Exhibit 99.1

OBSIDIAN ENERGY LTD.

Annual Information Form

for the year ended December 31, 2018

March 6, 2019

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS		3
CONVENTIONS		4
ABBREVIATIONS		5
OIL AND GAS INFORMATION ADVISORIES		5
CONVERSIONS		6
EFFECTIVE DATE OF INFORMATION		6
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		6
GENERAL AND ORGANIZATIONAL STRUCTURE		8
DESCRIPTION OF OUR BUSINESS		9
CAPITALIZATION OF OBSIDIAN ENERGY		15
DIRECTORS AND EXECUTIVE OFFICERS OF OBSIDIAN ENERGY		17
AUDIT COMMITTEE DISCLOSURES		21
DIVIDENDS AND DIVIDEND POLICY		23
MARKET FOR SECURITIES		24
INDUSTRY CONDITIONS		25
RISK FACTORS		36
MATERIAL CONTRACTS		58
LEGAL PROCEEDINGS AND REGULATORY ACTIONS		59
TRANSFER AGENTS AND REGISTRARS		59
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		59
INTERESTS OF EXPERTS		59
ADDITIONAL INFORMATION		60

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

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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 6, 2019.

“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 January 24, 2019 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, 2018.

“Form 40-F” means our Annual Report on Form 40-F for the fiscal year ended December 31, 2018 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.

“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.

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“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$60 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 6, 2019, the exchange rate based on the noon rate as reported by WM/Reuters, was Cdn$1.00 equals US$1.3444.

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, 2018, 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, 2018.

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 2019 capital budget and our average production guidance for 2019; the details of our ongoing acquisition, disposition, farm-out and financing strategy; that the Company will conduct a vote on the proposed share consolidation at part of its Annual General Meeting in 2019; our dividend policy; our expectations regarding the operational and financial impact that climate change regulations in the jurisdictions in which we operate will have on us; that the Corporation is unable to predict what additional legislation or amendment governments may enact in the future and what will need to be reported, remitted and in what time frame; that we are committed to mitigating the environmental impact from our operations, and to involving stakeholders throughout the exploration, development, production and abandonment process; that we will seek to drive improvement and to ensure compliance with our environmental policies; that we seek to communicate our commitment to environmental stewardship to our stakeholders in order to always be held accountable; that we continue to work cooperatively with governments to develop an approach to deal with climate change issues that protects the industry’s competitiveness, limits the cost and administrative burden of compliance, and supports continued investment in the oil and gas sector; our belief that the trend towards heightened and additional standards in environmental legislation and regulation will continue and our expectation that we will be making increased expenditures as a result of the expansion of our operations and the adoption of new legislation relating to the protection of the environment; our commitment to mitigating the environmental impact from our operations and involving stakeholders throughout the exploration, development, production and abandonment process; our assessment of the operational and financial impacts that certain risks factors could have on us and the value of our Common Shares should such risk factors materialize; the quantity of our oil, natural gas liquids and natural gas reserves, the recoverability thereof, and the net present values of future

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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, Viking and Deep Basin resource plays in 2019 and additional optimization activity in 2019; the expected lands that will be surrendered unless we qualify them in some manner; our expectations regarding when we will be required to pay income taxes; our production volume estimates for 2019; 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: 2018 prices of $50.62 per barrel WTI and $1.31 per Mcf AECO and a 2018 US$/Cdn$ foreign exchange rate of $1.33; that 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 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”.

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

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our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the possibility that we are unable to execute some or all of our ongoing asset acquisition or disposition programs on favourable terms or at all, whether due to the failure to receive requisite regulatory or other third party approvals or satisfy applicable closing conditions or for other reasons that we cannot anticipate; the 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 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.

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.

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Our Organizational Structure

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

Notes:

(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.

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 discipline, 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, 2018, Obsidian Energy had 236 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, 2018.

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.

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Year Ended December 31, 2016

2016 Capital Expenditure Budget and Production

In January 2016, the Company announced its 2016 capital budget of $50 million. This capital budget was consistent with the strategy announced on September 1, 2015, which limited the total expenditures to funds flow from operations, in response to the weak commodity price environment. The Company’s average production guidance for 2016 was also set at 60,000 to 64,000 boe/d. In August 2016, the Company announced that due to the additional financial flexibility afforded the Company through the debt reduction efforts to date, that it would be resuming development in the Cardium and Alberta Viking in the second half of 2016 and therefore increasing the full year capital budget by approximately $40 million to $90 million, plus $15 million allocated to decommissioning expenditures. The Company’s average production guidance for 2016 was adjusted in November 2016, due to all the disposition activities, to 52,000 to 55,000 boe/d.

NYSE – Continued Listing Standard Notification

In January 2016, 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 June 30, 2016 since the average closing price of its common stock for the consecutive 30 trading days ended June 30, 2016 and the closing price of its common stock on June 30, 2016 both exceeded US$1.00. For further details, see the Company’s news release dated July 4, 2016 which is available on SEDAR at www.sedar.com

Settlement of Class Action Lawsuit

In February 2016, the Company announced that it entered into agreements to settle all class action proceedings in Canada and United States against the Company related to damages alleged to have been incurred due to a decline in share price related to the restatement of certain of the Company’s historical financial statements and related MD&A in 2014. The settlement agreements provide for a payment of $53 million split evenly between Canadian and U.S. investors that will be fully funded by insurance coverage maintained by the Company. As a result, the payment would not impact the Company’s cash or financial position. The settlements received the required court approval in each of Alberta, Ontario and Quebec and in New York, and all conditions to settlement have been satisfied. As a result of the approval of these settlements, there is no further exposure to the Company.

Board of Directors and Management Changes

Ms. Maureen Cormier Jackson joined the Board of Directors on March 8, 2016.

In October 2016, the Company announced that David Roberts (President and Chief Executive Officer) would be retiring from his position effective October 24, 2016 and that David French would succeed him.

In 2016, as part of our ongoing effort to operate in a more efficient manner, the Company reduced its staffing levels by over 40% percent.

Long Term Retention and Incentive Plan becomes Restricted Share Unit Plan

In March 2016, the Company announced that the Board had approved amendments to the Restricted Share Unit Plan (formerly the Long Term Retention and Incentive Plan) to allow for the administrators the discretion to make payments on future grants of restricted share units (formerly incentive awards) in either cash or Common Shares.

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Termination of DRIP

In March 2016, the Company announced that the Board had decided to terminate the Obsidian Energy’s Dividend Reinvestment and Optional Common Share Purchase Plan, which had been suspended since December 2014, pursuant to the terms and conditions set forth in the plan.

Prepayment of Outstanding Debt

In September 2016, the Company offered $448 million of net proceeds received from dispositions during the year for prepayment of outstanding senior notes. The note holders accepted $437 million which was subsequently prepaid in October 2016. The remaining $11 million was used to repay indebtedness on our syndicated bank facility. This prepayment reduced the outstanding principal on our senior notes to approximately $139 million at that date, lowered the average interest rate on our debt, and reduced the number of noteholders from 36 down to two.

Aggregate Disposition Activity

The Company completed property dispositions of $1.4 billion in 2016 (including the sale of all its Saskatchewan assets for cash consideration of approximately $975 million – for further details, see the Company’s news release dated June 24, 2016 which is available on SEDAR at www.sedar.com). Total production associated with the combined divestments was approximately 30,000 boe/d with production weighted approximately 25% toward natural gas. These divested assets were located in Alberta, Saskatchewan and British Columbia and represented both non-core and core base assets in the Company’s asset portfolio. The net proceeds of the dispositions were used to repay a portion of the indebtedness outstanding under our bank facility and senior notes, as agreed to in the amending agreements.

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.

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New Reserve-Based Credit Facility

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 ends on May 17, 2018, with an additional one year term out period, and is 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 Law Suit

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 law suit 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 law suit. 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 law suit 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.

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Year Ended December 31, 2018

Board of Directors Changes

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

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

2018 Production Guidance and Disposition Activity

In January 2018, the Company closed an agreement to dispose of a significant portion of 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.

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 is proposing a share consolidation which will be voted on by the shareholders as part of the Company’s Annual General Meeting in 2019.

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.

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$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

2019 Developments

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 Change

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.

Covenant amendment

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).

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.

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Potential Financings

Obsidian Energy continuously evaluates its capital structure, liquidity and capital resources, and financing opportunities that arise from time to time. Obsidian Energy may in the future complete financings of Common Shares or debt (including debt which may be convertible into Common Shares) for purposes that may include the financing of acquisitions, the financing of Obsidian Energy’s operations and capital expenditures, and the repayment of indebtedness. As of the date hereof, Obsidian Energy has not reached agreement on the pricing or terms of any potential material financing. Obsidian Energy cannot predict whether any current or future financing opportunity will result in one or more material financings being completed.

