Exhibit 99.1

OBSIDIAN ENERGY LTD.

Annual Information Form

for the year ended December 31, 2019

March 30, 2020

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	13
DIRECTORS AND EXECUTIVE OFFICERS OF OBSIDIAN ENERGY	14
AUDIT COMMITTEE DISCLOSURES	20
DIVIDENDS AND DIVIDEND POLICY	22
MARKET FOR SECURITIES	22
INDUSTRY CONDITIONS	23
RISK FACTORS	39
MATERIAL CONTRACTS	61
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	62
TRANSFER AGENTS AND REGISTRARS	62
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	62
INTERESTS OF EXPERTS	63
ADDITIONAL INFORMATION	63

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 30, 2020.

"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 3, 2020 where they evaluated one hundred percent of the crude oil, natural gas and natural gas liquids reserves of Obsidian Energy and the net present value of future net revenue attributable to those reserves effective as at December 31, 2019.

"Form 40-F" means our Annual Report on Form 40-F for the fiscal year ended December 31, 2019 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 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

(c) in relation to properties, the total area of properties in which we have an interest.

"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. The changeover date to IFRS was January 1, 2011 with retrospective adoption from January 1, 2010 onwards. For periods relating to financial years beginning on or after January 1, 2011, 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) 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 each of our gross wells; and

(c) in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we own.

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

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"Non-Resident" means: (i) a person who is not a resident of Canada for the purposes of the Tax Act; or (ii) a partnership that is not a Canadian partnership for the purposes of the Tax Act.

"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 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”) pursuant to obtaining the requisite shareholder approval.

"OPEC" means the Organization of the Petroleum Exporting Countries.

"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, references to "US$" are to United States dollars, references to "£" are to pounds sterling, and references to "€" are to Euros. On March 30, 2020, the exchange rate based on the noon rate as reported by WM/Reuters, was Cdn$1.00 equals US$0.7057.

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	m3 MMbtu	cubic metres million British thermal units
Other
AECO	the Alberta benchmark price for natural gas.
BOE or boe	barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one barrel of oil.
WTI	West Texas Intermediate, the reference price paid in United States dollars at Cushing, Oklahoma for crude oil of standard grade.
API	American Petroleum Institute.
°API	the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
psi	pounds per square inch.
MM$	million dollars.
MW	megawatt.
MWh	megawatt hour.
CO2	carbon dioxide.

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 the Appendices hereto) have been prepared in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by United States companies. Nevertheless, as part of Obsidian Energy's Form 40-F for the year ended December 31, 2019, filed with the SEC, Obsidian Energy has disclosed proved reserves quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with the U.S. Financial Accounting Standards Board, "Disclosures About Oil and Gas Producing Activities", which disclosure complies with the SEC's rules for disclosing oil and gas reserves.

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

Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of 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, 2019.

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").  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 first half 2020 capital plan; that given the current low commodity price environment, the Company expects minimal capital spending in the second half of 2020; that we will continue to monitor commodity prices and adjust our development plans accordingly; our updated syndicated credit facility and the possible reconfirmation, redetermination and term-out dates under the various scenarios; our updated senior note maturity dates under various scenarios; our expected lease payments and indemnity from the landlord going forward; our expected financial covenant relief and the applicable time frames; the details of our ongoing acquisition, disposition, farm-out and financing strategy; our dividend policy; potential impacts that the government of Alberta curtailment will have on the Company; our expectations regarding the operational and financial impact that climate change regulations in the jurisdictions in which we operate will have on us; 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

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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; our ability to continue as a going concern in the future, our forecast, based on strip pricing as of March 27, 2020, that sufficient liquidity exists under our syndicated credit facility, and our forecast that sufficient liquidity exists under situations where further potential strip price reductions occur due to a combination of excess capacity and the ability to implement additional proactive actions within our control; 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 each of our Cardium, Peace River and Viking resource plays in 2020 and additional optimization activity in 2020; 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; that our development capital spending will be minimal if these oil prices continue; that we have a flexible portfolio to manage capital expenditures through the balance of 2020 to preserve long term shareholder value;; our intention to continue to actively identify and evaluate hedging opportunities in order to reduce our exposure to fluctuations in commodity prices and protect our future cash flows and capital programs; and the nature of, effectiveness of, and benefits to be derived from, our future marketing arrangements and risk management strategies.  

With respect to forward-looking statements contained or incorporated by reference in this document, we have made assumptions regarding, among other things that: we will have the ability to continue as a going concern going forward and realize our assets and discharge our liabilities in the normal course of business; 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; the impact of regional and/or global health related events on energy demand; global energy policies going forward; that we are able to move forward through the various reconfirmation, redetermination dates with the credit facility and pay the senior notes at the new 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".

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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 not able to continue as a going concern and realize our assets and discharge our liabilities in the normal course of business; the possibility that 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;  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 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.

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.

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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 its material Subsidiaries as at the date hereof.

(1) The remaining 45% interest in Peace River Oil Partnership is owned by Winter Spark Resources, Inc., an affiliate of China Investment Corporation.

(2) Each of the entities identified in the diagram was incorporated, continued, formed or organized, as the case 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, 2019, Obsidian Energy had 184 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, 2019.

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.

Year Ended December 31, 2017

2017 Capital Expenditure Budget and Production

In January 2017, the Company announced its 2017 capital budget of $180 million (which includes $160 million in exploration and development capital and $20 million in decommissioning expenditures) and that it anticipated 2017 average production to be between 27,000 to 29,000 boe/d. In March 2017, Obsidian Energy announced it was increasing full year 2017 production guidance to 30,500 to 31,500 boe/d as a result of retaining certain assets in the outer Cardium and central Alberta that it potentially planned to sell. In August 2017, the Company reduced it full-year capital guidance to $160 million (which includes $145 million in exploration and development capital and $15 million in decommissioning expenditures) in response to sustained weak commodity prices. The Company kept its full-year production guidance unchanged at 30,500 to 31,500 boe/d.

Reduction to Senior Secured Debt

In January 2017, the Company announced that it had reduced the capacity available under its revolving syndicated bank facility to $600 million, from $1.2 billion. The reduced facility size was more appropriate for the Company after a meaningful debt reduction program throughout 2016 and a plan to fund future capital and other expenditures through funds flow from operations. This move was expected to save the Company approximately $2.5 million annually in reduced standby fees.

Board of Directors and Management Changes

In January 2017, David Dyck (Senior Vice President, Chief Financial Officer) and Gregg Gegunde (Senior Vice President, Exploration, Production & Delivery) retired from their positions and David Hendry was appointed Chief Financial Officer.

In August 2017, the Company’s Chair of the Board of Directors, Mr. Rick George, passed away. Mr. Gordon Ritchie joined the Board of Directors on December 1, 2017.

Aggregate Acquisition and Disposition Activity

In 2017, Obsidian Energy closed property dispositions for total proceeds of $110 million on properties located within British Columbia and the Swan Hills area of Alberta as well as certain royalty interests. Total production associated with the combined divestments was approximately 10,600 boe/d. The net proceeds of the dispositions were used to repay a portion of the indebtedness outstanding under our bank facility.

New Reserve-Based Credit Facility

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In May 2017, the Company transitioned to a reserve-based syndicated revolving credit facility with a group of lenders. The credit facility had a borrowing base of $550 million, less the amount of outstanding pari passu senior notes outstanding. The initial revolving period of the credit facility ended on May 17, 2018, with an additional one-year term out period, and was subject to a semi-annual borrowing base redetermination in May and November of each year.

Changes approved at the Annual General Meeting

In June 2017, in connection with the shareholder approval obtained at the annual general meeting of the Company, the Company: (i) changed its name to Obsidian Energy Ltd. and replaced its stock symbol with “OBE” on both the Toronto Stock Exchange and New York Stock Exchange; (ii) reduced the Company’s share capital for accounting purposes; and (iii) amended the restricted share unit plan to become the Restricted and Performance Share Unit Plan which allows for, among other things, the option for the Company to make payment on certain awards through the issuance of shares through treasury, purchase of shares on the open market or through payment with cash. The Company also changed the name of the partnership from Penn West Petroleum to Obsidian Energy Partnership at the same time.

SEC Lawsuit

In June 2017, the Company announced that the U.S. Securities and Exchange Commission named the Company and three of its former employees in a lawsuit filed in the U.S. District Court for the Southern District of New York. The SEC’s complaint, based on those historic practices, alleges that Penn West (now Obsidian Energy) violated statutes which include Section 10(b), 13(b), 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act of 1934 and certain related rules. The complaint requests the entry of injunctive relief preventing a reoccurrence of the practices and certain financial relief. In November 2017, the Company announced it had reached a settlement with the SEC regarding the lawsuit. Under the terms of the settlement, the Company, without admitting or denying any of the factual allegations in the SEC’s Complaint, agreed to pay a penalty of US$8.5 million. In addition, the Company was enjoined from future violations of certain provisions of U.S. securities legislation. Further details of the settlement and its consequences can be found in the Company’s press release dated November 15, 2017. The lawsuit would continue against the former Company employees named in the SEC Complaint.

NYSE – Continued Listing Standard Notification

In September 2017, the Company received notification from the NYSE that it was 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 had 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. The Company regained compliance at the close of trading on October 31, 2017 since the average closing price of its common stock for the consecutive 30 trading days ended October 31, 2017 and the closing price of its common stock on October 31, 2017 both exceeded US$1.00. For further details, see the Company’s news release dated November 1, 2017 which is available on SEDAR at www.sedar.com.

2018 Capital Expenditure Budget and Production

In November 2017, the Company announced its 2018 capital budget of $135 million which includes $86 million associated with development and existing wellbore optimization, $25 million of infrastructure and corporate capital, $10 million of decommissioning expenditures, and $14 million of capital associated with meeting the AER Directive 84 requirements for Hydrocarbon Emission Controls and Gas Conservation in the Peace River area. The capital budget would focus on the Company’s core areas of Cardium, PROP, Viking and Deep Basin. The Company’s average production guidance for 2018 was also set at 31,000 to 32,000 boe/d. The Company also announced its increased hedging levels for 2018. For further details, see the Company’s news release dated November 10, 2017 which is available on SEDAR at www.sedar.com.

Year Ended December 31, 2018

Board of Directors Changes

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

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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 its 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 its average production guidance for 2018 to 29,000 to 30,000 boe/d at that time.

NYSE – Continued Listing Standard Notification

On March 12, 2018, the Company received notification from the NYSE that it was 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 had 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. The Company regained compliance at the close of trading on April 30, 2018 since the average closing price of its common stock for the consecutive 30 trading days ended April 30, 2018 and the closing price of its common stock on April 30, 2018 both exceeded US$1.00. For further details, see the Company’s news release dated May 1, 2018 which is available on SEDAR at www.sedar.com. On September 18, 2018, the Company received notification from the NYSE again that it was not in compliance with the same continued listing standard. Under the NYSE's rules, the Company had 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. To regain compliance, the Company proposed and passed a 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 its common stock for the consecutive 30 trading days ended July 23, 2019 and the closing price of its 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.

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 its 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

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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, it was revising its 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.

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 its senior notes to temporarily amend its financial covenants for all quarters in 2019. EBITDA will be reset during this period and calculated on a rolling basis starting on January 1, 2019. The maximum for both ratios will be 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 its 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 ends, with the expiration of the term-out date of November 30, 2020. Additionally, there are two reconfirmation dates on November 19, 2019 and January 20, 2020 whereby the commencement of the term-out period may be accelerated on November 30, 2019 and January 30, 2020, respectively. If the facility is 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 its common stock for the consecutive 30 trading days ended July 23, 2019 and the closing price of its 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.

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NYSE – Continued Listing Standard Notification

On October 1, 2019, the Company received notification from the NYSE that it was 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 does not increase sufficiently by the deadline to meet the continued standards requirements, the Company will not take further steps to regain compliance and expects the NYSE will commence with de-listing procedures.

Strategic Alternatives

On September 10, 2019, the Company publicly announced that the Board had determined that it is in the best interests of the Company and its stakeholders to initiate a formal process to explore strategic alternatives. The process is 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 plan of $49 million to fund the continued drilling of the remaining nine wells in its 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.

2020 Developments

Syndicated Credit Facility

On February 28, 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 is $550 million and $450 million, respectively. Additionally, the following terms were noted under the amending agreement:

· The revolving period ends on May 31, 2021 with a term-out period of November 30, 2021;

· There will be no borrowing base redetermination on May 31, 2020, the next scheduled borrowing base redetermination will occur on November 30, 2020; and

· A re-confirmation date on June 22, 2020 at which point, the banking syndicate has the option of accelerating the term-out period to April 1, 2021.

Senior Notes Agreement

On March 15, 2020, the Company announced that it 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 are as follows:

· the senior notes maturing on March 16, 2020, May 29, 2020 and December 2, 2020 will be extended to November 30, 2021;

· the senior note maturing on November 30, 2021 will remain the same;

· the senior notes maturing on December 2, 2022 and December 2, 2025 will now mature on November 30, 2021; and

· if the end date of the revolving period on the syndicated credit facility is accelerated to April 1, 2021, as described below, then the senior notes maturities will also be accelerated to that date.

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 covenants; and

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· the maximum for both the Senior Debt and Total Debt to Capitalization will be permanently increased to 75%.

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

Updated Office Lease Commitment

On March 15, 2020, the Company reached an agreement with its building landlord on renewed lease terms for its Calgary office space. The effective date of these terms is 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 million on an annualized basis); and

· the building landlord has agreed to indemnify the Company on all existing subleases.

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

Updated 2020 Outlook

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

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 its 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, its 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 its 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

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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.

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 30, 2020, 73,022,321 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.

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Senior Notes

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.

Series	Currency / Principal Amount	Interest Rate	Issue Date	Maturity Date
Series G	US$4 million	6.40%	May 29, 2008	November 30, 2021
Series S	US$10 million	5.85%	March 16, 2010	November 30, 2021
Series X	US$13 million	4.88%	December 2, 2010 and January 4, 2011	November 30, 2021
Series Y	US$6 million	4.98%	December 2, 2010	November 30, 2021
Series Z	US$2 million	5.23%	December 2, 2010 and January 4, 2011	November 30, 2021
Series EE	US$12 million	4.79%	November 30, 2011	November 30, 2021

Credit Facility

The Company has a reserve-based syndicated credit facility, with an underlying borrowing base of $550 million and an amount available to draw totalling $450 million. The revolving period of the syndicated credit facility ends on May 31, 2021, with a term out period of November 30, 2021, and is subject to a semi-annual borrowing base redetermination in May and November of each year.

