)
Prepaid expenses and other	****	0.6	****		—
Accounts payable and accrued liabilities ^(2)(3)^	****	(41.3	)		(30.0	)
	****	(15.7	)		(48.2	)
Operating activities	****	(6.6	)		(39.6	)
Investing activities	****	(9.1	)		(8.6	)
	$	(15.7	)	$	(48.2	)
Interest paid in cash	$	25.5	****	$	35.2
Income taxes paid (recovered) in cash	$	0	****	$	—
(1)	At December 31, 2020, $nil is related to assets classified as held for sale (2019 - $3.9 million).<br>
---	---
(2)	At December 31, 2020, $nil is related to assets classified as held for sale (2019 - $6.0 million).<br>
---	---
(3)	Includes share-based compensation plans.
---	---

17. Capital management

Obsidian Energy manages our capital to provide a flexible structure to support capital programs, production maintenance and other operational strategies. Attaining a strong financial position enables the capture of business opportunities and supports Obsidian Energy’s business strategy of providing strong shareholder returns.

Obsidian Energy defines capital as the sum of shareholders’ equity and long-term debt. Shareholders’ equity includes shareholders’ capital, other reserves and retained earnings (deficit). Long-term debt includes bank loans and senior notes.

Management reviews Obsidian Energy’s capital structure to allow our objectives and strategies to be met. The capital structure is reviewed based on a number of key factors including, but not limited to, current market conditions, hedging positions, trailing and forecast debt to capitalization ratios, debt to Adjusted EBITDA and other economic risk factors.

The Company is subject to certain quarterly financial covenants under its secured, syndicated credit facility and the senior secured notes. These financial covenants include Senior debt and Total debt to capitalization as defined in Obsidian Energy’s lending agreements. As at December 31, 2020, the Company was in compliance with all of our financial covenants under such lending agreements.

The Company intends to continue to 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.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  36
	Year ended December 31
---	---	---	---	---	---	---
(millions, except ratio amounts)	2020			2019
Components of capital
Shareholders’ equity	$	323.1	****	$	1,092.7
Credit facility and senior secured notes	$	455.3	****	$	460.5
Ratios
Senior debt to capitalization ^(1)^	****	59	%		30	%
Total debt to capitalization ^(1)^	****	59	%		30	%
Priority debt to consolidated tangible assets<br>^(2)^	****	0	****		—
Credit facility and senior secured notes	$	455.3	****	$	460.5
Letters of credit ^(3)^	****	4.9	****		4.8
Senior debt and total debt	****	460.2	****		465.3
Total shareholders’ equity	****	323.1	****		1,092.7
Total capitalization	$	783.3	****	$	1,558.0
(1)	Not to exceed 75 percent.
---	---
(2)	Priority debt not to exceed 15% of consolidated tangible assets.
---	---
(3)	Letters of credit defined as financial under the lending agreements are included in the calculation.<br>
---	---

18. Commitments and contingencies

Obsidian Energy is committed to certain payments over the next five calendar years and thereafter as follows:

	2021		2022		2023		2024		2025		Thereafter		Total
Long-term debt ^(1)^	$	—	$	451.8	$	—	$	—	$	—	$	—	$	451.8
Transportation	****	7.1		5.4		2.9		2.5		2.1		5.6		25.6
Power infrastructure	****	6.7		3.2		—		—		—		—		9.9
Interest obligations	****	30.0		28.1		—		—		—		—		58.1
Office lease	****	10.0		10.0		10.0		10.0		0.8		—		40.8
Lease liability	****	4.9		3.5		0.8		0.2		0.1		5.0		14.5
Decommissioning liability	****	7.3		12.4		3.5		3.3		3.1		40.9		70.5
Total	$	66.0	$	514.4	$	17.2	$	16.0	$	6.1	$	51.5	$	671.2
(1)	Based on agreements signed subsequent to December 31, 2020, the 2022 figure includes<br>$395.0 million related to the syndicated credit facility and non-revolving term loan that is due for renewal in 2022 and $60.3 million of senior notes set to mature in 2022. Refer to Note 7 for further details. Historically, the Company<br>has successfully renewed its syndicated credit facility.
---	---

Obsidian Energy has an aggregate of $60.3 million in senior notes maturing in 2022. Refer to Note 7 for further details.