Significant Acquisitions

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

CAPITALIZATION OF OBSIDIAN ENERGY

Share Capital

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

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 6, 2019, 507,471,393 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

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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.

Senior Notes

Obsidian Energy has issued the Senior Notes, which consist of US$60 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 C	US$	5 million		5.90	%	May 31, 2007	May 31, 2019
Series G	US$	4 million		6.40	%	May 29, 2008	May 29, 2020
Series L	US$	8 million		9.32	%	May 5, 2009	May 5, 2019
Series S	US$	10 million		5.85	%	March 16, 2010	March 16, 2020
Series X	US$	13 million		4.88	%	December 2, 2010 and January 4, 2011	December 2, 2020
Series Y	US$	6 million		4.98	%	December 2, 2010	December 2, 2022
Series Z	US$	2 million		5.23	%	December 2, 2010 and January 4, 2011	December 2, 2025
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, less the amount of outstanding pari passu senior notes, resulting in $470 million currently being available under the syndicated credit facility. The revolving period of the syndicated credit facility ends on May 31, 2019, with an additional one-year term out period, 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, 2016, Year Ended December 31, 2017, Year Ended December 31, 2018 Developments and 2019 Development” in this Annual Information Form, Note 7 to our audited consolidated financial statements for the year ended December 31, 2018 (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.

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DIRECTORS AND EXECUTIVE OFFICERS OF OBSIDIAN ENERGY

The following table sets forth, as at March 6, 2019, 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
John Brydson(1)(3)(4) 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)(3) Alberta, Canada	Director since March 6, 2015	Partner with PricewaterhouseCoopers LLP from 1996 until his retirement in March 2015, serving as the Managing Partner, Western Canada, from 2011 to 2013. Currently a director of Pure Technologies Ltd. and the Canada West Foundation.
Michael J. Faust(3) Alaska, USA	Director since May 11, 2018	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.
David L. French Alberta, Canada	Director, President and Chief Executive Officer since October 24, 2016	President and Chief Executive Officer of Obsidian Energy since October 2016. Prior thereto, President and Chief Executive Officer of Bankers Petroleum Ltd. from April 2013 to October 2016. Vice-President, Business Development of Apache Corporation, January 2010 to April 2013.
William A. Friley(2)(3)(4) 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

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Name, Province and Country of Residence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five Preceding Years
		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 Ltd., the Founding Chair of the Wood Buffalo Community Foundation and serves on the Dean’s Advisory Board of Dean of Medicine at the University of Calgary. She was previously a director of a privately-owned family business for more than 15 years and has been involved in several non-profit organizations in various capacities during her career. 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(1)(4) New York, USA	Director since May 11, 2018	Partner, managing member, and portfolio manager at FrontFour Capital Group LLC. Previosuly, 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 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.

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Name, Province and Country of Residence	Positions and Offices Held with Obsidian Energy	Principal Occupations during the Five Preceding Years
David Hendry Alberta, Canada	Chief Financial Officer since January 5, 2017	Chief Financial Officer of Obsidian Energy since January 2017. Prior thereto, Vice President Finance at Obsidian Energy from May 2015 until December 2016. Prior thereto, Vice President Finance at Talisman Energy Inc. from August 2009 to April 2015.

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

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

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

(a) was subject to a cease trade order (including a management cease trade order), an order similar to a cease 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, no director or executive officer of Obsidian Energy or shareholder holding a sufficient number of securities of Obsidian Energy to affect materially the control of Obsidian Energy (nor any personal holding company of any of such persons):

(a) is, as of the date of this Annual Information Form, or has been within the ten years before the date of this Annual Information Form, a director or executive officer of any company (including Obsidian Energy) that,

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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.

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 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.

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.

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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, Maureen Cormier Jackson and Stephen Loukas, 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 management. Ms. Cormier Jackson is also a director of Enerflex Ltd., the Founding Chair of the Wood Buffalo Community Foundation and serves on the Dean’s Advisory Board of Dean of Medicine at the University of Calgary. She was previously a director of a privately-owned family business for more than 15 years and has been involved in several non-profit organizations in various capacities during her career. 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.

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Raymond Crossley (Chairman)

Mr. Crossley is a corporate director. He serves as chair of the audit committee of Pure Technologies Ltd. Mr. Crossley has served as a member of the Financial Review Committee of the Alberta Securities Commission (“ASC”) and has been a member of the Financial Advisory Committee of the ASC. Mr. Crossley retired in 2015 from the accounting firm of PricewaterhouseCoopers (“PwC”) after serving for more than 33 years. He joined the firm in 1981 and had been a partner since 1996, working with a number of large publicly traded corporations operating in the natural resource and utilities sectors. Mr. Crossley served as an elected member of the Partnership Board (PwC’s governing body), from 2001-2005. From 2005-2011, Mr. Crossley was the Managing Partner of PwC’s Calgary office. From 2011-2013 Mr. Crossley acted as Managing Partner, Western Canada. Mr. Crossley is a member of the Chartered Professional Accountants of Alberta. He graduated from the University of Western Ontario with a degree in Economics and Political Science.

Stephen Loukas

Mr. Loukas is partner, managing member, and portfolio manager at FrontFour Capital Group LLC, a value-based investment management firm. Previously, Mr. Loukas held roles including 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. Mr. Loukas has also worked within the Corporate Finance & Distribution Group of Scotia Capital where he focused on the structuring and syndication of leveraged loans and high yield debt. Mr. Loukas started his career at restructuring firm Zolfo Cooper where he assisted corporate clients in the development and implementation of operational and financial restructuring plans. Mr. Loukas received a B.A. in Finance and Accounting from New York University.

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.

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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) ($)
2018		876,000		39,000		6,000
2017		811,000		39,000		16,000

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.

(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”.

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MARKET FOR SECURITIES

Trading Price and Volume

The following tables set forth certain trading information for the Common Shares in 2018 as reported by the TSX and the NYSE.

	TSX
Period	Common Share price ($) High		Common Share price ($) Low		Volume
January		1.70		1.25		30,862,438
February		1.30		1.06		27,690,586
March		1.34		1.14		29,863,420
April		1.53		1.27		25,717,173
May		1.59		1.38		20,054,339
June		1.55		1.38		20,557,240
July		1.53		1.35		14,831,053
August		1.41		1.23		14,022,999
September		1.31		1.15		9,708,766
October		1.26		0.91		11,622,329
November		0.98		0.61		13,566,144
December		1.56		0.43		16,116,638

	NYSE
Period	Common Share price ($US) High		Common Share price ($US) Low		Volume
January		1.35		1.01		41,070,547
February		1.06		0.85		33,021,996
March		1.04		0.88		35,239,156
April		1.18		1.00		28,007,686
May		1.24		1.07		30,954,409
June		1.19		1.05		23,112,353
July		1.18		1.02		19,517,283
August		1.08		0.94		19,005,819
September		1.02		0.90		8,973,438
October		0.97		0.70		15,236,715
November		0.75		0.46		24,755,767
December		0.56		0.33		27,481,499

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).

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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 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 governmental legislation is a matter of public record, the Corporation is unable to predict what additional legislation 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, 2018.

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.

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Exports from Canada

Crude oil, natural gas and NGLs exports from Canada are subject to the National Energy Board Act (Canada) (the “NEB Act”) and the National Energy Board Act Part VI (Oil and Gas) Regulation (the “Part VI Regulation”). The NEB Act and the Part VI Regulation authorize crude oil, natural gas and NGLs exports under either short-term orders or long-term licences. To obtain a crude oil export licence, a mandatory public hearing with the National Energy Board (the “NEB”) is required. There is no longer a public hearing requirement for the export of natural gas and NGLs. Instead, the NEB uses a written process that includes a public comment period for impacted persons. Following the comment period, the NEB completes its assessment of the application and either approves or denies the application. For natural gas, the maximum duration of an export licence is 40 years and, for crude oil and other gas substances (e.g. NGLs), the maximum term is 25 years. In addition to NEB approval, all crude oil, natural gas and NGLs licences require the approval of the cabinet of the Canadian federal government (“Cabinet”).

Orders from the NEB provide a short-term alternative to export licences and may be issued more expediently, since they do not require a public hearing or approval from 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 NEB and the federal government. The Corporation does not directly enter into contracts to export its production outside of Canada.

On February 8, 2018, the Government of Canada introduced Bill C-69, draft legislation that, if enacted, will replace the NEB with the Canadian Energy Regulator (“CER”). The CER will take on the NEB’s responsibilities with respect to the export of crude oil, natural gas and NGLs from Canada. However, it is not proposed that the legislative regime relating to exports of crude oil, natural gas and NGLs exports from Canada will substantively change under the new regime as currently drafted.

