Bellatrix Exploration (BXEFF) 40-F 2018 FY Annual report (Canada)

Exhibit 13.1

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED

DECEMBER 31, 2018 

March 21, 2019

TABLE OF CONTENTS

ABBREVIATIONS	i
OIL AND GAS INFORMATION ADVISORIES	i
CONVERSIONS	ii
CERTAIN DEFINITIONS	iii
FORWARD-LOOKING STATEMENTS	v
BACKGROUND	1
GENERAL DEVELOPMENT OF OUR BUSINESS	1
DESCRIPTION OF BUSINESS	4
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	6
DIVIDENDS	19
RATINGS	19
DESCRIPTION OF SHARE CAPITAL	20
MARKET FOR SECURITIES	21
PRIOR SALES	24
ESCROWED SECURITIES	24
BORROWINGS	24
DIRECTORS AND OFFICERS	27
AUDIT COMMITTEE INFORMATION	31
INDUSTRY CONDITIONS	33
RISK FACTORS	45
HUMAN RESOURCES	63
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	63
INTERESTS OF EXPERTS	63
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	63
MATERIAL CONTRACTS	63
AUDITORS, TRANSFER AGENT AND REGISTRAR	64
ADDITIONAL INFORMATION	64

APPENDIX "A" -	REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
APPENDIX "B" -	REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
APPENDIX "C" -	MANDATE OF THE AUDIT COMMITTEE

ABBREVIATIONS

Oil and Natural Gas Liquids
Bbl	barrel
Bbls	barrels
Mbbls	thousand barrels
MMbbls	million barrels
Bbls/d	barrels per day
BOPD	barrels of oil per day
NGLs	natural gas liquids

Natural Gas
Mcf	thousand cubic feet
MMcf	million cubic feet
Mcf/d	thousand cubic feet per day
MMcf/d	million cubic feet per day
MMbtu	million British Thermal Units
Bcf	billion cubic feet
GJ	gigajoule
GJ/d	gigajoules per day
MM	Million

Other
AECO	the natural gas storage facility located at Suffield, Alberta.
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale.
BOE	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 Mcfe of natural gas
BOE/d	barrel of oil equivalent per day
m3	cubic metres
MBOE	1,000 barrels of oil equivalent
Mcfe	thousand cubic feet of gas equivalent
Mcfe/d	thousand cubic feet of gas equivalent per day
MMcfe/d	million cubic feet of gas equivalent per day
$000s or $M	thousands of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

OIL AND GAS INFORMATION ADVISORIES

Where any disclosure of reserves data is made in this Annual Information Form that does not reflect all of the reserves of Bellatrix, 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 Bellatrix's Annual Report on Form 40-F for the year ended December 31, 2018 filed with the SEC, Bellatrix 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, "Extractive Activities - Oil and Gas", which disclosure complies with the SEC's rules for disclosing oil and gas reserves.

Disclosure provided herein in respect of BOEs or Mcfs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl and an Mcfe conversion ratio of 1 Bbl:6 Mcf are 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 of 6Mcf:1Bbl, utilizing a conversion on a 6Mcf:1Bbl basis may be misleading as an indication of value.

i

CONVERSIONS

To Convert From	To	Multiply By
Mcf	Cubic metres	28.174
Cubic metres	Cubic feet	35.494
Bbls	Cubic metres	0.159
Cubic metres	Bbls oil	6.292
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres (Alberta)	Hectares	0.400
Hectares (Alberta)	Acres	2.500
Acres (British Columbia)	Hectares	0.405
Hectares (British Columbia)	Acres	2.471

ii

CERTAIN DEFINITIONS

In this Annual Information Form, the following words and phrases have the following meanings, unless the context otherwise requires:

"2019 Capital Budget" has the meaning ascribed to such term under the heading "General Development of our Business - 2019 Capital Budget";

"2L Notes" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowings and Financings - Second Lien Refinancing";

"ABCA" means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, as amended, including the regulations in respect thereof;

"Applicable Securities Laws" means all applicable securities laws, the respective regulations, rules and orders made thereunder, and all applicable policies and notices issued by the securities regulatory authorities of Canada;

"Bellatrix", the "Corporation", "we", "us" or "our" means Bellatrix Exploration Ltd.;

"Bellatrix Alder Flats Gas Plant" means the O'Chiese Ness-Ohpawganu'ck deep-cut gas plant in the Alder Flats area of Alberta;

"Board" means the board of directors of Bellatrix;

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;

"Common Shares" means the common shares in the capital of Bellatrix;

"Convertible Debentures" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowings and Financings - Convertible Debenture and Subscription Receipt Offering";

"Convertible Debenture andSubscription Receipt Offering" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowings and Financings - Convertible Debenture and Subscription Receipt Offering";

"Credit Facilities" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowings and Financings - Credit Facilities";

"Debenture Indenture" means the indenture dated August 9, 2016 between Bellatrix and Computershare Trust Company of Canada, as trustee, pursuant to which the Convertible Debentures were issued;

"Exchange Agreements" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowings and Financings - Senior Note Exchanges";

"First Lien Credit Agreement" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowings and Financings - Credit Facilities";

"gross" means:

(a) in relation to our interest in production and reserves, our "company gross" reserves, which are our working interest (operating and non-operating) share before deduction of royalties and without including any of our royalty interests;

(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;

"InSite" means InSite Petroleum Consultants Ltd., independent oil and gas reservoir engineers;

"InSite Report" means the report prepared byInSite dated March 7, 2019evaluating our crude oil, NGLs and natural gas reserves as at December 31, 2018;

"Keyera Transaction" has the meaning ascribed to such term under the heading "General Development of our Business - Acquisitions and Divestures - Disposition of Interest in Bellatrix Alder Flats Gas Plant";

"net" means:

(a) in relation to our interest in production and reserves, our interest (operating and non-operating) share after deduction of royalties obligations, plus our royalty interest in production or reserves.

(b) in relation to 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;

iii

"New Money Notes" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowing and Financings - Second Lien Refinancing";

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

"NI 51-102" means National Instrument 51‑102 - Continuous Disclosure Obligations;

"Note Purchase Agreement" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowing and Financings - Second Lien Refinancing";

"NYSE" means the New York Stock Exchange;

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

"Preferred Shares" means the preferred shares issuable pursuant to Bellatrix's articles;

"SEC" means the U.S. Securities and Exchange Commission;

"Second Lien Notes" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowing and Financings - Second Lien Refinancing";

"Second Lien Refinancing" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowing and Financings - Second Lien Refinancing";

"Senior Note Exchanges" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowing and Financings - Senior Notes";

"Senior Note Indenture" means the indenture dated May 21, 2015 Between Bellatrix and U.S. Bank National Association, as trustee, pursuant to which the Senior Notes were issued;

"Senior Notes" means the 8.5% senior unsecured notes due 2020 issued by Bellatrix pursuant to the Senior Note Indenture;

"Shelf Prospectus"has the meaning ascribed to such term under the heading"General Development of our Business - Borrowings and Financings - Shelf Prospectus";

"TSX" means the Toronto Stock Exchange;

"U.S. or United States" means the United States of America, its territories and possessions, any states of the United States and the District of Columbia; and

"Warrants" has the meaning ascribed to such term under the heading "General Development of our Business - Borrowing and Financings - Second Lien Refinancing".

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. Unless otherwise specified, information in this Annual Information Form is as at the end of Bellatrix's most recently completed financial year, being December 31, 2018. All dollar amounts herein are in Canadian dollars, unless otherwise stated.

iv

FORWARD-LOOKING STATEMENTS

Certain of the statements contained herein including, without limitation, management plans and assessments of future plans and operations, Bellatrix's expected 2019 Capital Budget, the effect of refinancing the Senior Notes (as defined herein) prior to March 2020, expected timing for spending capital and expected costs, Bellatrix's future business plans and strategy, Bellatrix's criteria for evaluating acquisitions, dispositions and other opportunities, Bellatrix's intentions with respect to future acquisitions, dispositions and other opportunities, production estimates, plans with respect to excess processing and transportation commitments, plans and timing for development of undeveloped proved and probable reserves, timing of when Bellatrix may be taxable, estimated abandonment and reclamation costs, wells to be drilled, the weighting of commodity expenses, and capital expenditures and the nature of capital expenditures and the timing and method of financing thereof, may constitute "forward-looking statements" or "forward-looking information" within the meaning of Applicable Securities Laws (collectively "forward-looking statements"). Words such as "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "potential", "continue", "shall", "estimate", "expect", "propose", "might", "project", "predict", "forecast" and similar expressions may be used to identify these forward-looking statements. These statements reflect management's current beliefs and are based on information currently available to management. Forward-looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements including, but not limited to, the risk that Bellatrix may be unable to repay its debt at maturity, the risk that Bellatrix's lenders may take actions that result in Bellatrix's debt becoming due prior to maturity, the risk that Bellatrix may be unable to secure alternative financing arrangements, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and the risk factors outlined under "Risk Factors" and elsewhere herein. The recovery and reserve estimates of Bellatrix's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

Forward-looking statements are based on a number of factors and assumptions which have been used to develop such forward-looking statements but which may prove to be incorrect. Although Bellatrix believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements because Bellatrix can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the ability of Bellatrix to refinance its debt prior to maturity; the impact of increasing competition; the general stability of the economic and political environment in which Bellatrix operates; the timely receipt of any required regulatory approvals; the ability of Bellatrix to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which Bellatrix has an interest in, to operate the field in a safe, efficient and effective manner; the ability of Bellatrix to obtain financing on acceptable terms; the ability to maintain in good standing under agreements governing Bellatrix’s outstanding indebtedness; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of Bellatrix to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Bellatrix operates; and the ability of Bellatrix to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list of factors is not exhaustive of all factors and assumptions which have been used. Additional information on these and other factors that could affect Bellatrix's operations and financial results are included in reports on file with Canadian and United States securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), through the SEC website (www.sec.gov), and at Bellatrix's website (www.bxe.com). Although the forward-looking statements contained herein are based upon what management believes to be reasonable assumptions, management cannot assure that actual results will be consistent with these forward-looking statements. Investors should not place undue reliance on forward-looking statements. These forward-looking statements are made as of the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward-looking statements as a result of new information, or review them to reflect new events or circumstances except as required by Applicable Securities Laws.

v

BACKGROUND

General

Bellatrix is a publicly traded Western Canadian based growth oriented oil and natural gas company engaged in the exploration for, and the acquisition, development and production of oil and natural gas reserves, with highly concentrated operations in West Central Alberta, principally focused on profitable development of the Spirit River liquids rich natural gas play. Bellatrix was formed pursuant to a plan of arrangement completed on November 1, 2009 under which True Energy Inc. and True Newco Inc. were amalgamated under the ABCA to form a new corporation which was subsequently amalgamated under the ABCA with 1485166 Alberta Ltd. to form Bellatrix.

On December 11, 2013, Bellatrix was amalgamated with Angle Energy Inc. and its subsidiary, Angle Resources Inc., pursuant to a plan of arrangement under the ABCA, and continued under the name "Bellatrix Exploration Ltd.". Bellatrix does not have, and at December 31, 2018 did not have, any material subsidiaries.

Bellatrix's principal, head office and registered office is located at 1920, 800 - 5th Avenue S.W., Calgary, Alberta T2P 3T6. The Common Shares trade on the TSX under the symbol "BXE".

GENERAL DEVELOPMENT OF OUR BUSINESS

The following is a summary description of the development of our business since January 1, 2016.

Acquisitions, Divestures and Joint Ventures

Daewoo Acquisition

On November 23, 2018, Bellatrix entered into a definitive agreement to acquire, effective September 1, 2018, complementary assets within the Ferrier area of west central Alberta from POSCO DAEWOO E&P Canada Corporation (the "DaewooAcquisition") for total consideration of approximately $9,500,000, payable in: (i) $1,750,000 in cash; and (ii) the issuance of 6,750,000 Common Shares at a deemed price $1.1514 per Common Share. The Daewoo Acquisition consolidated Bellatrix's interest in its core Ferrier area into a 100% working interest and included production volumes from 61 gross (19.6 net) producing wells, which were producing approximately 1,250 BOE/d (65% natural gas, 35% liquids) at the time of the Daewoo Acquisition. The deemed price per Common Share issued pursuant to the Daewoo Acquisition was determined by negotiation between Daewoo and Bellatrix.

Grafton Joint Venture and Asset Acquisitions

In the second quarter of 2016, Bellatrix completed a transaction with Grafton Energy Co. I Ltd. ("Grafton"), acquiring producing assets within Bellatrix’s core Ferrier area for $29.2 million with consideration payable in Common Shares (the "Grafton Acquisition"). The acquired assets were originally earned by Grafton pursuant to a joint venture between Bellatrix and Grafton entered into in 2013 (the "Grafton Joint Venture") and consisted of Grafton’s interest in 18 gross wells and related lands, which were already operated by Bellatrix.

On November 5, 2018, the Corporation completed the acquisition, effective September 1, 2018, of the remainder of Grafton's earned interests and earned program lands pursuant to the Grafton Joint Venture. The purchase price for the acquired assets was: (i) $7.66 million in cash; (ii) 4,000,000 Common Shares issued at a deemed price of $1.4246 per Common Share (based on the volume weighted average trading price of the Common Shares on the TSX for the five days prior to the date of the definitive agreement of October 3, 2018); and (iii) $9.1 million in purchase price adjustments. The acquired assets comprised approximately 2,200 BOE/d of production at the time of the acquisition. Following the transaction, the agreement governing the Grafton Joint Venture was terminated and each of Bellatrix and Grafton released the other from all existing and future claims and obligations under or in connection with such agreement.

Facilities Monetization

Effective May 3, 2016, Bellatrix monetized certain production facilities for cash proceeds of $75 million. Bellatrix maintained operatorship and preferential access to such facilities and will pay an annual rental fee over the eight year term of the governing agreement. Bellatrix retained the option to repurchase the facilities at any time during the term of the agreement.

1

Disposition of Interest in Bellatrix Alder Flats Gas Plant

On August 9, 2016, Bellatrix completed the disposition of a 35% interest in the Bellatrix Alder Flats Gas Plant to Keyera Partnership ("Keyera") for total cash consideration of $112.5 million (the "KeyeraTransaction"). A portion of the cash consideration paid by Keyera represented a prepayment by Keyera of 35% of the estimated future construction costs of phase 2 of the Bellatrix Alder Flats Gas Plant. As part of the Keyera Transaction, Bellatrix and Keyera entered into a midstream services and governance agreement pursuant to which Bellatrix will, for a 10 year term, have exclusive access to approximately 80.5 mmcf/d of post-phase 2 commissioning capacity. In exchange for exclusive access to the purchased capacity during the term, Keyera will be entitled to receive, on an annual basis, a guaranteed fee calculated with reference to the capital fees that Keyera will otherwise receive in accordance with the terms of the construction, ownership and operation agreement governing the Bellatrix Alder Flats Gas Plant. Pursuant to the Keyera Transaction, Bellatrix remained operator and continued to hold a 25% interest in the Bellatrix Alder Flats Gas Plant with an option to reacquire a 5% interest in the plant near the end of the final year of the agreement with Keyera for a cost of $8 million. The proceeds from the sale were used to reduce Bellatrix's indebtedness under its Credit Facilities.

For additional information relating to the Alder Flats Gas Plant, see "- Other Developments - Completion of Alder Flats Plant Phase 2".

Non-Core Asset Dispositions

In the fourth quarter of 2016, Bellatrix completed two separate dispositions of non-core assets. In November 2016, Bellatrix completed the sale of certain Cardium focused assets in the greater Pembina area of Alberta for $47 million. Bellatrix received $42 million of cash consideration and was issued 2,171,667 common shares of InPlay Oil Corp., the purchaser of the assets. In April 2017, Bellatrix sold the InPlay Oil Corp. common shares. In December 2016, Bellatrix completed the sale of certain non-core assets in the greater Harmattan area of Alberta for $80 million, comprised of $65 million of net cash proceeds and a $15 million vendor take back loan. The cash proceeds from both asset dispositions were used to reduce the indebtedness of Bellatrix under its Credit Facilities. Bellatrix sold the vendor take back loan in April 2017 for $16 million.

In the third quarter of 2017, Bellatrix completed the disposition of non-core assets in the Strachan area of Alberta for cash consideration of $34.5 million. A portion of the cash proceeds were reinvested to maintain production volume guidance with the remaining portion of the proceeds applied to reduce the indebtedness of Bellatrix under its Credit Facilities.

Borrowings and Financings

Senior Note Exchanges

Beginning in May of 2018, Bellatrix entered into a series of agreements (the "ExchangeAgreements") with several arms' length third parties to exchange US$24,115,000 aggregate principal amount of Senior Notes for an aggregate of 19,900,032 Common Shares (collectively, the "Senior Note Exchanges"). Pursuant to the terms of the Exchange Agreements, the surrendered Senior Notes were exchanged at a value of US$900 for each US$1,000 principal amount of Senior Notes (the "RepurchaseValue") and the Repurchase Value was applied towards the purchase of the Common Shares at a deemed price per Common Share which was based on a 5% discount to the volume average trading price on the TSX for the five trading days preceding the dates of the respective Exchange Agreements. All accrued and unpaid interest up to but excluding the respective closing dates of the Senior Note Exchanges was satisfied by a cash payment made by Bellatrix.

The issuances of the Common Shares pursuant to the Senior Note Exchanges was qualified pursuant to prospectus supplements filed by the Corporation, copies of which are available on www.sedar.com under Bellatrix's SEDAR profile.

For additional information relating to the Senior Notes, see "Borrowings - Senior Notes".

Second Lien Refinancing

On September 11, 2018, Bellatrix completed debt refinancing transactions (the "SecondLienRefinancing") pursuant to a note purchase agreement dated July 25, 2018, as amended (the "Note Purchase Agreement"), between Bellatrix and certain funds advised by FS/EIG Advisor, LLC and FS/KKR Advisor, LLC (the "ExchangingNoteholders") whereby the Exchanging Noteholders (i): agreed to exchange US$80.12 million of outstanding Senior Notes for US$72.108 million aggregate principal amount of 8.5% second lien notes due 2023 (the "SecondLienNotes"); (ii) were granted 3,088,205 warrants ("Warrants") to purchase Common Shares at an exercise price of $1.30 per Common Share expiring five years from the date of issuance; and (iii) committed to fund, through the purchase of additional Second Lien Notes for cash (the "New Money Notes"), between US$30 million to US$40 million of Bellatrix's future capital expenditures, development capital and Senior Note repurchases. On September

2

11, 2018, the Exchanging Noteholders were issued US$72.108 million aggregate principal amount of Second Lien Notes and US$15 million aggregate principal amount of New Money Notes. A further US$15 million aggregate principal amount of New Money Notes were issued on December 12, 2018. In addition, the Exchanging Noteholders also agreed in the Note Purchase Agreement to permit Bellatrix an option to issue up to US$50 million aggregate principal amount of additional Second Lien Notes in exchange for the Senior Notes held by certain other holders, which option expired effective February 28, 2019.