Obsidian Energy’s commitments relate to the following:

•	Transportation commitments relate to costs for future pipeline access.
•	Power infrastructure commitments pertain to electricity contracts.
---	---
•	Interest obligations are the estimated future interest payments related to Obsidian Energy’s debt<br>instruments.
---	---
•	Office leases pertain to total leased office space.
---	---
•	The decommissioning liability represents the inflated, discounted future reclamation and abandonment costs<br>that are expected to be incurred over the life of the properties.
---	---

The Company is involved in various litigation and claims in the normal course of business and records provisions for claims as required.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  37

In 2018, the Company fully utilized available insurance coverage relating to ongoing claims against former Penn West employees arising from the Company’s 2014 restatement of certain financial results when we were known as Penn West. A claim brought by the United States Securities and Exchange Commission (“SEC”) against Penn West was previously settled. The Company had been indemnifying two former employees pursuant to indemnity agreements in connection with the claims brought by the SEC arising out of the same restatement. In 2020, the SEC reached a settlement with the two former employees.

In 2019, the Company notified and commenced legal proceedings against the two former employees that the Company did not believe that the former employees met the criteria for indemnification, that the amounts invoiced on account of indemnification to date were in any event unreasonable, and that the Company would not be making any further advancements on account of indemnification. The preliminary application Judge ruled in favour of the two former employees. The Company appealed the preliminary application decision and was notified in late 2020 that the appeal was ruled in favour of the two former employees as well.

The Company continued to accrue for, but not pay, defense costs incurred on behalf of the two former employees and recently agreed to a settlement to pay $6.4 million of the defense costs equally over a 30-month period beginning in April 2021. As a result of the settlement, the Company will be recording a recovery of costs previously accrued in the first quarter of 2021.

19. Related-party transactions

Operating entities

The consolidated financial statements include the results of Obsidian Energy Ltd. and our wholly owned subsidiaries, notably the Obsidian Energy Partnership. Transactions and balances between Obsidian Energy Ltd. and all of our subsidiaries are eliminated upon consolidation.

Compensation of key management personnel

In 2020, key management personnel included the Interim President and Chief Executive Officer, Chief Financial Officer, Senior Vice-Presidents, Vice Presidents and the Board of Directors. The Human Resources, Governance & Compensation Committee makes recommendations to the Board of Directors who approves the appropriate remuneration levels for management based on performance and current market trends. Compensation levels of the Board of Directors are also recommended by the Human Resources, Governance & Compensation Committee of the Board. The remuneration of the directors and key management personnel of Obsidian Energy during the year is below.

	Year ended December 31
	2020		2019
Salary and employee benefits	$	4.5	$	2.2
Termination benefits	****	0		0.9
Share-based payments ^(1)^	****	1.7		1.1
	$	6.2	$	4.2
(1)	Includes changes in the fair value of PSUs, DSUs and non-cash<br>charges related to the Option Plan and RPSU plan (equity method) for key management personnel.
---	---

20. SupplementalItems

In the consolidated financial statements, compensation costs are included in both operating and general and administrative expenses. For 2020, employee compensation costs of $13.0 million (2019 - $15.7 million) were included in operating expenses and $15.7 million (2019 - $21.1 million) were included in general and administrative expenses on a gross basis.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  38

21. Government grants

The Company has received payments as part of the Canadian Emergency Wage Subsidy (“CEWS”). The CEWS allows eligible companies to receive a subsidy of employee wages, subject to a maximum. For 2020, this resulted in a benefit to the Company of approximately $3.5 million which resulted in a $2.2 million reduction to operating costs, a $0.7 million reduction to general and administrative costs and a $0.6 reduction to capital expenditures.

Additionally, in 2020 the Company received a grant allocation under the Alberta Site Rehabilitation Program (“ASRP”). These awards will allow the Company to expand our abandonment activities for wells, pipelines, facilities, and related site reclamation and thus reduce our decommissioning liability. The Company began utilization these grants during the fourth quarter of 2020 which totaled $2.2 million on a net basis. The benefit of these grants has been recorded as Government decommissioning assistance in the Consolidated Statements of Income (Loss).

22. Potential Business Combination

On September 21, 2020, the Company formally launched an offer to purchase all issued and outstanding common shares of Bonterra Energy Corp. (“Bonterra”) for consideration of two common shares of Obsidian Energy for each Bonterra common share. The offer is open until 5:00pm (Mountain Daylight Time) on March 29, 2021, unless extended, accelerated or withdrawn. The Company continues to pursue a path of consolidation within the Cardium as we focus on further enhancing our size and scale while strengthening our balance sheet and reducing debt. As a result of this offer, the Company recorded certain transaction related costs during the period.