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

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 areas 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. Although the current federal government introduced Bill C-69 to amend the current federal approval processes, it is uncertain when the new legislation will be brought into force and whether any changes will be made in the interim. It is also uncertain whether any new approval process adopted by the federal government will result in a more efficient approval process. The lack of regulatory certainty is likely to have an influence on 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, as well as court challenges related to issues such as indigenous title, the government’s duty to consult and accommodate indigenous peoples and the sufficiency of the relevant environmental review processes. Such political and legal opposition creates further uncertainty. In addition, export pipelines from Canada to the United States face additional uncertainty 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, especially the Midwest United States and export shipping

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terminals on the west coast of Canada, could help to alleviate the downward pressures affecting commodity prices. Several proposals have been announced to increase pipeline capacity out of Western Canada to reach Eastern Canada, the United States and international markets via export terminals. While certain projects are proceeding, the regulatory approval process and other economic and socio-political factors related to transportation and export infrastructure has led to the delay, suspension or cancellation of many 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 expansion from Hardisty, Alberta, to Superior, Wisconsin, formerly expected to be in-service in late 2019, experienced a construction permitting setback and is now expected to be in-service in the latter half of 2020.

The proposed Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of sustained political opposition in British Columbia, the federal government entered into an agreement with Kinder Morgan Cochin ULC in May 2018 to purchase the shares and units of the entities that own and operate the Trans Mountain Pipeline system. The shareholders subsequently voted to approve the transaction 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. Following the Court’s direction, Cabinet ordered the NEB to reconsider its recommendation in light of the Federal Court of Appeal decision, including the environmental effects of project-related marine shipping. On February 22, 2019, the NEB delivered an updated report to Cabinet, recommending that Cabinet approve the pipeline expansion, subject to 156 conditions and 16 new recommendations, notwithstanding the fact that project-related marine shipping may have a significant adverse effect on the marine environment. While Cabinet has three months to consider the NEB’s report, it may extend this deadline to accommodate a new round of indigenous consultation, upon completion of which it will decide whether to approve or deny the pipeline expansion.

While it was expected that construction on the Keystone XL Pipeline would commence in the first half of 2019, pre-construction work was halted in late 2018 when a U.S. Federal Court Judge determined the underlying environmental review was inadequate. This decision has been appealed.

Finally, Bill C-48 continues to advance through the federal legislative process. If enacted, Bill C-48 will impose a moratorium on tanker traffic transporting certain crude oil and NGLs products from British Columbia’s north coast. See “Regulatory Authorities and Environmental Regulation – Federal”.

The Government of Alberta has also sought to alleviate these transportation constraints by pursuing different transportation modalities and creating new markets. On November 28, 2018, the Government of Alberta announced that Alberta had started negotiations for investment in new rail capacity to address the historically high price differential. On February 19, 2019, the Government of Alberta announced that it would lease 4,400 rail cars capable of transporting 120,000 bbl/day of crude oil out of the province. The Alberta Petroleum Marketing Commission will purchase crude oil from producers and market it, using the expanded rail capacity to transport the marketed oil to purchasers. The Government expects the first railcars to be in service by July 2019 and believes this strategy will: (i) narrow the crude oil price gap by up to $4 per barrel; and (ii) provide junior producers with a more affordable option to move their crude oil to market.

On December 11, 2018, the Government of Alberta announced a Request for Expressions of Interest to create new refining capacity or expand existing capacity. Little is known about this strategy, but the deadline for interested parties to submit Expressions of Interest was February 8, 2019, and an internal governmental committee is currently reviewing such submissions.

Natural gas prices in Alberta and British Columbia have also been constrained in recent years due to increasing North American supply, limited access to markets and limited storage capacity. While 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, other companies 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. Additionally, while a number of liquefied natural gas export plants have been proposed for the west coast of Canada, 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. In October 2018, the proponents of the LNG Canada liquefied natural gas export terminal announced a positive final investment decision to proceed with the project.

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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 (Alberta), the Government of Alberta will, on a monthly basis, direct crude oil producers producing more than 10,000 bbl/d to curtail their production according to a pre-determined formula that apportions production limits proportionately amongst those operators subject to a curtailment order. The first curtailment order took effect on January 1, 2019, limiting province-wide production of crude oil and crude bitumen to 3.56 million bbl/d—a reduction of approximately 8.7% of total daily average crude oil production in Alberta during December 2018. The Government of Alberta indicated that it expected the curtailment rate to gradually drop over the course of 2019. As a result of decreasing price differentials and volumes of crude oil and crude bitumen in storage, the Government of Alberta announced on January 30, 2019 that it would ease the mandatory production curtailment beginning February 1, 2019, increasing the allowable production cap by 75,000 bbl/d to a maximum output of approximately 3.63 million bbl/d. The Corporation is subject to a curtailment order. The curtailment order has led to the Company reducing repair and maintenance work, delaying bringing on new development wells and the shut in of marginally economic production across the Company’s asset base through January and February. As curtailment production caps have increased in February and March and new well declines have impacted overall production capacity, the Company will bring on new wells previously delayed.

The North American Free Trade Agreement and Other Trade Agreements

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the United States and Mexico came into force on January 1, 1994. 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.

On November 30, 2018, U.S. President Donald Trump, Prime Minister Trudeau, and outgoing Mexican President Enrique Pena Nieto signed an authorization for a new trade deal that will replace NAFTA, referred to as the United States-Mexico-Canada Agreement (“USMCA”). However, NAFTA remains the North American trade agreement currently in force until the legislative bodies of the three signatory countries ratify the USMCA. Amid political uncertainty in Canada, Mexico, and the United States it is unclear when the end of the NAFTA era will be. As the United States remains by far Canada’s largest trade 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.

As discussed above, at the end of 2018 the Government of Alberta announced a curtailment of Alberta’s crude oil and crude bitumen production for 2019. Curtailment 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 reduces 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 is at depressed prices, may be reduced. It is not clear whether the USMCA will come into force before the Government of Alberta’s curtailment order is repealed automatically on December 31, 2019.

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.

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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 certain national legislatures in the European Union, provisional application of CETA commenced on September 21, 2017. In addition, Canada and ten other countries recently concluded discussions and agreed on the draft 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. On December 30, 2018, the CPTPP came into force among the first six countries to ratify the agreement – Canada, Australia, Japan, Mexico, New Zealand, 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. The 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 estate 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 in 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. Additionally, the provinces of Alberta and British Columbia have shallow rights reversion for 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 each of the provinces 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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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 governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical 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.

In addition, the federal government may from time to time provide incentives to the oil and gas industry. In November 2018, the federal government announced its plans to implement an accelerated investment incentive, which will provide oil and gas businesses with eligible Canadian development expenses and Canadian oil and gas property expenses with a first-year deduction of one and a half times the deduction that is otherwise available. The federal government also announced in late 2018 that it will make $1.6 billion available to the crude oil and natural gas industry in light of worsening commodity price differentials. The aid package, however, is mostly in the form of loans and is earmarked for crude oil and natural gas projects related to economic diversification as well as direct funding for clean growth crude oil and natural gas projects.

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.

Alberta

In Alberta, the provincial government royalty rates apply to Crown-owned mineral rights. In 2016, Alberta adopted a modernized Alberta 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 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. 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.

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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 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.

IOGC is a special agency responsible for managing and regulating the crude oil and natural gas resources located on indigenous reservations across Canada. IOGC’s responsibilities include negotiating and issuing the crude oil and natural gas agreements between indigenous groups and crude oil and natural gas companies, as well as collecting royalty revenues on behalf of indigenous groups and depositing the revenues in their trust accounts. While certain standards exist, 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 terms.

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, may impose further requirements on operators and other companies in the crude oil and natural gas industry.

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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. However, such conflicts are uncommon. 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 June 20, 2016, the federal government launched a review of current environmental and regulatory processes. On February 8, 2018, the Government of Canada introduced draft legislation to overhaul the existing environmental assessment process and replace the NEB with the CER. Pursuant to the draft legislation, the Impact Assessment Agency of Canada (the “Agency”) would replace the Canadian Environmental Assessment Agency. It appears that additional categories of projects may be included within the new impact assessment process, such as large-scale wind power facilities and in-situ oilsands facilities. The revamped approval process for applicable major developments will have specific legislated timelines at each stage of the formal impact assessment process. The Agency’s process would focus on: (i) early engagement by proponents to engage the Agency and all stakeholders such as the public and indigenous groups prior to the formal impact assessment process; (ii) potentially increased public participation where the project undergoes a panel review; (iii) providing analysis of the potential impacts and effects of a project without making recommendations, to support a public-interest approach to decision-making, with cost-benefit determinations and approvals made by the Minister of Environment and Climate Change or the Cabinet; (iv) analyzing further specified factors for projects such as alternatives to the project and social and indigenous issues in addition to health, environmental and economic impacts; and (v) overseeing an expanded follow-up, monitoring and enforcement process with increased involvement of indigenous peoples and communities. As to the proposed CER, many of its activities would be similar to the NEB, albeit with a different structure and the notable exception that the CER would no longer have primary responsibility in the consideration of the new major projects, instead focusing on the lifecycle regulation (e.g. overseeing construction, tolls and tariffs, operations and eventual winding down) of approved projects, while providing for expanded participation by communities and indigenous peoples. It is unclear when the new regulatory scheme will come into force or whether any amendments will be made prior to coming into force. Until then, the federal government’s interim principles released on January 27, 2016 will continue to guide decision-making authorities for projects currently undergoing environmental assessment. The eventual effects of the proposed regulatory scheme on proponents of major projects remains unclear.