If the Senior Notes have not been refinanced or repaid by March 14, 2020 on terms permitted under the Note Purchase Agreement such that no more than US$25 million in principal amount of Senior Notes remains outstanding on that date, then the maturity date for all Second Lien Notes and New Money Notes (collectively, the "2L Notes") will be March 14, 2020.

Credit Facilities

In connection with the monetization of certain production facilities and non-core asset dispositions, Bellatrix’s borrowing base under its extendible revolving reserves-based credit facilities (the "Credit Facilities") was reduced a number of times in 2016 and 2017. In connection with the completion of the Second Lien Refinancing, the lenders under the CreditFacilities amended and restated the agreement governing the Credit Facilities (the "FirstLienCreditAgreement") and reconfirmed the borrowing base at $100 million, with total commitments set at $95 million.

A copy of the First Lien Credit Agreement has been filed on www.sedar.com and www.sec.gov under Bellatrix's SEDAR and EDGAR profiles, respectively.

For additional information relating to the Credit Facilities, see "Borrowings - Credit Facilities".

Base Shelf Prospectus

On June 29, 2018, Bellatrix filed a short form base shelf prospectus ("ShelfProspectus") in each of the Provinces of Canada except Quebec, that enables Bellatrix, from time to time until July 2020, to offer for sale up to $500 million of Common Shares, Preferred Shares, subscription receipts, warrants, or units comprising any combination thereof.

Convertible Debenture and Subscription Receipt Offering

On August 9, 2016, Bellatrix completed the issuance and sale of extendible unsecured subordinated convertible debentures for an aggregate principal amount of $50 million (the "Convertible Debentures") initially set to mature on September 30, 2016 and 25,000,000 subscription receipts ("Subscription Receipts") at a price of $1.20 per Subscription Receipt, for gross proceeds of $80 million (the "Convertible Debenture and Subscription Receipt Offering"). In connection with the Convertible Debenture and Subscription Receipt Offering, Bellatrix filed a short-form prospectus in all provinces in Canada, other than Quebec. Pursuant to the subscription receipt agreement dated August 9, 2016 between Bellatrix and National Bank Financial Inc. and Computershare Trust Company of Canada, providing for the issue of Subscription Receipts pursuant to the Convertible Debenture and Subscription Receipt Offering,andas a result of the closing of the Keyera Transaction, Common Shares were issued on the automatic conversion of the Subscription Receipts. Also resulting from the closing of the Keyera Transaction, was the automatic extension of the maturity date of the Convertible Debentures to September 30, 2021 pursuant to the terms of the Debenture Indenture. The net proceeds from the Convertible Debenture and Subscription Receipt Offering were primarily used to reduce Bellatrix’s indebtedness under its Credit Facilities. For additional information relating to the Convertible Debentures, see "Borrowings - Convertible Debentures".

Other Developments

Completion of the Bellatrix Alder Flats Gas Plant Phase 2

On April 3, 2018, the Corporation announced that the Phase 2 expansion project for the Bellatrix Alder Flats Gas Plant was fully commissioned in mid-March and began selling volumes March 19, 2018. The project significantly increased Bellatrix's throughput capacity at the Alder Flats Gas Plant to 230 MMcf/d (from 110 MMcf/d) and combined NGLs recovery at the Bellatrix Alder Flats Gas Plant increased to approximately 55 to 60 bbl/MMcf, from approximately 45 bbl/MMcf under Phase 1. Completion of Phase 2 added an incremental 30 MMcf/d ownership capacity net to Bellatrix's 25% working interest. Bellatrix was also able to redirect approximately 65 MMcf/d of its gross natural gas volumes from third party processing plants to the Bellatrix Alder Flats Plant to process such volumes under Bellatrix's ownership and processing volume commitments.

Share Consolidation and NYSE Delisting

3

In August 2016, Bellatrix received a continued listing standards notice from the NYSE as a result of the average closing price of the Common Shares being less than US$1.00 per share over a period of 30 consecutive trading days. Bellatrix had six months following receipt of such notification to regain compliance with the minimum share price requirement.

At Bellatrix’s annual shareholder meeting, held on May 17, 2017, shareholders approved a 5 for 1 Common Share consolidation with articles of amendment filed on July 1, 2017, whereby 5 old Common Shares would be exchanged for 1 new Common Share. On August 16, 2017, Bellatrix announced that it had received notification from the NYSE that Bellatrix had regained compliance with the NYSE’s minimum share price requirement.

On January 22, 2019, Bellatrix announced that its Board has determined to commence proceedings for the voluntary delisting of Bellatrix’s common shares from the NYSE, with such delisting effective February 12, 2019.

2019 Capital Budget

On January 15, 2019, Bellatrix announced a 2019 capital budget of between $40 to 50 million (the "2019 Capital Budget"), to maintain average production volumes of between 34,000 to 36,000 BOE/d. Bellatrix anticipates that the 2019 Capital Budget will be flexible throughout the year to focus primarily on development opportunities and to continue to utilize Bellatrix’s infrastructure, takeaway capacity and market egress.

Significant Acquisitions

The Corporation has not completed any acquisitions that would be considered significant pursuant to NI 51-102 since January 1, 2018.

DESCRIPTION OF BUSINESS

Business Plan and Growth Strategies

Bellatrix is a Western Canadian based growth oriented oil and gas company engaged in the exploration for, and the acquisition, development and production of oil and natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan. The business plan of Bellatrix is to create sustainable and profitable per share growth in reserves, production and cash flow in the oil and gas industry. To accomplish this, Bellatrix pursues an integrated growth strategy with active development and exploration drilling within its core areas, together with focused acquisitions and strategic joint ventures, and maintenance of a flexible financial position. Bellatrix will continue to target areas and prospects that it believes could result in meaningful reserve and production additions.

Bellatrix will continue to pursue internal and external generation of exploration plays that have low to medium risk and multi-zone potential and intends to maintain a balance between exploration, exploitation and development drilling targeting both oil and natural gas reserves over the course of the next several years. Bellatrix considers asset and corporate acquisition opportunities from time to time that meet Bellatrix's business parameters.

In reviewing potential opportunities, Bellatrix will use the most current methodologies in giving consideration to the following criteria:

• Bellatrix's technical expertise in the opportunity;

• the amount of risk capital required to secure or evaluate the investment opportunity;

• the potential return on the project, if successful;

• the likelihood of success; and

• risked return versus cost of capital.

In general, Bellatrix expects to continue to pursue a portfolio approach in developing a large number of opportunities with a balance of risk profiles and commodity exposure in an attempt to generate high levels of sustainable growth.

The Corporation continues to target areas and prospects that it believes could result in meaningful reserve and production additions. Bellatrix may, however, in its discretion, proceed with asset or corporate acquisitions or investments that do not conform to the guidelines discussed above based upon its consideration of the qualitative aspects of the subject properties, including risk profile, technical upside, reserve life and asset quality. In addition, Bellatrix may from time to time consider seeking joint venture partners, strategic investors or other business arrangements to help accelerate development of its properties.

4

Bellatrix's management team is comprised of a proven team of professional management in all key operational areas of the organization including a team experienced in providing organic growth through full cycle exploration, exploitation and development. See "Directors and Officers".

Cyclical and Seasonal Impact of Industry

Our operational results and financial condition are dependent on the prices received for our oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and, natural gas prices, in particular, have sharply declined since 2014 and continue to remain depressed. Such prices are determined by supply and demand factors, including weather, general economic conditions, and actions taken by OPEC and other oil and gas producing countries, as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect on our financial condition. We partially mitigate such price risk through closely monitoring the various commodity markets and establishing price risk management programs. Additionally, we continually review our capital program and implement initiatives to adapt to such price changes.

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. 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 swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for the goods and services of Bellatrix as the demand for natural gas rises during cold winter months and hot summer months.

See "Risk Factors".

Social and Environmental Policies

We are committed to managing and operating in a safe, efficient, environmentally responsible manner in association with our industry partners and are committed to continually improving our environmental, health, safety and social performance. To fulfill this commitment, our operating practices and procedures are consistent with the requirements established for the oil and gas industry. Key environmental considerations include air quality and climate change, water conservation, spill management, waste management plans, lease and right-of-way management, natural and historic resource protection, and liability management (including site assessment and remediation). These practices and procedures apply to our employees and we monitor all activities and make reasonable efforts to ensure that companies who provide services to us will operate in a manner consistent with such requirements.

A copy of Bellatrix's 2018 Corporate Responsibility Report that addresses Bellatrix's policies and commitment to health and safety, environment, people and culture, and community and stakeholder engagement matters is available on Bellatrix's website at www.bxe.com.

Competitive Conditions

The oil and natural gas industry is intensely competitive in all its phases. Bellatrix competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Bellatrix's competitors include resource companies which have greater financial resources, staff and facilities than those of Bellatrix. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. Bellatrix believes that its competitive position is equivalent to that of other oil and gas issuers of similar size and at a similar stage of development.

5

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated March 7, 2019. The effective date of the Statement is December 31, 2018.

Disclosure of Reserves Data

The reserves data set forth below (the "Reserves Data") is based upon an evaluation by InSite with an effective date of December 31, 2018. The Reserves Data summarizes our crude oil, NGLs and natural gas reserves and the net present values of future net revenue for these reserves using forecast prices and costs. The Reserves Data conforms with the requirements of NI 51-101. We engaged InSite to provide an evaluation of proved and proved plus probable reserves. No attempt was made to evaluate possible reserves. All of our reserves are in Canada in the provinces of Alberta, British Columbia and Saskatchewan. Field inspections were not conducted. The Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 and the Report on Reserves Data by Bellatrix's independent qualified reserves evaluator in Form 51-101F2 are attached as Appendix "A" and Appendix "B" respectively, hereto.

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 prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of the crude oil, NGLs 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 NGLs reserves may be greater than or less than the estimates provided herein.

Bellatrix's reserves information includes the impact of IFRS 16, which changes the accounting treatment of certain operating leases so that the future lease payments associated with such leases are recognized as a financial liability on the Corporation’s balance sheet. As a result, for the purposes of preparing the reserves data presented herein, the lease payments associated with such leases are recognized as financing costs rather than as operating costs and have not been deducted in calculating the value of the Corporation's reserves. If such reserves payments were recognized as operating costs in calculating the value of the Corporation’s reserves, it would result in a reduction to the before tax net present value of the future net revenue associated with the Corporation's proved plus probable reserves by $87.4 million from approximately $1.5 billion to $1.412 billion.

6

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2018

FORECAST PRICES AND COSTS

	Light And Medium Crude Oil		Heavy Crude Oil		Conventional Natural Gas(1)		Natural Gas Liquids
Reserves Category	Gross (Mbbls)	Net (Mbbls)	Gross (Mbbls)	Net (Mbbls)	Gross (MMcf)	Net (MMcf)	Gross (Mbbls)	Net (Mbbls)
Proved Developed Producing	953.1	866.1	5.8	6.0	319,093.7	288,710.0	23,185.6	18,626.1
Proved Developed Non-Producing	46.0	41.6	—	—	5,919.0	4,960.5	336.8	236.1
Proved Undeveloped	1,925.0	1,579.0	114.3	98.9	459,011.1	412,635.4	35,741.5	30,446.9
Total Proved	2,924.1	2,486.7	120.1	104.9	784,023.8	706,305.9	59,263.9	49,309.0
Probable	1,366.9	1,094.6	198.2	165.8	292,933.6	262,378.3	21,855.9	17,829.3
Total Proved Plus Probable	4,291.0	3,581.3	318.3	270.7	1,076,957.4	968,684.2	81,119.8	67,138.3

Note:

(1) Includes minor amounts of natural gas from coal bed methane, shale gas reserves and solution gas. Coal bed methane, shale gas and solution gas reserves represent an immaterial portion of Bellatrix's natural gas reserves.

	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted At (%/year)					After Income Taxes Discounted at (%/year)					Unit Value Before Income Tax Discounted at 10% Year(1)
Reserves Category	0 ($000s)	5 ($000s)	10 ($000s)	15 ($000s)	20 ($000s)	0 ($000s)	5 ($000s)	10 ($000s)	15 ($000s)	20 ($000s)	($/BOE)	($/ Mcfe)
Proved Developed Producing	887,468	619,667	472,545	382,630	323,001	887,468	619,667	472,545	382,630	323,001	6.99	1.17
Proved Developed Non–Producing	18,791	13,685	10,637	8,654	7,275	18,791	13,685	10,637	8,654	7,275	9.63	1.61
Proved Undeveloped	1,506,640	885,604	566,101	382,763	268,811	1,245,226	763,538	503,942	348,934	249,414	5.61	0.94
Total Proved	2,412,899	1,518,957	1,049,282	774,046	599,087	2,151,485	1,396,890	987,124	740,217	579,691	6.19	1.03
Probable	1,380,898	727,696	450,971	309,923	228,015	1,022,509	545,391	344,313	241,878	182,099	7.18	1.20
Total Proved Plus Probable	3,793,797	2,246,653	1,500,254	1,083,970	827,102	3,173,994	1,942,281	1,331,436	982,095	761,789	6.45	1.08

Note:

(1) Unit values are based upon net reserves.

TOTAL FUTURE NET REVENUE (UNDISCOUNTED)

AS OF DECEMBER 31, 2018

FORECAST PRICES AND COSTS 

Reserves Category	Revenue ($000s)	Royalties ($000s)	Operating Costs(1) ($000s)	Capital Development Costs ($000s)	Abandonment and Reclamation Costs(2) ($000s)	Future Net Revenue Before Income Taxes ($000s)	Income Tax ($000s)	Future Net Revenue After Income Taxes ($000s)
Proved Reserves	5,264,280	644,411	1,498,698	678,596	29,667	2,412,899	261,415	2,151,485
Proved Plus Probable	7,641,723	971,992	1,976,192	863,002	36,727	3,793,797	619,803	3,173,994

7

Notes:

(1) Under IFRS 16, lease payments are recognized as financing costs rather than as operating costs and have not been deducted in calculating the value of the Corporation's reserves.

(2) Includes well abandonment, reclamation and disconnect costs and for all wells that were assigned reserves (including future wells to be drilled) and for dedicated facilities required to produce these reserves. Allowance for salvage value was included.

FUTURE NET REVENUE BY PRODUCTION GROUP

AS OF DECEMBER 31, 2018

FORECAST PRICES AND COSTS

Reserves Category	Production Group(1)	Future Net Revenue Before Income Taxes (discounted at 10%/year) ($000s)	Unit Value(2) Before Income Tax (discounted at 10%/year)
Proved	Light and Medium Crude Oil (including solution gas and other by–products)	121,482	$50.15/BOE
	Heavy Crude Oil (including solution gas and other by-products)	1,322	$12.61/BOE
	Conventional Natural Gas (including by–products but excluding solution gas from oil wells)(3)	926,478	$6.14/BOE
	Natural Gas Liquids	—
	Total	1,049,282	$6.19/BOE
Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by–products)	168,141	$48.01/BOE
	Heavy Crude Oil (including solution gas and other by-products)	4,119	$15.22/BOE
	Conventional Natural Gas (including by–products but excluding solution gas from oil wells)(3)	1,327,993	$6.43/BOE
	Natural Gas Liquids	—
	Total	1,500,254	$6.45/BOE

Notes:

(1) Other company revenue and costs not related to a specific production group have been allocated proportionately to production groups.

(2) Unit values are based on net reserves of primary product.

(3) Includes minor amounts of revenue and costs associated with natural gas from coal bed methane and shale gas reserves.

Notes to Reserves Data Tables:

1. Columns may not add due to rounding.

2. The crude oil, NGLs and natural gas reserve estimates presented in the InSite Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:

• Analysis of drilling, geological, geophysical and engineering data;

• The use of established technology; and

• 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:

8

(a) 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.

(b) 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 categorization of reserves are provided in Section 5.5 of the COGE Handbook. Each of the reserve 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 classification (proved, probable) to which they are assigned.

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

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve 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 are made). 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 qualitative 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 will be prepared using deterministic methods that do not provide a 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 Section 5.5.3 of the COGE Handbook.

3. Well abandonment, reclamation and disconnect costs were estimated and included in the InSite Report at the individual entity level for all wells that were assigned reserves (including future wells to be drilled) and for dedicated facilities required to produce these reserves, for the purposes of estimating the Reserves Data. Allowance for salvage value was included. Abandonment and reclamation costs for wells with no assigned reserves and for non-dedicated gathering systems, batteries, plants and processing facilities were not included for the purposes of estimating the Reserves Data contained in the InSite Report. We use historical cost information on an area by area basis as the means for estimating the future abandonment and reclamation costs. When this information is not available, the estimate is determined with reference to appropriate regulatory standards and requirements.

4. The after-tax net present value of Bellatrix's properties reflect the tax burden on all of the properties of Bellatrix taken as a whole. It does not consider the business-entity-level tax situation, or tax planning. It does not provide an estimate of the value at the level of the business entity, which may be significantly different. The financial statements and the

9

management's discussion and analysis of Bellatrix should be consulted for information at the level of the business entity. Furthermore, the tax methodology used assumes that all tax pools are utilized to the maximum depreciation rate as currently permitted.

5. Forecast Prices and Costs

The forecast cost and price assumptions are generally acceptable, in the opinion of InSite, as being a reasonable outlook of the future as at December 31, 2018. 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 following tables set forth the benchmark reference prices, as at December 31, 2018, reflected in the Reserves Data. These price assumptions were provided to Bellatrix by InSite and were InSite's then current forecast at the effective date of the InSite Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

FORECAST PRICES AND COSTS

	OIL
Year	Canadian Light Sweet Crude 40° API ($Cdn/Bbl)	Western Canada Select 20.5° API ($Cdn/Bbl)	NATURAL GAS AECO Price ($Cdn/MMBtu)	NATURAL GAS LIQUIDS at Edmonton(1) ($Cdn/Bbl)	INFLATION RATES(2) %/Year	EXCHANGE RATE(3) ($US/$Cdn)
Forecast
2019	63.50	47.75	1.90	67.95	—	0.760
2020	75.55	59.05	2.29	78.95	2.0	0.780
2021	80.50	65.50	2.71	83.72	2.0	0.800
2022	83.25	68.25	3.03	86.58	2.0	0.800
2023	85.60	70.60	3.21	88.60	2.0	0.800
2024	87.62	72.62	3.33	90.68	2.0	0.800
2025	90.01	74.51	3.44	93.16	2.0	0.800
2026	92.68	76.68	3.50	95.92	2.0	0.800
2027	94.53	78.53	3.57	97.84	2.0	0.800
2028	96.42	80.42	3.65	99.79	2.0	0.800
Thereafter	+2.0%/yr	+2.4%/yr(4)	+2.0%/yr	+2.0%/yr

Notes:

(1) NGLs are represented by pentanes plus price.