Additional Information

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, 2017, Year Ended December 31, 2018, Year Ended December 31, 2019 and 2020 Development" in this Annual Information Form, Note 7 to our audited consolidated financial statements for the year ended December 31, 2019 (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 30, 2020, 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 and Country of Residence Positions and Offices Held with Obsidian Energy Principal Occupations
during the Five Preceding Years

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Name, Province and Country of Residence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five Preceding Years
John Brydson(1)(3) Connecticut, United States	Director since June 4, 2014	Private investor since 2012. From 2010 until the end of 2012, Chairman of Hestan Consulting Group, a full-service management consulting firm that he founded. Prior thereto, a Managing Director with Credit Suisse First Boston (now Credit Suisse).
Raymond Crossley(1)(2) Alberta, Canada	Director since March 6, 2015	Corporate director, and serves on the boards of Stuart Olson Ltd., Alberta Securities Commission and Canada West Foundation.  Mr. Crossley is also the Chief Financial Officer of the Calgary Health Trust. 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.
Michael J. Faust(3)(4) Alaska, USA	Director since May 11, 2018 Appointed Interim President and Chief Executive Officer from March 2019 to December 5, 2019	A consultant with Quartz Geophysical LLC, director of SAExploration Holdings, Inc., and 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 Science degree in Geology from the University of Washington in 1981.
William A. Friley(2)(3) 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. (as the Chairman), 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) 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.  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 and financial controls, environment, health and safety, and project management.  Is also a director of Enerflex

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Name, Province and Country of Residence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five Preceding Years
		Ltd. and serves on the Dean’s Advisory Board of Dean of Medicine at the University of Calgary.  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.
Edward H. Kernaghan(2)(3) Ontario, Canada	Director since January 3, 2018	Mr.  Kernaghan holds a Master of Science Degree from the University of Toronto.  He is Senior Investment Advisor of Kernaghan & Partners Ltd., a brokerage firm.  Mr. Kernaghan is also President of Principia Research Inc., a research and investment company, and of Kernwood Ltd., an investment holding company.
Stephen E. Loukas(4) New York, USA	Director since May 11, 2018 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 Credit Suisse Securities where he was a Portfolio Manager and Head of Investment Research of the Multi-Product Event Proprietary Trading Group, and at Pirate Capital where he was a senior investment analyst and worked within the Corporate Finance & Distribution Group of Scotia Capital.  He has a B.A. in Finance and Accounting from New York University.
Gordon Ritchie(4) Alberta, Canada	Chairman of the Board and Director since December 1, 2017	Retired as Vice Chairman of RBC Capital Markets April 1, 2016 after 37 years with RBC.  Previously, Mr. Ritchie served as Managing Director and Head of RBC’s Global E&P Energy Group, from 2000 to 2005; spent six years in New York where he served as President and Chief Executive Officer of RBC’s U.S. Broker/Dealer, RBC Dominion Securities Corporation, from 1993 to 1999; served as Managing Director of RBC’s International Corporate Finance Group based in London, England, from 1989 to 1993; and worked as Investment Banker and Energy Research Analyst in Calgary, from 1979 through 1988.
Peter Scott Alberta, Canada	Senior Vice President and Chief Financial Officer since December 2, 2019	Chief Financial Officer of Obsidian Energy since December 2019.  Mr. Scott previously held the role of Senior Vice President and Chief Financial Officer at Ridgeback Resources Inc., previously Lightstream Resources Ltd., for seven years.  Before joining Lightstream, Mr. Scott held Vice President Finance and Chief Financial Officer roles at several oil and gas companies including Iteration Energy Ltd., Rock Energy Inc., and Beau Canada Exploration Ltd.  Mr. Scott began his career with Amoco Canada Petroleum Company Ltd. in 1983.

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Name, Province and Country of Residence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five Preceding Years
Aaron Smith Alberta, Canada	Senior Vice President, Development and Operations since July 9, 2019	Mr. Smith joined the Company in July 2018 and brings over 20 years of engineering expertise across a broad range of 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 the Development and Marketing divisions and served in asset leadership roles in the Cardium area.

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.

(4) Member of the Commercial 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 7.5 million Common Shares, or approximately 10 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 trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an "Order") that was issued while the director or executive officer was acting in the capacity as director, Chief Executive Officer or Chief Financial Officer; or

(b) was subject to an Order that was issued after the director or executive officer ceased to be a director, 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 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):

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

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

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

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 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 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".

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

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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.

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

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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., 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 Stuart Olson board. Mr. Crossley is also the Chief Financial Officer of the Calgary Health Trust. The Trust 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 Policies and 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 and Ernst & Young for external audit and other services during the periods indicated.

Year	Audit Fees(1) ($)	Audit-Related Fees(2) ($)	Tax Fees(3) ($)
2019	757,900	41,340	5,800
2018	876,000	39,000	6,000

Notes:

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

(2) The aggregate fees billed in each of the last two fiscal years by our external auditor for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements (and not included in audit services fees in note (1)). The services comprising the fees disclosed under this category principally consisted of Obsidian Energy's portion of fees for the Peace River Oil Partnership audit.

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(3) The aggregate fees billed in the applicable fiscal year by our external auditor for professional services 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

In September 2015, the Board of Directors adopted a no dividend policy (effective after the 2015 third quarter payment of $0.01 per Common Share on October 15, 2015) until further notice.

Depending on the foregoing factors and any other factors that the Board deems relevant from time to time, many of which are beyond the control of our Board and management team, the Board may change our dividend policy or at any other time that the Board deems appropriate. 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 2019 as reported by the TSX and the NYSE adjusted for the 7 to 1 share consolidation approved at the June 2019 Annual General Meeting.

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	TSX
	Common Share price ($)	Common Share price ($)
Period	High	Low	Volume
January	5.18	3.43	1,904,978
February	3.71	3.05	2,189,638
March	3.71	2.56	5,851,301
April	3.64	2.42	3,264,401
May	3.15	1.93	3,846,592
June	2.23	1.32	4,347,549
July	1.56	1.17	2,052,037
August	1.77	1.25	1,548,052
September	1.73	1.10	2,752,155
October	1.12	0.77	2,391,733
November	0.91	0.51	1,951,091
December	1.14	0.60	4,185,632

	NYSE
	Common Share price ($US)	Common Share price ($US)
Period	High	Low	Volume
January	3.85	2.62	1,962,844
February	2.87	2.31	2,287,126
March	2.77	1.93	5,522,563
April	2.70	1.82	3,444,531
May	2.36	1.44	3,448,045
June	1.70	0.99	6,246,361
July	1.21	0.89	4,627,195
August	1.34	0.95	3,200,751
September	1.19	0.83	4,612,875
October	0.85	0.59	4,031,103
November	0.68	0.43	3,354,465
December	0.87	0.46	6,550,928

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 carrying on business in the crude oil and natural gas sector in Canada are subject to extensive controls and regulations imposed through legislation of the federal government and the provincial governments in the jurisdictions where the companies have assets or operations. While these regulations 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 regulations carefully. Although existing laws and regulations are a matter of public

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record, the Corporation is unable to predict what additional laws, regulations or amendments governments may enact in the future.

The Corporation holds interests in crude oil and natural gas properties, along with related assets, primarily in the Canadian province of Alberta. The Corporation's assets and operations are regulated by administrative agencies deriving authority from underlying legislation enacted by the applicable level of government. Regulated aspects of the Corporation's upstream crude oil and natural gas business include all manner of activities associated with the exploration for and production of crude oil and natural gas, including, among other matters: (i) permits for the drilling of wells; (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; (vi) storage, injection and disposal of substances associated with production operations; (vii) consultation with aboriginal groups; and (viii) the abandonment and reclamation of impacted sites. In order to conduct crude 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 discussion below outlines certain pertinent conditions and regulations that impact the crude oil and natural gas industry in Western Canada, particularly in the province of Alberta where substantially all of the Corporation's reserves and resources were located at December 31, 2019.

Pricing and Marketing in Canada

Crude Oil

Producers of crude oil are entitled to negotiate sales contracts directly with crude oil purchasers. As a result, macroeconomic and microeconomic market forces determine the price of crude oil. Worldwide supply and demand factors are the primary determinant of crude oil prices; however, regional market and transportation issues also influence prices. The specific price depends, in part, on crude oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, supply/demand balance and contractual terms of sale.

Natural Gas

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

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. 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.

Exports from Canada

On August 28, 2019, Bill C-69 came into force, replacing, among other things, the National Energy Board Act (the "NEB Act") with the Canadian Energy Regulator Act (Canada) (the "CERA"), and replacing the National Energy Board (the "NEB") with the Canadian Energy Regulator ("CER"). The CER has assumed the NEB's responsibilities, including with respect to the export of crude oil, natural gas and NGLs from Canada. The legislative regime relating to exports of crude oil, natural gas and NGL from Canada has not changed substantively under the new regime.

Exports of crude oil, natural gas and NGLs from Canada are subject to the CERA and remain subject to the National Energy Board Act Part VI (Oil and Gas) Regulation (the "Part VI Regulation"). While the Part VI Regulation was enacted under the

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NEB Act, it will remain in effect until 2022, or until new regulations are made under the CERA. The CERA and the Part VI Regulation authorize crude oil, natural gas and NGLs exports under either short-term orders or long-term licences. For natural gas, the maximum duration of an export licence is 40 years; for crude oil and other gas substances (e.g. NGLs), the maximum term is 25 years. To obtain a crude oil export licence, a mandatory public hearing with the CER is required; however, there is no public hearing requirement for the export of natural gas and NGLs. Instead, the CER will continue to apply the NEB's written process that includes a public comment period for impacted persons. Following the comment period, the CER completes its assessment of the application and either approves or denies the application. The CER can approve an application if it is satisfied that proposed export volumes are not greater than Canada's reasonably foreseeable needs, and if the proposed exporter is in compliance with the CERA and all associated regulations and orders made under the CERA. Following the CER's approval of an export licence, the federal Minister of Natural Resources is mandated to give his or her final approval. While the Part VI Regulation remains in effect, approval of the cabinet of the Canadian federal government ("Cabinet") is also required. The discretion of the Minister of Natural Resources and Cabinet will be framed by the Minister of Natural Resources' mandate to implement the CERA safely and efficiently, as well as the purpose of the CERA, to effect "oil and natural gas exploration and exploitation in a manner that is safe and secure and that protects people, property and the environment".

The CER also has jurisdiction to issue orders that provide a short-term alternative to export licences. Orders may be issued more expediently, since they do not require a public hearing or approval from the Minister of Natural Resources or Cabinet. Orders are issued pursuant to the Part VI Regulation for up to one or two years depending on the substance, with the exception of natural gas (other than NGLs) for which an order may be issued for up to twenty years for quantities not exceeding 30,000 m³ per day.

As to price, 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.

As discussed in more detail below, one major constraint to the export of crude oil, natural gas and NGLs outside of Canada is the deficit of overall pipeline and other transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline and other transportation projects are underway, many contemplated projects have been cancelled or delayed due to regulatory hurdles, court challenges and economic and other socio-political factors. The transportation capacity deficit is not likely to be resolved quickly. Major pipeline and other transportation infrastructure projects typically require a significant length of time to complete once all regulatory and other hurdles have been cleared. In addition, production of crude oil, natural gas and NGLs in Canada is expected to continue to increase, which may further exacerbate the transportation capacity deficit.

Transportation Constraints and Market Access

Pipelines

Producers negotiate with pipeline operators (or other transport providers) to transport their products to market on a firm or interruptible basis. 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 that can be reached in a cost-effective manner and the price received. Due to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low commodity pricing relative to other markets in the last several years.

Under the Canadian constitution, interprovincial and international pipelines fall within the Federal government's jurisdiction and require a regulatory review and approval by Cabinet. However, recent years have seen a perceived lack of policy and regulatory certainty at a federal level. The federal government amended the federal approval process with the CER, which aims to create efficiencies in the project approval process while upholding stringent environmental and regulatory standards. However, as the CER has not yet undertaken a major project approval, it is unclear how the new regulator operates compared to the NEB and whether it will result in a more efficient approval process. The lack of regulatory certainty is likely to influence investment decisions for major projects. Even when projects are approved on a federal level, such projects often face further delays due to interference by provincial and municipal governments. Additional delays causing further uncertainty result from 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

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United States face additional unpredictability as such pipelines require approvals of several levels of government in the United States.

In the face of this regulatory uncertainty, the Canadian crude oil and natural gas industry has experienced significant difficulty expanding the existing network of transportation infrastructure for crude oil, natural gas and NGLs, including pipelines, rail, trucks and marine transport. Improved access to global markets through the Midwest United States and export shipping terminals on the west coast of Canada could help to alleviate downward pressure on commodity prices. Several proposals have been announced to increase pipeline capacity from Western Canada to Eastern Canada, the United States, and other international markets via export terminals. While certain projects are proceeding, the regulatory approval process and other factors related to transportation and export infrastructure have led to the delay, suspension or cancellation of a number of pipeline projects.

With respect to the current state of the transportation and exportation of crude oil from Western Canada to domestic and international markets, the Enbridge Line 3 replacement from Hardisty, Alberta, to Superior, Wisconsin, formerly expected to be in-service in late 2019, continues to experience permitting difficulties in the United States and is now expected to be in-service in the latter half of 2020. The Canadian portion of the replaced pipeline began commercial operation on December 1, 2019.

The Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of sustained political opposition in British Columbia, the federal government purchased the Trans Mountain Pipeline from Kinder Morgan Cochin ULC in August 2018. However, the Trans Mountain Pipeline expansion experienced a setback when, in August 2018, the Federal Court of Appeal identified deficiencies in the NEB's environmental assessment and the Government's Indigenous consultations. The Court quashed the accompanying certificate of public convenience and necessity and directed Cabinet to correct these deficiencies. On June 18, 2019, Cabinet re-approved the Trans Mountain Pipeline expansion and directed the NEB to issue a certificate of public convenience and necessity for the project. Ongoing opposition by Indigenous groups continues to affect the progress of the Trans Mountain Pipeline. Along with its approval of the expansion, the federal government also announced the launch of the first step of a multi-step process of engagement with Indigenous groups for potential Indigenous economic participation in the pipeline. Following a public comment period initiated after the approval, the NEB ruled that NEB decisions and orders issued prior to the Federal Court of Appeal decision quashing the original Certificate of Public Convenience and Necessity will remain valid unless the CER (having replaced the NEB) decides that relevant circumstances have materially changed, such that there is a doubt as to the correctness of a particular decision or order. Construction commenced on the Trans Mountain Pipeline in late 2019 and is proceeding concurrently alongside CER hearings with landowners and affected communities to determine the final route for the pipeline.

In December 2019, the Federal Court of Appeal heard a judicial review application brought by six Indigenous applicants challenging the adequacy of the federal government's further consultation on the Trans Mountain Pipeline expansion. Two First Nations subsequently withdrew from the litigation after reaching a deal with Trans Mountain. On February 4, 2020, the Federal Court of Appeal dismissed the remaining four appellants' application for judicial review, upholding Cabinet's second approval of the Trans Mountain Pipeline expansion from June 2019.