On May 12, 2017, the federal government introduced the Oil Tanker Moratorium Act 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 is still considering the bill, which passed second reading on October 4, 2017. If implemented, the legislation may prevent the building of pipelines to, and export terminals located on, the portion of the British Columbia coast subject to the moratorium and, as a result, negatively affect 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 Acts 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 Alberta 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 Alberta Environment and Parks, Alberta Energy, the Policy Management Office, the Aboriginal Consultation Office and the Land Use Secretariat.

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

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”). At its core, the AER uses the AB LMR Program to aid in determining the ability of licensees to manage the abandonment and reclamation obligations associated with the licensee’s assets. 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”). The AER assesses the LMR of all licensees on a monthly basis and posts the ratings on the AER’s public website. 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.

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 (“WIP”) becomes insolvent or is unable to meet its obligations. Licensees in the AB LLR Program and AB OWL Program fund the Orphan Fund through a levy administered by the AER. 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.

In Redwater Energy Corporation (Re) (“Redwater”), the Court of Queen’s Bench of Alberta found that there was an operational conflict between the abandonment and reclamation provisions of the provincial OGCA, including the AB LLR Program, and the federal Bankruptcy and Insolvency Act (the “BIA”). This ruling meant that receivers and trustees of insolvent entities had the right to renounce assets within insolvency proceedings, and was affirmed by a majority of the Alberta Court of Appeal. On January 31, 2019, the Supreme Court of Canada overturned the lower courts’ decisions, 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 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 pending a final decision from the Supreme Court of Canada. The AER amended its Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, which deals with licencee 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. While the Supreme Court of Canada’s Redwater decision alleviates some of the concerns that the AER’s rule changes were intended to address, it is unclear how or if the AER will respond.

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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 by 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 completed its third year on March 31, 2018 but the AER has not yet released its third annual report.

As part of its strategy to encourage the decommissioning of inactive or marginal oil and 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 while enabling participants to meet their liability reduction targets. The Corporation is 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 regulation of the crude oil and natural gas industry in Canada.

In general, there is some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as 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 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 January 1, 2019, 185 of the 197 parties to the convention have ratified the Paris Agreement. In December 2018, the United Nations annual Conference of the Parties took place in Katowice, Poland. The Conference concluded with the attendees reiterating their commitment to the targets set out in the Paris Agreement and establishing a transparency framework related to, among other matters, emissions and climate finance reporting.

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, increasing annually until it reaches $50/tonne in 2022. A draft legislative proposal for the federal carbon pricing system was released on January 15, 2018. This system would apply 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 in 2018. Seven provinces and territories have introduced carbon-pricing systems that would meet federal requirements (Alberta, British Columbia, Quebec, Prince Edward Island, Nova Scotia, Newfoundland and Labrador and the Northwest Territories). The federal carbon-pricing regime will take effect in Saskatchewan, Manitoba, Ontario and New Brunswick in April 2019; it will take effect in the Yukon and Nunavut in July 2019. Saskatchewan and Ontario have challenged the constitutionality of the federal government’s pricing regime; New Brunswick has intervened in Saskatchewan’s constitutional challenge. In October 2018, the federal government announced an alternative pricing scheme for large electricity generators designed to incentivize a reduction in emissions intensity, rather than encouraging a reduction in generation rates.

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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, but will not come into force until 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 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.

Alberta

On November 22, 2015, the Government of Alberta introduced its Climate Leadership Plan (the “CLP”). The CLP has four areas of focus: implementing a carbon price on GHG emissions, phasing out coal-generated electricity and developing renewable energy, legislating an oil sands emission limit, and introducing a new methane emissions reduction plan. The Government of Alberta has since introduced new legislation to give effect to these initiatives. The Climate Leadership Act came into force on January 1, 2017 and enabled a carbon levy that increased from $20 to $30 per tonne on January 1, 2018. While the levy is anticipated to increase again in 2021 in line with the federal legislation, the Government of Alberta has announced it will not proceed with the scheduled 2021 increase unless the expansion to the Trans Mountain Pipeline proceeds. 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.

The Carbon Competitiveness Incentives Regulation (the “CCIR”), which replaces the Specified Gas Emitters Regulation, came into effect on January 1, 2018. Unlike the previous regulation, which set emission reduction requirements, the CCIR imposes an output-based benchmark on competitors in the same emitting industry. The aim is to reduce annual GHG emissions by 20 megatonnes by 2020 and 50 megatonnes by 2030, and targets facilities that emit more than 100,000 tonnes of GHGs per year and mandates quarterly and final reporting requirements. The CCIR compliance obligations will be reduced by 50% and 25% for 2018 and 2019, respectively, with no reduction for 2020 onward. In addition to the industry-specific benchmarks, each benchmark will decrease annually at a rate of 1%, beginning in 2020. The Government of Alberta intends for this strategy to align with the federal Framework.

The Government of Alberta also signaled its intention through its CLP to implement regulations that would lower annual methane emissions by 45% by 2025. Regulations are planned to take effect in 2020 to ensure the 2025 target is met.

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 over 15 years to fund two large-scale carbon capture and storage projects that will begin commercializing the technology on the scale needed to be successful. 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, 2018, see “– Disclosure of Reserves Data – Total Future Net Revenue (Undiscounted) as of December 31, 2018 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.

Obsidian Energy does not operate any facilities in Alberta that are regulated to reduce GHG emissions and has no facilities that are required to report their emissions and remit the carbon levy until 2023. Obsidian Energy has minor working interests in several non-operated facilities that are required to meet the requirements of the Alberta GHG regulations. Obsidian Energy’s financial obligations related to compliance with existing federal and provincial legislation regarding GHG emissions is 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 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. The following information is a summary only of certain risk factors 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 supply, demand, market uncertainty and other factors that are beyond our control. These factors include, but are not limited to:

• the limitations on the ability of Western Canadian energy producers to export oil, 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;

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• the availability of transportation infrastructure, and in particular:

• our ability to acquire space on pipelines that deliver crude oil 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;

• global energy policy, including the ability of OPEC (and in particular the Kingdom of Saudi Arabia) and other oil and gas exporting nations to set and maintain production levels and influence prices for oil;

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

• existing and threatened political instability and hostilities in 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 level of energy demand;

• production and storage levels of oil and natural gas;

• 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;

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

Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by OPEC, slowing growth in China and emerging economies, market volatility and disruptions in Asia, weakening global relationships, isolationist trade policies, increased U.S. shale production, sovereign debt levels and political upheavals in various countries, have caused significant weakness and volatility in commodity prices. These events and conditions have caused a significant decrease 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 tax, royalty, environmental and other regulatory regimes. In addition, the inability to get the necessary approvals 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 and uncertainty and reduced confidence in the oil and gas industry in western Canada. 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

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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.

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 concerns regarding the effects of the use of fossil fuels on climate change, the impact of oil and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation, and indigenous rights, have affected certain investors’ sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail 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 change.

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 the market price of our Common Shares.

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

In the last several years, the United States and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. Since the 2016 U.S. presidential election, the American administration has begun taking steps to implement certain of its promises made during the campaign. The administration has withdrawn the United States from the Trans-Pacific Partnership and Congress has passed sweeping tax reform, which, among other things, significantly reduces U.S. corporate tax rates. This may affect 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 which will replace NAFTA once ratified by the three signatory countries. 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 citizens of the United Kingdom voted to withdraw from the European Union and the Government of the United Kingdom has taken steps to implement such withdrawal. The terms of the United Kingdom’s exit from the European Union and whether it will occur at all 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. 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.

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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, such as the impact of the change of government in British Columbia and announcements and actions by the government of British Columbia that impact the completion of the Trans-Mountain Pipeline project, liquefied natural gas facilities and other infrastructure projects.

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 devices 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 its assets.

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 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. Recently, the federal government and certain provincial governments have taken steps to initiate protocols and regulations to limit the release of methane from oil and gas operations. Such draft regulations and protocols may require additional expenditures or otherwise negatively impact the Corporation’s operations, which may affect the Corporation’s profitability. See “Industry Conditions”. Also, in response to widening pricing differentials, the Government of Alberta implemented production curtailment. See “Industry Conditions – Curtailment” for further details.