(2)Inflation rates for forecasting costs only.

(3)Exchange rates used to generate the benchmark reference prices in this table.

(4)Inflation rate is 2.4% until 2037 and 2.0% thereafter.

Weighted average historical prices realized by Bellatrix (before commodity price risk management contracts) for the year ended December 31, 2018, were $1.78/Mcf for natural gas, $73.63/Bbl for light and medium crude oil, and $24.46/Bbl for NGLs.

Reconciliation of Changes in Reserves

The following table sets out the reconciliation of our gross reserves as at December 31, 2017 compared to December 31, 2018 based on forecast prices and costs by principal product type:

10

	LIGHT AND MEDIUM  CRUDE OIL			HEAVY CRUDE OIL
FACTORS	Gross Proved (Mbbl)	Gross Probable (Mbbl)	Gross Proved Plus Probable (Mbbl)	Gross Proved (Mbbl)	Gross Probable (Mbbl)	Gross Proved Plus Probable (Mbbl)
December 31, 2017(2)	2,912.8	1,373.4	4,286.3	120.9	200.4	321.3
Discoveries	—	—	—	—	—	—
Extensions	—	—	—	—	—	—
Infill Drilling	0.8	0.3	1.1	—	—	—
Improved Recovery	—	—	—	—	—	—
Technical Revisions	(44.1)	(52.8)	(97.0)	2.5	—	0.2
Acquisitions	214.8	61.8	276.6	—	(2.3)	—
Dispositions	(12.4)	(3.5)	(15.9)	—	—	—
Economic Factors	(30.0)	(12.3)	(42.3)	(3.2)	—	—
Production	(117.8)	—	(117.8)	—	—	(3.2)
December 31, 2018(3)	2,924.1	1,366.9	4,291.0	120.1	198.2	318.3

	NATURAL GAS LIQUIDS			CONVENTIONAL NATURAL GAS(1)
FACTORS	Gross Proved (Mbbl)	Gross Probable (Mbbl)	Gross Proved Plus Probable (Mbbl)	Gross Proved (MMcf)	Gross Probable (MMcf)	Gross Proved Plus Probable (MMcf)
December 31, 2017(2)	45,411.5	16,836.8	62,248.2	736,518.8	274,326.1	1,010,844.9
Discoveries	—	—	—	—	—	—
Extensions	—	—	—	—	—	—
Infill Drilling	1,883.3	(520.7)	1,362.6	25,847.5	(3,309.8)	22,537.7
Improved Recovery	—	—	—	—	—	—
Technical Revisions	11,069.8	3,666.0	14,735.8	20,719.2	(1,995.2)	18,724.0
Acquisitions	4,761.6	1,827.2	6,588.8	64,636.3	22,435.0	87,071.4
Dispositions	(0.5)	(0.1)	(0.6)	(120.3)	(20.5)	(140.9)
Economic Factors	(392.0)	46.8	(345.2)	(7,269.2)	1,497.9	(5,771.2)
Production	(3,469.8)	—	(3,469.8)	(56,308.5)	—	(56,308.5)
December 31, 2018(3)	59,263.9	21,855.9	81,119.8	784,023.8	292,933.6	1,076,957.4

Notes:

(1) Includes minor amounts of natural gas from coal bed methane and shale gas reserves.

(2) As evaluated by InSite in a report dated February 28, 2018 and effective as of December 31, 2017 using the forecast prices and costs published by InSite.

(3) As evaluated by InSite in the InSite Report using the forecast prices and costs published by InSite.

Additional Information Relating to Reserves Data

Undeveloped Reserves

The following tables set forth the proved undeveloped gross reserves and the probable undeveloped gross reserves, each by product type, attributed to Bellatrix's assets for the years ended December 31, 2018, 2017 and 2016 and, in the aggregate, before that time based on forecast prices and costs.

Proved Undeveloped Reserves

11

	Light and Medium Crude Oil (Mbbl)		Heavy Crude Oil (Mbbl)		Conventional Natural Gas(1) (MMcf)		NGLs (Mbbl)
Year	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End
2016	375.9	2,651.3	—	108.9	92,750.8	431,439.8	4,825.6	22,397.3
2017	116.6	1,856.5	—	112.5	99,776.8	448,493.6	6,292.8	22,338.7
2018	—	1,925.0	—	114.3	21,734.4	459,011.1	1,679.0	35,741.5

Probable Undeveloped Reserves

	Light and Medium Crude Oil (Mbbl)		Heavy Crude Oil (Mbbl)		Conventional Natural Gas(1) (MMcf)		NGLs (Mbbl)
Year	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End
2016	118.8	998.5	—	154.8	62,261.9	146,381.7	2,832.9	7,689.8
2017	—	610.0	—	154.8	20,974.5	112,166.9	1,205.6	6,945.0
2018	—	614.9	—	154.8	1,377.5	109,042.6	91.0	8,232.2

Note:

(1)Includes minor amount of natural gas from coal bed methane and shale gas reserves.

Proved Undeveloped Reserves

A total of 459,011 MMcf of natural gas, 2,039 Mbbl of oil and 35,742 Mbbl of NGLs were assigned as proved undeveloped reserves as at December 31, 2018, representing approximately 59% of our total proved reserves. The proved undeveloped reserves are generally associated with infill/development drilling locations supported by offset well data. In estimating future net revenue, InSite reviewed Bellatrix's future development plans in order to estimate and deduct future development costs. Therefore, the future development costs, as set out under "Additional Information Relating to Reserves Data - Future Development Costs" below, are consistent with Bellatrix's future development plans at year end. The capital associated with developing proved undeveloped reserves is expected to be spent between 2019 and 2024. With respect to capital development costs associated with proved undeveloped reserves in the InSite Report, approximately 45% of the capital is scheduled to be spent over the next three years and 97% is scheduled to be spent over the next five years. Bellatrix’s capital development cost schedule has been spread over five years due to the currently depressed pricing environment and overall economic conditions.

The west central region of Alberta is a significant producing and development area for Bellatrix. Development drilling in both the proved and probable cases is anticipated for oil and natural gas in Brazeau, Ferrier and Willesden Green representing 91% of all assigned proven future development capital. The programs are staged in line with sound development practices and to exploit horizontal drilling and multi-fracturing completion opportunities. Residual future development capital is assigned across various other properties operated by Bellatrix including Baptiste and Pembina. The majority of this spending is also forecast for the next five years with minor work planned past this point, based on relief of existing wellbore constraints.

Although Bellatrix expects the development of its proved undeveloped reserves to be consistent with that set out above, current industry conditions and other uncertainties as discussed under "Risk Factors" herein could result in development of Bellatrix's proved undeveloped reserves on a different schedule than set out above. See also the discussion under "Additional Information Relating to Reserves Data - Future Development Costs" below that references Bellatrix's 2019 Capital Budget.

Probable Undeveloped Reserves

A total of 109,043MMcf of natural gas, 770 Mbbl of oil and 8,232 Mbbl of NGLs were assigned as gross probable undeveloped reserves in 2018, representing approximately 38% of our total probable reserves or 10% of total proved plus probable reserves.

The bulk of the probable undeveloped reserves assigned are associated with projects that have a proved reserves component. Probable reserves are attributed in addition to provide reserves in these cases according to the definitions and guidelines of the

12

COGE Handbook. There are also some projects assigned probable reserves that do not have a proven reserves component, as per the terms of the COGE Handbook.

As was the case with proved undeveloped reserves, the West Central Alberta region has significant probable undeveloped reserves. The expenditures required to develop the probable undeveloped reserves are scheduled in a staggered pattern from 2019 to 2024. With respect to capital development costs associated with probable undeveloped reserves in the InSite Report, approximately 18% of the capital is scheduled to be spent over the next three years and 95% is scheduled to be spent over the next five years. In scheduling future development capital, priority is given to projects with a proved component, as those projects tend to have reduced risk and may be easier to predict timing or serve to prove up further projects currently only assigned probable reserves. Bellatrix’s capital development cost schedule has been spread over five years to align forecasted capital spending with cash generation of the reserves model.

Although Bellatrix expects the development of its probable undeveloped reserves to be consistent with that set out above, current industry conditions and other uncertainties discussed under "Risk Factors" herein could result in development of Bellatrix's probable undeveloped reserves on a different schedule than set out above. See also the discussion under "Additional Information Relating to Reserves Data - Future Development Costs" below that references Bellatrix's 2019 Capital Budget.

Significant Factors or Uncertainties

While we do not anticipate any significant economic factors or uncertainties will affect any particular components of the reserves data, the reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs, royalty regimes and well performance that are beyond our control (see "Risk Factors").

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:

Year	Proved Reserves ($000s)	Proved Plus Probable Reserves ($000s)
2019	54,269.5	57,719.5
2020	116,464.7	121,268.9
2021	135,577.4	160,503.0
2022	167,697.9	214,044.9
2023	186,866.3	282,152.9
Thereafter	17,719.8	27,312.8
Total: Undiscounted	678,596.0	863,002.0

The capital expenditure program developed for the reserves evaluation, including estimated future development costs, was developed based on using cash flow from operations, funding transactions and available credit facilities. Equity financing was also considered to fund future development costs. If cash flows are other than projected, capital expenditure levels may be adjusted. Our practice of continually monitoring spending opportunities in comparison to expected cash flow levels allows for adjustments to the capital program as required. In addition, depending on a number of factors including commodity prices, industry conditions and Bellatrix's financial and operating results, available funds from credit facilities and equity financings may not be available on terms acceptable to Bellatrix, which could also result in adjustments to the capital program as required. The expected costs of funding our capital expenditures have been built into the economics of the programs and the reserves evaluation.

As indicated under "General Development of our Business - 2019 Capital Budget", the Board set the 2019 Capital Budget at between $40 and $50 million. It is expected that the 2019 capital budget will meet the development schedule contemplated by the InSite Report.

Other Oil and Gas Information

Principal Properties

13

The following is a description of Bellatrix's principal oil and natural gas properties as at December 31, 2018. Unless otherwise indicated, production stated is average daily production for the year ended December 31, 2018 received by Bellatrix in respect of its working interest share before deduction of royalties and without including any royalty interest.

Ferrier

Located 35 kilometres northwest of Rocky Mountain House, Alberta, the Ferrier and Alder Flats areas produce natural gas and NGLs from the Belly River, Cardium, Spirit River and Rock Creek zones at depths ranging from 1,800 to 2,700 metres.The Spirit River comprises the Notikewin, Falher and Wilrich zones.Area production for 2018 averaged 32,865 BOE/d, comprised of 71.4% natural gas, 23.2% NGLs and 5.4% light oil and condensate. Bellatrix operates four compressor stations in the area. The majority of oil production from the area is delivered to two batteries and Bellatrix has a 61.18% working interest in one of the oil batteries. All of Bellatrix's net gas volumes from the area are delivered to the Bellatrix Alder Flats Gas Plant. With the start up of phase II of the Alder Flats Gas Plant in 2018 any volumes previously delivered to third party non-operated gas plants for processing were rerouted to the Alder Flats Gas Plant. Our land holdings in the area were 71,193 gross (54,279 net) acres of developed land and 15,929 gross (12,396) acres of undeveloped land as at December 31, 2018.

In Ferrier in 2018, Bellatrix participated in 12 gross (7.98 net) wells. The drilling program consisted of 10 gross (7.68 net) operated wells and 2 gross (0.30 net) non-operated wells, and all but two wells were completed and tied in in 2018 with the remaining wells completed and tied in in the first quarter of 2019. Of the 10 gross (7.68 net) operated wells, 9 gross (6.68 net) wells were Spirit River horizontal liquids-rich gas wells and 1 gross (1 net) well was a Cardium liquids-rich gas well.

In the first quarter of 2019 in Ferrier, Bellatrix expects to drill, complete and tie-in 5 gross (5 net) operated horizontal liquids-rich gas wells, one of which was spud in late December 2018. Of the 5 gross (5 net) wells, 4 gross (4 net) wells are Spirit River horizontal liquids rich gas wells and 1 gross (1 net) well is a Cardium liquids rich gas well. For the remainder of 2019, Bellatrix plans to drill an additional 7 gross (4.56 net) horizontal liquids-rich gas wells.

Willesden Green

The Willesden Green area is located approximately 45 kilometres north of Rocky Mountain House, Alberta. This property produces oil and associated natural gas from the Cardium zone, liquids-rich natural gas from the Notikewin, Falher, Ellerslie, and Rock Creek formations at depths of 1,800 to 2,800 metres, and sweet dry natural gas from five shallower horizons, including the Paskapoo, Ardley, Horseshoe Canyon, Edmonton and Belly River at depths of 300 to 1,200 metres. Production from this area averaged 2,469 BOE/d for 2018, consisting of 81% natural gas,12.9% NGLs and 6.1% light oil and condensate. The majority of this production is operated by Bellatrix. The Corporation operates three compressor stations in the area with ownership of approximately 70% in two of the stations. The Corporation delivers production to two third party operated gas plants in the area and holds a minority interest in one of the plants.The Corporation held 42,722 gross (28,059 net) acres of developed land and 10,080 gross (7,731 net) acres of undeveloped land as at December 31, 2018.

In Willesden Green in 2018, Bellatrix participated in 2 gross (1.2 net) wells. The drilling program consisted of 1 gross (1 net) operated Spirit River horizontal liquids-rich gas well and 1 gross (0.20 net) non-operated Notikewin horizontal gas well.

Bellatrix plans to drill and complete an additional 1 gross (0.5 net) Spirit River horizontal well in the Willesden Green area in the second half of 2019.

Oil and Natural Gas Wells

The following table sets forth the number and status of oil wells and gas wells in which we have a working interest as at December 31, 2018.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	167	105.4	37	17.0	704	454.2	416	218.8
Saskatchewan	4	2.9	—	—	—	—	33	32.3
British Columbia	—	—	1	0.4	1	0.4	12	2.6
Total	171	108.3	38	17.4	705	454.6	461	253.7

14

Developed and Undeveloped Lands

The following table sets out our developed and undeveloped land holdings as at December 31, 2018.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Alberta	366,664	230,940	142,313	105,764	508,977	336,705
Saskatchewan	7,602	1,910	62,637	20,318	70,240	22,228
British Columbia	13,327	12,720	8,005	7,732	21,332	20,452
Total	387,593	245,570	212,956	133,814	600,549	379,385

Note:

(1)May not add due to rounding.

Bellatrix does not expect any material expiries in its core land holdings in 2019.

Development of Bellatrix properties with no attributable reserves are subject to current industry conditions and uncertainties as indicated under "Risk Factors" herein. In addition, we expect that funding of development operations on such properties will be evaluated in the context of our total capital requirements having regard to rates of return, the likelihood of success and risked return versus cost of capital, and availability and reliability of methods of hydrocarbon delivery.

Forward Contracts and Marketing

Commodity Marketing

Our commodity marketing strategy is to sell production in the spot market, complemented from time to time by price risk management instruments.

We periodically hedge the price on a portion of our crude oil, NGLs and natural gas production. We hedged an average of 32% of total crude oil and NGLs production and an average of 48% of total natural gas production during the twelve months ended December 31, 2018. The following provides details of the commodity price risk management arrangements outstanding as at December 31, 2018 and as of the date hereof.

As at December 31, 2018, Bellatrix had entered into commodity price risk management arrangements as follows:

Type	Period	Volume	Price	Index
Oil call option	January 1, 2019 - December 31, 2019	500 bbl/d	$80.00	WTI - NYMEX
Oil call option	January 1, 2019 - December 31, 2019	500 bbl/d	$95.00	WTI - NYMEX
Oil call option	January 1, 2020 - December 31, 2020	1,000 bbl/d	$77.90	WTI - NYMEX
Natural gas fixed	January 2019	10,000 GJ/d	$2.54	AECO 7A
Natural gas fixed	February 2019	10,000 GJ/d	$2.43	AECO 7A
Natural gas fixed	April 1, 2019 - October 31, 2019	20,000 GJ/d	$1.79	AECO 5A
Natural gas swap	January 1, 2019 - October 31, 2020	10,000 MMBTU/d	(US$1.26)	AECO 7A/NGI Chicago
Natural gas swap	January 1, 2019 - October 31, 2020	5,000 MMBTU/d	(US$1.30)	AECO 5A/Dawn Gas Daily
Natural gas swap	April 1, 2019 - October 31, 2020	10,000 MMBTU/d	(US$1.24)	AECO 7A/NYMEX

Subsequent to December 31, 2018, the Corporation monetized certain natural gas basis differential arrangements from April 1, 2019 to October 31, 2019 of 25,000 MMBTU/d for proceeds of $2.4 million.

Also subsequent to December 31, 2018, the Corporation entered into commodity price risk management arrangements as follows:

15

Type	Period	Volume	Price	Index
Natural gas fixed	March 2019	20,000 GJ/d	$2.33	AECO 5A
Natural gas fixed	March 2019	10,000 GJ/d	$2.30	AECO 5A
Natural gas fixed	March 2019	10,000 GJ/d	$2.54	AECO 5A
Natural gas fixed	April 1, 2019 - October 31, 2019	15,000 MMBTU/d	US$2.68	NGI Chicago

Finally, and also subsequent to December 31, 2018, the Corporation entered into the following contracts with customers for the sale of future production:

Type	Period	Volume	Price	Delivery Point
Natural gas fixed	April 1, 2019 - October 31, 2019	10,000 MMBTU/d	US$2.74	Union Dawn
Natural gas fixed	April 1, 2019 - October 31, 2019	5,000 MMBTU/d	US$2.70	Chicago Citygate
Natural gas fixed	April 1, 2019 - October 31, 2019	15,000 MMBTU/d	US$2.46	Malin
Natural gas fixed	April 1, 2019 - October 31, 2019	15,000 MMBTU/d	US$2.73	Union Dawn

Transportation and Processing Commitments

In the ordinary course of its business, Bellatrix enters into firm service agreements for the transportation and processing of its natural gas and NGL volumes to secure access to infrastructure necessary to transport and process such volumes. From time-to-time Bellatrix will renew, amend or add firm service commitments based on forecast capacity requirements.