In addition, on April 25, 2018, the British Columbia Government submitted a reference question to the British Columbia Court of Appeal, seeking to determine whether it has the constitutional jurisdiction to amend the Environmental Management Act (the "BC EMA") to impose a permitting requirement on carriers of heavy crude within British Columbia. The British Columbia Court of Appeal answered the reference question unanimously in the negative, and on January 16, 2020, the Supreme Court of Canada heard the Attorney General of British Columbia's appeal. The Supreme Court of Canada unanimously dismissed the appeal and adopted the reasons of the British Columbia Court of Appeal.

While it was expected that construction on the Keystone XL Pipeline, owned by the Canadian company TC Energy Corporation ("TC Energy"), would commence in the first half of 2019, pre-construction work was halted in late 2018 when a United States Federal Court Judge determined the underlying environmental review was inadequate. The United States Department of State issued its final Supplemental Environmental Impact Statement in late 2019, and in January 2020, the United States Government announced its approval of a right-of-way that would allow the Keystone XL Pipeline to cross 74 kilometers of federal land. TC Energy announced in January 2020 that it plans to begin mobilizing heavy equipment for pre-construction work in February 2020, and that work on pipeline segments in Montana and South Dakota will begin in August 2020. Nevertheless, the Keystone XL pipeline remains subject to legal and regulatory barriers. In December 2019, a federal judge in Montana rejected the United States Government's request to dismiss a lawsuit by Native American tribes attempting to block required pipeline permits. The

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tribes claim that a permit issued in March 2019 would allow the pipeline to disturb cultural sites and water supplies in violation of tribal laws and treaties. Furthermore, the 1.9-kilometer long segment of the pipeline that will cross the Canada-United States Border remains dependant on the receipt of a grant of right-of-way and temporary use permit from the United States Bureau of Land Management and other related federal land authorizations.

Marine Tankers

Bill C-48 received royal assent on June 21, 2019, enacting the Oil Tanker Moratorium Act, which imposes a ban on tanker traffic transporting certain crude oil and NGLs products in excess of 12,500 metric tones to or from British Columbia's north coast. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Federal".

Crude Oil and Bitumen by Rail

On February 19, 2019, the Government of Alberta announced that it would lease 4,400 rail cars capable of transporting 120,000 bbls/day of crude oil out of the province to help alleviate the high price differential plaguing Canadian oil prices. The Alberta Petroleum Marketing Commission would purchase crude oil from producers and market it, using the expanded rail capacity to transport the marketed oil to purchasers. However, in the spring of 2019, the Government of Alberta indicated that the rail program would be cancelled by assigning the transportation contracts to industry proponents. On February 11, 2020, the Government of Alberta announced that it had sold $10.6 billion worth of crude-by-rail contracts to the private sector.

In February 2020, the federal government announced that trains hauling more than 20 cars carrying dangerous goods, including crude oil and diluted bitumen, would be subject to reduced speed limits, following two derailments that led to fires and oil spills in Saskatchewan. These reduced speed limits will remain in effect until April 1, 2020.

Natural Gas

Natural gas prices in Western Canada have also 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 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 (at times producers have received negative pricing for their natural gas production). Required repairs or upgrades to existing pipeline systems have also led to further reduced capacity and apportionment of firm access, which in Western Canada may be further exacerbated by natural gas storage limitations. However, in September 2019, the CER approved a policy change by TC Energy on its NOVA Gas Transmission Ltd. pipeline network (which carries much of Alberta's natural gas production) to give priority to deliveries into storage. The change has served to somewhat stabilize supply and pricing, particularly during periods of maintenance on the system. January 2020 has seen the narrowest price differential between Canadian and United States natural gas benchmarks since early 2019.

In addition, while a number of liquefied natural gas export plants have been proposed for the west coast of Canada, with 24 export licences issued since 2011, government decision-making, regulatory uncertainty, opposition from environmental and Indigenous groups, 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 liquefied natural gas export terminal announced a positive final investment decision to proceed with the project, which will allow LNG Canada to transport natural gas from northeastern British Columbia to the LNG Canada liquefaction facility and export terminal in Kitimat, BC, via the Coastal GasLink pipeline, which will be built and operated by TC Energy's subsidiary Coastal GasLink ("CGL") (the "CGL Pipeline"). Pre-construction activities began in November 2018, with a completion target of 2025. In late 2019, TC Energy announced that it would sell 65% of its interest in the CGL Pipeline to investment companies KKR & Co Inc. and Alberta Investment Management Corporation while remaining the pipeline operator. The transaction is expected to close in the first half of 2020. The CGL Pipeline's route was altered as a result of feedback that LNG Canada received from Indigenous groups in the area, and on May 1, 2019, the British Columbia Oil and Gas Commission (the "BC Commission") approved the current planned route for the CGL Pipeline. However, the CGL Pipeline has faced intense opposition. For example, a challenge to the approval process of the CGL Pipeline was launched in August 2018, contending that it should have been subject to federal review instead of a provincial review. In July 2019, the NEB confirmed that the CGL Pipeline was properly subject to provincial jurisdiction. In addition, protests involving the Hereditary Chiefs of the Wet'suwet'en First Nation and their supporters have caused delays of construction activities on the CGL Pipeline. Coastal Gaslink Pipeline Ltd. obtained an injunction on December 31, 2019, and enforcement of the injunction started in February 2020.

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On February 19, 2020, the British Columbia Environmental Assessment Office (the "EAO") directed CGL to re-engage and consult further with Unist'ot'en, one of the Wet'suwet'en clans opposed to the pipeline route, regarding the impacts of the pipeline on a nearby healing centre. The EAO prescribed a 30-day timeline for the completion of these consultations and CGL is permitted to continue pre-construction work in the relevant area.

In December 2019, the CER approved a 40-year export licence for the Kitimat LNG project, a proposed joint venture between Chevron Canada Limited and Woodside Energy International (Canada Limited), a subsidiary of Australian Energy Ltd. This licence remains subject to Cabinet approval, and Chevron Canada Limited has indicated that it is interested in selling its 50 percent interest in Kitimat LNG. The Woodfibre LNG Project is a small-scale LNG processing and export facility near Squamish, British Columbia. The BC Commission approved a project permit for Woodfibre LNG, a subsidiary of Singapore-based Pacific Oil and Gas Ltd. in July 2019. Pre-construction agreements for Woodfibre LNG are in the process of being finalized. A project by GNL Québec Inc. is working through the federal impact assessment process for the construction and operation of a LNG facility and export terminal located on Saguenay Fjord, an inlet which feeds into the St. Lawrence River. The Goldboro LNG project, located in Nova Scotia, proposed by Pieridae Energy Ltd., 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, and Pieridae Energy Ltd. has forecast a positive final investment decision for 2020. The Cedar LNG Project near Kitimat by Cedar LNG Export Development Ltd. is currently in the 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").

Enbridge Open Season

In early August 2019, Enbridge initiated an open season for the Enbridge mainline system, which has historically operated as a common carrier pipeline system, wherein producers could nominate volumes to ship through the pipeline. The changes that Enbridge intends to implement in the open season include the transition of the mainline system from a common carrier to a primarily contract carrier pipeline, wherein producers will have to commit to reserved space in the pipeline for a fixed term, with only 10% of available capacity reserved for nominations. As a result, 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 prior regulatory approval. Following an expedited hearing process, the CER decided to shut down the open season, citing concerns about fairness and uncertainty regarding the ultimate terms and conditions of service.

On December 19, 2019, Enbridge applied to the CER for a hearing for the right to hold an open season. Similar to the earlier open season process, several shippers continue to raise concerns around this plan. The CER is expected to establish a timeline for the process in early 2020. Interveners will have the opportunity to make written submissions, and then an oral hearing will take place later in the year. A final decision from the CER is expected in early 2021.

Curtailment

On December 2, 2018, the Government of Alberta announced that, commencing January 1, 2019, it would mandate a short-term reduction in provincial crude oil and crude bitumen production. As contemplated in the Curtailment Rules, as amended effective October 1, 2019and thereafter, the Government of Alberta, on a monthly basis, subjects crude oil and bitumen producers producing more than 20,000 bbls/d, on a gross basis, to curtailment orders that limit their production according to a pre-determined formula that allocates production limits proportionately amongst all operators subject to curtailment orders.

Where an operator to whom a curtailment order applies is a joint venture or partnership, the partners or joint venturers may enter into an agreement respecting the allocation of the combined production among themselves to comply with the curtailment order.

Curtailment first took effect on January 1, 2019, limiting province-wide production of crude oil and crude bitumen to 3.56 million bbls/d. The curtailment rate dropped gradually over the course of 2019 as a result of decreasing price differentials and volumes of crude oil and crude bitumen in storage. Allowable production for December 2019 to April 2020, inclusive, was set at 3.81 million bbls/d.

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The Government of Alberta introduced certain policy changes to the curtailment program in late 2019, including giving the Minister of Energy the power to set revised production limits for a producer following a merger or acquisition, and creating an exemption for newly drilled conventional oil wells. Furthermore, the Government of Alberta created a special production allowance, effective October 28, 2019, that allows crude oil production in excess of a curtailment order, provided that the extra production is shipped out of Alberta by rail.

Curtailment volumes affect sixteen of over 300 producers in Alberta. The Curtailment Rules are set to be repealed by December 31, 2020.

The Corporation is currently subject to a curtailment order. Given that new wells are exempt from the Curtailment Rules, our production volumes and capital spending are currently not materially affected by the order.

The North American Free Trade Agreement and Other Trade Agreements

NAFTA / USMCA

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico came into force on January 1, 1994. The three NAFTA signatories have been working towards replacing NAFTA. On November 30, 2018, Canada, Mexico, and the United States signed a new trade agreement, widely referred to as the United States Mexico Canada Agreement (the "USMCA"). Legislative bodies in the three signatory countries must ratify the USMCA before it comes into force. Mexico's senate ratified the USMCA in June 2019. In late December 2019, the United States' House of Representatives approved the USMCA, and the USMCA received approval from the United States Senate on January 16, 2020. On January 29, 2020, the Government of Canada tabled Bill C-4 to ratify the USMCA. According to Bill C-4, the USMCA will come into force two months after the House of Commons and the Senate pass Bill C-4, which occurred on March 13, 2020. Until then, NAFTA remains the North American trade agreement in force. As the United States remains Canada's primary trading partner and the largest international market for the export of crude oil, natural gas and NGLs from Canada, the implementation of the final ratified version of the USMCA could have an impact on Western Canada's crude oil and natural gas industry at large, including the Corporation's business.

Under the terms of NAFTA's Article 605, a proportionality clause prevents Canada from implementing policies that limit exports to the United States and Mexico, relative to the total supply produced in Canada. Canada remains free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of Canada as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply. Further, all three signatory countries are prohibited from imposing a minimum or maximum price requirement on exports (where any other form of quantitative restriction is prohibited) and imports (except as permitted in the enforcement of countervailing and anti-dumping orders and undertakings). NAFTA also requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of such changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements.

The Government of Alberta's curtailment program complies with NAFTA's Article 605, under which Canada must make available a consistent proportion of the crude oil and bitumen produced to the other NAFTA signatories. As a result of the proportionality rule, reducing Canadian supply reduced the required offering under NAFTA, with the result that the amount of crude oil and bitumen that Canada is required to offer, while Canadian crude oil prices are depressed, may be reduced. It is likely that the USMCA will come into force before the Government of Alberta's curtailment order is set to be repealed by the end of 2020.

The USMCA does not contain the proportionality rules of NAFTA's Article 605. The elimination of the proportionality clause removes a barrier in Canada's transition to a more diversified export portfolio. While diversification depends on the construction of infrastructure allowing more Canadian production to reach Eastern Canada, Asia, and Europe, the USMCA may allow for greater export diversification than currently exists under NAFTA.

Other Trade Agreements

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Canada has also pursued a number of other international free trade agreements with other countries around the world. As a result, a number of free trade or similar agreements are in force between Canada and certain other countries while in other circumstances Canada has been unsuccessful in its efforts.

Canada and the European Union recently agreed to the Comprehensive Economic and Trade Agreement ("CETA"), which provides for duty-free, quota-free market access for Canadian crude oil and natural gas products to the European Union. Although CETA remains subject to ratification by 14 of the 28 national legislatures in the European Union, provisional application of CETA commenced on September 21, 2017. In light of the United Kingdom's departure from the European Union on January 31, 2020, the United Kingdom and Canada are expected to work towards a new trade agreement through the 11-month implementation period, during which the United Kingdom will transition out of the European Union. As such, CETA will remain in place until December 31, 2020.

Canada and ten other countries have agreed on the text of the Comprehensive and Progressive Agreement for Trans-Pacific Partnership ("CPTPP"), which is intended to allow for preferential market access among the countries that are parties to the CPTPP. The CPTPP is in force among the first seven countries to ratify the agreement – Canada, Australia, Japan, Mexico, New Zealand, Vietnam, and Singapore.

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

Land Tenure

The respective provincial governments (i.e. the Crown) predominantly own the mineral rights to crude oil and natural gas located in Western Canada, with the exception of Manitoba (which only owns 20% of the mineral rights). Provincial governments grant rights to explore for and produce crude oil and natural gas pursuant to leases, licences and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. The provincial governments in Western Canada's provinces conduct regular land sales where crude oil and natural gas companies bid for leases to explore for and produce crude oil and natural gas pursuant to mineral rights owned by the respective provincial governments. Oil and natural gas leases generally have a fixed term; however, a lease may generally be continued after the initial term where certain minimum thresholds of production have been reached, all lease rental payments have been paid on time, and other conditions are satisfied.

To develop crude oil and natural gas resources, it is necessary for the mineral owner to have access to the surface lands as well. Each province has developed its own process for obtaining surface access to conduct operations that operators must follow throughout the lifespan of a well, including notification requirements and providing compensation for affected persons for lost land use and surface damage.

Each 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 lease or licence. 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 licences.

In addition to Crown ownership of the rights to crude oil and natural gas, private ownership of crude oil and natural gas (i.e. freehold mineral lands) also exists in Western Canada. In the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, approximately 19%, 6%, 20% and 80%, respectively, of the mineral rights are owned by private freehold owners. Rights to explore for and produce such crude 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 crude oil and natural gas explorers and producers.

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 ("IOGC"), which is a federal government agency, manages subsurface and surface leases, in consultation with the applicable Indigenous peoples, for exploration and production of crude oil and natural gas on Indigenous reservations.

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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 (the "1995 Regulations"). 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. At a high level, the Modernized IOGA and the 2019 Regulations govern both surface and subsurface IOGC leases, establishing the terms and conditions with which an IOGC leaseholder must comply. The two enactments also establish a substitution system whereby provincial oil and natural gas/environmental regulatory authorities act on behalf of the federal government to ensure greater symmetry between federal and provincial regulatory standards. The Corporation does not have operations on Indian reserve lands.