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 – Regulatory Authorities and Environmental Regulation – Liability Management Rating Programs” for further details.

We use conventional recovery methods, such as horizontal multi-stage fracturing technology, and non-conventional recovery methods, such as enhanced oil recovery technologies, both of which are subject to significant risk factors which could lead to the delay or cancellation of some or all of our projects, which could adversely affect the market price of our Common Shares.

Obsidian Energy utilizes new drilling and completion technologies, including horizontal multi-stage fracture completions, intended to increase the resource recovery from known oil and natural gas fields. However, Obsidian Energy may not realize the anticipated increase in resource recovery from the employment of such techniques due to particular reservoir characteristics or other adverse factors.

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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 being 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.

Due to seismic activity reported in the Fox Creek area of Alberta, in 2015 the AER announced seismic monitoring and reporting requirements for hydraulic fracturing operators in the Duvernay zone in the Fox Creek area. These requirements include, among others, 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 if a seismic event above a particular threshold occurs. These requirements will remain in effect as long as the AER deems them necessary. Further, although we do not currently own oil and gas assets in the Fox Creek area, the AER continues to monitor seismic activity around the province and may extend these requirements to other areas of the province where we do own oil and gas assets if necessary.

The potential or planned use of enhanced oil recovery (“EOR”) methods such as steam injection (steam assisted gravity drainage, cyclical steam stimulation and steam flooding), water injection, solvent injection and firefloods to increase the ultimate recovery of oil resources in place are subject to significant risk factors. These factors include but are not limited to the following:

• changing economic conditions (including commodity pricing and operating and capital expenditure fluctuations);

• changing engineering and technical conditions (including the ability to apply EOR methods to the reservoir and the production response thereto);

• large development programs may need to be spread over a longer time period than initially planned due to the requirement to allocate capital expenditures to different periods;

• surface access and deliverability issues (including landowner and stakeholder relations, weather, pipeline, road and processing matters);

• environmental regulations relating to such items as GHG emissions and access to water, which could impact capital and operating costs; and

• the availability of sufficient financing on acceptable terms.

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.

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 and flooding; 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.

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;

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• 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.

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. This program involves an assessment of the ratio of a licensee’s deemed assets to deemed liabilities. If a licensee’s deemed liabilities exceed its deemed assets, a security deposit is generally required. Changes to the required ratio of our deemed assets to deemed liabilities or other changes to the requirements of liability management programs may result in significant increases to the Corporation’s compliance obligations. In addition, the liability management regime 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 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. The impact and consequences of the Supreme Court of Canada’s decision in the Redwater case 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 will no doubt evolve as the consequences of the decision are evaluated and considered by regulators, lenders and receivers/trustees. See “Industry Conditions – Regulatory Authorities and Environmental Regulation – Liability Management Rating Programs”.

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 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.

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

An increase in interest rates could result in a significant increase in the amount we pay to service debt, resulting in a reduced amount available to fund our exploration and development activities which could negatively impact the market price of the Common Shares.

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, less the amount of our pari passu Senior Notes outstanding. The revolving period of the credit facility ends on May 31, 2019, with an additional one year term out period, and is subject to a semi-annual borrowing base redetermination in May and November of each year. As of December 31, 2018, there was $337 million drawn on our credit facility. In the event that our credit facility is not extended before the maturity date, all outstanding indebtedness under such tranche will be repayable at that date. 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 continue to be depressed and have fallen dramatically since 2014, and while prices have recently increased they remain volatile as a result of various factors including limited egress options for Western Canadian oil and natural gas producers, actions taken to limit OPEC and non-OPEC production and increasing production by U.S. shale producers. Depressed commodity prices could reduce the Corporation’s borrowing base, reducing the funds available to the Corporation under the credit facility. This could result in the requirement to repay a portion, or all, of the Corporation’s indebtedness.

We also currently have US$60 million principal amount of Senior Notes outstanding, which have maturity dates ranging between 2019 and 2025. 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. 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, which could result in the Corporation being required to repay amounts owing thereunder.

The impact of the Supreme Court of Canada’s decision in the Redwater case on lending practices in the crude oil and natural gas sector and actions taken by secured creditors and receivers/trustees of insolvent borrowers has not yet been determined but could affect lending practices as secured creditors will be subject to prior satisfaction of abandonment and restoration claims which may not be capable of quantification at the time credit is advanced. See “Industry Conditions – Regulatory Authorities and Environmental Regulation – Liability Management Rating Programs”.

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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.

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 resources that allow them to implement and benefit from technological advantages 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. In such case, our business, financial condition and results of operations could be materially adversely affected. 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.

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 weather;

• 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.

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Actual reserves will vary from reserves 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;

• changes in technology;

• 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 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;

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• 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.

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. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Roads 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 oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of 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 recent years, 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 in recent years 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, 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. 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 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”.

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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. An increase in royalties would reduce our earnings and could make future capital investments, or our operations, less economic. On January 29, 2016, the Government of Alberta adopted a new royalty regime which took effect on January 1, 2017. 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 state of the market 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 above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither our articles nor our by-laws limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise, and may adversely affect the market price of our Common Shares if investors consider our debt levels to be higher than that of our peers.

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

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In addition, the Corporation’s oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Corporation’s properties, wells or facilities are the subject of 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, 2018 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 acquisition, exploration, development 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.

Further, if the Corporation’s revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. The conditions in, or affecting, the oil and gas industry have at times negatively impacted the ability of some 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 at times negatively impacted the ability of some oil and gas companies to access additional financing or increased the cost of such financing.

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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 and of joint venture partners 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.

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

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The impact on us of claims of aboriginal title is unknown.

Aboriginal peoples have claimed aboriginal title and rights to portions of Western Canada. We are not aware that any material claims have been made in respect of our properties and assets; however, if a material claim arose and was successful this could have an adverse effect on our results of operations and business. In addition, the process of addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays which could have a material adverse effect on our business and financial results.

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.

An inability to recruit and retain a skilled workforce 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, could result in the failure to implement the Corporation’s business plans. The Corporation competes with other companies in the oil and natural gas industry as well as other industries for this skilled workforce. A decline in market conditions has prompted increasing numbers of skilled personnel to seek employment in other industries. 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.

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

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

In addition, due to the current low and volatile commodity price environment, many companies, including companies that may operate some of the assets in which the Corporation has an interest, may be in financial difficulty, which could impact their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner, and satisfy regulatory requirements with respect to abandonment and reclamation obligations. If companies that operate some of the assets in which the Corporation has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations, the Corporation may be required to satisfy such obligations and to seek reimbursement from such companies. To the extent that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in such assets being shut-in, the Corporation potentially becoming subject to additional liabilities relating to such assets, and the Corporation having difficulty collecting revenue due from such operators or recovering amounts owing to the Corporation from such operators for their share of abandonment and reclamation obligations. Any of these factors could have a material adverse affect on the Corporation’s financial and operational results.

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A portion of the Corporation’s revenues from royalty payers and certain of 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. In addition, weak commodity prices and/or governmental production curtailment might 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 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.

We may incur material expenses complying with new or amended laws and regulations governing climate change.

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. As a signatory to the United Nations Framework Convention on Climate Change and a signatory to the Paris Agreement, which was ratified in Canada on October 3, 2016, the Government of Canada pledged to cut its GHG emissions by 30 per cent from 2005 levels by 2030. One of the pertinent policies announced to date by the Government of Canada to reduce GHG emission is the planned implementation of a nation-wide price on carbon emissions. The federal carbon levy goes into effect on April 1, 2019 and will affect provinces which have not implemented their own carbon taxes, cap-and-trade systems or other plans for carbon pricing, namely Ontario, Manitoba, Saskatchewan and New Brunswick. The federal carbon levy will be at an initial rate of $20 per tonne. Provincially, the Government of Alberta has already implemented a carbon levy on almost all sources of GHG emissions, now at a rate of $30 per tonne. The implementation of the federal carbon levy is currently subject to constitutional challenges submitted by the Provinces of Saskatchewan and Ontario, which are supported by the Province of New Brunswick. 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.

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. Historically, political and legal opposition to the fossil 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 a class action against the Government of Canada for climate related matters. 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 climate related harms.

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Given the evolving nature of the debate related to climate change and the control of GHG 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 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 asset write-offs. See “Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation”.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather could interfere with the Corporation’s production and increase the Corporation’s costs. At this time, the Corporation is unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting its operations.

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. See “Industry Conditions”. In Canada, the federal and certain provincial governments have implemented legislation aimed at incentivizing the use of alternative fuels and in turn reducing carbon emissions. The 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.

We depend upon our management and other key personnel and the loss of one or more of such individuals could negatively affect our business.

The Corporation’s success depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. The Corporation does not have any key personnel insurance in effect. The 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, the 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. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of the Corporation.