Based on the forecast production volumes in the InSite Report, Bellatrix’s transportation commitments will exceed forecast production of its proved reserves for: (i) NGLs, over the next five years by an average of 2,385 bbls/d at a cost of $3.87/bbl for an aggregate cost over five years of $5,049,808; and (ii) natural gas, from January 2019 to March 2022 by an average of 12,072 BOE/d at a cost of $0.74/boe for an aggregate cost of $5,940,213.

Based on the forecast production volumes for Bellatrix's proved reserves in the InSite Report, Bellatrix’s processing commitments will exceed forecast production for NGLs over the next five years by an average of 368 bbls/d at a cost of $3.14/bbl for an aggregate cost over five years of $957,215.

For Bellatrix’s proved plus probable reserves as estimated in the InSite Report, transportation commitments will exceed forecast production for (i) NGLs over the next 5 years, by an average of 2,261 bbls/d at a cost of $3.87/bbl for an aggregate cost over 5 years of $3,891,291; and (ii) natural gas, by an average of 10,270 BOE/d at a cost of $0.74/boe from January 2019 to March 2022 for an aggregate cost of $4,804,874.

Bellatrix's processing commitments will exceed forecast production for Bellatrix’s proved plus probable reserves, as estimated in the InSite Report, by 110 bbls/d at a cost of $3.14/bbl for an aggregate cost $289,292.

Such transportation and processing costs may be partially or fully mitigated to the extent that actual production exceeds the production forecasts as set out in the InSite Report. In addition, Bellatrix may be able to assign all or a portion of its unused, contracted, pipeline system transportation capacityto other producers.

Bellatrix’s ability to fulfill its transportation and processing commitments could be impacted by a number of factors including well performance, disruptions and infrastructure constraints. See "Industry Conditions - Transportation Constraints and Market Access" and "Risk Factors".Additional disclosure related to such transportation and processing commitments can be found in Bellatrix’s audited financial statements as at and for the year ended December 31, 2018, which can be accessed under the Corporation's SEDAR and EDGAR profiles on www.sedar.com and www.sec.gov, respectively.

Tax Horizon

The Corporation does not expect to pay current income tax for the 2018 fiscal year. Depending on production, commodity prices and capital spending levels, management believes that Bellatrix will not be taxable in 2019. The Corporation does not expect to pay current taxes until 2020 or beyond. This expectation will be impacted by, among other factors, production volumes, commodity prices, foreign exchange rates, operating costs, interest rates, changes in tax laws and Bellatrix's other business activities. Changes in these factors and in the estimates used by Bellatrix could result in Bellatrix paying income taxes earlier than expected.

16

Capital Expenditures

The following table summarizes capital expenditures (excludes non-cash expenditures relating to decommissioning liabilities, capitalized unit based compensation and corporate acquisitions) related to our assets and activities for the year ended December 31, 2018:

	$000's
Property acquisition costs	10,462
Proved properties	9,984
Undeveloped properties	478
Exploration costs	4
Development costs	48,898
Dispositions(1)	(1,106	)
Corporate Assets	1,311
Total	59,569

Note:

(1)Dispositions are comprised of sales of various miscellaneous inventory and assets.

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which Bellatrix has an interest that were drilled during the year ended December 31, 2018.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	—	—	1.00	0.02
Gas	—	—	13.00	9.17
Service	—	—	—	—
Stratigraphic Test	—	—	—	—
Dry	—	—	—	—
Total	0.00	0.00	14.00	9.19

For additional details on Bellatrix's exploration and development activities during 2018, see "Other Oil and Gas Information - Principal Properties" above.

Production Estimates

The following table sets out the volume of our gross production estimated for the year ended December 31, 2019, which is reflected in the estimate of gross proved reserves and gross proved plus probable reserves disclosed in the tables contained under "Disclosure of Reserves Data" above.

Reserves Category	Light And Medium Crude Oil (Bbls/d)	Heavy Crude Oil (Bbls/d)	Conventional Natural Gas(1) (Mcf/d)	Natural Gas  Liquids (Bbls/d)	Total (BOE/d)
Total Proved	362	7	147,981	10,987	36,020
Total Proved Plus Probable	369	7	156,422	11,611	38,059

17

Note:

(1)Includes minor amounts of coal bed methane and shale gas production.

The Ferrier property in the west central area of Alberta accounts for 26,642 BOE/d, or 70% of the estimated total production on a proved plus probable basis for the year ended December 31, 2018, which is reflected in the estimate of gross proved reserves and gross proved plus probable reserves disclosed in the tables contained under "Disclosure of Reserves Data" above.

Production History

The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback, before hedging, associated with our assets for the periods indicated below:

	Quarter Ended
	2018
	Dec. 31		Sept. 30		June 30		Mar. 31
Average Daily Production(1)
Light and Medium Crude Oil (Bbls/d) (2)	1,861		1,635		1,999		2,217
Conventional Natural Gas (Mcf/d)(3)	148,319		145,527		161,052		163,579
NGLs (Bbls/d) (4)	8,420		7,640		8,468		7,260
Combined (BOE/d)	35,001		33,530		37,309		36,740
Average Price Received
Light and Medium Crude Oil ($/Bbl) (2)	50.98		82.47		83.93		77.01
Conventional Natural Gas ($/Mcf)(3)	2.24		1.42		1.30		2.16
NGLs ($/Bbl) (4)	20.89		26.31		24.70		26.42
Combined ($/BOE)	17.21		16.17		15.71		19.50
Royalties Paid
Light and Medium Crude Oil ($/Bbl) (2)	11.22		19.21		22.23		16.31
Conventional Natural Gas ($/Mcf)(3)	(0.05	)	(0.12	)	(0.15	)	(0.13	)
NGLs ($/Bbl) (4)	5.40		6.25		5.61		7.99
Combined ($/BOE)	1.68		1.84		1.80		2.00
Operating Expenses
Light and Medium Crude Oil ($/Bbl) (2)	7.31		8.77		8.15		8.73
Conventional Natural Gas ($/Mcf)(3)	1.09		1.28		1.25		1.35
NGLs ($/Bbl) (4)	6.55		7.62		7.55		8.09
Combined ($/BOE)	6.59		7.71		7.55		8.13
Netback Received before Transportation
Light and Medium Crude Oil ($/Bbl) (2)	32.45		54.49		53.55		51.97
Conventional Natural Gas ($/Mcf)(3)	1.20		0.26		0.20		0.94
NGLs ($/Bbl) (4)	8.94		12.44		11.54		10.34
Combined ($/BOE)	8.94		6.62		6.36		9.37
Transportation Costs
Light and Medium Crude Oil ($/Bbl) (2)(5)	7.84		8.79		7.43		6.24
Conventional Natural Gas ($/Mcf)(3)	0.17		0.26		0.19		0.15

18

NGLs ($/Bbl) (4)	4.19	3.01	3.54	4.69
Combined ($/BOE)	2.15	2.23	2.03	1.99
Netback Received after Transportation (6)
Light and Medium Crude Oil ($/Bbl) (2)	24.61	45.70	46.12	45.73
Conventional Natural Gas ($/Mcf)(3)	1.03	—	0.01	0.79
NGLs ($/Bbl) (4)	4.75	9.43	8.00	5.65
Combined ($/BOE)	6.79	4.39	4.33	7.38

Notes:

(1) Includes minor royalty volumes received but does not deduct royalty volumes paid.

(2) Includes condensate production and minor amounts of heavy oil production.

(3) Includes minor amounts of coal bed methane and shale gas production. Negative values reflect gas cost allowance credits from the Alberta government.

(4) NGL pricing excludes condensate.

(5) Fourth quarter transportation costs for Light and Medium Crude Oil reflect adjustments for certain credits received for reductions in trucking expenses.

(6) Netbacks are calculated by subtracting royalties, operating and transportation costs from revenues. Netbacks do not include other income.

The following table indicates average daily company share production from important fields in respect of our assets for the year ended December 31, 2018. Company share production includes minor royalty volumes received but does not deduct royalty volumes paid.

	Light and Medium Crude Oil (Bbls/d) (1)	Condensate (Bbls/d)	Conventional Natural Gas (Mcf/d)	NGLs (Bbls/d)	BOE (BOE/d) (2)
West Central Alberta Region
Ferrier	455	1,428	146,754	6,374	32,716
Willesden Green	16	128	10,152	307	2,143
Total West Central Alberta Region	471	1,556	156,906	6,681	34,859
Other Properties	66	147	9,172	271	2,013
TOTALS	537	1,703	166,078	6,952	36,872

Note:

(1) Includes minor amounts of heavy oil production.

(2) May not add due to rounding.

For the year ended December 31, 2018, approximately 55% of gross revenue from our assets was derived from crude oil and NGLs production and 45% was derived from natural gas production.

DIVIDENDS

Bellatrix has not paid any dividends on the outstanding Common Shares. The Board has determined not to pay any dividends on the Common Shares at the present time. Any future decision to pay dividends, including the actual timing, payment and amount of dividends, if any, will be made by the Board based upon, among other things, the cash flow, results of operations and financial conditions of Bellatrix, the need for funds to finance ongoing operations and other business considerations as the Board considers relevant.

RATINGS

The following table outlines the ratings assigned to Bellatrix and the Senior Notes as of the date hereof:

19

Rating Agency	Corporate Rating	Senior Notes Rating	Trend/Outlook
Standard and Poor's Ratings Service ("S&P")	CCC	D	Negative
Moody's Investor Service, Inc. ("Moody's")	Caa2	Caa3	Negative

The corporate rating addresses the overall credit strength of Bellatrix, without consideration for security or ranking of security or ranking of any particular indebtedness. The long-term credit rating on the Senior Notes is intended by the ratings agencies to provide an independent indication of the risk that a borrower will not fulfill its full obligations with respect to a given type and/or series of securities in a timely manner with respect to both interest and principal commitments.

The credit ratings assigned by the rating agencies are not recommendations to purchase, hold or sell the Senior Notes or Bellatrix's other securities (including the Common Shares) and may be subject to revision or withdrawal at any time by the credit rating organization.

A definition of the categories of each rating has been obtained from the respective rating organization's website and is outlined below:

S&P's credit ratings are on a long-term rating scale that ranges from AAA to D, which represents the highest to lowest opinions of creditworthiness. The ratings from AA to CCC may be modified by the addition of a plus (+) or a minus (-) sign to show relative standing within the major rating categories. In addition, S&P may add a rating outlook of "positive", "negative" or "stable" which assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years). A rating of B by S&P is within the sixth highest of ten categories and is regarded as having significant speculative characteristics. According to S&P, an obligor rated "B" is more vulnerable than the obligors rated "BB" to adverse business, financial and economic conditions, but currently has the capacity to meet its financial commitments. An obligation rated "CCC" is currently vulnerable to nonpayment, and is dependent upon favorable business, financial, and economic conditions for the obligor to meet its financial commitment on the obligation. A rating of "CCC+" is considered to be less vulnerable than "CCC".

Moody's credit ratings are on a long-term rating scale that ranges from Aaa to C, which represents the highest to lowest opinions of creditworthiness. Moody's appends numerical modifiers 1, 2, and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the security ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of its generic rating category. In addition, Moody's may add a rating outlook of "positive", "negative", "stable" or "developing" which assess the likely direction of an issuers rating over the medium term. A rating of "Caa" by Moody's is within the seventh highest of nine categories. According to Moody's, obligations rated "Caa" are judged to be speculative of poor standing and are subject to very high credit risk.

Bellatrix has paid customary fees to S&P and Moody's in connection with the above-mentioned ratings. Bellatrix did not make any payments to S&P and Moody's in respect of any other service provided to Bellatrix by S&P and Moody's during the last two years.

DESCRIPTION OF SHARE CAPITAL

Bellatrix is authorized to issue an unlimited number of Common Shares and up to 95,978,621 Preferred Shares, issuable in series. There are currently 80,909,225 Common Shares and no issued and outstanding Preferred Shares of any series. The following is a description of the material provisions attaching to Bellatrix's share capital.

Common Shares

The Common Shares have the following rights, privileges, restrictions and conditions:

Voting Rights: Holders of Common Shares are entitled to receive notice of, to attend and to vote at all meetings of shareholders and are entitled to one vote per Common Share held at such meetings, except meetings of holders of another class or one or more series of another class of shares who are entitled to vote separately as a class at such meeting.

Dividends: Subject to the preferences accorded holders of any shares of Bellatrix ranking senior to the Common Shares from time to time with respect to the payment of dividends, holders of Common Shares are entitled to receive if, as and when declared by the Board, such dividends or other distributions as may be declared thereon by the Board from time to time.

20

Ranking: In the event of any voluntary or involuntary liquidation, dissolution or winding-up of Bellatrix or any other distribution of Bellatrix's assets among its shareholders for the purpose of winding-up its affairs, holders of Common Shares are entitled, subject to the preferences accorded to holders of any shares of Bellatrix ranking senior to the Common Shares from time to time with respect to payment on a Distribution, to share equally, share for share, in the remaining property of Bellatrix.

Preferred Shares

The Preferred Shares may at any time and from time to time be issued in one or more series, where the Board will be authorized to fix the number of shares of each series, subject to the limitation on the number of Preferred Shares to be issued as described above, and to determine for each series, subject to the terms and conditions set out below, the designation, rights, privileges, restrictions and conditions, including dividend rates, redemption prices, conversion rights and other matters. The Preferred Shares have the following rights, privileges, restrictions and conditions:

Voting Rights: Holders of any series of Preferred Shares will not be entitled (except as otherwise provided by law and except for meetings of the holders of Preferred Shares or a series thereof) to receive notice of, attend at, or vote at any meeting of shareholders of Bellatrix, unless the Board determines otherwise, in which case voting rights will only be provided in circumstances where Bellatrix has failed to pay a certain number of dividends on such series of Preferred Shares, which determination and number of dividends and any other terms in respect of such voting rights, will be determined by the Board and set out in the designations, rights, privileges, restrictions and conditions of such series of Preferred Shares.

Dividends: The holders of each series of Preferred Shares will be entitled to receive dividends (which may be cumulative or non-cumulative and variable or fixed) as and when declared by the Board on such series of Preferred Shares.

Ranking: Each series of Preferred Shares will be entitled to priority over the Common Shares and any other shares of Bellatrix ranking junior to the Preferred Shares with respect to the payment of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of Bellatrix, whether voluntary or involuntary, and any other distribution of the assets of Bellatrix among its shareholders for the purpose of winding-up its affairs. The Preferred Shares of any series may also be given such other preferences, not inconsistent with the provisions hereof, over the Common Shares and any other shares of Bellatrix ranking junior to the Preferred Shares, as may be determined by the Board.

Parity among Series: Each series of Preferred Shares will rank on a parity with every other series of Preferred Shares with respect to priority in the payment of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of Bellatrix, whether voluntary or involuntary, and any other distribution of the assets of Bellatrix among its shareholders for the purpose of winding-up its affairs.

Participation upon Liquidation, Dissolution or Winding Up: In the event of the liquidation, dissolution or winding up of Bellatrix or other distribution of assets of Bellatrix among its shareholders for the purpose of winding up its affairs, the holders of the Preferred Shares will be entitled to receive from the assets of Bellatrix any cumulative dividends, whether or not declared, or declared non-cumulative dividends or amounts payable on a return of capital which are not paid in full in respect of any Preferred Shares, before any amount is paid or any assets of Bellatrix are distributed to the holders of any Common Shares or shares of any other class ranking junior to the Preferred Shares. After payment to the holders of the Preferred Shares of the amount so payable to them as above provided they will not be entitled to share in any further distribution of assets of Bellatrix among its shareholders for the purpose of winding up its affairs.

Conversion: The Preferred Shares may be convertible into Common Shares or another series of Preferred Shares provided that the maximum number of Common Shares that may be issuable upon conversion of all series of Preferred Shares is limited to 38,391,448 Common Shares, which is equal to 20% of the number of Common Shares issued and outstanding as of April 10, 2015, which was the record date for the annual and special meeting of shareholders where the shareholders authorized the creation of the Preferred Shares.

Redemption: Each series of Preferred Shares may be redeemable by Bellatrix on such terms as may be determined by the Board.

MARKET FOR SECURITIES

Common Shares

The Common Shares are listed and trade on the TSX and trade under the symbol "BXE". The Common Shares were listed and traded on the NYSE until February 12, 2019. See "General Development of our Business - Share Consolidation and NYSE

21

Delisting". The following tables set forth the price range and trading volume of the Common Shares on the TSX and NYSE for the periods indicated.

TSX

Period	High ($)	Low ($)	Volume
2018
January	2.22	1.55	14,851,376
February	1.79	1.24	11,163,484
March	1.64	1.34	6,374,895
April	1.96	1.35	9,875,144
May	2.17	1.34	29,943,415
June	1.55	1.28	16,460,568
July	1.34	1.16	10,905,314
August	1.30	1.07	9,790,381
September	1.35	1.14	6,008,730
October	1.60	1.07	11,887,737
November	1.25	0.99	12,814,533
December	1.06	0.60	11,865,323
2019
January	0.74	0.48	20,921,481
February	0.72	0.58	6,341,923
March (1 – 15)	0.69	0.54	3,884,244

NYSE

Period	High (US$)	Low (US$)	Volume
2018
January	1.78	1.26	3,549,329
February	1.42	0.99	3,239,072
March	1.27	1.02	1,633,816
April	1.52	1.05	2,422,793
May	1.69	1.04	4,096,617
June	1.19	0.96	3,021,414
July	1.03	0.89	2,726,651
August	1.01	0.84	1,531,129
September	1.06	0.87	863,248
October	1.24	0.82	2,114,139
November	0.96	0.74	1,809,309
December	0.79	0.45	2,079,313
2019
January	0.55	0.35	3,189,715
February (1 - 11)(1)	0.55	0.45	404,484

Note:

22

(1) Effective February 12, 2019 the Common Shares were delisted from the NYSE. See "General Development of our Business - Other Developments - Share Consolidation and NYSE Delisting".

Convertible Debentures

The Convertible Debentures are listed and trade on the TSX and trade under the symbol "BXE.DB". The following tables set forth the price range and trading volume of the Convertible Debentures on the TSX for the periods indicated.