Royalties and Incentives

General

Each province has legislation and regulations that govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oil sands projects and crude oil, natural gas and NGLs production. Royalties payable on production from lands where the Crown does not hold the mineral rights are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by provincial regulation and are generally calculated as a percentage of the value of gross production at the well level. The rate of royalties payable typically depends in part on prescribed reference prices, well productivity, geographic location, field discovery date, method of recovery and the type or quality of the petroleum substance produced.

Occasionally, the governments of Western Canada's provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are often introduced when commodity prices are low to encourage exploration and development activity. In addition, such programs may be introduced to encourage producers to undertake initiatives using new technologies that may enhance or improve recovery of crude oil, natural gas and NGLs.

The federal government also announced in late 2018 that it would make $1.6 billion available to the oil and natural gas industry in light of worsening commodity price differentials. The aid package has been administered through federal agencies including the Business Development Bank of Canada, Natural Resources Canada, Export Development Canada, and Innovation, Science and Economic Development Canada. Export Development Canada has lent or guaranteed a total of $629 million to 37 companies, of $1 billion available to oil and natural gas producers. The Bank of Canada has made 892 loans totaling $207.5 million out of its $500-million commercial loan allotment in the aid package. Innovation, Science and Economic Development Canada announced $49 million each for two projects to help Alberta companies building facilities to turn propane into polypropylene, a type of plastic not currently produced in Canada, but often used in packaging and labels. Natural Resources Canada distributed $37 million of a $50-million commitment under its Clean Growth Program for nine projects that help oil and natural gas companies reduce their carbon footprints.

In response to the recent dramatic decline in crude oil prices arising as a result of sharply decreased demand for crude oil due to the COVID-19 pandemic, the inability of OPEC and Russia to agree on crude oil production output constraints, and certain OPEC member countries beginning to discount prices on future crude oil deliveries and increase crude oil supply in to the market, the Alberta government has announced tax relief and other measures to assist the Alberta oil and gas industry. In addition, the federal government of Canada is reported to be preparing a multibillion dollar assistance program for Canada's oil and gas sector, which may include access to credit and funding to clean up abandoned oil and gas wells. The details of these assistance programs are not all available at this time and we are therefore unable to predict if and to what extent we will be able to access assistance under these programs and their impact on us.

Producers and working interest owners of crude oil and natural gas rights may also carve out additional royalties or royalty-like interests through non-public transactions, which include the creation of instruments such as overriding royalties, net profits interests and net carried interests.

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Alberta

In Alberta, provincially set royalty rates apply to Crown-owned mineral rights. In 2016, the Government of Alberta adopted a modernized royalty framework (the "Modernized Framework") that applies to all wells drilled after December 31, 2016. The previous royalty framework (the "Old Framework") will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years ending on December 31, 2026. After the expiry of this ten-year period, these older wells 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.

The Modernized Framework applies to all hydrocarbons other than oil sands which will remain subject to their existing royalty regime. Royalties on production from non-oil sands wells under the Modernized Framework are determined on a "revenue-minus-costs" basis with the cost component based on a Drilling and Completion Cost Allowance formula for each well, depending on its vertical depth and/or horizontal length. The formula is based on the industry's average drilling and completion costs as determined by the Alberta Energy Regulator (the "AER") on an annual basis.

Producers pay a flat royalty rate of 5% of gross revenue from each well that is subject to the Modernized Framework until the well reaches payout. Payout for a well is the point at which cumulative gross revenues from the well equals the Drilling and Completion Cost Allowance for the well set by the AER. After payout, producers pay an increased post-payout royalty on revenues of between 5% and 40% for crude oil and pentanes and 5% and 36% for methane, ethane, propane and butane, all determined by reference to the then current commodity prices of the various hydrocarbons and well flow rate. Similar to the Old Framework, the post-payout royalty rate under the Modernized Framework varies with commodity prices. Once production in a mature well drops below a threshold level where the rate of production is too low to sustain the full royalty burden, its royalty rate is adjusted downward towards a minimum of 5% as the mature well's production declines. As the Modernized Framework uses deemed drilling and completion costs in calculating the royalty and not the actual drilling and completion costs incurred by a producer, low cost producers benefit if their well costs are lower than the Drilling and Completion Cost Allowance and, accordingly, they continue to pay the lower 5% royalty rate for a period of time after their wells achieve actual payout.

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 and shortened the window during which producers can submit amendments to their royalty calculations before they become statute-barred (from four years to three years). Both the 2014 and 2015 production years became statute barred on December 31, 2018 as the pre-amendment four-year period applied for the years up to and including 2014. Going forward, producers will only have three years to amend their royalty calculations.

The Old Framework is applicable to all conventional crude oil and natural gas wells drilled prior to January 1, 2017 and bitumen production. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for conventional crude oil production under the Old Framework range from a base rate of 0% to a cap of 40%. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for natural gas production under the Old Framework range from a base rate of 5% to a cap of 36%. The Old Framework also includes a natural gas royalty formula which provides for a reduction based on the measured depth of the well below 2,000 meters deep, as well as the acid gas content of the produced gas. Under the Old Framework, the royalty rate applicable to NGLs is a flat rate of 40% for pentanes and 30% for butanes and propane. Currently, producers of crude oil and natural gas from Crown lands in Alberta are also required to pay annual rental payments, at a rate of $3.50 per hectare, and make monthly royalty payments in respect of crude oil and natural gas produced.

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

Freehold mineral taxes are levied for production from freehold mineral lands on an annual basis on calendar year production. Freehold mineral taxes are calculated using a tax formula that takes into consideration, among other things, the amount of production, the hours of production, the value of each unit of production, the tax rate and the percentages that the owners hold

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in the title. On average, in Alberta the tax levied is 4% of revenues reported from freehold mineral title properties. The freehold mineral taxes would be in addition to any royalty or other payment paid to the owner of such freehold mineral rights, which are established through private negotiation.

Freehold and Other Types of Non-Crown Royalties

Royalties on production from privately-owned freehold lands are negotiated between the mineral freehold owner and the lessee under a negotiated lease or other contract. Producers and working interest participants may also pay additional royalties to parties other than the mineral freehold owner where such royalties are negotiated through private transactions.

In addition to the royalties payable to the mineral owners (or to other royalty holders if applicable), producers of crude oil and natural gas from freehold lands in each of the Western Canadian provinces are required to pay freehold mineral taxes or production taxes. Freehold mineral taxes or production taxes are taxes levied by a provincial government on crude oil and natural gas production from lands where the Crown does not hold the mineral rights. A description of the freehold mineral taxes payable in Alberta is set out above.

Where oil and natural gas leases fall under the jurisdiction of the IOGC, the IOGC is responsible for issuing crude oil and natural gas agreements between Indigenous groups and producers, and collecting and distributing royalty revenues. The exact terms and conditions of each crude oil and natural gas lease dictate the calculation of royalties owed, which may vary depending on the involvement of the specific Indigenous group. Ultimately, the relevant Indigenous group must approve the royalty rate for each lease.

Regulatory Authorities and Environmental Regulation

General

The Canadian crude oil and natural gas industry is currently 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 crude oil and natural gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well, facility and pipeline sites. Compliance with such regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability and the imposition of material fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gas ("GHG") emissions, including carbon dioxide equivalents ("CO2e"), may impose further requirements on operators and other companies in the crude oil and natural gas industry.

Federal

Canadian environmental regulation is the responsibility of both the federal and provincial governments. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law will prevail. The federal government has primary jurisdiction over federal works, undertakings and federally regulated industries such as railways, aviation and interprovincial transport including interprovincial pipelines.

On August 28, 2019, with the passing of Bill C-69, the CERA and the Impact Assessment Act ("IAA") came into force and the NEB Act and the Canadian Environmental Assessment Act, 2012 ("CEAA 2012") were repealed. In addition, the IA Agency replaced the Canadian Environmental Assessment Agency ("CEA Agency").

Bill C-69 introduced a number of important changes to the regulatory regime for federally regulated major projects and associated environmental assessments. Previously, the NEB administered its statutory jurisdiction as an integrated regulatory body. Now, the CERA separates the CER's administrative and adjudicative functions. A board of directors and a chief executive officer will manage strategic, administrative and policy considerations while adjudicative functions will fall into the purview of a group of independent commissioners. The CER has assumed the jurisdiction previously held by the NEB over matters such as the environmental and economic regulation of pipelines, transmission infrastructure and offshore renewable energy projects,

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including offshore wind and tidal facilities. In its adjudicative role, the CERA tasks the CER with reviewing applications for the development, construction and operation of these projects, culminating in their eventual abandonment.

Designated projects will require an impact assessment as part of their regulatory review. The impact assessment, conducted by a review panel, jointly appointed by the CER and the IA Agency, includes expanded criteria the review panel may consider when reviewing an application. The impact assessment also requires consideration of the project's potential adverse effects, the overall societal impact and the expanded public interest that a project may have. The impact assessment must look at the direct result of the project's construction and operation, including environmental, biophysical and socio-economic factors,  including consideration of a gender-based analysis, climate change and impacts to Indigenous rights. Designated projects 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 greenhouse gas emissions and certain refining, processing and storage facilities will also require an impact assessment.

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. Applications for non-designated projects will follow a similar process as under the NEB Act. There is significant uncertainty surrounding the impact of Bill C-69 on oil and natural gas projects. There was significant opposition from the oil and natural gas industry and others in respect of Bill C-69, and notwithstanding its stated purpose, there is concern that the changes brought about by Bill C-69 will result in projects not being approved or increased delays in approvals. The Minister of Natural Resources has a mandate to implement the CER efficiently and effectively, but the CER's ability to expedite the project approval process has not yet been substantially tested.

On May 12, 2017, the federal government introduced Bill C-48 in Parliament. This legislation is aimed at providing coastal protection in northern British Columbia by prohibiting crude oil tankers carrying more than 12,500 metric tonnes of crude oil or persistent crude oil products from stopping, loading, or unloading crude oil in that area. Parliament passed Bill C-48 as the Oil Tanker Moratorium Act which received royal assent on June 21, 2019. The enactment of this statute may prevent pipelines from being built, and export terminals from being located on, the portion of the British Columbia coast subject to the moratorium (north of 50°53′00′′ north latitude and west of 126°38′36′′ west longitude) and, as a result, may negatively impact the ability of producers to access global markets.

Alberta

The AER is the single regulator responsible for all energy resource development in Alberta. It derives its authority from the Responsible Energy Development Act and a number of related legislation including the Oil and Gas Conservation Act (the "OGCA"), the Oil Sands Conservation Act, the Pipeline Act, and the Environmental Protection and Enhancement Act. The AER is responsible for ensuring the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as the Alberta Ministry of Energy's responsibility for mineral tenure. The objective behind a single regulator is an enhanced regulatory regime that is intended to be efficient, attractive to business and investors and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners.

The Government of Alberta relies on regional planning to accomplish its responsible 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 by incorporating the management of all resources, including energy, minerals, land, air, water and biodiversity. 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 for surface land 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’

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management approach into such plans. As a result, several regional plans have been implemented. These regional plans may affect further development and operations in such regions.

The AER monitors seismic activity across Alberta, in the context of assessing the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. Hydraulic fracturing is an important and common practice to stimulate production of oil and gas from dense subsurface rock formations. The process 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 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 the areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further.

In an ongoing process spanning between February 19, 2015 to December 9, 2019, 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 that are aimed at limiting the impact and potential of induced earthquakes from hydraulic fracturing are Fox Creek, Red Deer, and Brazeau (the "Seismic Protocol 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. The 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 oil or natural gas producers' operations while it conducts investigations following a seismic event, and only when the AER has assessed ongoing risk of earthquakes in a specific area and/or required the oil or natural gas producer to update its response plan, can operations resume. The AER may extend these requirements to other areas of Alberta if necessary, subject to the results of the AER's ongoing province-wide monitoring.

Liability Management Rating Program - Alberta

The AER administers the licensee Liability Management Rating Program (the "AB LMR Program"). The AB LMR Program is a liability management program governing most conventional upstream crude oil and natural gas wells, facilities and pipelines. It consists of three distinct programs: the Licensee Liability Rating Program (the "AB LLR Program"), the Oilfield Waste Liability Program (the "AB OWL Program") and the Large Facility Liability Management Program (the "AB LFP"). 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 AB LMR Program requires the licensee to provide the AER with a security deposit and 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"). Where the AER determines that a security deposit is required, the failure to post any required amounts may result in the initiation of enforcement action by the AER.

The AER previously assessed the LMR of all licensees on a monthly basis and posted the individual ratings on the AER's public website. However, in December 2019 the AER ceased posting the detailed LMR report, stating that resource and budget limitations have impacted its ability to maintain and administer the AB LMR Program. Licensees can continue to access their individual LMR calculations through the AER's Digital Data Submission System. The AER is currently reviewing the AB LMR Program as it no longer considers the LMR value alone to be a good indicator of a company's financial health. It is unclear if, or when, any changes will be made to the current regulatory framework. Any changes to the AB LMR Program may affect the Corporation's ability to obtain or transfer licenses.

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, including the Corporation, fund the Orphan Fund through a levy administered by the AER. A separate orphan levy applies to persons holding licences 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.

On January 31, 2019, the Supreme Court of Canada overturned the lower courts' decisions in Redwater Energy Corporation (Re) ("Redwater"), holding that there is no operational conflict between the abandonment and reclamation provisions contained in the provincial OGCA, the liability management regime administered by the AER and the federal bankruptcy and insolvency

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regime. As a result, 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 transfer when such a licensee is subject to formal insolvency proceedings. This means that insolvent estates can no longer disclaim assets of a bankrupt licensee that have reached the end of their productive lives and represent a liability and deal with the company's valuable assets for the benefit of the company's creditors, without first satisfying abandonment and reclamation obligations.

In response to the lower courts' decisions in Redwater, the AER issued several bulletins and interim rule changes to govern the AER's administration of its licensing and liability management programs. In response to Redwater's trajectory through the Courts, the AER introduced amendments to its liability management framework. The AER amended its Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, which deals with licensee eligibility to operate wells and facilities, to require the provision of extensive corporate governance and shareholder information, including whether any director and officer has been a director or officer of an energy company that has been subject to insolvency proceedings in the last five years. All transfers of well, facility and pipeline licences in the province are subject to AER approval. As a condition of transferring existing AER licences, 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 the transferee can meet its abandonment and reclamation obligations. The AER may make further rule changes at any time. The Supreme Court of Canada's Redwater decision alleviates some of the concerns that the AER's rule changes were intended to address, however the AER has indicated it is in the process of reviewing the current framework.