OBSIDIAN ENERGY 2020	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  39

EX-99.4

Exhibit 99.4

SUPPLEMENTARY OIL AND GAS INFORMATION - (UNAUDITED)

The disclosures contained in this section provide oil and gas information in accordance with the U.S. standard, “Extractive Activities – Oil and Gas”. Obsidian Energy’s financial reporting is prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board.

For the years ended December 31, 2020 and 2019, Obsidian Energy has filed our reserves information under National Instrument 51-101 – “Standards of Disclosure of Oil and Gas Activities” (“NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada.

There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission (“SEC”) requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore, the difference between the reported numbers under the two disclosure standards can be material.

For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2020 and 2019 Obsidian Energy used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.

NET PROVED OIL AND NATURAL GAS RESERVES

Obsidian Energy engaged independent qualified reserve evaluator, Sproule Associates Limited (“Sproule”), to evaluate Obsidian Energy’s proved developed and proved undeveloped oil and natural gas reserves. As at December 31, 2020 and 2019, all of Obsidian Energy’s oil and natural gas reserves are located in Canada. The changes in the Company’s net proved reserve quantities are outlined below.

Net reserves include Obsidian Energy’s remaining working interest and royalty reserves, less all Crown, freehold, and overriding royalties and other interests that are not owned by Obsidian Energy.

Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that can be estimated with a high degree of certainty to be economically recoverable under existing economic and operating conditions.

Proved developed reserves are those proved reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure to put the reserves on production. Proved developed reserves may be subdivided into producing and non-producing.

Proved undeveloped reserves are those reserves that are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

Obsidian Energy cautions users of this information as the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity.

1

YEAR ENDED DECEMBER 31, 2020

CONSTANT PRICES AND COSTS

	Light and<br>Medium<br>Crude Oil<br>(mmbbl)			Heavy<br>Crude Oil<br>and<br>Bitumen<br>(mmbbl)			Natural<br>Gas<br>(bcf)			Natural Gas<br>Liquids<br>(mmbbl)			Barrels of Oil<br>Equivalent<br>(mmboe)
Net Proved Developed and<br> <br><br><br><br>Proved Undeveloped Reserves ^(1)^
December 31, 2019		46			5			143			6			82
Extensions & Discoveries		0			0			0			0			0
Improved Recovery & Infill Drilling		2			0			5			0			3
Technical Revisions		(4	)		(3	)		11			0			(5	)
Acquisitions		0			0			0			0			0
Dispositions		0			0			0			0			0
Production		(4	)		(1	)		(19	)		(1	)		(9	)
Change for the year		(6	)		(4	)		(3	)		(1	)		(11	)
December 31, 2020		40			2			140			6			70
Developed		26			2			105			4			48
Undeveloped		14			0			35			2			22
Total ^(2)^		40			2			140			6			70
(1)	Columns may not add due to rounding.
---	---
(2)	Obsidian Energy does not file any estimates of total net proved crude oil or natural gas reserves with any<br>U.S. federal authority or agency other than the SEC.
---	---

YEAR ENDED DECEMBER 31, 2019

CONSTANT PRICES AND COSTS

	Light and<br>Medium<br>Crude Oil<br>(mmbbl)			Heavy<br>Crude Oil<br>and<br>Bitumen<br>(mmbbl)			Natural<br>Gas<br>(bcf)			Natural Gas<br>Liquids<br>(mmbbl)			Barrels of Oil<br>Equivalent<br>(mmboe)
Net Proved Developed and<br> <br><br><br><br>Proved Undeveloped Reserves ^(1)^
December 31, 2018		43			5			143			6			78
Extensions & Discoveries		—			—			1			—			—
Improved Recovery & Infill Drilling		5			—			13			1			8
Technical Revisions		2			2			5			—			5
Acquisitions		—			—			—			—			—
Dispositions		—			—			—			—			—
Production		(4	)		(1	)		(19	)		(1	)		(10	)
Change for the year		3			—			—			—			4
December 31, 2019		46			5			143			6			82
Developed		31			4			102			4			57
Undeveloped		15			1			41			2			25
Total ^(2)^		46			5			143			6			82
(1)	Columns may not add due to rounding.
---	---
(2)	Obsidian Energy does not file any estimates of total net proved crude oil or natural gas reserves with any<br>U.S. federal authority or agency other than the SEC.
---	---

In both 2020 and 2019, the Company focused development activities on the Cardium area of Alberta, specifically in the Willesden Green play. In response to the low commodity price environment due to the COVID-19 pandemic, the Company deferred our second half 2020 development program which resulted in minimal capital spending. In December 2020, the Company recommenced drilling within our Cardium play.