TSX

Period	High ($)	Low ($)	Volume
2018
January	93.00	90.00	666,000
February	86.50	68.00	904,000
March	84.61	76.00	206,000
April	90.00	79.50	155,000
May	90.95	81.00	91,000
June	88.00	77.99	207,000
July	88.00	71.00	263,000
August	73.00	68.00	548,000
September	71.98	64.50	277,000
October	70.00	60.01	764,000
November	61.00	44.99	900,000
December	55.00	41.16	327,000
2019
January	53.00	47.99	263,000
February	53.80	50.00	74,000
March (1 – 15)	53.80	40.01	701,000

23

PRIOR SALES

The following table sets out the details of each outstanding class of Bellatrix's securities that are not listed or quoted on a marketplace that were issued during the year ended December 31, 2018:

Date	Type of Security	Number of Securities	Price per Security ($)
April 12, 2018	Restricted Awards	60,100	$1.71(1)
May 31, 2018	Restricted Awards	36,700	$1.45(1)
June 4, 2018	Options	95,000	$1.48(2)
June 4, 2018	Performance Awards	335,800	$1.48(1)
June 4, 2018	Restricted Awards	664,000	$1.48(1)
August 31, 2018	Restricted Awards	11,500	$1.27(1)
September 11, 2018	Warrants	3,088,205	$1.30(3)
September 11, 2018	Second Lien Notes	n/a	US$72,108,000
September 11, 2018	New Money Notes	n/a	US$15,000,000
October 18, 2018	Flow-Through Shares	793,651	$1.44
November 13, 2018	Restricted Awards	107,900	$1.13(1)
December 12, 2018	New Money Notes	n/a	US$15,000,000

Notes:

(1) The value listed as the "price per security" represents the volume weighted average trading price of the Common Shares on the TSX for the five trading days prior to the grant of such restricted awards ("RestrictedAwards") or performance awards ("PerformanceAwards") of Bellatrix or issuance of Common Shares, as applicable.

(2) The value listed as the "price per security" represents the exercise price of Bellatrix's options to purchase Common Shares ("Options") granted.

(3) The value listed as the "price per security" represents the exercise price of the Warrants.

Additional information relating to Bellatrix's share option plan and incentive award plan is available in the management information circular dated March 26, 2018 for Bellatrix's annual general and special meeting of shareholders of Bellatrix held May 9, 2018.

ESCROWED SECURITIES 

There are no securities of Bellatrix currently held in escrow.

BORROWINGS

Credit Facilities

The Corporation maintains extendible revolving reserves-based credit facilities with a syndicate of lenders (the "Credit Facilities"). The Credit Facilities are available on a fully revolving basis until May 30, 2019, do not have any scheduled principal payments prior to maturity, can be further extended beyond May 30, 2019 with the consent of the lenders, and have a six month term-out period if not renewed. The Credit Facilities are available for general corporate purposes. The borrowing base under the Credit Facilities is subject to semi-annual review in May and November of each year. The semi-annual borrowing base review is at the sole discretion of the lenders taking into consideration the estimated future net revenue after income tax from Bellatrix's oil and natural gas properties and such other factors as the lenders determine relevant in accordance with customary practices for oil and gas production loans. Effective September 11, 2018, Bellatrix completed the Second Lien Refinancing, thereby amending and restating the terms of its Credit Facilities and reconfirming the borrowing base under the Credit Facilities at $100 million, with total commitments set at $95 million.

Amounts borrowed under the Credit Facilities bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 1.25% and 3.75%, depending on the type of borrowing and our Consolidated First Lien Debt to Consolidated EBITDA Ratio (as defined in the First Lien Credit Agreement). A standby fee is charged of between 0.5625% to 0.9375% on the undrawn portion of the Credit Facilities, depending on our Consolidated First

24

Lien Debt to consolidated EBITDA Ratio. At December 31, 2018, we had $47.8 million outstanding under the Credit Facilities (excluding outstanding letters of credit) at a weighted average interest rate of 4.42%.

The Credit Facilities are secured by a $1.0 billion demand debenture containing a first ranking floating charge and security interest over all of Bellatrix's current and future real and personal property.

The First Lien Credit Agreement contains customary borrowing base provisions and negative covenants including, but not limited to, restrictions on our ability to incur indebtedness, grant liens or security interests on assets, sell or otherwise transfer assets, make distributions, make investments, provide financial assistance, enter into hedging arrangements, prepay other debt (including the Senior Notes and 2L Notes) and amend certain material contracts (including the Senior Note Indenture and Note Purchase Agreement) and on our ability to merge and consolidate with other companies or change the nature of our business, in each case, subject to certain exceptions. The First Lien Credit Agreement also contains customary positive covenants including, but not limited to, delivery of financial and other information to the lenders, maintenance of existence, payment of taxes and other claims, maintenance of properties and insurance, access to premises and books and records by the lenders, compliance with applicable laws and regulations, including environmental laws, notice of certain events or circumstances to the lenders, and further assurances and provision of additional collateral and guarantees.

The Credit Facilities are subject to two financial covenants, which must be met quarterly and which were met as at December 31, 2018. The financial covenants provide that Bellatrix must maintain: (a) a consolidated First Lien Debt to consolidated EBITDA ratio of not greater than 3.0 to 1; and (b) a Consolidated Senior Debt (as defined in the First Lien Credit Agreement) to consolidated EBITDA ratio of not greater than (i) 5.0 to 1 until December 31, 2020, (ii) 4.5 to 1 during the fiscal year ending December 31, 2021, and (iii) 4.0 to 1 thereafter. We calculate our financial covenants quarterly at the end of each fiscal quarter.

The First Lien Credit Agreement provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, covenant defaults, inaccuracies of representations and warranties, bankruptcy and insolvency proceedings, material money judgments, cross defaults, change of control and other customary events of default.

For a complete description of the terms of the Credit Facilities, a copy of the First Lien Credit Agreement and all amendments thereto, have been filed on www.sedar.com and www.sec.gov under Bellatrix's SEDAR and EDGAR profiles, respectively.

Senior Notes

In 2018, through a series of transactions, US$24,115,000 aggregate principal amount of Senior Notes were surrendered to Bellatrix in exchange for an aggregate of 19,900,032 Common Shares. The Common Shares were qualified for issuance pursuant to prospectus supplements filed by Bellatrix under the Shelf Prospectus. See "General Development of our Business - Borrowings and Financings - Senior Note Exchanges".

In addition, pursuant to the Second Lien Refinancing, US$80.12 million of outstanding Senior Notes were exchanged for US$72.108 million aggregate principal amount of Second Lien Notes. See "General Development of our Business - Borrowings and Financings - Second Lien Refinancing".

The remaining Senior Notes continue to be governed by the Senior Note Indenture and bear interest at 8.5% per annum, payable semi-annually in arrears on May 15 and November 15 of each year. The Senior Notes are unsecured and are effectively subordinated to the Credit Facilities and the 2L Notes to the extent of the value of the collateral. The Senior Notes mature on May 15, 2020. The Senior Notes may be redeemed at Bellatrix's option as follows:

(a) the Senior Notes may be redeemed in whole or in part at the following redemption prices (expressed as a percentage of the principal amount of the Senior Notes) plus accrued and unpaid interest: from May 15, 2018 to May 14, 2019 at 102.125%; on or after May 15, 2019 at 100%; and

(b) at any time, upon not less than 30 nor more than 60 days' notice, in whole, but not in part at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus accrued but unpaid interest thereon if Bellatrix determines that it has or will become obligated to pay Additional Amounts (as defined in the Senior Note Indenture) because of a Change in Tax Law (as defined in the Senior Note Indenture).

If a Change of Control (as defined in the Senior Note Indenture) occurs, and unless an exemption described in the Senior Note Indenture applies, the holders of the Senior Notes can require Bellatrix to repurchase their Senior Notes at a price equal to 101% of the aggregate principal amount of the Notes together with accrued and unpaid interest thereon.

25

For a complete description of the terms of the Senior Notes, a copy of the Senior Note Indenture has been filed on www.sedar.com and www.sec.gov under Bellatrix's SEDAR and EDGAR profiles, respectively.

2L Notes

The 2L Notes are governed by the terms of the Note Purchase Agreement. The 2L Notes bear interest at 8.5% per annum payable quarterly and are due September 11, 2023, provided that if the Senior Notes have not been refinanced or repaid by March 14, 2020 on terms permitted under the Note Purchase Agreement such that no more than US$25 million in principal amount of the Senior Notes remains outstanding on that date, then the maturity date for all 2L Notes will be March 14, 2020. As of December 31, 2018, there was approximately US$102.1 million of principal 2L Notes outstanding.

Bellatrix's obligations pursuant to the 2L Notes are secured by a $250,000,000 demand debenture with a floating charge and security interest over all of Bellatrix's current and future real and personal property, which is subordinated to the security the Corporation has provided to secure its obligations under the Credit Facilities pursuant to the terms of an intercreditor agreement. Any 2L Notes issued may be voluntarily prepaid subject to certain make-whole amounts and/or repayment fees. If a Change of Control (as defined in the Note Purchase Agreement) occurs, Bellatrix is required to make an offer to repurchase the 2L Notes at a price equal to 101% of the aggregate principal amount of the 2L Notes, together with accrued and unpaid interest thereon.

The Note Purchase Agreement contains customary negative covenants including, but not limited to, restrictions on our ability to incur indebtedness, grant liens or security interests on assets, sell or otherwise transfer assets, make distributions, make investments, provide financial assistance, prepay other debt (including the Senior Notes) and amend certain material contracts (including the Senior Note Indenture and the First Lien Credit Agreement) and on our ability to merge and consolidate with other companies or change the nature of our business, in each case, subject to certain exceptions. The Note Purchase Agreement also contains customary positive covenants including, but not limited to, delivery of financial and other information to the noteholders, maintenance of existence, payment of taxes and other claims, maintenance of properties and insurance, access to premises and books and records by noteholders, compliance with applicable laws and regulations, including environmental laws, notice of certain events or circumstances to the noteholders, and further assurances and provision of additional collateral and guarantees.

The Note Purchase Agreement contains one financial covenant, which is identical to the second financial covenant under the First Lien Credit Agreement and which provides that Bellatrix must maintain a Consolidated Senior Debt to Consolidated EBITDA Ratio (as defined in the Note Purchase Agreement) of not greater than (a) 5.0 to 1 until December 31, 2020, (b) 4.5 to 1 during the fiscal year ending December 31, 2021, and (c) 4.0 to 1 thereafter. The Corporation will calculate this financial covenant at the end of each fiscal quarter. The calculation for the financial covenant is based on specific definitions that are not in accordance with International Financial Reporting Standards.

The Note Purchase Agreement provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and any outstanding commitments terminated. Such events of default include payment defaults to the noteholders, covenant defaults, inaccuracies of representations and warranties, bankruptcy and insolvency proceedings, material money judgments, cross defaults and other customary events of default.

A copy of the Note Purchase Agreement and all amendments thereto, have been filed on www.sedar.com and www.sec.gov under our SEDAR and EDGAR profiles, respectively.

Convertible Debentures

On August 9, 2016 Bellatrix issued $50,000,000 principal amount of Convertible Debentures pursuant to the Convertible Debenture and Subscription Receipt Offering. The Convertible Debentures have a face value of $1,000 per Convertible Debenture and have a maturity date of September 30, 2021 (the "Maturity Date"). The Convertible Debentures bear interest at an annual rate of 6.75% payable semi-annually in arrears, on September 30 and March 31 in each year. The payment of the principal and premium, if any, of, and interest on, the Convertible Debentures is subordinated in right of payment to the prior payment in full of all "Senior Indebtedness" (as such term is defined in the Debenture Indenture and which includes the Credit Facilities, the Senior Notes and the 2L Notes). Convertible Debentures will rank equally with one another and will rank pari passu with all of Bellatrix’s other existing and future unsecured subordinated indebtedness to the extent subordinated on the same terms.

Each Convertible Debenture will be convertible into Common Shares at a conversion price of $8.10 per Common Share (the "Conversion Price") at the option of the holder thereof at any time prior to 5:00 p.m. (Calgary time) on the earlier of: (i) the last business day immediately preceding the Maturity Date; (ii) the last business day immediately preceding any date set for redemption, and (iii) if called for repurchase pursuant to a mandatory repurchase, on the business day immediately preceding the payment date,

26

representing a conversion rate of approximately 123.4568 Common Shares per $1,000 principal amount of Convertible Debentures, subject to adjustment in accordance with the Debenture Indenture.

The Convertible Debentures are not redeemable by Bellatrix before September 30, 2019. On and after September 30, 2019 and prior to September 30, 2020, the Convertible Debentures are redeemable at Bellatrix's option, in whole or in part from time to time, on not more than 60 days' and not less than 30 days' prior written notice, at a redemption price equal to the principal amount thereof plus accrued and unpaid interest thereon, if any, up to but excluding the date set for redemption, if the weighted average trading price of the Common Shares for the specified period is not less than 125% of the Conversion Price. On and after September 30, 2020, the Convertible Debentures are redeemable at Bellatrix's option, in whole or in part from time to time, on not more than 60 days' and not less than 30 days' prior written notice, at a redemption price equal to the principal amount thereof plus accrued and unpaid interest thereon, if any, up to but excluding the date set for redemption.

Upon the maturity or redemption of the Convertible Debentures, Bellatrix may pay the outstanding principal of the Convertible Debentures in cash or may, at its option, on not greater than 60 days and not less than 40 days prior notice and subject to regulatory approval, elect to satisfy its obligations to repay all or a portion of the principal amount of the Convertible Debentures, which have matured or been redeemed, by issuing and delivering that number of Common Shares obtained by dividing the aggregate principal of the Convertible Debentures which have matured or redeemed by 95% of the weighted average trading price of the Common Shares on the TSX for the 20 consecutive trading days ending five trading days preceding the date fixed for redemption or the Maturity Date, as the case may be. Any accrued and unpaid interest will be paid in cash.

Within 30 days following the occurrence of a "Change of Control" (as such term is defined in the Debenture Indenture), Bellatrix will be required to make an offer (the "Change of Control Purchase Offer") in writing to purchase all of the Convertible Debentures then outstanding, at a price equal to 100% of the principal amount thereof plus accrued and unpaid interest thereon. If 90% or more of the aggregate principal amount of the Convertible Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to Bellatrix pursuant to the Change of Control PurchaseOffer, Bellatrix will have the right to redeem all the remaining Convertible Debentures at the same offer price.

In addition, if a Change of Control occurs in which 10% or more of the consideration for the Common Shares in the transaction or transactions constituting the Change of Control consists of cash (other than payment for fractional Common Shares or cash payments made in satisfaction of appraisal rights), equities, securities or other properties not traded or intended to be traded immediately following such transaction on a stock exchange, then during the period beginning 10 trading days after the anticipated date that such Change of Control becomes effective and ending 30 days after the Change of Control Purchase Offer is delivered, holders of the Convertible Debentures will be entitled to convert the Convertible Debentures at an adjusted conversion price which will be adjusted based on a formula dependent on the then current trading price and the remaining period up to but excluding September 30, 2020.

For a complete description of the terms of the Convertible Debentures, see the copy of the Debenture Indenture that has been filed on www.sedar.com and www.sec.gov under Bellatrix's SEDAR and EDGAR profiles, respectively.

DIRECTORS AND OFFICERS

The following table sets forth the name, age (as at December 31, 2018), province or state and country of residence, date first elected as a director of Bellatrix where applicable and office held for each of the current (as at the date hereof) directors and officers of Bellatrix together with their principal occupations during the last five years. The directors of Bellatrix shall hold office until the next annual meeting of shareholders or until their respective successors have been duly elected or appointed.

Name, Municipality of Residence and Age	Position with Bellatrix	Date First Elected or Appointed as Director(1)	Principal Occupation
Brent A. Eshleman, P. Eng. Calgary, Alberta, Canada Age: 54	President and Chief Executive Officer and Director	February 15, 2017	President and Chief Executive Officer of Bellatrix since February 15, 2017 and prior thereto was Interim President and Chief Executive Officer since November 25, 2016; prior thereto Chief Operating Officer since September 1, 2014 and Executive Vice-President since July 2012.

27

Maxwell A. Lof, CFA Calgary, Alberta, Canada Age: 51	Executive Vice-President and Chief Financial Officer	N/A	Executive Vice-President and Chief Financial Officer of Bellatrix since July 1, 2017 and prior thereto was Chief Financial Officer of geoLOGIC systems Ltd. from May 2016 to June 2017. Prior thereto, Chief Financial Officer of Surge Energy Inc. from April 2010 to June 2015.
Charles R. Kraus, Esq. Calgary, Alberta, Canada Age: 43	Executive Vice-President, General Counsel and Corporate Secretary	N/A	Executive Vice-President, General Counsel and Corporate Secretary of Bellatrix since March 15, 2017. Prior thereto, Vice-President, General Counsel and Corporate Secretary since September, 2014. Prior thereto, Vice-President, General Counsel and Corporate Secretary of Lone Pine Resources Inc. from 2011 to 2014. Prior thereto, Mr. Kraus was in private practice for 10 years, most recently with the Calgary office of Stikeman Elliott LLP.
Garrett K. Ulmer, P. Eng. Calgary, Alberta, Canada Age: 48	Chief Operating Officer	N/A	Chief Operating Officer since March 15, 2017. Prior thereto, Vice-President, Engineering of Bellatrix since October 2011.
Timothy A. Blair Cochrane, Alberta, Canada Age: 60	Vice-President, Land	N/A	Vice-President, Land of Bellatrix, and prior to November 1, 2009 of True Energy Inc.. Prior thereto, Vice-President, Land for Terra Energy Corp. from June 2004 to September 2009.
Chris D. Curry, CPA, CA Calgary, Alberta, Canada Age: 44	Vice-President, Finance	N/A	Vice-President, Finance of Bellatrix since November 2017. Prior thereto, Vice-President, Controller since May 2014.
Robert O. Lee, CET Cochrane, Alberta, Canada Age: 57	Vice-President, Marketing	N/A	Vice-President, Marketing since March 15, 2017. Prior thereto, Director, Marketing and Commercial of Bellatrix since December 2008.
Mark L. Stephen, P. Eng. Calgary, Alberta, Canada Age: 58	Vice-President, Operations	N/A	Vice-President, Operations of Bellatrix since September 1, 2014. Prior thereto, Director of Drilling and Completions of Bellatrix from December 2013 to August 2014.
Steve G. Toth, CFA Calgary, Alberta, Canada Age: 41	Vice-President, Investor Relations and Corporate Development	N/A	Vice-President, Investor Relations and Corporate Development since November 2017. Prior thereto, Vice-President, Investor Relations of Bellatrix since October 2014. Prior thereto, Director, Oil & Gas Equity Research Analyst at a leading global wealth management and investment firm.