The AER has also implemented the Inactive Well Compliance Program (the "IWCP") to address the growing inventory of inactive wells in Alberta and to increase the AER's surveillance and compliance efforts under Directive 013: Suspension Requirements for Wells ("Directive 013"). The IWCP applies to all inactive wells that are noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive noncompliant wells under the IWCP into compliance with the requirements of Directive 013 within five years. As of April 1, 2015, each licensee is required to bring 20% of its inactive wells into compliance every year, either by reactivating or suspending the wells in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment. The list of current wells subject to the IWCP is available on the AER's Digital Data Submission System. The AER has announced that from April 1, 2015 to April 1, 2016, the number of noncompliant wells subject to the IWCP fell from 25,792 to 17,470, with 76% of licensees operating in the province having met their annual quota. From April 1, 2016 to April 1, 2017, this number fell from 17,470 to 12,375 noncompliant wells, with 81% of licensees operating in the province having met their annual quota. The IWCP will complete its fifth year on March 31, 2020 but the AER has not released subsequent annual reports on compliance levels since 2017.

As part of its strategy to encourage the decommissioning, remediation and reclamation of inactive or marginal oil and natural gas infrastructure, 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 through industry collaboration and economies of scale. Participants seeking the program incentives must commit to an inactive liability reduction target to be met through closure work of inactive assets. The program incentivizes closure activity by setting an annual spending target while providing abeyance on D13 requirements for low risk wells. The Corporation is currently participating in the voluntary ABC program.

Climate Change Regulation

Climate change regulation at both the federal and provincial level has the potential to significantly affect the future of the crude oil and natural gas industry in Canada. The impacts of federal or provincial climate change and environmental laws and regulations are uncertain. It is currently not possible to predict the extent of future requirements. 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 experiments 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. As of December 23, 2019, 187 of the 197 parties to the convention have ratified the Paris Agreement. In December 2019, the United Nations annual Conference of the Parties took place in Madrid, Spain. The Conference concluded with the attendees delaying

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decisions about a prospective carbon market and emissions cuts until the next climate conference in Glasgow in 2020. However, the European Union reached an agreement about "The European Green New Deal" that aims to lower emissions to zero by 2050.

Following the Paris Agreement and its ratification in Canada, the Government of Canada pledged to cut its emissions by 30% from 2005 levels by 2030. Further, on December 9, 2016, the Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change (the "Framework"). The Framework provided for a carbon-pricing strategy, with a carbon tax starting at $10/tonne in 2018, increasing annually until it reaches $50/tonne in 2022. This system applies in provinces and territories that request it and in those that do not have a carbon pricing system in place that meets the federal standards. 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 emissions trading system for large industry and a regulatory fuel charge imposing an initial price of $20/tonne of GHG emissions. Under current federal plans, this price will escalate by $10 per year until it reaches a price of $50/tonne in 2022. Starting April 1, 2020, the minimum price permissible under the GGPPA is $30/tonne of GHG emissions.

Six provinces and territories have introduced carbon-pricing systems that meet federal requirements: British Columbia, Quebec, Prince Edward Island, Nova Scotia, Newfoundland and Labrador, and the Northwest Territories. The federal fuel charge regime took effect in Saskatchewan, Manitoba, Ontario and New Brunswick on April 1, 2019 and in the Yukon and Nunavut on July 1, 2019. The federal fuel charge regime took effect in Alberta on January 1, 2020.

Alberta, Saskatchewan and Ontario have referred the constitutionality of the GGPPA to their respective Courts of Appeal. In both the Saskatchewan and Ontario references, the appellate Courts ruled in favour of the constitutionality of the GGPPA. The Attorneys General of Saskatchewan and Ontario have appealed these decisions to the Supreme Court of Canada and the Court was set to hear the appeals in March 2020, although the appeals have been postponed to at least June 2020 as a result of the COVID-19 pandemic. On February 24, 2020, the Alberta Court of Appeal determined that the GGPPA is unconstitutional. It is unclear whether the Alberta reference will be appealed and heard with the Saskatchewan and Ontario appeals. However, each of Saskatchewan, Ontario and Alberta will participate in the scheduled hearings, along with the Attorneys General of Quebec, New Brunswick, Manitoba and British Columbia and various other interested parties.

On April 26, 2018, the federal government passed the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Federal Methane Regulations"). The Federal Methane Regulations seek to reduce emissions of methane from the crude 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 intentional venting of methane, as well as ensuring that crude 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. These facilities would need to capture the gas and either re-use it, re-inject it, send it to a sales pipeline, or route it to a flare. In addition, in provinces other than Alberta and British Columbia (which already regulate such activities), well completions by hydraulic fracturing would be required to conserve or destroy gas instead of venting. The federal government anticipates that these actions will reduce annual GHG emissions by about 20 megatonnes by 2030.

In October 2018, the federal government announced a pricing scheme as an alternative for large electricity generators so as to incentivize a reduction in emissions intensity, rather than encouraging a reduction in generation capacity.

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

Alberta

On November 22, 2015, the Government of Alberta introduced a Climate Leadership Plan (the "CLP"). Under this strategy, the Climate Leadership Act (the "CLA") came into force on January 1, 2017 and established a fuel charge intended to first outstrip and subsequently keep pace with the federal price. On December 14, 2016, the Oil Sands Emissions Limit Act came into force, establishing an annual 100 megatonne limit for GHG emissions from all oil sands sites, excluding some attributable to upgraders, the electric energy portion of cogeneration and other prescribed emissions.

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In June 2019, the Government of Alberta pivoted in its implementation of the CLP and repealed the CLA. The Carbon Competitiveness Incentives Regime ("CCIR") remained in place. As a result, the federally imposed fuel charge took effect in Alberta on January 1, 2020, at a rate of $20/tonne. In accordance with the GGPPA, this will increase to $30/tonne on April 1, 2020. However, on December 4, 2019, the federal government approved Alberta's proposed Technology Innovation and Emissions Reduction ("TIER") regulation intended to replace the CCIR, so the regulation of emissions from heavy industry remains subject to provincial regulation, while the federal fuel charge still applies. The TIER regulation came into effect on January 1, 2020.

The TIER regulation operates differently than the former facility-based CCIR, and instead applies industry-wide to emitters that emit more than 100,000 tonnes of CO2e per year in 2016 or any subsequent year. The 2020 target for most TIER-regulated facilities is to reduce emissions intensity by 10% as measured against that facility's individual benchmark (which is, generally, its average emissions intensity during the period from 2013 to 2015), with a further 1% reduction for each subsequent year. The facility-specific benchmark does not apply to all facilities. Certain facilities, such as those in the electricity sector, are compared against the good-as-best-gas standard, which measures against the emissions produced by the cleanest natural gas-fired generation system. Similarly, for facilities that have already made substantial headway in reducing their emissions, a different "high-performance" benchmark is available to ensure that the cost of ongoing compliance takes this into account. As with the former CCIR, the TIER regulation targets emissions intensity rather than total emissions. Under the TIER regulation, facilities in high-emitting sectors can opt-in to the program despite the fact that they do not meet the 100,000 tonne threshold. A facility can opt-in to TIER regulation if it competes directly against another TIER-regulated facility or if it has annual CO2e emissions that exceed 10,000 tonnes per year and belongs to an emissions-intensive or trade exposed sector with international competition. In addition, the owner of two or more "conventional oil and gas facilities" may apply to have those facilities regulated under the TIER regulation. The Company has been accepted to the TIER program as it targets improved efficiencies and minimizes carbon tax payments. 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 previously signaled its intention through the CLP to implement regulations that would lower annual methane emissions by 45% by 2025. Pursuant to this goal, the Government of Alberta enacted the Methane Emission Reduction Regulation (the "Alberta Methane Regulations") 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 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 new Directives represent Alberta's first step toward achieving its 2025 goal, as outlined in the Alberta Methane Regulations; however, the Government of Alberta and the federal government have not yet reached an equivalency agreement with respect to the Alberta Methane Regulations and the Federal Methane Regulations.

Alberta was also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta has committed $1.24 billion through 2025 to fund two commercial-scale carbon capture and storage projects. Both projects will help reduce the CO2 emissions from the oil sands and fertilizer sectors, and reduce GHG emissions by 2.76 million megatonnes per year. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be, and to have always been, the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.

Obsidian Energy and the Environment

Obsidian Energy understands its responsibilities for reducing the environmental impacts from its operations and recognizes the interests of other land users in resource development areas and conducts its operations accordingly. Obsidian Energy is committed to mitigating the environmental impact from its 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 improvement 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.

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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, 2019, see "– Disclosure of Reserves Data – Total Future Net Revenue (Undiscounted) as of December 31, 2019 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 Technology Innovation and Emissions Reduction (“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, financial penalties are imposed. Obsidian Energy has only minor working interests in several non-operated facilities that are considered large emitters (emissions of 100,000 CO₂e per year) within the requirements of the Alberta GHG regulations. 

Obsidian 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, but unlike large emitters, this requirement does not become more stringent over time.  Further, Obsidian believes it has 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 its 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 it operates. Obsidian Energy anticipates that its expenditures, both capital and expense in nature, will continue to increase as a result of operational growth and/or increasing legislation relating to the protection of the environment. Obsidian Energy will be taking such steps as required to ensure continued compliance with applicable environmental legislation in each jurisdiction in which it operates. Obsidian Energy believes that it is currently in compliance with applicable environmental laws and regulations in all material respects. Obsidian Energy also believes that it is reasonably likely that the trend towards heightened and additional standards in environmental legislation and regulation will continue.

RISK FACTORS

The following is a summary of certain risk factors relating to Obsidian Energy and its 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 its business, nor should they be taken as a complete summary or description of all the risks associated with Obsidian Energy and its business and the oil and natural gas business generally.

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

Our results of operations and financial condition are dependent upon the prices that we receive for the oil 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

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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 COVID-19 pandemic on energy demand;

· global energy policy, including the ability of OPEC (and in particular the Kingdom of Saudi Arabia) and other oil and gas exporting nations (and in particular Russia) to set and maintain production levels and influence prices for oil. For instance, OPEC +, led by Saudi Arabia and Russia, have recently failed to reach an agreement on constraining crude oil output to support global crude oil prices in the face of lower global demand arising from, among other things, the global response to the COVID-19 pandemic, which has in turn resulted in certain OPEC member countries beginning to discount prices on future crude oil deliveries and increase crude oil supply in to the market;

· the limitations on the ability of Western Canadian energy producers to export oil, natural gas and natural gas 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;

· the availability of transportation infrastructure, and in particular:

· our ability to access space on pipelines that deliver crude oil, natural gas liquids and natural gas to commercial markets or alternatively contract for the delivery of our products by rail;

· deliverability uncertainties related to the distance of our production from existing pipeline, railway line, processing and storage facility infrastructure; and

· operational problems affecting the pipelines, railway lines and processing and storage facilities on which we rely;

· increased growth of shale oil production in the U.S.;

· production and storage levels of oil and natural gas;

· existing and threatened political instability and hostilities in commodity producing regions such as the Middle East, Northern Africa and elsewhere;

· sanctions imposed on certain oil producing nations by other countries;

· foreign supply of, and demand for, oil and natural gas, including liquefied natural gas;

· weather conditions;

· the overall economic and political environment in Canada, the U.S., Europe, China, Russia, emerging markets and globally;

· the overall level of energy demand;

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

· currency exchange rates;

· the effect of worldwide environmental and/or energy conservation measures;

· the price and availability of alternative energy supplies; and

· the advent of new technologies.

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

All these factors could result in a material decrease in the Corporation's expected net production revenue and a reduction in its 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 its 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.

Weakness and volatility in market conditions for the oil and gas industry may affect the value of the Corporation's reserves and restrict its cash flow and its ability to access capital to fund the development of its oil and 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

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arise between these countries when they compete for market share, sanctions against Iran and Venezuela, slowing growth in China and emerging economies, weakening 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 gas companies and a decrease in confidence in the oil and 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 to build pipelines, liquefied natural gas plants and other facilities to provide better access to markets for the oil and 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 gas industry in western Canada. See "Industry Conditions".

Global or national health concerns, including the outbreak of pandemic or contagious diseases, such as COVID-19 (coronavirus), may adversely affect us by (i) reducing global economic activity thereby resulting in lower demand for crude oil, NGLs and natural gas, (ii) impairing our supply chain (for example, by limiting the manufacturing of materials or the supply of services used in our operations), and (iii) affecting the health of our workforce, rendering employees unable to work or travel.

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 its 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 its 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 gas assets on its balance sheet and the recognition of an impairment charge in its income statement. Given the current market conditions and the lack of confidence in the Canadian oil and gas industry, the Corporation may have difficulty raising additional funds or if it is 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.

There is a material uncertainty that casts substantial doubt on our ability to continue as a going concern.

Our audited financial statements for the year ended December 31, 2019 have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that we will be able to realize our assets and discharge our liabilities in the normal course of business.

As at December 31, 2019, we were in compliance with all financial covenants in our bank credit facility and senior unsecured notes and had sufficient liquidity under our syndicated credit facility. Subsequent to December 31, 2019, we negotiated to eliminate our Debt to Adjusted EBITDA covenants, thus management's going concern assessment at December 31, 2019 focused on liquidity capacity over the next 12 months. Based on strip pricing as of March 27, 2020, we are currently forecasting that sufficient liquidity exists under our syndicated credit facility. Additionally, under our current forecast, sufficient liquidity exists under situations where further potential strip price reductions occur due to a combination of excess capacity and the ability to implement additional proactive actions within our control.

However, due to significant commodity price volatility currently due to the COVID-19 pandemic, potential increased production supply from OPEC and Russia and potential lack of storage forcing production shut-ins, future significant decreases to commodity prices may occur which could impact future cash flows and cause uncertainty as to whether we have sufficient liquidity throughout 2020. As a result, we may be required to obtain additional financing to increase liquidity, which is uncertain at this time. As such, there is a material uncertainty that casts substantial doubt on our ability to continue as a going concern. Our audited financial statements for the year ended December 31, 2019 do not include adjustments in the carrying values of our assets and liabilities that would be necessary if the going concern assumption were not appropriate. Such adjustments could be material.

Changing investor sentiment towards the oil and 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, governmental and public investors have announced that they no longer are willing to fund or invest in oil and 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. Developing and implementing such policies and practices 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 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 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. 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.

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

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

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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".

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".

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

From time to time, the Corporation may enter into agreements to receive fixed prices on its 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 itself from commodity price declines, it 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 it 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;

· there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the hedge arrangement;

· the counterparties to the hedging arrangements or other price risk management contracts fail to perform under those arrangements; or

· a sudden unexpected event materially impacts oil and natural gas prices.

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.

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

Under IFRS, accounting for financial instruments may result in non-cash charges against income as a result of reductions in the fair market value of 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.

Liability management programs enacted by regulators in the western provinces may prevent or interfere with the Corporation's ability 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, or other 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. In addition, the AB LMR 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 gas assets must be in compliance with the

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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 gas companies that may be disproportionately affected by price instability. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Liability Management Rating Program – Alberta".

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

Political changes in North America and political instability in the Middle East and elsewhere may cause disruptions in the supply of oil 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 and decisions made in Canada, the United States, Europe and elsewhere.