2

CAPITALIZED COSTS

As at December 31, ($CAD millions)	2020			2019
Proved oil and gas properties	$	10,838.3		$	10,387.2
Unproved oil and gas properties		0			—
Total capitalized costs		10,838.3			10,387.2
Accumulated depletion and depreciation		(9,942.6	)		(8,708.3	)
Net capitalized costs	$	895.7		$	1,678.9

COSTS INCURRED

For the years ended December 31, ($CAD millions)	2020			2019
Property acquisition (disposition) costs<br>^(1)^
Proved oil and gas properties – acquisitions	$	0		$	—
Proved oil and gas properties – dispositions		(0.1	)		(10.7	)
Unproved oil and gas properties		0			—
Exploration costs ^(2)^		0.3			0.2
Development costs ^(3)^		56.7			102.5
Capital expenditures		56.9			92.0
Corporate acquisitions		0			—
Total expenditures	$	56.9		$	92.0
(1)	Acquisitions are net of disposition of properties.
---	---
(2)	Cost of geological and geophysical capital expenditures and costs on exploratory plays.
---	---
(3)	Includes equipping and facilities capital expenditures.
---	---

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN

The standardized measure of discounted future net cash flows is based on estimates made by Sproule of net proved reserves. Future cash inflows are computed based on constant prices and cost assumptions from annual future production of proved crude oil and natural gas reserves. Future development and production costs are based on constant price assumptions and assume the continuation of existing economic conditions. Constant prices are calculated as the average of the first day prices of each month for the prior 12-month calendar period. Deferred income taxes are calculated by applying statutory income tax rates in effect at the end of the fiscal period. Obsidian Energy is currently not cash taxable and does not expect to be based on the assumptions in the forecast period. The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.

Obsidian Energy cautions users of this information that the discounted future net cash flows relating to proved crude oil and natural gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent is arbitrary and may not reflect applicable future interest rates.

3

STANDARD MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

For the years ended December 31, ($CAD millions)	2020			2019
Future cash inflows	$	2,288		$	3,884
Future production costs		(1,108	)		(1,659	)
Future development/ abandonment costs		(586	)		(1,104	)
Undiscounted pre-tax cash flows		594			1,121
Deferred income taxes ^(1)^		0			—
Future net cash flows		594			1,121
Less 10% annual discount factor		(183	)		(289	)
Standardized measure of discounted future net cash flows	$	411		$	832
(1)	Obsidian Energy is currently not cash taxable and does not expect to be based on the assumptions in the<br>forecast period.
---	---

STANDARD MEASURE OF DISCOUNTED FUTURE NET CASH FLOW CHANGES

For the years ended December 31, ($CAD millions)	2020			2019
Standardized measure of discounted future net cash flows at beginning of year	$	832		$	826
Oil and gas sales during period net of production costs and royalties ^(1)^		(123	)		(215	)
Changes due to prices ^(2)^		(419	)		(20	)
Development costs during the period<br>^(3)^		57			103
Changes in forecast development costs<br>^(4)^		69			(88	)
Changes resulting from extensions, infills and improved recovery ^(5)^		(2	)		48
Changes resulting from discoveries<br>^(2)^		0			—
Changes resulting from acquisitions of reserves<br>^(5)^		0			—
Changes resulting from dispositions of reserves<br>^(5)^		(3	)		(4	)
Accretion of discount ^(6)^		83			83
Net change in income tax ^(7)^		0			—
Changes resulting from other changes and technical reserves revisions plus effects on timing ^(8)^		(83	)		98
Standardized measure of discounted future net cash flows at end of year	$	411		$	832
(1)	Company actual before income taxes, excluding general and administrative expenses.
---	---
(2)	The impact of changes in prices and other economic factors on future net revenue.
---	---
(3)	Actual capital expenditures relating to the exploration, development and production of oil and gas reserves.<br>
---	---
(4)	The change in forecast development costs.
---	---
(5)	End of period net present value of the related reserves.
---	---
(6)	Estimated as 10 percent of the beginning of period net present value.
---	---
(7)	The difference between forecast income taxes at beginning of period and the actual taxes for the period plus<br>forecast income taxes at the end of period.
---	---
(8)	Includes changes due to revised production profiles, development timing, operating costs, royalty rates and<br>actual prices received versus forecast, etc.
---	---