28

W.C. (Mickey) Dunn Calgary, Alberta, Canada Age: 65	Chairman(2)	August 31, 2000	Chairman of Bellatrix; previously director of Precision Drilling Inc. from 1992 to 2013.
Murray L. Cobbe Calgary, Alberta, Canada Age: 69	Director(4)	September 22, 2006	Chairman and, prior to August 2009, President and Chief Executive Officer of Trican Well Service Ltd. (a publicly traded well service company). Director of Secure Energy Services Inc. since 2010; previously a director of Pason Systems Inc.
John H. Cuthbertson, Q.C. Calgary, Alberta, Canada Age: 68	Director(2)	August 31, 2000	Partner, Burnet, Duckworth & Palmer LLP (barristers and solicitors).
Lynn Kis, P. Eng. Calgary, Alberta, Canada Age: 68	Director(4)	August 9, 2017	Independent businesswoman; previously Senior Vice President and Manager of Ryder Scott Company, an oil and gas consulting firm, from 2013 to 2015; currently a director of Painted Pony Energy Ltd.
Keith E. Macdonald, CPA, CA Calgary, Alberta, Canada Age: 62	Director(3)	April 26, 2007	President of Bamako Investment Management Ltd., a private holding and financial consulting company, since July 1994. Mr. Macdonald was the Chief Executive Officer and a director of EFLO Energy Inc. from March 2011 to January 2015. Currently a director of Surge Energy Inc.; previously a director of Madalena Energy Inc. from 2010 to 2017 and Mountainview Energy Ltd. from 2010 to 2017.
Thomas E. MacInnis Calgary, Alberta, Canada Age: 47	Director(3)	February 6, 2017	Independent businessman;previously Head of Financial Markets at National Bank Financial, Calgary from 2009 to 2017; prior thereto, a founder and Managing Director of Tristone Capital, an energy focused boutique investment banking practice in Calgary, Alberta, from 2000 to 2009. Mr. MacInnis currently a director of Claim Post Resources Inc.
Steven J. Pully, Esq., CPA, CFA Dallas, Texas, USA Age: 58	Director	January 1, 2015	Independent businessman and consultant and director of VAALCO Energy, Inc., Goodrich Petroleum Corporation and Titan Energy, LLC; previously General Counsel and a Partner of Carlson Capital, L.P., an alternative asset management firm, from January 2008 to September 2014. Previously a director of Energy XXI Gulf Coast, Inc.

29

Murray B. Todd, B.Sc. P. Eng. Calgary, Alberta, Canada Age: 83	Director(4)	November 2, 2005	Independent businessman; previously President and CEO of Canada Hibernia Holding Corporation (an oil and gas production company) from 1996 to 2017.
Keith Turnbull, B.Sc., CPA, CA Calgary, Alberta, Canada Age: 69	Director(3)	January 1, 2014	Business consultant since January 1, 2010. Prior thereto, Partner at KPMG LLP. President of K.S. Turnbull Professional Corporation and currently a director of Crown Point Energy Inc; previously a director of Renegade Petroleum Ltd. from June 2012 to March 2014.

Notes:

(1) To the extent the date of election or appointment is prior to November 1, 2009, such date reflects the date of election or appointment as a director of True Energy Inc. (administrator of True Energy Trust). The term of each director is until the next annual meeting of Bellatrix or until their successors are elected, but not later than the date of the next annual meeting of Bellatrix.

(2) Member of Compensation and Governance Committee.

(3) Member of Audit Committee.

(4) Member of Reserves, Safety and Environment Committee.

As at March 21, 2019, the directors and officers of Bellatrix, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 889,675 Common Shares, representing approximately 1.10% of the issued and outstanding Common Shares.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Cease Trade Orders

To the knowledge of Bellatrix, except as described below, no director or executive officer of Bellatrix (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 Bellatrix), 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.

Following the resignation of W.C. (Mickey) Dunn from the board of directors of The Cash Store Financial Services Inc. ("Cash Store Financial") on January 2, 2014, the company announced that a Cease Trade Order was issued on May 30, 2014 by the Alberta Securities Commission (and subsequently on June 18, 2014 by the Ontario Securities Commission) due to Cash Store Financial failing to file interim financial statements for the 6-month period ended March 31, 2014.

Keith Macdonald served on the board of directors of Mountainview Energy Ltd. ("Mountainview") until March 15, 2017. On May 5, 2016, the Alberta Securities Commission issued a Cease Trade Order against Mountainview for failure to file annual audited financial statements, annual management discussion and analysis and certification of annual filing for the fiscal period ended December 31, 2015 (the "Order"). As of the date hereof, the Order remains in effect.

Bankruptcies

To the knowledge of Bellatrix, except as described below, no director or executive officer of Bellatrix (nor any personal holding company of any of such persons) or shareholder holding a sufficient number of securities of Bellatrix to affect materially the control of Bellatrix: (a) is, as of the date of this Annual Information Form, or has been within the ten years before the date of this

30

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

W.C. (Mickey) Dunn, the Chairman of the Board, was a director of Cash Store Financial from May 1, 2003 until his resignation on January 2, 2014. On April 14, 2014, Cash Store Financial, The Cash Store Inc., TCS Cash Store Inc., Instaloans Inc., 7252331 Canada Inc., 5515433 Manitoba Inc., 1693926 Alberta Ltd. doing business as "The Title Store" obtained an Initial Order under the Companies' Creditors Arrangement Act (the "CCAA"). The applicants sought and were granted the stay of proceedings and other relief provided under the CCAA. On January 4, 2016, 1511419 Ontario Inc., formally known as Cash Store Financial and applicants announced that it had successfully implemented its Plan of Compromise and Arrangement pursuant to the CCAA with an implementation date of December 31, 2015. On November 16, 2016, 1511419 Ontario Inc. was granted a stay extension until November 18, 2017.

Keith Macdonald, a director of Bellatrix, served on the board of directors of Mountainview until March 15, 2017. On October 14, 2016, a wholly-owned entity of Mountainview, Mountainview Divide LLC which owned key assets in North Dakota, filed a voluntary petition under Chapter 11 of the United States Bankruptcy Code. A plan of reorganization was filed September 22, 2017 and amended October 16, 2017 to sell the company’s oil and gas assets (and related abandonment/environmental obligations) in settlement of outstanding liabilities.

Penalties and Sanctions

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

Conflicts of Interest

There are potential conflicts of interest to which the directors and officers of Bellatrix will be subject to in connection with the operations of Bellatrix. In particular, certain of the directors and officers of Bellatrix are involved in managerial or director positions with other oil and gas companies whose operations may, from time to time, be in direct competition with Bellatrix or with entities which may, from time to time, provide financing to, or make equity investments in, its competitors. In accordance with the ABCA, directors who have a material interest or any person who is a party to a material contract or a proposed material contract with Bellatrix are required, subject to certain exceptions, to disclose that interest and generally abstain from voting on any resolution to approve the contract.

AUDIT COMMITTEE INFORMATION

Audit Committee Mandate and Terms of Reference

The Mandate of the Audit Committee of the Board is attached hereto as Appendix "C".

Composition of the Audit Committee

The following table sets forth the names of each current member of the Audit Committee, whether such member is independent, whether such member is financially literate and the relevant education and experience of each such member:

31

Name and municipality of residence	Independent	Financially literate	Relevant education and experience
Keith E. Macdonald, CPA, CA	Yes	Yes	President of Bamako Investment Management Ltd., a private holding and financial consulting company since July 1994. Mr. Macdonald was the Chief Executive Officer and a director of EFLO Energy Inc. from March 2011 to January 2015. Currently an independent businessman. to September 2017. He is also a director of Surge Energy Inc. Mr. MacDonald is a Chartered Accountant.
Keith Turnbull, B.Sc. CPA, CA Calgary, Alberta, Canada	Yes	Yes	Chartered Accountant and business consultant since his retirement as a Partner from KPMG LLP on December 31, 2009, after nearly 30 years of service. He has extensive experience in all aspects of public company accounting, finance and management matters, including serving as Office Managing Partner at KPMG LLP's Calgary office, where he was responsible for the strategic direction and growth of the Calgary practice, as well its audit, tax and advisory business. A member of the Alberta and Canadian Institute of Chartered Accountants and the Institute of Corporate Directors. He is currently a director and chair of the audit committee of Crown Point Energy Inc.
Thomas E. MacInnis Calgary, Alberta, Canada	Yes	Yes	Independent businessman; previously head of Financial Markets for National Bank Financial, Calgary from 2009 to 2017. Prior thereto, a founder and Managing Director of Tristone Capital, an energy focused boutique investment banking practice in Calgary, Alberta, from 2000 to 2009. He currently serves as a director of Claim Post Resources Inc. He has a masters of business administration from the Richard Ivey School of Business, a professional engineering diploma from the Southern Alberta Institute of Technology and a bachelor of commerce from Saint Mary`s University. He is a member of the Institute of Corporate Directors and is currently a director of Lex Capital Partners Fund, Lex Energy Partners Fund and Lex Energy Partners II Fund and serves on such funds investment committees. He is also currently a director of Claim Post Resources Inc.

Pre-Approval Policies and Procedures

The Audit Committee has adopted an Auditor Services Pre-Approval Policy (the "Policy") with respect to the pre-approval of audit and permitted non-audit services to be provided by KPMG LLP, Bellatrix's independent auditor. Pursuant to the Policy, the Audit Committee on an annual basis may approve the provision of a specified list of audit and permitted non-audit services that the Audit Committee believes to be typical, re-occurring or otherwise likely to be provided by KPMG LLP during the current fiscal year. The list of services should be sufficiently detailed as to the particular services to be provided to ensure that the Audit Committee knows precisely what services it is being asked to pre-approve and it is not necessary for any member of management to make a judgment as to whether a proposed service fits within the pre-approved services.

In addition, pursuant to the Policy, the Audit Committee has delegated its pre-approval authority to the Chair of the Audit Committee. The Chair of the Audit Committee is required to report any granted pre-approvals to the Audit Committee at its next scheduled meeting. The Audit Committee shall not delegate to management the Audit Committee's responsibilities for pre-approving audit and non-audit services to be performed by KPMG LLP.

Pursuant to the Policy, there is an exception to the pre-approval requirements for permitted non-audit services, provided all such services were not recognized at the time of the engagement to be non-audit services and, once recognized, are promptly brought to the attention of the Audit Committee and approved prior to the completion of the audit. The aggregate amount of all services approved in this manner may not constitute more than five percent of the total fees paid to KPMG LLP during the fiscal year in which the services are provided.

32

External Auditor Service Fees

Audit Fees

The aggregate fees billed by Bellatrix's external auditor in each of the last two fiscal years for services including audit and review of Bellatrix’s financial statements and services normally provided in connection with statutory and regulatory filings or engagements were $782,170 in 2018 and $833,530 in 2017.

Audit - Related Fees

There were no audit-related feesbilled in 2018 or 2017 by the external auditor that are reasonably related to the performance of the audit or review of the financial statements that are not reported under "Audit Fees" above.

Tax Fees

There was $22,750 in 2018 and $51,044 in 2017 billed for professional services rendered by the external auditor for tax compliance, and routine tax advice and planning.

All Other Fees

No other professional services fees were billed by the external auditor for other non-audit related fees in 2018 or 2017.

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 Bellatrix's operations in any manner that is materially different than 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, Bellatrix is unable to predict what additional legislation or amendments governments may enact in the future.

The Corporation has interests in crude oil and natural gas properties, along with related assets, in the Canadian provinces of Alberta, Saskatchewan and British Columbia. 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 Bellatrix'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; and (vii) 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.

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,

33

natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions, supply/demand balance and other contractual terms. Spot and future prices can also be influenced by supply and demand fundamentals on various trading platforms.

Natural Gas Liquids

The pricing of condensates and other NGLs such as ethane, butane and propane sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such prices depend, in part, on the quality of the NGLs, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply/demand balance and other contractual terms.

Exports from Canada

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

34

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 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 or their cancellation altogether.

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 has been delayed approximately 12 months due to a revised permitting schedule. Enbridge now expects to receive Minnesota State permits by November 2019 and remaining Federal permits 30-60 days thereafter. An in-service date is now expected to only occur by the end of 2019.

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, the Cabinet ordered the NEB to reconsider its recommendation in light of the Federal Court of Appeal decision. The NEB is expected to deliver an updated recommendation and list of proposed conditions to Cabinet by February 22, 2019. While the scope of the NEB's reconsideration is limited to the environmental effects of project-related marine shipping, its recommendation will apply to the entire proposed pipeline expansion. Cabinet will have three months to consider the NEB's report and, subject to a new round of indigenous consultation, decide whether it will 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 "Industry Conditions - Regulatory Authorities and Environmental Regulation - Federal".

On November 28, 2018, the Government of Alberta announced that Alberta has started negotiations for investment in new rail capacity to address the historically high price differential. Commencing in late 2019, the Government of Alberta intends to create enough new rail capacity to move 120,000 barrels a day out of the province. The Government expects that the railcar acquisition will narrow the crude oil price gap by up to $4 per barrel and will provide junior producers with a more affordable option to move their crude oil to market.

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.

35

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 bbls/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 bbls/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 bbls/d to a maximum output of approximately 3.63 million bbls/d. The Corporation is not subject to a curtailment order.

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 version 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 curtailment of Alberta's crude oil and 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 reduced the required offering under NAFTA, with the result that the amount of crude oil and bitumen that Canada is required to offer, which 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.

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

36

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 of Western Canada have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or licence. 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 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.

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 of 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

37

make $1.6 billion available to the 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 "ModernizedFramework") that applies to all wells drilled after December 31, 2016. The previous royalty framework (the "OldFramework") 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.

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 metres 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 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.

British Columbia

38

Producers of crude oil in British Columbia receive royalty invoices each month for every well or unitized tract that is producing and/or reporting sales. The royalty calculation takes into account the production of crude oil on a well-by-well basis, which can be up to 40%, based on factors such as the volume of crude oil produced by the well or tract and the crude oil vintage, which depends on density of the substance and when the crude oil pool was located. Royalty rates are reduced on low-productivity wells and other wells with applicable royalty exemptions to reflect higher per-unit costs of exploration and extraction.

Producers of natural gas and NGLs in British Columbia receive royalty invoices each month for every well or unitized tract that is producing and/or reporting sales. Different royalty rates apply for natural gas, NGLs and natural gas by-products. For natural gas, the royalty rate can be up to 27% of the value of the natural gas and is based on whether the gas is classified as conservation gas or non-conservation gas, as well as reference prices and the select price. For NGLs and condensates, the royalty rate is fixed at 20%.

The royalties payable by each producer will thus vary depending on the types of wells and the characteristics of the substances being produced. Additionally, the Government of British Columbia maintains a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbia's low productivity natural gas wells. These include both royalty credit and royalty reduction programs.

Producers of crude oil and natural gas from freehold lands in British Columbia are required to pay monthly freehold production taxes. For crude oil, the applicable freehold production tax is based on the volume of monthly production, which is either a flat rate, or, beyond a certain production level, is determined using a sliding scale formula based on the production level. For natural gas, the applicable freehold production tax is a flat rate, or, at certain production levels, is determined using a sliding scale formula based on a reference price, and depends on whether the natural gas is conservation gas or non-conservation gas. The production tax rate for freehold NGLs is a flat rate of 12.25%. Additionally, owners of mineral rights in British Columbia must pay an annual mineral land tax that is equivalent to $4.94 per hectare of producing lands. Non-producing lands are taxed on a sliding scale from $1.25 to $4.94 per hectare, depending on the total number of hectares owned by the entity.

Saskatchewan

In Saskatchewan, the Crown owns approximately 80% of the crude oil and natural gas rights, with the remainder being freehold lands. For Crown lands, taxes (the "ResourceSurcharge") and royalties are applicable to revenue generated by entities focused on crude oil and natural gas operations. The Resource Surcharge rate is 3% of the value of sales of all crude oil and natural gas produced from wells drilled in Saskatchewan prior to October 1, 2002. For crude oil and natural gas produced from wells drilled in Saskatchewan after September 30, 2002, the Resource Surcharge rate is 1.7% of the value of sales. Additionally, a mineral rights tax is charged to mineral rights holders paid on an annual basis at the rate of $1.50 per acre owned regardless of whether or not there is production from the lands.

In addition to such surcharges and taxes, the Crown royalty rate payable in respect of crude oil, depends on a number of variables including, the type and vintage of crude oil, the quantity of crude oil produced in a month, the average wellhead price and certain price adjustment factors determined monthly by the provincial government. This means that producers may pay varying royalties each month, depending on monthly production, governmental price adjustments and the underlying characteristics of the producer's assets. Where production equals the relevant reference well production rate, the minimum Crown royalty rate payable ranges from 5% to 20% and the maximum royalty rate payable ranges from 30% to 45%, depending on the classification of the crude oil, the average wellhead price and subject to applicable deductions.

The amount payable as a Crown royalty in respect of production of natural gas and NGLs is determined by a sliding scale based on the monthly provincial average gas price published by the Government of Saskatchewan, the quantity produced in a given month, the type of natural gas, the classification of the natural gas and the finished drilling date of the respective well. Similar to crude oil royalties, the royalties payable on natural gas will range from 5% to 20%, and additional marginal royalty rates may apply between 30% to 45%, where average wellhead prices are above base prices. Again, this means that producers may pay varying royalties each month, depending on pricing factors, governmental adjustments and the underlying characteristics of the producer's assets.

The Government of Saskatchewan currently provides a number of targeted incentive programs. These include both royalty reduction and incentive volume programs, with targeted programs in effect for certain vertical crude oil wells, exploratory gas wells, horizontal crude oil and natural gas wells, enhanced crude oil recovery wells and high water-cut crude oil wells.

For production from freehold lands, producers must pay a freehold production tax, determined by first determining the Crown royalty rate, and then subtracting a calculated production tax factor. Depending on the classification of the petroleum substance produced, this subtraction factor may range between 6.9 and 12.5, however, in certain circumstances, the minimum rate for freehold

39

production tax can be zero. This means that the ultimate tax payable to the Crown by producers on freehold lands will vary based on the underlying characteristics of the producer's assets.

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 each of the Western Canadian provinces is included in the above descriptions of the royalty regimes in such provinces.

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.

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

40

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 publicand 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.

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.

British Columbia

In British Columbia, the Oil and Gas Activities Act (the "OGAA") impacts conventional crude oil and natural gas producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the "B.C.Commission") has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for crude oil and natural gas activities. The Environmental Protection and Management Regulation establishes the government's environmental objectives for water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the B.C. Commission to consider these environmental objectives in deciding whether or not to authorize a crude oil or natural gas activity. In addition, although not an exclusively environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires proponents to obtain various approvals before undertaking exploration or production work, such as geophysical licences, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.

The British Columbia Government recently passed Bill 51 - 2018: Environmental Assessment Act, which replaces the environmental assessment regime that has been in place since 2002. The Government expects that the updated Environmental Assessment Act will enter into force in late 2019. The amendments will subject proposed projects to an enhanced environmental review process

41

similar in substance to the federal environmental assessment process, as well as enhance indigenous engagement in the project approval process with an emphasis on consensus-building.