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. Alberta elected a new government in 2019 that is supportive of the Trans Mountain Pipeline expansion project. Although the Supreme Court of Canada unanimously rejected the government of British Columbia's proposed regulation of the transport of heavy oil products into and through British Columbia in January 2020, tensions remain high between provincial and federal governments. 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, some 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".

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. Since the 2016 U.S. presidential election, the American administration has withdrawn the United States from the Trans-Pacific Partnership and the United States Congress has passed sweeping tax reform, which, among other things, significantly reduces U.S. corporate tax rates. This has affected the competitiveness of other jurisdictions, including Canada. In addition, NAFTA has been renegotiated and on November 30, 2018, Canada, the U.S. and Mexico signed the Canada-United States –Mexico Agreement (or USMCA) which will replace NAFTA. See "Industry Conditions - The North American Free Trade Agreement and Other Trade Agreements". The U.S. administration has also taken action with respect to reduction of regulation, which may also affect relative competitiveness of other jurisdictions. It is unclear exactly what other actions the U.S. administration will implement, and if implemented, how these actions may impact Canada and in particular the oil and gas industry. Any actions taken by the current U.S. administration may have a negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of Canadian oil and gas companies, including the Corporation.

In addition to the political disruption in the United States, the impact of the United Kingdom's exit from the European Union remains to be determined. 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

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continues 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 its 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 the Common Shares.

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

Fuel conservation measures, alternative fuel requirements, 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 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.

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 typically 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 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 addition to owning oil and gas assets in the Brazeau area, the AER continues to monitor seismic activity around the province and may extend these requirements to other areas of the province where we own oil and gas assets. By way of example, in March 2018 and March 2019, two earthquakes felt in Red Deer and Sylvan Lake were characterized as seismic activity induced by hydraulic fracturing. In March 2019, the AER suspended operations of an oil and natural gas company in the area where the earthquake occurred, pending further investigation. In May 2019, the suspended oil and natural gas company was able to resume operations with a risk assessment plan in place that was approved by the AER. See "Industry Conditions".

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

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of Obsidian Energy depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, our existing reserves, and the production from them, will decline over time as we produce from such reserves. A future increase in our reserves will depend on both our ability to explore and develop our existing properties and on our ability to select and acquire

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suitable producing properties or prospects. There is no assurance that we will be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of Obsidian Energy may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participations uneconomic. There is also no assurance that we will discover or acquire further commercial quantities of oil and natural gas.

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

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. 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;

· the invasion of water into producing formations;

· blowouts, explosions, equipment failures and other accidents;

· sour gas releases;

· uncontrollable flows of oil, natural gas or well fluids;

· personal injury to staff and others;

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

· 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.

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

We currently have a reserve-based syndicated revolving credit facility in place that has an aggregate borrowing limit of $550 million and an amount available to draw totalling $450 million. The revolving period of the credit facility ends on May 31, 2021 with a term out period of November 30, 2021, and is subject to a semi-annual borrowing base redetermination in May and November of each year. As of December 31, 2019, there was $399 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

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at that date. The Company also has a borrowing base reconfirmation date on June 22, 2020 at which point the bank syndicate may end the revolving period on June 30, 2020 and accelerate the term out period to April 1, 2021. 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.

The amount authorized under the Corporation's credit facility is dependent on the borrowing base determined by its 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 they remain volatile as a result of various factors including sharply decreased demand for crude oil due to the COVID-19 pandemic, the inability of OPEC and Russia to agree on crude oil production output constraints, certain OPEC member countries beginning to discount prices on future crude oil deliveries and increase crude oil supply in to the market, limited egress options for Western Canadian oil and natural gas producers, and increasing production by U.S. shale producers. These and other factors have recently resulted in crude oil experiencing its largest weekly price decline since 1991. 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, 2021. If our borrowing base is not reconfirmed on June 22, 2020 by our banking syndicate, the maturity date of the Senior Notes will be accelerated to April 1, 2021. 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 may give 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 its lenders regarding its existing and/or budgeted abandonment and reclamation obligations, its decommissioning expenses, its 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 its estimated cost of compliance with such order exceeds a certain threshold. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Liability Management Rating Program - Alberta".

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 its 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.

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

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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.

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

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

Absent 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.

To the extent that 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.

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

World oil and natural gas prices are 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.

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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.

We may from time to time participate in one or more large projects and have more concentrated risks in these areas of our operations.

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;

· the availability of storage capacity;

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

· the supply of and demand for oil and natural gas;

· the availability of alternative fuel sources;

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

· the availability of drilling and related equipment;

· unexpected cost increases;

· accidental events;

· currency fluctuations;

· changes in regulations;

· 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.

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

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

Acquisitions of oil and 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 gas, future prices of oil and 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 variations could be material and negatively affect the market price of our Common Shares.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and 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;

· 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;

· royalty rates;

· the assumed effects of regulation by governmental agencies; and

· future operating costs;

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.

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

There is strong competition relating to all aspects of the oil and 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

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

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

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

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. Other oil and gas companies may have greater financial, technical and personnel

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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 thereby adversely affect our business and the market price of our Common Shares.

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable, which prevents, delays or makes operations more difficult. Consequently, municipalities and provincial transportation departments 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 its 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 to environmental claims and liability and/or increased compliance costs, all of which could affect the market price of our Common Shares.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, 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".

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 will be in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance

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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 regarding the disposal of fluids used in the Corporation's operations may increase its costs of compliance or subject it 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 the anticipated benefits of acquisitions or dispositions and the integration of acquisitions may result in the loss of key employees and the disruption of on-going business relationships.

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

Increased debt levels may impair the Corporation's ability to borrow additional capital on a timely basis to fund opportunities as they 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. Depending on future exploration and development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither our articles nor our by-laws limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise, and may adversely affect the market price of our Common Shares if investors consider our debt levels to be higher than that of our peers.

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

The oil and natural gas exploration, development and operating activities conducted by the Corporation may, at times, be subject to public opposition. Such public opposition could expose the Corporation to the risk of higher costs, delays or even project cancellations due to increased pressure on governments and regulators by special interest groups including Indigenous groups, landowners, environmental interest groups (including those opposed to oil and gas production operations) and other non-governmental organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support of 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. There is no guarantee that the Corporation will be able to satisfy the concerns of the special interest groups and non-governmental organizations and

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attempting to address such concerns may require the Corporation to incur significant and unanticipated capital and operating expenditures.

In addition, the Corporation's oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Corporation's properties, wells or facilities are the subject of 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.

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

In this Annual Information Form, we report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by United States companies. Nevertheless, as part of Obsidian Energy's Form 40-F for the year ended December 31, 2019 filed with the SEC, Obsidian Energy has disclosed proved reserves quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with the U.S. Financial Accounting Standards Board, "Disclosures About Oil and Gas Producing Activities", which disclosure complies with the SEC's rules for disclosing oil and gas reserves.

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

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

· the overall state of the capital markets;

· the Corporation's credit rating (if applicable);

· commodity prices;

· interest rates;

· royalty rates;

· tax burden due to current and future tax laws; and

· investor appetite for investments in the energy industry and the Corporation's securities in particular.

The conditions in, or affecting, the oil and gas industry have negatively impacted the ability of oil and 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 its 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 properties and 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 its ongoing activities at all times and from time to time, the Corporation may require additional financing in order to carry out its oil and natural gas acquisition, exploration and development activities. Failure to obtain financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities, and/or reduce or terminate its operations. Due to the conditions in the oil and 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 gas industry have negatively impacted the ability of oil and gas companies to access additional financing and/or increased the cost of such financing. Failure to obtain suitable

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financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations.

If the Corporation's revenues from its 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 its reserves or to maintain its 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 its 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 it would otherwise not sell.

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

We may be exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production 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.

In the normal course of our operations, we are exposed to litigation, which if determined 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.

Restrictions on the availability and cost of materials and equipment may impede the Corporation's exploration, development and operating 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.

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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.

A portion of the Corporation's revenues from royalty payers and certain of its operations are dependent on the financial and operational capacity of third-party working interest owners to develop and produce from the Corporation's properties, over which it has 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 it has 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 its assets or intellectual property or diverting the efforts of its 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

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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.

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 its 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.

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. See "Industry Conditions – Climate Change Regulation".

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 storm and fire 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.

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 its 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 its 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 November 2018, ENvironment JEUnesse, a Quebec advocacy group, applied to the Quebec Superior Court to certify all Quebecois under the age of 35 as a class in a proposed class action lawsuit against the Government of Canada for climate related matters. While the application was denied, the group has stated it plans to appeal. In January 2019, the City of Victoria became the first municipality in Canada to endorse a class action lawsuit against oil and natural gas producers for alleged climate related harms. The Union of British Columbia

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Municipalities defeated the City of Victoria's motion to initiate a class action lawsuit to recover costs it claims are related to climate change.

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 gas production resulting in a decrease in the Corporation's profitability and a reduction in the value of its assets or requiring asset impairments for financial statement purposes. See "Industry Conditions – Climate Change Regulation".

Taxes on carbon emissions affect the demand for oil and natural gas, 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 currently applies in provinces and territories without their own system that meets federal standards. The federal regime is currently subject to a number of court challenges. 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 to recruit and retain a skilled workforce and key personnel may negatively impact the Corporation.

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

Competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract and retain all personnel necessary for the development and operation of its 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 incentive plans may result in Shareholder dilution.

We may make future acquisitions or enter into financings or other transactions involving the issuance of our securities, which may be dilutive to Shareholders. Shareholder dilution may also result from the issuance of Common Shares pursuant to our

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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.

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 Supreme Court of Canada and the Federal Court of Appeal both dismissed challenges to Cabinet's approval of the Trans Mountain Pipeline expansion, 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 is increasing. In recent years, the volume of crude oil shipped by rail in North America has 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.

The federal government has adopted a new framework regarding the approval of major energy projects including infrastructure projects. On August 28, 2019, with the passing of Bill C-69, the Canadian Energy Regulator Act and the Impact Assessment Act came into force and the National Energy Board Act and the Canadian Environmental Assessment Act, 2012 were repealed. In addition, the Impact Assessment Agency of Canada replaced the Canadian Environmental Assessment Agency. 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.

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.

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

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

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

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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 could have an adverse effect on the market price of our Common Shares.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise. The actual title to and interest of the Corporation in its properties, and its 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 its right to produce 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.

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

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

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

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

The Corporation does not pay dividends and there can be 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, and other considerations as the Board considers relevant.

Our directors and management may have conflicts of interest that 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

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subject to conflicts of interest. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director must disclose his interest in such contract or agreement and must refrain from voting on any matter in respect of such contract or agreement 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 it 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.

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

The Corporation's business, operations or financial condition may be negatively impacted as a result of any negative public opinion towards the Corporation or as a result of any negative sentiment toward or in respect of the Corporation's reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups' negative portrayal of the industry in which the Corporation operates as well as their opposition to certain oil and natural gas projects. Potential impacts of negative public opinion or reputational issues may include delays or interruptions in operations, legal or regulatory actions or challenges, blockades, increased regulatory oversight, reduced support for, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses 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 try and 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 unauthorized parties.

We have become 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 and third-party partners.

As a result, we are subject to a variety of information technology and/or system risks as a part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of our information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations, or disruption to our business activities or our competitive position. In addition, cyber phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, 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

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the Corporation's financial resources or critical data and information or could result in a loss of control of the Corporation's technological infrastructure or financial resources. The Corporation's employees are often the targets of such cyber phishing attacks, as they are and will continue to be targeted by parties using fraudulent "spoof" emails to misappropriate information or to introduce viruses or other malware through "Trojan horse" programs to the Corporation's computers. These emails appear to be legitimate emails, but direct recipients to fake websites operated by the sender of the email or request recipients to send a password or other confidential information through email or to download malware.

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

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

In particular, the Corporation has at times failed to comply with the NYSE's continued listing standards. On October 1, 2019, the Corporation received notification from the NYSE that it was no longer in compliance with one of the NYSE's continued listing standards because the average closing price of the Common Shares was less than US$1.00 per share over a consecutive 30 day trading period. Under the NYSE's rules, the Corporation has a period of six months from the date of the NYSE notification to regain compliance with the NYSE's price listing standard. If at the expiration of the applicable cure period (expected to be approximately April 1, 2020) the Corporation has not regained compliance, the Corporation does not intend to take further steps to regain compliance and expects the NYSE will commence with de-listing procedures.

Although the Common Shares would continue to trade on the TSX, the delisting of the Common Shares from the NYSE could adversely impact the trading value of the Common Shares.

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

Increasingly, social media is used as a vehicle to carry out cyber phishing attacks. Information posted on social media sites, for business or personal purposes, may be used by attackers to gain entry into the Corporation's systems and obtain confidential information. The Corporation restricts the social media access of its 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

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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-Looking Statements" 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:

(a) the amended and restated credit agreement dated May 18, 2017 (as amended on May 10, 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 and March 27, 2020) among Obsidian Energy and certain lenders and other parties in respect of Obsidian Energy's $550 reserve-based loan syndicated credit facility, which agreement is described under "Capitalization of Obsidian Energy – Debt Capital – Credit Facility";

(b) the note purchase agreement dated May 29, 2008 (as amended on December 2, 2010, August 15, 2014, May 22, 2015, August 23, 2017, November 7, 2018, March 6, 2019, March 13, 2020 and March 27, 2020) among Obsidian Energy and the holders of our Series E, Series F, Series G and Series H Senior Notes, which agreement is described under "Capitalization of Obsidian Energy – Debt Capital – Senior Notes";

(c) the note purchase agreement dated March 16, 2010 (as amended on December 2, 2010, August 15, 2014, May 22, 2015, August 23, 2017, November 7, 2018, March 6, 2019, March 13, 2020 and March 27, 2020) among Obsidian Energy and the holders of our Series R, Series S, Series T and Series U Senior Notes, which agreement is described under "Capitalization of Obsidian Energy – Debt Capital – Senior Notes";

(d) the note purchase agreement dated December 2, 2010 (as amended on December 2, 2010 , August 15, 2014, May 22, 2015, August 23, 2017, November 7, 2018, March 6, 2019, March 13, 2020 and March 27, 2020) among Obsidian Energy and the holders of our Series W, Series X, Series Y, Series Z and Series BB Senior Notes, which agreement is described under "Capitalization of Obsidian Energy – Debt Capital – Senior Notes"; and

(e) the note purchase agreement dated November 30, 2011 (as amended on August 15, 2014, May 22, 2015, August 23, 2017, November 7, 2018, March 6, 2019, March 13, 2020 and March 27, 2020) among Obsidian Energy and the holders of our Series CC, Series DD, Series EE and Series FF Senior Notes, which agreement is described under "Capitalization of Obsidian Energy – Debt Capital – Senior Notes".

Copies of each of these agreements have been filed on SEDAR at www.sedar.com.

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.

62  

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

Other than 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.