4

EX-99.5

Exhibit 99.5

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THESECURITIES EXCHANGE ACT OF 1934

I, Stephen E. Loukas, certify that:

1.	I have reviewed this annual report on Form 40-F of Obsidian Energy<br>Ltd.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state<br>a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report,<br>fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
---	---
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure<br>controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
---	---
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be<br>designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being<br>prepared;
---	---
(b)	Designed such internal control over financial reporting, or caused such internal control over financial<br>reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting<br>principles;
---	---
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that<br>occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
---	---
5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of<br>internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent function):
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over<br>financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role<br>in the issuer’s internal control over financial reporting.
---	---

Dated: March 29, 2021

/s/ Stephen E. Loukas
Stephen E. Loukas
Interim President and Chief Executive Officer

EX-99.6

Exhibit 99.6

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934

I, Peter D. Scott, certify that:

1.	I have reviewed this annual report on Form 40-F of Obsidian Energy<br>Ltd.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state<br>a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report,<br>fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
---	---
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure<br>controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
---	---
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be<br>designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being<br>prepared;
---	---
(b)	Designed such internal control over financial reporting, or caused such internal control over financial<br>reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting<br>principles;
---	---
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that<br>occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
---	---
5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of<br>internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent function):
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over<br>financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role<br>in the issuer’s internal control over financial reporting.
---	---

Dated: March 29, 2021

/s/ Peter D. Scott
Peter D. Scott
Senior Vice President and Chief Financial Officer

EX-99.7

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Obsidian Energy Ltd. (the “Company”) on Form 40-F for the year ended December 31, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Stephen E. Loukas, Interim President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of<br>1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition<br>and results of operations of the Company.
---	---
By:	/s/ Stephen E. Loukas
---	---
	Stephen E. Loukas
	Interim President and Chief Executive Officer

March 29, 2021

EX-99.8

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Obsidian Energy Ltd. (the “Company”) on Form 40-F for the year ended December 31, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Peter D. Scott, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of<br>1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition<br>and results of operations of the Company.
---	---
By:	/s/ Peter D. Scott
---	---
	Peter D. Scott
	Senior Vice President and Chief Financial Officer

March 29, 2021

EX-99.9

Exhibit 99.9

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Directors and Shareholders of Obsidian Energy Ltd.

We consent to the reference to our Firm under the caption “Experts” and to the use in this Annual Report on Form 40-F of our report dated March 26, 2021, with respect to the consolidated balance sheets of Obsidian Energy Ltd. as at December 31, 2020 and 2019, and the consolidated statements of income (loss), changes in shareholders’ equity and cash flows for each of the years in the two year period ended December 31, 2020, included in this Annual Report on Form 40-F.

/s/ Ernst & Young LLP
Calgary, Canada
March 29, 2021

EX-99.10

Exhibit 99.10

March 29, 2021

Securities and Exchange Commission (SEC)

Re:	Evaluation of the P&NG Reserves of Obsidian Energy Ltd.

(As of December 31, 2020)

We refer to our report dated February 1, 2021 entitled “Evaluation of the P&NG Reserves of Obsidian Energy Ltd. (“Obsidian Energy”) (As of December 31, 2020)” (the “Sproule Report”).

We hereby consent to the inclusion of, or incorporation by, reference of and reference to, the Sproule Report in Obsidian Energy’s:

(i)	Annual Report on Form 40-F for the year ended December 31, 2020<br>
(ii)	press release regarding 2020 year-end results;<br>
---	---

(collectively, the “Disclosure Documents”).

We have read the Disclosure Documents and have no reason to believe that there are any misrepresentations in the information contained therein that is derived from the Report, or that is within our knowledge as a result of the services performed by us in connection with the Report.

Sincerely,
Sproule Associates Limited
Original Signed by Rodney E. Fradette, P.Eng.
Rod Fradette, P.Eng.
Senior Petroleum Engineer

140 Fourth Avenue SW, Suite 900

Calgary, AB, Canada T2P 3N3

Sproule.com

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