Saskatchewan

The Saskatchewan Ministry of the Economy, Petroleum Branch, is the primary regulator of crude oil and natural gas activities in the province. In May 2011, the Government of Saskatchewan passed changes to The Oil and Gas Conservation Act (the "SKOGCA"), the act governing the regulation of resource development operations in the province. Although the associated Bill received Royal Assent on May 18, 2011, it was not proclaimed into force until April 1, 2012, in conjunction with the release of The Oil and Gas Conservation Regulations, 2012 (the "OGCR") and The Petroleum Registry and Electronic Documents Regulations (the "Registry Regulations"). The aim of the amendments to the SKOGCA, and the associated regulations, is to provide resource companies investing in Saskatchewan's energy and resource industries with the best support services and business and regulatory systems available. With the enactment of the Registry Regulations and the OGCR, the Government of Saskatchewan has implemented a number of operational requirements, including the increased demand for record-keeping, increased testing requirements for injection wells and increased investigation and enforcement powers; and, procedural requirements including those related to Saskatchewan's participation as partner in the Petroleum Registry of Alberta.

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 have 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 licensing and liability management programs pending a final decision from the Supreme Court of Canada. The AER amended it's 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

42

shareholder information, including whether any director and officer was 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 it 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.

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.

British Columbia

Similar to Alberta, the B.C. Commission oversees a Liability Management Rating Program (the "BC LMR Program"), which is designed to manage public liability exposure related to crude oil and natural gas activities by ensuring that permit holders carry the financial risks and regulatory responsibility of their operations through to regulatory closure. Under the BC LMR Program, the B.C. Commission determines the required security deposits for permit holders under the OGAA. The LMR is the ratio of a permit holder's deemed assets to deemed liabilities. Permit holders whose deemed liabilities exceed deemed assets (i.e., an LMR of below a ratio of 1.0) will be considered at-risk and reviewed for a security deposit. Permit holders that fail to comply with security deposit requirements are deemed non-compliant under the OGAAand enter the compliance and enforcement framework.

In the spring of 2018 the Government of British Columbia passed certain amendments to the OGAA (the "Amendments") which when brought into force, will replace the orphan site reclamation fund tax currently paid by permit holders with a levy paid to the Orphan Site Reclamation Fund ("OSRF"). Similar to Alberta's Orphan Fund, the OSRF is an industry-funded program created to address the abandonment and reclamation costs for orphan sites. Permit holders currently make monthly payments of $0.03 per 1,000 cubic metres of marketable gas produced and $0.06 per cubic meter of petroleum produced. The Amendments will require permit holders to pay their proportionate share of the regulated amount of the levy, calculated using each permit holder's proportionate share of the total liabilities of all permit holders required to contribute to the fund. The Amendments permit the B.C. Commission to impose more than one levy in a given calendar year. It is not clear when these provisions of the Amendments changing from a tax based on production to a liability-based payment will be brought into force.

Saskatchewan

The Ministry of the Economy administrates the Licensee Liability Rating Program (the "SK LLR Program"). The SK LLR Program is designed to assess and manage the financial risk that a licensee's well and facility abandonment and reclamation liabilities pose to the orphan fund (the "Oil and Gas Orphan Fund") established under the SKOGCA. The Oil and Gas Orphan Fund is responsible for carrying out the abandonment and reclamation of wells and facilities contained within the SK LLR Program when a licensee or WIP is defunct or missing. The SK LLR Program requires a licensee whose deemed liabilities exceed its deemed assets (i.e., an LLR of below 1.0) to post a security deposit. The ratio of deemed assets to deemed liabilities is assessed once each month for all licensees of crude oil, natural gas and service wells and upstream crude oil and natural gas facilities. On August 19, 2016, the Ministry of the Economy released a notice to all operators introducing interim measures in response to Redwater. Among other things, the Ministry announced that it considers all licence transfer applications non-routine as the Ministry does not strictly rely on the standard LMR calculation in evaluating deposit requirements, and that further changes may be forthcoming.

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.

43

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, 184 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 in place 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.

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

44

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.

British Columbia

On August 19, 2016, the Government of British Columbia launched its Climate Leadership Plan, which aims to reduce British Columbia's net annual emissions by up to 25 million tonnes below current forecasts by 2050 and recommit the province to achieving its target of reducing emissions by 80% below 2007 levels by 2050. Additionally, British Columbia seeks to generate at least 93% of its electricity from clean or renewable sources and build the infrastructure necessary to transmit it. The legislation established no date for this target.

British Columbia was also the first Canadian province to implement a revenue-neutral carbon tax. In 2012, the carbon tax was frozen at $30/tonne. However, in its September update to the 2017/2018 Budget, the Government signalled raising the carbon tax to $35/tonne in April 2018.

On January 1, 2016, the Greenhouse Gas Industrial Reporting and Control Act (the "GGIRCA") came into effect, which streamlined the regulatory process for large emitting facilities. The GGIRCA sets out various performance standards for different industrial sectors and provides for emissions offsets through the purchase of credits or through emission offsetting projects.

On December 5, 2018, the Government of British Columbia announced an updated clean energy plan, "CleanBC", which seeks to ensure that British Columbia achieves 75% of its GHG emissions reduction target by 2030. The CleanBC plan includes a number of strategies targeting the industrial, transportation construction, and waste sectors of the British Columbia economy. Key initiatives include: i) increasing the generation of electricity from clean and renewable energy sources; ii) imposing a 15% renewable content requirement in natural gas by 2030; iii) requiring fuel suppliers to reduce the carbon intensity of diesel and gasoline by 20% by 2030; iv) investing in the electrification of crude oil and natural gas production; v) reducing 45% of methane emissions associated with natural gas production; and vi) incentivizing the adoption of zero-emissions vehicles. On January 16, 2019, the B.C. Commission announced a series of amendments to the B.C. Drilling and Production Regulation that will require facility and well permit holders to, among other things, reduce natural gas leaks and curb monthly natural gas emissions from their equipment and operations. These new rules will come into effect on January 1, 2020

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced the Management and Reduction of Greenhouse Gases Act (the "MRGGA")to regulate GHG emissions in the province. The MRGGA, partially proclaimed into force on January 1, 2018, establishes a framework to reduce GHG emissions by 20% of 2006 levels by 2020. On October 18, 2016, the Government of Saskatchewan released a White Paper on Climate Change, resisting a carbon tax and committing to an approach that focuses on technological innovation and adaptation.

Accountability and Transparency

In 2015, the federal government's Extractive Sector Transparency Measures Act (the "ESTMA") came into effect, which imposed mandatory reporting requirements on certain entities engaged in the "commercial development of oil, gas or minerals", including exploration, extraction and holding permits. All companies subject to ESTMA must report payments over CAD$100,000 made to any level of a Canadian or foreign government (including indigenous groups), including royalty payments, taxes (other than consumption taxes and personal income taxes), fees, production entitlements, bonuses, dividends (other than ordinary dividends paid to shareholders), infrastructure improvement payments and other prescribed categories of payment.

RISK FACTORS

45

Investors should carefully consider the risk factors set out below and consider all other information contained herein and in Bellatrix's other public filings before making an investment decision. The risks set out below are not an exhaustive list and should not be taken as a complete summary or description of all the risks associated with Bellatrix's business and the oil and natural gas business generally.

Credit Facility and Debt Arrangements

Failing to comply with covenants under Bellatrix's Credit Facilities could result in restricted access to capital or being required to repay amounts owing thereunder.

The Corporation is required to comply with covenants under the agreements governing the Credit Facilities, Second Lien Notes and Senior Notes and in the event that Bellatrix does not comply with these covenants, Bellatrix's access to capital could be restricted or repayment could be required. Even if Bellatrix is able to obtain new financing, it may not be on commercially reasonable terms or terms that are acceptable to Bellatrix. Events beyond Bellatrix's control may contribute to the failure of Bellatrix to comply with such covenants. A failure to comply with covenants could result in default under the agreements governing the Credit Facilities, Second Lien Notes and Senior Notes, which could result in Bellatrix being required to repay amounts owing thereunder. The acceleration of Bellatrix's indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the agreements governing the Credit Facilities, Second Lien Notes and Senior Notes may impose operating and financial restrictions on Bellatrix that could include restrictions on, the payment of dividends, repurchase or making of other distributions with respect to Bellatrix's securities, incurring of additional indebtedness, the provision of guarantees, the assumption of loans, making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets, among others.

The Corporation's lenders use Bellatrix's reserves, commodity prices, applicable discount rate and other factors to periodically determine Bellatrix's borrowing base. There remains a substantial amount of uncertainty as to when and if commodity prices will recover. Continued depressed commodity prices or further reductions in commodity prices could result in a further reduction to Bellatrix's borrowing base, reducing the funds available to Bellatrix under the Credit Facilities. This could result in the requirement to repay a portion, or all, of Bellatrix's indebtedness.

The revolving period under the Credit Facilities ends on May 30, 2019 unless extended by the lenders thereunder. The maturity date under the Credit Facilities is six months after the end of the revolving period. Unless the revolving period is extended, the maturity date is November 30, 2019. There is no certainty that the lenders under the Credit Facilities will grant such extension. The Senior Notes mature in May 2020. In addition, although the Second Lien Notes have a maturity date in 2023, the Note Purchase Agreement provides that the maturity date of the Second Lien Notes will be accelerated to March 14, 2020 if more than US$25 million principal amount of Senior Notes remain outstanding as at March 14, 2020. Future liquidity and operations of the Corporation are dependent on the ability of the Corporation to refinance its debt obligations and to generate sufficient operating cash flows to fund its on-going operations.

Exploration, Development and Production Risks

The Corporation's future performance may be affected by the financial, operational, environmental and safety risks associated with the exploration, development and production of oil and natural gas

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 the Corporation depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the Corporation's existing reserves, and the production from them, will decline over time as the Corporation produces from such reserves. A future increase in the Corporation's reserves will depend on both the ability of the Corporation to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Corporation will be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of the Corporation may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participation uneconomic. There is also no assurance that the Corporation 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 ensure a profit on the investment or recovery of drilling, completion and operating costs.

46

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.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills and other environmental hazards. 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, the Corporation may explore for and produce sour gas in certain areas. An unintentional leak of sour 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 the Corporation.

Oil and natural gas production operations are also subject to geological and seismic risks, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

As is standard industry practice, the Corporation is not fully insured against all risks, nor are all risks insurable. Although the Corporation maintains liability insurance in an amount that it considers consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. See "Risk Factors - Insurance". In either event, the Corporation could incur significant costs.

Weakness in the Oil and Natural Gas Industry

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

Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by the 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. See "Risk Factors - Political Uncertainty". These events and conditions have caused a significant decrease in the valuation of oil and natural gas companies and a decrease in confidence in the oil and natural gas industry. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation. See "Risk Factors -Royalties and Incentives", "Risk Factors - Regulatory Authorities and Environmental Regulation" and "Risk Factors - Climate Change Regulation". In addition, the inability to get the necessary approvals to build pipelines, LNG plants and other facilities to provide better access to markets for the oil and natural gas industry in Western Canada has led to additional downward price pressure on oil and natural gas produced in Western Canada and uncertainty and reduced confidence in the oil and natural gas industry in Western Canada. See "Industry Conditions - Transportation Constraints and Market Access".

Lower commodity prices may also affect the volume and value of the Corporation's reserves, 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. Consequently, 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. See "Risk Factors - Reserves Estimates". Any decrease in value of the Corporation's reserves may reduce the borrowing base under its 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. See "Risk Factors - Credit Facilities". In addition to possibly resulting in a decrease in the value of the Corporation's economically recoverable reserves, lower commodity prices may also result in a decrease in the value of the Corporation's infrastructure and facilities, all of which could also have the effect of requiring a write down of the carrying value of the Corporation's oil and natural gas assets on 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 natural 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. See "Risk Factors - Additional Funding Requirements". If these conditions persist, the Corporation's cash flow may not be sufficient to continue to fund its operations and to satisfy its obligations when due, and the Corporation's ability to continue as a going concern and discharge its obligations will require additional equity or debt financing and/or proceeds or reduction in liabilities from asset sales. There can be no assurance that such equity or debt financing will be available on terms that are satisfactory to

47

the Corporation or at all. Similarly, there can be no assurance that the Corporation will be able to realize any or sufficient proceeds or reduction in liabilities from asset sales to discharge its obligations and continue as a going concern.

Prices, Markets and Marketing

Various factors may adversely impact the marketability of oil and natural gas, affecting net production revenue, production volumes and development and exploration activities

Numerous factors beyond the Corporation's control do, and will continue to, affect the marketability and price of oil and natural gas acquired, produced, or discovered by the Corporation. The Corporation's ability to market its oil and natural gas may depend upon its ability to acquire capacity on pipelines that deliver natural gas to commercial markets or contract for the delivery of crude oil by rail. See "Industry Conditions - Transportation Constraints and Marketing" and "Risk Factors - Weakness in the Oil and natural gas Industry". Deliverability uncertainties related to the distance the Corporation's reserves are from pipelines, railway lines, processing and storage facilities; operational problems affecting pipelines, railway lines and processing and storage facilities; and 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 may also affect the Corporation.

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors include economic and political conditions in the United States, Canada, Europe, China and emerging markets, the actions of OPEC and other oil and natural gas exporting nations, governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the foreign supply and demand of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Prices for oil and natural gas are also subject to the availability of foreign markets and the Corporation's ability to access such markets. A material decline in prices could result in a reduction of the Corporation's net production revenue. 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.

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, 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.

Oil and natural gas prices are expected to remain volatile for the near future because of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, increased growth of shale oil production in the United States, OPEC actions, political uncertainties, sanctions imposed on certain oil producing nations by other countries and ongoing credit and liquidity concerns. 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.

Market Price

The trading price of the Common Shares may be adversely affected by factors related and unrelated to the oil and natural gas industry

The trading price of securities of oil and natural gas issuers is subject to substantial volatility often based on factors related and unrelated to the financial performance or prospects of the issuers involved. Factors unrelated to the Corporation's performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices, or current perceptions of the oil and natural gas market. In recent years, the volatility of commodities has increased due, in part, to 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 natural gas entities which may impact the liquidity of certain securities and may put downward pressure on the trading price of those securities. Similarly, the market price of the Common Shares could be subject to significant fluctuations in response to variations in the Corporation's operating results, financial condition, liquidity and other internal factors. Accordingly, the price at which the Common Shares will trade cannot be accurately predicted.

48

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The anticipated benefits of acquisitions may not be achieved and the Corporation may dispose of non-core assets for less than their carrying value on the financial statements as a result of weak market conditions.

The Corporation considers acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation. The integration of acquired businesses and assets may require substantial management effort, time and resources diverting management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided by third parties and the resources required to provide such services. In this regard, non‑core assets may be periodically disposed of so the Corporation can focus its efforts and resources more efficiently. Depending on the state of the market for such non‑core assets, certain non‑core assets of the Corporation may realize less on disposition than their carrying value on the financial statements of the Corporation.

Political Uncertainty

The Corporation's 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, the North American Free Trade Agreement has been renegotiated and on November 30, 2018, Canada, the U.S. and Mexico signed the USMCA, which will replace NAFTA once ratified by the three signatory countries. See "Industry Conditions - The North American 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 natural 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 natural 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.

A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and natural gas industry including the balance between economic development and environmental policy such as the potential impact of the recent change of government in British Columbia and announcements and actions by the government of British Columbia that may impact the completion of the Trans-Mountain Pipeline project, LNG facilities and other infrastructure projects.

Reliance on Joint Venture Partners

The Corporation’s business may be adversely affected by actions taken or not taken by joint venture partners.

The Corporation relies on joint venture partners with respect to the evaluation, acquisition and development of, and future production from, certain of its properties and a failure or inability to perform or a differing development objective by such partners, including, without limitation, O’Chiese Energy Limited Partnership, could materially affect the development of such properties.

49

Operational Dependence

The successful operation of a portion of Bellatrix's properties is dependent on third parties.

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 prices, 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. See "Industry Conditions - Liability Management Rating Program".

Project Risks

The success of the Corporation's operations may be negatively impacted by factors outside of its control resulting in operational delays and cost overruns

The Corporation manages a variety of small and large projects in the conduct of its business. Project interruptions may delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. The Corporation's ability to execute projects and market oil and natural gas depends upon numerous factors beyond the Corporation's control, including:

• the availability of processing capacity;

• the availability and proximity of 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 the Corporation's ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations;

• the effects of inclement weather;

• the availability of drilling and related equipment;

• unexpected cost increases;

• accidental events;

• currency fluctuations;

• regulatory changes;

• 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, the Corporation could be unable to execute projects on time, on budget, or at all.

Gathering and Processing Facilities, Pipeline Systems and Rail

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

The Corporation delivers its products through gathering and processing facilities, pipeline systems and, in certain circumstances, by rail. The amount of oil and natural gas that the Corporation 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 7,000 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 and railway lines could result in the Corporation's inability to realize the full economic potential of its production, or in a reduction of the price offered for the Corporation's 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. See "Industry Conditions - Transportation Constraints and Market

50

Access ". In addition, the pro-rationing of capacity on inter-provincial pipeline systems 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. 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 or uncertainty in constructing new infrastructure systems and facilities could harm the Corporation's business and, in turn, the Corporation's financial condition, 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 of 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 adds 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 the Corporation's production may, from time to time, be processed through facilities owned by third parties and over which the Corporation does not have 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 have a materially adverse effect on the Corporation's ability to process its production and 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.

Competition

The Corporation competes with other oil and natural gas companies, some of which have greater financial and operational resources

The petroleum industry is competitive in all of its phases. The Corporation competes with numerous other entities in the exploration, development, production and marketing of oil and natural gas. The Corporation's competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Corporation. Some of these companies 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. The Corporation's ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price, process, and reliability of delivery and storage.

Cost of New Technologies

The Corporation's ability to successfully implement new technologies into its operations in a timely and efficient manner will affect its ability to compete

The petroleum industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. Other companies may have greater financial, technical and personnel resources that allow them to implement and benefit from technological advantages. There can be no assurance that the Corporation 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 the Corporation or implemented in the future may become obsolete. In such case, the Corporation's business, financial condition and results of operations could also be affected adversely and materially. If the Corporation is unable to utilize

51

the most advanced commercially available technology, or is unsuccessful in implementing certain technologies, its business, financial condition and results of operations could also be adversely affected in a material way.

Alternatives to and Changing Demand for Petroleum Products

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

Full 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 liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen the demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and natural gas products. The Corporation cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Corporation's business, financial condition, results of operations and cash flow by decreasing the Corporation's profitability, increasing its costs, limiting its access to capital and decreasing the value of its assets.