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

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

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

We deliver our products through gathering and processing facilities, pipeline systems and, in certain circumstances, by railway systems. The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities, pipeline systems and railway lines. Notwithstanding the Government of Alberta’s plans to purchase 4,400 rail cars and the implementation of production curtailment in Alberta, the ongoing lack of availability of capacity in any of the gathering and processing facilities, pipeline systems or railway lines, 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. The lack of firm pipeline capacity continues to affect the oil and natural gas industry and limits the ability to transport produced oil and natural gas to market. In addition, the pro-rationing of capacity on inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas. 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 are increasingly turning to rail lines 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. In addition, while the federal government has introduced Bill C-69 to overhaul the existing environmental assessment process and replace the NEB with a new regulatory agency, the impact of the new proposed regulatory scheme on proponents and the timing for receipt of approvals for major projects remains unclear.

Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board of Canada and the U.S. National Transportation Board have recommended additional regulations for railway tank cars carrying crude oil. In June 2015, as a result of these recommendations, the Government of Canada passed the Safe and Accountable Rail Act, which increased insurance obligations on the shipment of crude oil by rail and imposed a per tonne levy of $1.65 on crude oil shipped by rail to compensate victims and for environmental cleanup in the event of a railway accident. In addition to this legislation, new regulations have implemented the TC-117 standard for all rail tank cars carrying flammable liquids, which formalized the commitment to retrofit, and eventually phase out, DOT-111 tank cars carrying crude oil. The increased regulation of rail transportation may reduce the ability of rail transportation to alleviate pipeline constraints and add additional costs to the transportation of crude oil by rail. On July 13, 2016, the Minister of Transport (Canada) issued Protective Direction No. 38, which directed that the shipping of crude oil on DOT-111 tank cars end by November 1, 2016. Tank cars entering Canada from the United States will be monitored to ensure they are compliant with Protective Direction No. 38.

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.

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

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

Our inability to manage growth could adversely affect our business.

We may be subject to growth related risks, including capacity constraints and pressures on our internal systems and controls. These constraints and pressures could result from, among other things, the completion of large acquisitions. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base. Our inability to deal with this growth could have a material adverse impact on our business, operations and prospects.

The market price of our Common Shares has been and will likely continue to be volatile and may at times be less than our net asset value per Common Share.

The trading price of securities of oil and natural gas issuers is subject to substantial volatility and is often based on factors both related and unrelated to the financial performance or prospects of the issuers involved. Factors unrelated to our performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices 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, 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.

Our net asset value from time to time will vary depending upon a number of factors beyond our control, including oil and gas prices. The trading price of the Common Shares from time to time is determined by a number of factors, some of which are beyond our control and such trading price may be greater or less than our net asset value.

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 interest of the Corporation in properties may accordingly vary from the Corporation’s records. If a title defect does exist, it is possible that the Corporation may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. There may be valid challenges to title or legislative changes, which affect the Corporation’s title to 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.

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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 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 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”.

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.

We may in the future expand our operations into new geographical regions where our existing management does not have experience. In addition, we may in the future acquire new types of energy related assets in respect of which our existing management does not have experience. Any such expansion or acquisition could result in our exposure to new risks that if not properly managed could ultimately have an adverse effect on our business and the market price of our Common Shares.

The operations and expertise of our management are currently focused primarily on oil and gas production, exploration and development in the Western Canada Sedimentary Basin. In the future, we may acquire or develop oil and gas properties outside of this geographic area. In addition, we could acquire other energy related assets, such as upgraders or pipelines. Expansion of our activities into new areas may present new risks or alternatively, significantly increase our exposure to one or more existing risk factors, which may in turn result in our future operational and financial conditions being adversely affected.

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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 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. In addition, environmental damage, loss of life, injury or damage to property caused by the Corporation’s operations 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 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 phishing attacks through education and training, 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

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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 addition, the Corporation has at times failed to comply with the NYSE’s continued listing standards due to the average closing price of the Common Shares being less than US$1.00 per share over a consecutive 30 trading day period. The Corporation is currently not in compliance with this continued listing standard. If the Corporation receives notice from the NYSE of its non-compliance with this listing standard and is subsequently unable to regain compliance with such listing standard during the applicable cure period, the Common Shares would be suspended from trading and subsequently delisted from the NYSE. 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, diluents supply may increase the Corporation’s operating costs.

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

Forward-Looking Information May Prove Inaccurate.

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

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

57

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) 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 31, 2007 (as amended on December 2, 2010, August 15, 2014, May 22, 2015, August 23, 2017, November 7, 2018 and March 6, 2019) among Obsidian Energy and the holders of our Series B, Series C and Series D Senior Notes, which agreement is described under “Capitalization of Obsidian Energy – Debt Capital – Senior Notes”;

(c) 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 and March 6, 2019) 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”;

(d) the note purchase agreement dated May 5, 2009 (as amended on December 2, 2010, August 15, 2014, May 22, 2015, August 23, 2017, November 7, 2018 and March 6, 2019) among Obsidian Energy and the holders of our Series K, Series L, Series M, Series N and Series O Senior Notes, which agreement is described under “Capitalization of Obsidian Energy – Debt Capital – Senior Notes”;

(e) 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 and March 6, 2019) 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”;

(f) 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 and March 6, 2019) 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

(g) the note purchase agreement dated November 30, 2011 (as amended on August 15, 2014, May 22, 2015, August 23, 2017, November 7, 2018 and March 6, 2019) 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.

58

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 within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations, and also that they are independent accountants with respect to Obsidian Energy under all relevant US professional and regulatory standards.

59

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).

60

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, 2018, 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) “David L. French”	(signed) “David Hendry”
President and Chief Executive Officer	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 6, 2019

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, 2018. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2018, 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, 2018, 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, 2018)		Canada		nil	$	1,702		nil	$	1,702
	January 24, 2019

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

January 24, 2019

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 6, 2019 is set forth below (the “Statement”). The effective date of the Statement is December 31, 2018 and the preparation date of the Statement is March 6, 2019. 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, 2018 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, 2018, 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”.

A3-2

SUMMARY OF OIL AND GAS RESERVES

AS OF DECEMBER 31, 2018

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		33		30		6		5
Developed Non-Producing		1		1		—		—
Undeveloped		14		13		1		1
TOTAL PROVED		47		43		7		6
PROBABLE		17		14		4		3
TOTAL PROVED PLUS PROBABLE		64		57		11		10

	RESERVES
	CONVENTIONAL NATURAL GAS				NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross (Bcf)		Net (Bcf)		Gross (MMbbl)		Net (MMbbl)
PROVED
Developed Producing		131		126		6		5
Developed Non-Producing		3		3		—		—
Undeveloped		41		39		2		2
TOTAL PROVED		176		168		8		7
PROBABLE		57		54		3		2
TOTAL PROVED PLUS PROBABLE		233		222		11		9

	RESERVES
	TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (MMboe)		Net (MMboe)
PROVED
Developed Producing		66		61
Developed Non-Producing		2		2
Undeveloped		24		22
TOTAL PROVED		92		84
PROBABLE		33		29
TOTAL PROVED PLUS PROBABLE		125		112

A3-3

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2018

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		2,140		1,474		1,128		921		784		18.61		3.10
Developed Non-Producing		43		33		26		22		19		16.93		2.82
Undeveloped		592		285		140		63		17		6.46		1.08
TOTAL PROVED		2,774		1,792		1,294		1,006		820		15.43		2.57
PROBABLE		1,417		674		408		282		212		14.29		2.38
TOTAL PROVED PLUS PROBABLE		4,191		2,466		1,702		1,288		1,032		15.14		2.52

Note:

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

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2018

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		2,140		1,474		1,128		921		784
Developed Non-Producing		43		33		26		22		19
Undeveloped		529		272		137		62		17
TOTAL PROVED		2,711		1,779		1,292		1,005		820
PROBABLE		1,044		552		361		262		203
TOTAL PROVED PLUS PROBABLE		3,755		2,332		1,653		1,268		1,022

A3-4

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

AS OF DECEMBER 31, 2018

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		6,211		611		2,063		511		252		2,774		63		2,711
Proved Plus Probable Reserves		8,874		1,020		2,759		618		286		4,191		436		3,755

FUTURE NET REVENUE

BY PRODUCTION TYPE

AS OF DECEMBER 31, 2018

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)		1,073		17.54		2.92
	Heavy Crude Oil and Bitumen(1)		104		13.59		2.26
	Conventional Natural Gas(2)		118		7.81		1.30
	Non-Conventional Oil and Gas Activities(1)		—		1.78		0.30
	TOTAL		1,294		15.43		2.57
Proved Plus Probable	Light and Medium Crude Oil(1)		1,416		17.28		2.88
Reserves	Heavy Crude Oil and Bitumen(1)		146		12.78		2.13
	Conventional Natural Gas(2)		140		7.36		1.23
	Non-Conventional Oil and Gas Activities(1)		—		2.10		0.35
	TOTAL		1,702		15.14		2.52

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.