Regulatory Actions

Other than 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, the independent engineering evaluator retained by us in 2018 (the "Expert"), and Ernst & Young LLP ("EY"), our auditors.

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

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.

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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 its 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 its 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 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, 2019, 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 evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

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 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 51-101F1 containing reserves data and other oil and gas information;

(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c) the content and filing of this report.

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 30, 2020

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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, 2019. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2019, estimated using forecast prices and costs.

2. The reserves data are the responsibility of Obsidian Energy's management. Our responsibility is to 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 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 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.

5. The following table sets forth the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of Obsidian Energy evaluated by us for the year ended December 31, 2019, 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:

Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)	Net Present Value of Future Net Revenue (millions before income taxes, 10% discount rate)
			Audited	Evaluated	Reviewed	Total
Sproule Associates Limited	Evaluation of the P&NG Reserves of Obsidian Energy Ltd. (As of December 31, 2019) February 3, 2020	Canada	nil	$1,602	nil	$1,602

6. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been 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.

7. We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the preparation date.

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

Executed as to our report referred to above:

(signed) "Sproule Associates Limited"
Sproule Associates Limited
Calgary, Alberta, Canada

February 3, 2020

A3-1

APPENDIX A-3

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Our statement of reserves data and other oil and gas information dated March 30, 2020 is set forth below (the "Statement"). The effective date of the Statement is December 31, 2019 and the preparation date of the Statement is March 30, 2020. 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, 2019 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, 2019, 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 the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.

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.

For more information as to the risks involved, see "Risk Factors".

SUMMARY OF OIL AND GAS RESERVES
AS OF DECEMBER 31, 2019
FORECAST PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM CRUDE OIL		HEAVY CRUDE OIL AND BITUMEN
RESERVES CATEGORY	Gross (MMbbl)	Net (MMbbl)	Gross (MMbbl)		Net (MMbbl)
PROVED
Developed Producing	34	31	5	4
Developed Non-Producing	1	1	-	-
Undeveloped	17	15	1	1
TOTAL PROVED	51	47	6	5
PROBABLE	16	13	3	3
TOTAL PROVED PLUS PROBABLE	67	60	9	8

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	RESERVES
	CONVENTIONAL NATURAL GAS		NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross (Bcf)	Net (Bcf)	Gross (MMbbl)		Net (MMbbl)
PROVED
Developed Producing	124	118	6	5
Developed Non-Producing	2	2	-	-
Undeveloped	47	44	2	2
TOTAL PROVED	173	164	8	7
PROBABLE	63	59	3	2
TOTAL PROVED PLUS PROBABLE	236	224	11	9

	RESERVES
	TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (MMboe)	Net (MMboe)
PROVED
Developed Producing	65	60
Developed Non-Producing	1	1
Undeveloped	28	26
TOTAL PROVED	94	86
PROBABLE	32	28
TOTAL PROVED PLUS PROBABLE	126	114

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2019
BEFORE INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

						Unit Value Before Income Tax Discounted at 10%/year(1)
RESERVES CATEGORY	0% (MM$)	5% (MM$)	10% (MM$)	15% (MM$)	20% (MM$)	($/boe)	($/Mcfe)
PROVED
Developed Producing	523	1,217	1,010	843	725	16.95	2.83
Developed Non-Producing	35	22	16	13	11	15.38	2.56
Undeveloped	675	365	210	124	72	8.22	1.37
TOTAL PROVED	1,232	1,605	1,236	979	808	14.35	2.39
PROBABLE	1,209	589	366	259	197	13.01	2.17
TOTAL PROVED PLUS PROBABLE	2,441	2,193	1,602	1,238	1,004	14.02	2.34

Note:

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

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SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2019
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	523	1,217	1,010	843	725
Developed Non-Producing	35	22	16	13	11
Undeveloped	675	365	210	124	72
TOTAL PROVED	1,232	1,605	1,236	979	808
PROBABLE	1,209	589	366	259	197
TOTAL PROVED PLUS PROBABLE	2,441	2,193	1,602	1,238	1,004

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF DECEMBER 31, 2019
FORECAST PRICES AND COSTS

RESERVES CATEGORY	REVENUE (MM$)	ROYALTIES (MM$)	OPERATING COSTS (MM$)	DEVELOPMENT COSTS (MM$)	ABANDONMENT AND RECLAMATION COSTS (MM$)	FUTURE NET REVENUE BEFORE FUTURE INCOME TAXES (MM$)	FUTURE INCOME TAXES (MM$)	FUTURE NET REVENUE AFTER FUTURE INCOME TAXES (MM$)
Proved Reserves	5,999	577	2,054	499	1,637	1,232	0	1,232
Proved Plus Probable Reserves	8,290	928	2,713	564	1,643	2,441	0	2,441

FUTURE NET REVENUE
BY PRODUCTION TYPE
AS OF DECEMBER 31, 2019
FORECAST PRICES AND COSTS

		FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at	UNIT VALUE(3)
RESERVES CATEGORY	PRODUCTION TYPE	10%/year) (MM$)	($/bbl)	($/Mcf)
Proved Reserves	Light and Medium Crude Oil(1)	1,070	15.98	2.66
	Heavy Crude Oil and Bitumen(1)	87	13.36	2.23
	Conventional Natural Gas(2)	78	6.20	1.03

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	Non-Conventional Oil and Gas Activities(1)	0	0	0
	TOTAL	1,236	14.37	2.40
Proved Plus Probable	Light and Medium Crude Oil(1)	1,393	15.63	2.61
Reserves	Heavy Crude Oil and Bitumen(1)	119	12.22	2.04
	Conventional Natural Gas(2)	91	5.87	0.98
	Non-Conventional Oil and Gas Activities(1)	0	0	0
	TOTAL	1,602	14.05	2.34

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 Oil & Gas activities.

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

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 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:

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

(c) specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

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 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 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.

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 installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

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(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable) to which they are assigned.

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 proved reserves; and

(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the 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 provided by Sproule.

A3- 6  

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
AS OF DECEMBER 31, 2019
FORECAST PRICES AND COSTS

	OIL			GAS	EDMONTON LIQUIDS PRICES
Year	WTI Cushing Oklahoma ($US/bbl)	Canadian Light Oil Sweet Price 40ºAPI ($Cdn/bbl)	Western Canada Select 20.5ºAPI ($Cdn/bbl)	NATURAL GAS AECO ($Cdn/MMbtu)	Propane ($Cdn/bbl)	Butane ($Cdn/bbl)	Condensates ($Cdn/bbl)	INFLATION RATES(1) %/year	EXCHANGE RATE(2) ($US/$Cdn)
Forecast
2020	61.00	73.84	59.81	2.04	25.07	37.72	76.32	0.00%	0.76
2021	65.00	78.51	63.98	2.27	31.84	43.9	80.52	1.00%	0.77
2022	67.00	78.73	63.77	2.81	32.43	47.74	80.00	2.00%	0.80
2023	68.34	80.30	65.04	2.89	33.26	48.69	81.68	2.00%	0.80
2024	69.71	81.91	66.34	2.98	34.12	49.67	83.38	2.00%	0.80
2025	71.10	83.54	67.67	3.06	34.99	50.66	85.13	2.00%	0.80
2026	72.52	85.21	69.02	3.15	35.88	51.67	86.90	2.00%	0.80
2027	73.97	86.92	70.40	3.24	36.78	52.71	88.72	2.00%	0.80
2028	75.45	88.66	71.81	3.33	37.71	53.76	90.57	2.00%	0.80
2029	76.96	90.43	73.25	3.42	38.65	54.84	92.45	2.00%	0.80
2030	78.50	92.24	74.71	3.51	39.61	55.93	94.38	2.00%	0.80
Thereafter	+2%	+2%	+2%	+2%	+2%	+2%	+2%	+2.0	0.80

(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, 2019 were $1.79/Mcf for natural gas, $67.51/bbl for light and medium crude oil, $38.82/bbl for heavy crude oil and $20.77/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$)	Proved Plus Probable Reserves (MM$)
2020	83	86
2021	88	106
2022	101	120
2023	123	137
2024	104	115
2025 and subsequent	-	-
Total: Undiscounted for all years	499	564

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

A3- 7  

do not currently expect that interest or other funding costs could make development of any of our properties uneconomic.

5. Estimated future well abandonment and reclamation costs related to reserve and inactive wells 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.

7. All factual data supplied to Sproule was accepted as represented. No field inspection was conducted.

8. The estimates of future net revenue presented in the tables above do not represent fair market value.

Reconciliations of Changes in Reserves

The following table sets forth the reconciliation of our gross reserves as at December 31, 2019, 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 OIL(1)			HEAVY CRUDE OIL AND BITUMEN(1)			CONVENTIONAL NATURAL GAS(1)
FACTORS	Gross Proved (MMbbl)	Gross Probable (MMbbl)	Gross Proved Plus Probable (MMbbl)	Gross Proved (MMbbl)	Gross Probable (MMbbl)	Gross Proved Plus Probable (MMbbl)	Gross Proved (Bcf)	Gross Probable (Bcf)	Gross Proved Plus Probable (Bcf)
December 31, 2018	47	17	64	7	4	11	176	57	233
Extensions	-	-	-	-	-	-	1	-	1
Infill drilling	5	1	6	-	-	-	13	7	21
Improved Recovery	-	-	-	-	-	-	-	-	-
Technical Revisions	4	(3)	1	-	(1)	-	15	1	16
Discoveries	-	-	-	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	(7)	(2)	(9)
Economic Factors	-	-	-	-	-	-	(6)	(1)	(7)
Production	(4)	-	(4)	(1)	-	(1)	(19)	-	(19)
December 31, 2019	51	16	67	6	3	9	173	63	236

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	NATURAL GAS LIQUIDS(1)			TOTAL OIL EQUIVALENT(1)
FACTORS	Gross Proved (MMbbl)	Gross Probable (MMbbl)	Gross Proved Plus Probable (MMbbl)	Gross Proved (MMboe)	Gross Probable (MMboe)	Gross Proved Plus Probable (MMboe)
December 31, 2018	8	3	11	92	33	125
Extensions	-	-	-	-	-	1
Infill drilling	1	-	1	8	3	11
Improved Recovery	-	-	-	-	-	-
Technical Revisions	-	-	1	7	(3)	4
Discoveries	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	(2)	-	(2)
Economic Factors	-	-	-	(2)	-	(2)
Production	(1)	-	(1)	(10)	-	(10)
December 31, 2019	8	3	11	94	32	126

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 one-fifth 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.

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Year	Light and Medium Crude Oil (MMbbl)		Heavy Crude Oil and Bitumen (MMbbl)			Conventional Natural Gas (Bcf)		NGLs (MMbbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed		Cumulative at Year End	First Attributed	Cumulative at Year End
2017	3	12	1	2	11		30	1	1
2018	3	14	-	1	13		41	1	2
2019	5	17	-	1	14		47	1	2

Sproule has assigned 28 MMboe of proved undeveloped reserves in the Engineering Report under forecast prices and costs, together with $499 million of associated undiscounted future capital expenditures. Proved undeveloped capital spending in the first two forecast years of the Engineering Report accounts for $170 million, or 34 percent, of the total forecast undiscounted capital expenditures for proved undeveloped reserves. These figures increase to $499 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 Oil (MMbbl)		Heavy Crude Oil and Bitumen (MMbbl)		Conventional Natural Gas (Bcf)		NGLs (MMbbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End		First Attributed	Cumulative at Year End
2017	6	10	1	1	5	19		1	1
2018	1	9	-	1	5	21		-	1
2019	1	9	-	1	7	33		-	2

Sproule has assigned 17 MMboe of probable undeveloped reserves in the Engineering Report under forecast prices and costs, together with $65 million of associated undiscounted future capital expenditures. Probable undeveloped capital spending in the first two forecast years of the Engineering Report accounts for $21 million, or 32 percent, of the total forecast undiscounted future capital expenditures for probable undeveloped reserves. These figures increase to $65 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.

Additional Information Concerning Abandonment and Reclamation Costs

Abandonment and reclamation costs in respect of surface leases, wells, facilities and pipelines (collectively, "A&R Costs") are primarily comprised of abandonment, decommissioning, remediation and reclamation costs. A&R Costs are estimated using guidance from the Alberta Energy Regulatory for abandonment and reclamation costs for wells and facilities.  Pipeline

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abandonment and reclamation costs have been estimated based on Obsidian Energy experience decommissioning pipelines in recent years. All Obsidian Energy A&R costs, including active and inactive wells, facilities, and pipelines, have been included in the Engineering Report as part of future net revenue calculations.

Obsidian Energy reviews its 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, 2019, we expect to incur future A&R Costs in respect of approximately 4,761 net well bores, 604 facilities and 6,515 kilometres of pipelines. On an undiscounted, inflated basis, approximately 68 percent of A&R Costs relate to well bores, 28 percent to facilities and 4 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 Reclamation Costs Escalated at 2% Undiscounted (MM$)	Abandonment and Reclamation Costs Escalated at 2% Discounted at 10% (MM$)
Total liability as at December 31, 2019	1,643	62
Anticipated to be paid in 2020	13	13
Anticipated to be paid in 2021	6	5
Anticipated to be paid in 2022	1	1
Total anticipated to be paid in 2020, 2021 and 2022	20	19

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 $1,643 million, and escalated at two percent and discounted at 10 percent, these A&R Costs were $62 million. On an undiscounted, uninflated basis total A&R costs are $621 million.

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, 2019 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, 2019, the majority of our proved plus probable reserves are located in Alberta, Canada.

Major Operating Regions

Our production and reserves are attributed to approximately 27 producing properties. The Company’s Willesden Green property accounts for 40 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.

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The following map illustrates Obsidian Energy's major operating regions as at December 31, 2019.

 

The following is a description of our principal oil and natural gas properties and related operations and activities as at December 31, 2019. Information in respect of gross and net acres and well counts are as of December 31, 2019 and information in respect of production is for the year ended December 31, 2019, except where indicated otherwise. For information on the Company’s disposition activity in 2019 see "Description of Our Business – General Development of the Business – 2019 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.

Cardium Development Area

The Cardium development play is located in West Central Alberta and extends over 300 kilometers from Calgary to Grande Prairie, Alberta. The Company’s Deep Basin rights are also included within this area which were previously separated. At December 31, 2019, Obsidian Energy is the largest land owner in the Cardium play, holding approximately 475 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 2019 capital expenditures was $103 million,

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excluding decommissioning expenditures, resulting in 23 (18.7 net) operated wells drilled, 3 (0.4 net) injector/service wells. In 2020, planned Cardium activity will continue in the Willesden Green area of the play and focus on primary development. For the first half of 2020, the Company’s capital expenditures budget for Cardium development totals $37 million. This will result in 10 additional gross horizontal producers in Willesden Green.

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, 2019, Obsidian Energy had approximately 234 net sections of developed and undeveloped land in the area. In 2019, minimal capital was spent in the area in as the Company focused activity in the Cardium and the Company anticipates spending minimal capital in 2020 as well.