A3-5

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.

(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.

A3-6

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.

A3-7

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

AS OF DECEMBER 31, 2018

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
2019		63.00			75.27			59.47			1.95			30.27			40.91			75.32			—		0.77
2020		67.00			77.89			62.31			2.44			34.51			50.25			80.00			2.0		0.80
2021		70.00			82.25			67.45			3.00			38.15			56.88			83.75			2.0		0.80
2022		71.40			84.79			69.53			3.21			39.64			58.01			85.50			2.0		0.80
2023		72.83			87.39			71.66			3.30			40.62			59.17			87.29			2.0		0.80
2024		74.28			89.14			73.10			3.39			41.62			60.36			89.11			2.0		0.80
2025		75.77			90.92			74.56			3.49			42.64			61.56			90.96			2.0		0.80
2026		77.29			92.74			76.05			3.58			43.68			62.79			92.86			2.0		0.80
2027		78.83			94.60			77.57			3.68			44.75			64.05			94.79			2.0		0.80
2028		80.41			96.49			79.12			3.78			45.83			65.33			96.76			2.0		0.80
2029		82.02			98.42			80.70			3.88			46.94			66.64			98.77			2.0		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, 2018 were $2.59/Mcf for natural gas, $48.99/bbl for light and medium crude oil, $33.07/bbl for heavy crude oil and $36.69/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$)		Proved Plus Probable Reserves (MM$)
2019		112		117
2020		113		131
2021		118		155
2022		127		154
2023		42		61
2024 and subsequent		—		—
Total: Undiscounted for all years		511		618

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.

A3-8

The interest and other costs of any external funding are not included in our reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized. We do not currently expect that interest or other funding costs could make development of any of our properties uneconomic.

5. Estimated future well abandonment and reclamation costs related to reserve 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, 2018, 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, 2017		47			19			66			8			3		12			194			64			258
Extensions		2			1			4			—			—		—			13			5			18
Infill drilling		1			—			1			—			—		—			3			1			3
Improved Recovery		—			—			—			—			—		—			—			—			—
Technical Revisions		2			(3	)		(1	)		—			—		—			19			(5	)		14
Discoveries		—			—			—			—			—		—			—			—			—
Acquisitions		—			—			—			—			—		—			—			—			—
Dispositions		(1	)		—			(1	)		—			—		—			(23	)		(8	)		(31	)
Economic Factors		—			—			—			—			—		—			(7	)		(1	)		(8	)
Production		(4	)		—			(4	)		(2	)		—		(2	)		(22	)		—			(22	)
December 31, 2018		47			17			64			7			4		11			176			57			233

A3-9

	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, 2017		8			3		10			96			35			131
Extensions		1			—		1			5			2			8
Infill drilling		—			—		—			2			1			2
Improved Recovery		—			—		—			—			—			—
Technical Revisions		1			—		1			6			(4	)		2
Discoveries		—			—		—			—			—			—
Acquisitions		—			—		—			—			—			—
Dispositions		—			—		—			(5	)		(2	)		(7	)
Economic Factors		—			—		—			(1	)		—			(1	)
Production		(1	)		—		(1	)		(11	)		—			(11	)
December 31, 2018		8			3		11			92			33			125

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 significant majority 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 the significant majority of the probable undeveloped reserves over the next five years. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing and/or operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals).

Proved Undeveloped Reserves

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

A3-10

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
2016		—		10		2		2		—		23		—		1
2017		3		12		1		2		11		30		1		1
2018		3		14		—		1		13		41		1		2

Sproule has assigned 24 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 $212 million, or 43 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
2016		2		10		2		2		3		23		—		1
2017		6		10		1		1		5		19		1		1
2018		1		9		—		1		5		21		—		1

Sproule has assigned 14 MMboe of probable undeveloped reserves in the Engineering Report under forecast prices and costs, together with $107 million of associated undiscounted future capital expenditures. Probable undeveloped capital spending in the first two forecast years of the Engineering Report accounts for $24 million, or 22 percent, of the total forecast undiscounted future capital expenditures for probable undeveloped reserves. These figures increase to $107 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 our experience conducting annual abandonment and reclamation programs over the past several years, the use of external consultants, and the use of comparisons to A&R Cost estimates obtained from the Alberta regulatory authorities.

A3-11

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, 2018, we expect to incur future A&R Costs in respect of approximately 5,078 net well bores, 743 facilities and 7,653 kilometres of pipelines. On an undiscounted, inflated basis, approximately 59% percent of A&R Costs relate to well bores, 35 percent to facilities and 6% percent to pipelines. The total amount of A&R Costs, net of estimated salvage values, 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, 2018		1,679		36
Anticipated to be paid in 2018		12		12
Anticipated to be paid in 2019		12		11
Anticipated to be paid in 2020		12		10
Total anticipated to be paid in 2018, 2019 and 2020		36		33

The above table includes certain A&R Costs, net of estimated salvage values, 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 $286 million, and escalated at two percent and discounted at 10 percent, these A&R Costs were $2 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, 2018 includes both unitized and non-unitized 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, 2018, the majority of our proved plus probable reserves are located in Alberta, Canada.

Major Operating Regions

Our production and reserves are attributed to approximately 32 producing properties. The Company’s Willesden Green property accounts for 35 percent of our proved plus probable reserves, no other property is above 25 percent. Obsidian Energy’s operations are currently focused on light-oil development.

A3-12

The following map illustrates Obsidian Energy’s major operating regions as at December 31, 2018.

The following is a description of our principal oil and natural gas properties and related operations and activities as at December 31, 2018. Information in respect of gross and net acres and well counts are as of December 31, 2018 and information in respect of production is for the year ended December 31, 2018, except where indicated otherwise. For information on the Company’s disposition activity in 2018 see “Description of Our Business – General Development of the Business – 2018 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. At December 31, 2018, Obsidian Energy is the largest land owner in the play, holding approximately 450 net sections of developed and undeveloped land. 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 2018 capital spending was $78 million (including lease acquisition costs) resulting in 20 (18.7 net) operated wells drilled, 6 (6.0 net) vertical injectors and 11 (1.6 net) non-operated wells.

In 2019, planned Cardium activity will continue in the Willesden Green area of the play and focus on primary development. The Company’s total capital expenditures budget for 2019 is $74 million which includes 16 horizontal producers in Willesden Green. Additionally, $6 million of non-operated capital expenditures resulting in 2.5 net producers has been allocated to 2019. Second half 2019 Capital has the flexibility to be increased by approximately $40 million of Cardium development (10 gross operated wells) if the outlook for crude oil pricing improves. The decision on Total Capital spend will be evaluated throughout 2019.

A3-13

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, 2018, Obsidian Energy had approximately 235 net sections of developed and undeveloped land in the area. In 2018, with the support of its joint venture partner, Obsidian Energy continued to focus on primary, cold flow, development within PROP, drilling a total of 8 wells (4.4 net wells) in addition to commissioning its gas gathering system to ensure compliance with Directive 84. Total capital for 2018 was $24 million. In 2019, in response to volatile commodity prices specifically heavy oil differentials, the Company has not allocated any capital to the area. The Company will continue to monitor the commodity price environment which may result in changes to its 2019 capital allocations.

Viking Development Area

The Viking development area is located in Eastern Alberta along the Alberta/Saskatchewan border. At December 31, 2018, Obsidian Energy had approximately 170 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 2018 and the Company is not anticipating any capital spending in 2019.

Deep Basin Development area

The Deep Basin development area underlies the Company’s Cardium acreage spanning an area from Drayton Valley to Rocky Mountain House in Alberta. At December 31, 2018, Obsidian Energy holds a dominant position in the area with approximately 700 net sections of developed and undeveloped land. In 2018, the Company drilled two (1.7 net) operated wells and one (0.4 net) non-operated wells in the area with for total capital of $11 million. In 2019, Obsidian Energy plans to continue to build on its activity in the area over the past two years with anticipated spending of $7 million resulting in two additional wells. The Company will continue to target liquids rich gas and oil locations that generate strong rates of return.

Optimization activity

In 2019, 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 $5 million and consists of over 25 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.

2019 Capital Budget

In November 2018, the Company announced its 2019 capital budget of $120 million which includes $92 million associated with development and existing wellbore optimization, $16 million of maintenance and corporate capital and $12 million of decommissioning expenditures. The capital budget will focus on the Company’s Willesden Green property in the Cardium. The Company’s average production guidance for 2019 was also set at 28,000 to 29,000 boe/d, and was further updated in February 2019 to 26,750 to 27,750 boe/d to reflect the recently announced mandatory production curtailment program by the Government of Alberta and the resultant shift in a portion of the Company’s capital expenditures from the first half of 2019 to the second half of 2019.