Viking Development Area

The Viking development area is located in Eastern Alberta along the Alberta/Saskatchewan border. At December 31, 2019, Obsidian Energy had approximately 196 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 2019 and the Company anticipates minimal capital spending in the area in 2020.

Optimization activity

In 2020, Obsidian Energy plans to leverage its 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 $4 million in the first half of 2020 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.

2020 Capital Budget

The Board has approved a $54 million first half 2020 capital plan to fund the continued drilling of the Willesden Green area with 10 gross wells planned in addition to other operational spending and decommissioning expenditures.

For the first quarter of 2020, the Company remained focused on development of the Company’s predictable, light oil, Cardium asset. Through the first quarter of 2020, market conditions have been volatile due to OPEC and Russia abandoning quotas and increasing production levels and commodity demand falling in conjunction with the impact of the COVID-19 virus. In response to lower commodity prices, the Company reduced spending starting in March. Given the current commodity price environment, we are restricting capital spending and beginning to shut-in certain heavy oil properties that are currently uneconomic to produce. If oil prices continue at these levels, our development capital spending will be minimal. We have flexibility in our portfolio to manage remaining capital expenditures through the balance of 2020 with a view to preserving long term shareholder value.

The primary components of our programs are described above under the heading "Major Operating Regions". See also "Description of our Business – General Development of the Business – Year Ended December 31, 2019 – 2019 Capital Expenditure Budget and Production– and –2020 Developments - Updated 2020 Outlook and Guidance ".

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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, 2019.

	Producing				Non-Producing		Total
	Oil		Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	1,815	1,429	445	290	3,863	3,024	6,123	4,744
Northwest Territories	-	-	-	-	41	6	41	6
Saskatchewan	-	-	-	-	3	-	3	-
Manitoba	-	-	-	-	4	2	4	2
USA	-	-	-	-	25	9	25	9
Total	1,815	1,429	445	290	3,936	3,042	6,196	4,761

Note:

(1) Total well counts differ then the well count provided under the Abandonment and Reclamation Costs as the 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, 2019.

	Unproved Properties (thousands of acres)
	Gross	Net
Alberta	227	227
Northwest Territories	4	1
Total	231	228

We currently have no material work commitments on these lands. The primary lease or extension term on approximately 30,240 net acres of unproved property is scheduled to expire by December 31, 2020. 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.

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Capital Expenditures

The following table summarizes capital expenditures related to our activities for the year ended December 31, 2019, irrespective of whether such costs were capitalized or charged to expense when incurred.

	2019 MM$
Property Acquisition Costs(1)
Proved Properties	(11)
Unproved Properties	-
Exploration Costs(1)	-
Development Costs(1)	102
Corporate Costs	1
Total Capital Expenditures	92
Corporate Acquisitions	-
Total Expenditures	92

Note:

(1) "Property Acquisition Costs", "Proved Properties", "Unproved Properties", "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, 2019.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	-	-	23	18.7
Gas and condensate	-	-	-	-
Injectors/Stratigraphic test	-	-	3	0.4
Total	-	-	26	19.1

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2020 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 Crude Oil		Heavy Crude Oil and Bitumen		Conventional Natural Gas			Natural Gas Liquids		Total Oil Equivalent
	(bbl/d)		(bbl/d)		(Mcf/d)			(bbl/d)		(boe/d)
	Gross	Net	Gross	Net		Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	10,110	9,244	3,145	3,017		41,526	39,611	1,811	1,370	21,987	20,233
Proved Developed Non- Producing	129	119	56	54		427	403	15	10	271	251
Proved Undeveloped	1,317	1,251	-	-		2,016	1,915	100	95	1,753	1,665
Total Proved	11,556	10,614	3,201	3,071		43,970	41,929	1,926	1,475	24,012	22,149
Total Probable	592	528	146	140		1,981	1,888	85	71	1,152	1,054
Total Proved Plus Probable	12,148	11,142	3,347	3,211		45,951	43,816	2,010	1,547	25,164	23,202

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The Company notes that our Willesden Green property (located in the Cardium development area) accounts for approximately 47% of the estimated production on a proved plus probable basis in 2020. 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:

	Quarter Ended 2019				Year Ended
	March 31	June 30	September 30	December 31	December 31, 2019
Share of Average Gross Daily Production
Light and Medium Crude Oil (bbl/d)	12,376	12,453	10,802	12,246	11,966
Heavy Crude Oil (bbl/d)	4,096	4,059	3,991	3,718	3,965
Conventional Natural Gas (Mcf/d)	54,342	54,730	51,116	51,478	52,904
NGLs (bbl/d)	2,122	2,201	2,192	2,095	2,153
Combined (boe/d)	27,651	27,835	25,505	26,639	26,901
Average Net Production Prices Received
Light and Medium Crude Oil ($/bbl)	64.88	72.20	68.14	70.57	68.99
Heavy Crude Oil ($/bbl)	30.62	42.63	40.44	41.80	38.82
Conventional Natural Gas ($/Mcf)	2.41	1.18	1.05	2.55	1.79
NGLs ($/bbl)	21.44	14.95	15.75	31.42	20.77
Combined ($/boe)	39.95	42.01	38.64	45.67	41.60
Royalties Paid
Light and Medium Crude Oil ($/bbl)	4.29	5.71	6.73	6.49	5.78
Heavy Crude Oil ($/bbl)	1.03	2.02	1.40	1.64	1.52
Conventional Gas ($/Mcf)	-	(0.02)	(0.02)	0.22	0.04
NGLs ($/bbl)	9.92	(0.78)	1.01	2.03	2.97
Combined ($/boe)	2.81	2.74	3.12	3.79	3.11
Production Costs(1)(2)(3)
Light and Medium Crude Oil ($/bbl)	19.16	17.73	22.43	20.55	19.89
Heavy Crude Oil ($/bbl)	17.72	16.59	16.30	14.17	16.23
Conventional Natural Gas ($/Mcf)	1.17	1.29	1.30	0.69	1.11
NGLs ($/bbl)	(0.19)	(0.20)	(0.20)	(0.18)	(0.19)
Combined ($/boe)	13.49	12.86	14.65	12.75	13.42
Transportation
Light and Medium Crude Oil ($/bbl)	2.78	2.94	2.83	2.47	2.75
Heavy Crude Oil ($/bbl)	6.81	7.14	6.39	6.74	6.77
Conventional Natural Gas ($/Mcf)	0.32	0.28	0.26	0.25	0.28
NGLs ($/bbl)	-	-	-	-	-
Combined ($/boe)	2.87	2.90	2.72	2.56	2.76
Risk Management Contracts Loss (Gain)
Light and Medium Crude Oil ($/bbl)	(4.03)	(4.41)	1.41	1.44	(1.48)
Heavy Crude Oil ($/bbl)	-	-	-	-	-
Conventional Gas ($/Mcf)	-	-	-	-	-
NGLs ($/bbl)	-	-	-	-	-
Combined ($/boe)	(1.80)	(1.97)	0.60	0.66	(0.66)

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Netback Received(4)
Light and Medium Crude Oil ($/bbl)	34.63	41.41	37.56	42.49	39.09
Heavy Crude Oil ($/bbl)	5.06	16.88	16.35	19.25	14.29
Conventional Natural Gas ($/Mcf)	0.92	(0.37)	(0.49)	1.39	0.36
NGLs ($/bbl)	11.70	15.93	14.94	29.57	18.00
Combined ($/boe)	18.98	21.54	18.75	27.23	21.65

Notes:

(1) Operating expenses are comprised of direct costs incurred to operate both oil and gas wells. 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 accounted for as a reduction to general and administrative costs.

(3) Netbacks are calculated by subtracting royalties, operating costs, transportation costs and losses/gains on commodity and foreign exchange contracts from revenues.

During the year ended December 31, 2019, Obsidian Energy produced 10 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 or regionally strategic counterparties wherever possible.

· Ensure competitive pricing by managing pricing exposures through a portfolio of various terms and geographic basis.

· Ensure optimization of netbacks through careful management of transportation obligations, facility utilization levels, blending opportunities and emulsion handling.

· Ensure protection of our receivables by, whenever possible, dealing only with credit worthy counterparties who have been subjected to regular credit reviews.

Oil and Liquids Marketing

Of our liquids production in 2019, approximately 66% percent was light and medium oil, 22% percent was conventional heavy crude oil and 12% 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.

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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:

	2019		2018		2017
	Light and Medium Crude Oil and NGLs	Heavy Crude Oil	Light and Medium Crude Oil and NGLs	Heavy Crude Oil	Light and Medium Crude Oil and NGLs	Heavy Crude Oil
Quarter Ended	($/bbl)	($/bbl)	($/bbl)	($/bbl)	($/bbl)	($/bbl)
March 31	58.52	30.62	64.25	31.34	57.00	33.21
June 30	63.60	42.63	72.32	46.81	56.12	31.61
September 30	59.31	40.44	75.49	45.30	51.06	30.36
December 31	64.85	41.80	35.35	7.70	62.70	38.12

Natural Gas Marketing

In 2019, we received an average price from the sale of conventional natural gas, before adjustments for hedging activities, of $1.79 per mcf compared to $2.21 per mcf realized in 2018. 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.

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, 2019, 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, 2019 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.

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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 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;

(c) To assist the Board in meeting its responsibilities regarding the oversight of the independent auditor's qualifications and independence;

(d) To assist the Board in meeting its responsibilities regarding the oversight of the credibility, integrity and objectivity of financial reports;

(e) To strengthen the role of the non-management directors by facilitating discussions between directors on the Committee, management and independent auditors;

(f) To assist the Board in meeting its responsibilities regarding the oversight of the performance of Obsidian 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 compliance with legal and regulatory requirements; and

(h) To assist the Board by monitoring the effectiveness and integrity of the Corporation’s financial 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 reasonably ensure that:

(i) controllable, material business risks are identified, monitored and mitigated where it is determined cost effective to do so;

(ii) internal controls over financial reporting are sufficient to meet the requirements under National Instrument 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.

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(b) Review the annual and interim financial statements of the Company prior to their submission to the Board for approval. The process should include, but not be limited to:

(i) review of changes in accounting principles, or in their application, which may have a material impact on the current or future years' financial statements;

(ii) review of significant accruals, reserves or other estimates such as the ceiling test calculation;

(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 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 statements;

(viii) review of unresolved differences between management and the independent auditors, if any;

(ix) review of reasonable explanations of significant variances with comparative reporting periods; and

(x) determination through inquiry if there are any related party transactions and ensure the nature and extent of such transactions are properly disclosed.

(c) Review, discuss and recommend for approval by the Board the annual and interim financial statements and 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 guidance provided to analysts and rating agencies (provided that the Committee is not required to review and discuss investor presentations that do not contain financial information or earnings guidance that has not previously been generally disclosed to the public).

(e) With respect to the appointment of independent auditors by the Board, the Committee shall:

(i) on an annual basis, review and discuss with the auditors all relationships the auditors have with Obsidian 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 itself;

(ii) be directly responsible for overseeing the work of the independent auditors engaged for the purpose of issuing an auditors' report or performing other audit, review or attest services for Obsidian Energy, including the resolution of disagreements between management and the independent auditor regarding financial reporting, and the independent auditors shall report directly to the Committee;

(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 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) of the independent auditors, including the appropriateness and reasonableness of the auditors' fees;

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(vi) when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change; and

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

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

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

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

(j) Obtain assurance from the independent auditors that disclosure to the Committee is not required pursuant to 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 independent auditors.

(l) Review all public disclosure containing financial information before release (provided that the Committee is 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.

(n) Satisfy itself that adequate procedures are in place for the review of Obsidian Energy's public 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 such exposures.

(p) Establish procedures independent of management for:

(i) the receipt, retention and treatment of complaints received by Obsidian Energy regarding accounting, internal accounting controls, or auditing matters; and

(ii) the confidential, anonymous submission by employees of Obsidian Energy of concerns regarding questionable accounting or auditing matters.

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(q) Review any other matters required by law, regulation or stock exchange requirement, or that the Committee feels are important to its mandate or that the Board chooses to delegate to it.

(r) Establish, review and update periodically a Code of Business and ensure that management has established systems to enforce these codes.

(s) Review management's monitoring of Obsidian Energy's compliance with the organization's Code of Business Conduct.

(t) Review and discuss with the Chief Executive Officer, the Chief Financial Officer and the independent 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 Officer.

(u) Review and discuss major issues regarding accounting principles and financial statement presentations, 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 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 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.

(x) Review and discuss the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on Obsidian Energy’s financial statements.

(y) Review and discuss the type and presentation of information to be included in earnings press releases, 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 any proposed changes to the Board for consideration.

(aa) Review and/or approve any other matters specifically delegated to the Committee by the Board.

3. KNOWLEDGE & EDUCATION

Committee members shall be "financially literate" within the meaning of National Instrument 52-110 Audit Committees ("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 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 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 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 Obsidian Energy's securities are listed for trading.

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(d) All of the members must be "financially literate" within the meaning of NI 52-110 and 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 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 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.

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

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

(c) Notice of the time and place of every meeting may be given orally, in writing, by facsimile or by other 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 notice.

(d) Agendas, with input from management and the Committee Chair, shall be circulated by the Committee Secretary 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 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 meeting.

(f) The Committee Chair shall be a full voting member of the Committee. If the Committee Chair is unavailable or unable to attend a meeting of the Committee, the Committee Chair shall ask another member to chair the meeting, failing which a member of the Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting. The Chair of any Committee meeting shall have a casting vote in the event of a tie on any matter upon which the Committee votes during such meeting.

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

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Committee members will also meet "in-camera" without any members of management present, and in the 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 Secretary of Obsidian Energy or his/her designate. The Committee Secretary shall record minutes of the meetings of the Committee, which shall be reviewed and approved by the Committee and maintained with Obsidian Energy's records by the Committee Secretary. The Committee shall report its activities and proceedings to the Board by oral or written report at the next Board meeting and by distributing the minutes of its meetings. Supporting schedules and information reviewed by the Committee shall be available for examination by any Director.

6. RESOURCES

(a) The Committee may retain special legal, accounting, financial or other consultants or advisors to advise the Committee at the Company's expense and shall have sole authority to retain and terminate any such consultants or advisors and to approve any such consultant's or advisor's fees and retention terms, subject to review by the Board, and at the expense of the Company.

(b) The Committee shall have access to Obsidian Energy's senior management and documents as required to 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 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, regulatory or other legal requirements for the Board or members of the Committee. The purposes and responsibilities outlined in this Mandate are meant to serve as guidelines rather than inflexible rules and the Committee may adopt such additional procedures and standards as it deems necessary from time to time to fulfill its responsibilities, subject to applicable statutory, regulatory and other legal requirements.

(b) The duties and responsibilities of a member of the Committee are in addition to those duties set out for a member of the Board.