A3-14

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, 2018 – 2018 Capital Expenditure Budget and Production– and –2019 Developments—Updated 2019 Outlook and Guidance ”.

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, 2018.

	Producing								Non-Producing				Total
	Oil				Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Alberta		1,901		1,466		782		553		3,397		2,472		6,080		4,491
Northwest Territories		1		—		11		1		31		6		43		7
Saskatchewan		6		1		—		—		29		12		35		13
Manitoba		—		—		—		—		4		2		4		2
Wyoming		—		—		—		—		2		1		2		1
Total		1,908		1,467		793		554		3,463		2,493		6,164		4,514

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, 2018.

	Unproved Properties (thousands of acres)
	Gross		Net
Alberta		414		309
Northwest Territories		84		18
Total		498		327

We currently have no material work commitments on these lands. The primary lease or extension term on approximately 34,595 net acres of unproved property is scheduled to expire by December 31, 2019. The right to explore, develop and exploit these leases will be surrendered unless we qualify them for continuation based on production, drilling or technical mapping.

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

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

Tax Horizon

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

A3-15

Capital Expenditures

The following table summarizes capital expenditures related to our activities for the year ended December 31, 2018, irrespective of whether such costs were capitalized or charged to expense when incurred.

	2018 MM$
Property Acquisition Costs(1)
Proved Properties		(13	)
Unproved Properties		2
Exploration Costs(1)		—
Development Costs(1)		165
Corporate Costs		1
Total Capital Expenditures		155
Corporate Acquisitions		—
Total Expenditures		155

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, 2018.

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net
Oil						38		25
Gas and condensate		—		—		3		2
Injectors/Stratigraphic test		—		—		7		6
Total		—		—		48		33

A3-16

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2019 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		8,906		8,153		3,594		3,314		43,970		42,329		1,952		1,465		21,780		19,987
Proved Developed Non-Producing		259		237		300		287		1,397		1,326		57		47		849		793
Proved Undeveloped		1,149		1,078		60		118		5,027		4,742		268		252		2,315		2,238
Total Proved		10,315		9,468		3,954		3,719		50,392		48,400		2,277		1,764		24,944		23,018
Total Probable		799		716		195		183		3,805		3,619		231		181		1,859		1,684
Total Proved Plus Probable		11,113		10,184		4,148		3,902		54,197		52,019		2,508		1,946		26,803		24,702

The Company noted that its Willesden Green property (located in the Cardium development area) accounts for approximately 38% of the estimated production on a proved plus probable basis in 2019. 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”.

A3-17

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 2018												Year Ended December 31, 2018
	March 31			June 30			September 30			December 31
Share of Average Gross Daily Production
Light and Medium Crude Oil (bbl/d)		12,105			11,057			10,790			11,429			11,342
Heavy Crude Oil (bbl/d)		4,751			5,172			4,833			4,784			4,885
Conventional Natural Gas (MMcf/d)		61,678			60,876			59,588			65,424			61,895
NGLs (bbl/d)		2,307			2,322			2,222			2,788			2,410
Combined (boe/d)		29,443			28,697			27,777			29,905			28,953
Average Net Production Prices Received
Light and Medium Crude Oil ($/bbl)		68.66			78.50			82.70			37.88			66.60
Heavy Crude Oil ($/bbl)		31.34			46.81			45.30			7.70			33.07
Conventional Natural Gas ($/Mcf)		2.87			1.62			1.87			2.46			2.21
NGLs ($/bbl)		41.11			42.91			40.47			24.99			36.69
Combined ($/boe)		42.52			45.59			47.26			23.42			39.45
Royalties Paid
Light and Medium Crude Oil ($/bbl)		5.28			7.47			8.60			4.10			6.31
Heavy Crude Oil ($/bbl)		1.45			2.69			3.00			0.72			1.98
Conventional Gas ($/Mcf)		0.07			0.17			0.16			0.21			0.15
NGLs ($/bbl)		2.16			4.52			4.53			1.91			3.20
Combined ($/boe)		2.73			4.09			4.56			2.33			3.40
Production Costs(1)(2)(3)
Light and Medium Crude Oil ($/bbl)		22.39			24.75			21.46			23.43			23.00
Heavy Crude Oil ($/bbl)		15.58			13.62			18.11			13.19			15.10
Conventional Natural Gas ($/Mcf)		1.50			1.27			1.42			0.34			1.12
NGLs ($/bbl)		—			—			—			—			—
Combined ($/boe)		14.86			14.47			14.53			11.82			13.89
Transportation
Light and Medium Crude Oil ($/bbl)		5.59			3.56			4.60			4.32			4.54
Heavy Crude Oil ($/bbl)		5.32			5.56			5.52			5.56			5.49
Conventional Natural Gas ($/Mcf)		0.38			0.41			0.45			0.41			0.41
NGLs ($/bbl)		—			—			—			—			—
Combined ($/boe)		3.16			3.24			3.71			3.45			3.39
Risk Management Contracts Loss (Gain)
Light and Medium Crude Oil ($/bbl)		11.92			22.70			26.10			10.63			17.61
Heavy Crude Oil ($/bbl)		—			—			—			—			—
Conventional Gas ($/Mcf)		(0.34	)		(0.69	)		(0.40	)		(0.10	)		(0.38	)
NGLs ($/bbl)		—			—			—			—			—
Combined ($/boe)		4.20			7.28			9.28			3.84			6.10
Netback Received(4)
Light and Medium Crude Oil ($/bbl)		23.48			20.02			21.94			(4.60	)		15.14
Heavy Crude Oil ($/bbl)		8.99			24.94			18.67			(11.77	)		10.50
Conventional Natural Gas ($/Mcf)		1.26			0.46			0.24			1.60			0.91
NGLs ($/bbl)		38.95			38.39			35.94			23.08			33.49
Combined ($/boe)		17.57			16.51			15.18			1.98			12.67

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.

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(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) Production costs include the effect of carried operating expenses from the Company’s partner under the Peace River Oil Partnership. The Company fully utilized the deferred funding asset in December 2017.

(4) 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, 2018, Obsidian Energy produced 11 MMboe, comprised of 4 MMbbl of light and medium crude oil, 2 MMbbl of heavy crude oil, 22 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 2018, approximately 61% percent was light and medium oil, 26% percent was conventional heavy crude oil and 13% percent was NGLs. In regard specifically to crude oil, our average quality was 30 degrees API, which was comprised of an average quality for our light and medium crude oil of 38 degrees API and an average quality for our conventional heavy crude oil of 11 degrees API.

To reduce risk, we market the majority of our production to large credit-worthy counterparties or end-users on varying term contracts. Where possible we aggregate our oil on pipelines and sell on a stream basis to maximize flexibility and reduce incremental costs. We actively manage our heavy oil sales by finding opportunities to optimize netbacks through ongoing evaluation of both pipeline and rail sales opportunities based on market conditions.

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:

	2018				2017				2016
Quarter Ended	Light and Medium Crude Oil and NGLs ($/bbl)		Heavy Crude Oil ($/bbl)		Light and Medium Crude Oil and NGLs ($/bbl)		Heavy Crude Oil ($/bbl)		Light and Medium Crude Oil and NGLs ($/bbl)		Heavy Crude Oil ($/bbl)
March 31		64.25		31.34		57.00		33.21		34.49		14.76
June 30		72.32		46.81		56.12		31.61		49.66		25.18
September 30		75.49		45.30		51.06		30.36		47.01		21.67
December 31		35.35		7.70		62.70		38.12		52.34		27.09

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Natural Gas Marketing

In 2018, we received an average price from the sale of conventional natural gas, before adjustments for hedging activities, of $2.21 per mcf compared to $2.81 per mcf realized in 2017. In 2018, we diversified our gas portfolio with 20% of our gas sold into the US Midwest market, this contract is no longer outstanding in 2019. We continue to maintain a significant weighting to the Alberta market which is one of the largest and most liquid market hubs in North America.

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

Forward Contracts

We are exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. In accordance with policies approved by our Board of Directors, we may, from time to time, manage these risks through the use of swaps, collars or other financial instruments. Commodity price risk may be hedged up to a maximum of 50 percent of forecast sales volumes, net of royalties, for the balance of any current year and one year following and up to 25 percent of forecast sales volumes, net of royalties, for one additional year thereafter. Subject to the Board’s approval, our hedging limits may be increased above the maximum limits. This policy is reviewed by management and our Board of Directors from time to time and amended as necessary. In November 2017, the Board approved the Company to hedge up to a maximum of 75 percent of forecast sales volumes on natural gas and up to a maximum of 67 percent of forecast sales volumes on crude, both net of royalties for the 2018 calendar year.

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, 2018, 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 9 to our audited consolidated financial statements as at and for the year ended December 31, 2018 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.

(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;

(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.

(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.

(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 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.