Regulatory

Modification to current, or implementation of additional, regulations may reduce the demand for oil and natural gas and/or increase the Corporation's 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 the Corporation's costs, either of which may have a material adverse effect on the Corporation's 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 of the oil and natural 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 natural 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 - Regulatory Authorities and Environmental Regulation - Climate Change Regulations". Also, in response to widening pricing differentials, the Government of Alberta implemented production curtailment. See "Industry Conditions - Curtailment" and "Risk Factors - Liability Management".

In order to conduct oil and natural gas operations, the Corporation 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 the Corporation will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that it may wish to undertake. In addition, certain federal legislation such as the Competition Act and the Investment Canada Act could negatively affect the Corporation's business, financial condition and the market value of its CommonShares or its assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity. See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Liability Management Rating Programs".

Royalty Regimes

Changes to royalty regimes may negatively impact the Corporation's cash flows

There can be no assurance that the governments in the jurisdictions in which the Corporation has assets will not adopt new royalty regimes, or modify the existing royalty regimes, which may have an impact on the economics of the Corporation's projects. An increase in royalties would reduce the Corporation's earnings and could make future capital investments, or the Corporation's 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 - Royalties and Incentives".

Hydraulic Fracturing

Implementation of new regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production volumes, adversely affecting the Corporation's financial position

52

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of oil and natural gas from reservoirs that were previously unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase the Corporation's costs of compliance and doing business, as well as delay the development of oil 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 the Corporation is ultimately able to produce from its reserves.

Alberta

Due to seismic activity reported in the Fox Creek area of Alberta, the AER announced in February 2015, 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, the AER continues to monitor seismic activity around the province and may extend these requirements to other areas of the province if necessary.

British Columbia

In 2018, the Government of British Columbia commissioned an independent scientific review panel to analyze hydraulic fracturing in the province and determine, among other things, how B.C.'s regulatory framework can be improved to better manage safety and environmental risks resulting from hydraulic fracturing operations. Despite a timeline to fulfill its mandate by December 31, 2018, the panel's findings are not yet publically available. Therefore, it is unclear how the panel's recommendations will influence the regulatory regime currently in place in B.C. The implementation of new regulations or modification of existing regulations, in response to the panel's findings, may adversely affect the Corporation's business operation, financial condition, results of operations and prospects.

Due to seismic activity recorded in the Kiskatinaw Seismic Monitoring and Mitigation ("Kiskatinaw") area, in May 2018, the British Columbia Oil & Gas Commission (the "B.C. Commission") issued special notification and monitoring requirements for hydraulic fracturing operators in the Kiskatinaw area. These requirements include, among others, the submission of a seismic monitoring and mitigation plan prior to conducting operations, pre-operation notification to both residents and the B.C. Commission, and the suspension of operations if a seismic event above a 3.0 magnitude occurs. In November 2018, seismic activity near Fort St. John in the Kiskatinaw area resulted in the suspension of several companies' operations, demonstrating the B.C. Commission's willingness to enforce these enhanced regulatory requirements. The B.C. Commission continues to monitor seismic events across the province and may implement similar requirements in other areas if necessary.

The Government of British Columbia has come under increased scrutiny for its enforcement of environmental assessment, safety and licensing requirements for dams companies have built in association with their hydraulic fracturing operations. Under the Water Sustainability Act, dams require a water licence. For dams over a certain size, dam-operators must comply with additional safety and reporting requirements set out in the Dam Safety Regulation. Larger dams are also subject to an environmental assessment and approval under the Environmental Assessment Act. Despite these regulatory requirements, reports have surfaced indicating that a number of unlicensed dams throughout northeastern B.C. have been constructed without the requisite regulatory authorization. While the B.C. Commission has issued compliance orders with respect to individual dams, it is uncertain how, and to what extent the relevant industry regulators will respond to this issue. The Corporation may face operational delays depending on the level of severity with which the overseeing regulatory authorities decide to address these unauthorized projects, particularly where the Corporation is not strictly complying with the current regulatory framework.

Disposal of Fluids Used in Operations

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.

53

Environmental

Compliance with environmental regulations requires the dedication of a portion of the Corporation's financial and operational resources

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 the spill, release or emission of various substances produced in association with oil and natural gas industry operations. In addition, such legislation sets out the 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 applicable environmental legislation may result in 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 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 the Corporation to incur costs to remedy such discharge. Although the Corporation believes that it 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 the Corporation's business, financial condition, results of operations and prospects.

Carbon Pricing Risk

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 - Regulatory Authorities and Environmental Regulation - Climate Change Regulation". 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 counterparts who operate in jurisdictions where there are less costly carbon regulations.

Liability Management

Liability management programs enacted by regulators in the western provinces may prevent or interfere with the Corporation's ability to acquire properties or require a substantial cash deposit with the regulator

Alberta, Saskatchewan and British Columbiahave developed liability management programs 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. These programs involve 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 the Corporation's 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 natural gas assets must be in compliance with the liability management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the transfer of such assets. This is of particular concern to junior oil and natural gas companies that may be disproportionately affected by price instability. 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 decsision are evaluated and considered by regulators, lenders and receivers/trustees.See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Liability Management Rating Programs".

Climate Change

Compliance with greenhouse gas emissions regulations may result in increased operational costs to the Corporation

The Corporation's exploration and production facilities and other operations and activities emit GHG which may require the Corporation to comply with greenhouse gas emissions legislation at the provincial or federal level. Climate change policy is

54

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 UNFCCC and a signatory to theParis 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. In addition, 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. 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 affect of increasing the Corporation's operating expenses and in the long-term reducing the demand for oil and natural gas production, resulting in a decrease in the Corporation's profitability and a reduction in the value of 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.

Variations in Foreign Exchange Rates and Interest Rates

Variations in foreign exchange rates and interest rates could adversely affect the Corporation's financial condition

World oil and natural gas prices are quoted in United States dollars. The Canadian/United States dollar exchange rate, which fluctuates over time, consequently affects the price received by Canadian producers of oil and natural gas. Material increases in the value of the Canadian dollar relative to the United States dollar will negatively affect the Corporation's production revenues. Accordingly, exchange rates between Canada and the United States could affect the future value of the Corporation's reserves as determined by independent evaluators. Although a low value of the Canadian dollar relative to the United States dollar may positively affect the price the Corporation receives for its oil and natural gas production, it could also result in an increase in the price for certain goods used for the Corporation's operations, which may have a negative impact on the Corporation's financial results.

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

An increase in interest rates could result in a significant increase in the amount the Corporation pays to service debt, resulting in a reduced amount available to fund its exploration and development activities, and if applicable, the cash available for dividends. Such an increase could also negatively impact the market price of the Common Shares.

Substantial Capital Requirements

The Corporation's access to capital may be limited or restricted as a result of factors related and unrelated to it, impacting its ability to conduct future operations and acquire and develop reserves

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:

55

• 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 natural gas industry have negatively impacted the ability of oil and natural gas companies, including the Corporation, to access additional financing and/or the cost thereof. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. The Corporation may be required to seek additional equity financing on terms that are highly dilutive to existing shareholders. The inability of the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation's business financial condition, results of operations and prospects.

Additional Funding Requirements

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

As a result of global economic and political volatility, the Corporation may, from time to time, have restricted access to capital and increased borrowing costs. Failure to obtain suitable financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Corporation's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Corporation's ability to expend the necessary capital to replace its reserves or to maintain its production. To the extent that external sources of capital become limited, unavailable or available on onerous terms, the Corporation's ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a result. In addition, the future development of the Corporation's petroleum properties may require additional financing and there are no assurances that such financing will be available or, if available, will be available upon acceptable terms. Alternatively, any available financing may be highly dilutive to existing shareholders. Failure to obtain any financing necessary for the Corporation's capital expenditure plans may result in a delay in development or production on the Corporation's properties.

Issuance of and Refinancing Debt

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, the Corporation may enter into transactions to acquire assets or shares of other entities. These transactions may be financed in whole, or in part, with debt, which may increase the Corporation's debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, the Corporation may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither the Corporation's articles nor its by‑laws limit the amount of indebtedness that the Corporation may incur.The level of the Corporation's indebtedness from time to time could impair the Corporation's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Hedging

Hedging activities expose the Corporation to the risk of financial loss and counter-party risk

56

From time to time, the Corporation may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, to the extent that the Corporation engages in price risk management activities to protect itself from commodity price declines, it may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Corporation's hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:

• production falls short of the hedged volumes or prices fall significantly lower than projected;

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

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

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

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

Title to and Right to Produce from Assets

Defects in the title or rights to produce the Corporation's properties may result in a financial loss

The Corporation's actual title to and interest in its properties, and its right to produce and sell the oil and natural gas therefrom, may vary from the Corporation's records. In addition, there may be valid legal challenges or legislative changes that affect the Corporation's title to and right to produce from its oil and natural gas properties, which could impair the Corporation's activities and result in a reduction of the revenue received by the Corporation.

If a defect exists in the chain of title or in the Corporation's right to produce, or a legal challenge or legislative change arises, it is possible that the Corporation may lose all, or a portion of, the properties to which the title defect relates and/or its right to produce from such properties. This may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Availability and Cost of Material and Equipment

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.

The Corporation requires a Skilled Workforce

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 led 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.

Reserves Estimates

The Corporation's estimated reserves are based on numerous factors and assumptions which may prove incorrect and which may affect the Corporation

57

There are numerous uncertainties inherent in estimating reserves, and the future cash flows attributed to such reserves. The reserves and associated cash flow information set forth in this document are estimates only. Generally, estimates of economically recoverable oil and natural gas reserves (including the breakdown of reserves by product type) and the future net cash flows from such estimated reserves are based upon a number of variable factors and assumptions, such as:

• historical production from properties;

• production rates;

• ultimate reserve recovery;

• timing and amount of capital expenditures;

• marketability of oil and natural gas;

• royalty rates; and

• the assumed effects of regulation by governmental agencies and future operating costs (all of which may vary materially from actual results).

For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times may vary. The Corporation's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates and such variations could be material.

The estimation of proved reserves that may be developed and produced in the future is often 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, the Corporation's independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein. Actual future net cash flows will be affected by other factors, such as 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 cash flows derived from the Corporation's oil and natural gas reserves will vary from the estimates contained in the reserve evaluation, and such variations could be material. The reserve evaluation is based in part on the assumed success of activities the Corporation intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom and contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation. The reserve evaluation is effective as of a specific effective date and, except as may be specifically stated, has not been updated and therefore does not reflect changes in the Corporation's reserves since that date.

Insurance

Not all risks of conducting oil and natural gas opportunities are insurable and the occurrence of an uninsurable event may have a materially adverse effect on the Corporation

The Corporation's involvement in the exploration for and development of oil and natural gas properties may result in the Corporation becoming subject to liability for pollution, blowouts, leaks of sour 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 are not, in all circumstances, insurable or, in certain circumstances, the Corporation 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 the Corporation. The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Geopolitical Risks

Global political events may adversely affect commodity prices which in turn affect the Corporation's cash flow

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 or discovered by the Corporation. Conflicts, or conversely peaceful developments, arising outside of Canada, including changes in political regimes or parties in power, may have

58

a significant impact on the price of oil and natural gas. Any particular event could result in a material decline in prices and result in a reduction of the Corporation's net production revenue.

Non-Governmental Organizations and Eco-Terrorism Risks

The Corporation's 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 natural 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, and delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses. 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.

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.

Reputational Risk Associated with the Corporation's Operations

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. In particular, the Corporation's reputation could be impacted by negative publicity related to environmental damage, loss of life, injury or damage to property caused by the Corporation's operations, or due to opposition from special interest groups opposed to oil and natural gas development. 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.

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 Corporation's securities.

Changing Investor Sentiment

Changing investor sentiment towards the oil and natural gas industry may impact the Corporation's access to, and cost of, capital

A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and natural gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and indigenous rights, have affected certain investors' sentiments towards investing in the oil and natural gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and natural gas properties or companies, or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. 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 natural gas industry and more specifically,

59

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 Corporation's securities 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 asset which may result in an impairment change.

Dilution

The Corporation may issue additional Common Shares, diluting current shareholders

The Corporation may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Corporation, which may be dilutive to shareholders of the Corporation.

Management of Growth

The Corporation may not be able to effectively manage the growth of its business

The Corporation may be subject to growth related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Corporation to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base. If the Corporation is unable to deal with this growth, it may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Expiration of Licenses and Leases

The Corporation, or its working interest partners, may fail to meet the requirements of a licence or lease, causing its termination or expiry

The Corporation's properties are held in the form of licences and leases and working interests in licences and leases. If the Corporation, or the holder of the licence or lease, fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of the Corporation's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Canadian and United States Reserves and Production Reporting Practices

The Corporation reports its 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.

The primary differences between the Canadian and United States reporting requirements include the following: (i) the Canadian standards require disclosure of proved and probable reserves, while the U.S. standards require disclosure of only proved reserves; (ii) the Canadian standards permit the disclosure of oil and gas resources, while the U.S. standards prohibit such disclosure; (iii) the Canadian standards require the use of forecast prices in the estimation of reserves, while the U.S. standards require the use of 12-month average prices which are held constant; (iv) the Canadian standards require disclosure of reserves on a gross (before royalties) and net (after royalties) basis, while the U.S standards require disclosure on a net (after royalties) basis; (v) the Canadian standards require disclosure of production on a gross (before royalties) basis, while the U.S. standards require disclosure on a net (after royalties) basis; and (vi) the Canadian standards require that reserves and other data be reported on a more granular product type basis than required by the U.S. standards.

This Annual Information Form includes estimates of proved and proved plus probable reserves. Probable reserves have a lower certainty of recovery than proved reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only proved reserves but permits the optional disclosure of probable reserves. The SEC definitions of proved reserves and probable reserves are different than NI 51-101; therefore, proved, probable and proved plus probable reserves disclosed in this Annual Information Form may not be comparable to United States standards. As a consequence of the foregoing, our reserves estimates and production volumes in this Annual Information Form may not be comparable to those made by companies utilizing United States reporting and disclosure standards. See "Oil and Gas Information Advisories".

60

Dividends

The Corporation does not pay dividends and there is no assurance that it will do so in the future

The Corporation has not paid any dividends on its outstanding shares. Payment of dividends in the future will be dependent on, among other things, cash flow, results of operations, financial condition of the Corporation, the need for funds to finance ongoing operations and other considerations, as the Board considers relevant.

Litigation

The Corporation may be involved in litigation in the course of its normal operations and the outcome of the litigation may adversely affect the Corporation and its reputation

In the normal course of the Corporation's operations, it 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. Potential litigation may develop in relation 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 and contract disputes). The outcome with respect to outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the Corporation and could have a material adverse effect on the Corporation's assets, liabilities, business, financial condition and results of operations. Even if the Corporation prevails 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 the Corporation's financial condition.

Aboriginal Claims

Aboriginal claims may affect the Corporation

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

Breach of Confidentiality

Breach of confidentiality by a third party could impact the Corporation's competitive advantage or put it at risk of litigation

While discussing potential business relationships or other transactions with third parties, the Corporation may disclose confidential information relating to its 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 the Corporation at competitive risk and may cause significant damage to its business. The harm to the Corporation's 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, the Corporation 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 its business that such a breach of confidentiality may cause.

Income Taxes

Taxation authorities may reassess the Corporation's tax returns

The Corporation files all required income tax returns and believes that it is in full compliance with the provisions of the Income Tax Act (Canada) 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 the Corporation, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable.

Income tax laws relating to the oil and natural gas industry, such as the treatment of resource taxation or dividends, may in the future be changed or interpreted in a manner that adversely affects the Corporation. Furthermore, tax authorities having jurisdiction over the Corporation may disagree with how the Corporation calculates its income for tax purposes or could change administrative practices to the Corporation's detriment.

61

Seasonality and Extreme Weather Conditions

Oil and natural gas operations are subject to seasonal and extreme weather conditions and the Corporation may experience significant operational delays as a result

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. 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. In addition, extreme cold weather, heavy snowfall and heavy rainfall may restrict the Corporation's ability to access its properties, cause operational difficulties including damage to machinery or contribute to personnel injury because of dangerous working conditions.

Third Party Credit Risk

The Corporation is exposed to credit risk of third party operators or partners of properties in which it has an interest

The Corporation may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In addition, the Corporation may be exposed to third party credit risk from operators of properties in which the Corporation has a working or royalty interest. In the event such entities fail to meet their contractual obligations to the Corporation, such failures may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry, generally, and of the Corporation's joint venture partners may affect a joint venture partner's willingness to participate in the Corporation's ongoing capital program, potentially delaying the program and the results of such program until the Corporation finds 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 the Corporation's financial and operational results.

Conflicts of Interest

Conflicts of interest may arise for the Corporation's directors and officers who are also involved with other industry participants

Certain directors or officers of the Corporation may also be directors or officers of other oil and natural gas companies and as such may, in certain circumstances, have a conflict of interest. Conflicts of interest, if any, will be subject to and governed by procedures prescribed by the ABCA which require a director or officer of a corporation who 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 proposed material contract with the Corporation to disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA . See "Directors and Officers - Conflicts of Interest".

Reliance on Key Personnel

Loss of key personnel would negatively impact the Corporation's operations

The Corporation's success depends in large measure on certain key personnel. Losing 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.

Information Technology Systems and Cyber-Security

Breaches of the Corporation's cyber-security and loss of, or access to, electronic data may adversely impact the Corporation's operations and financial position

The Corporation has 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. The Corporation depends on various information technology systems to estimate reserve quantities, process and record financial data,

62

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.

Further, the Corporation is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Corporation’s 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 cyber phishing attacks through education and training, cyber phishing activities remain a serious problem that may damage its information technology infrastructure. The Corporation applies technical and process controls in line with industry-accepted standards to protect its information, assets and systems, including a written incident response plan for responding to a cyber-security incident. However, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on our performance and earnings, as well as on our reputation, and any damages sustained may not be adequately covered by the Corporation's current insurance coverage, or at all. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Corporation’s business, financial condition and results of operations.

Social Media

The Corporation faces compliance and supervisory challenges in respect of the use of social media as a means of communicating with clients 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 client communications conducted through the use of social media platforms.

Expansion into New Activities

Expanding the Corporation's business exposes it to new risks and uncertainties

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

Forward-Looking Information

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

63

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 "Forward-Looking Statements"of this Annual Information Form.

HUMAN RESOURCES

As at December 31, 2018 Bellatrix employed 144 full-time employees (95 are located in the head office and 49 are field employees), 35 consultants on afull-time equivalent basis and 3 part-time employees.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Other than as described below, there were no material interests, direct or indirect, of directors or executive officers of Bellatrix, any holder of Common Shares who beneficially owns or controls or directs, directly or indirectly, more than 10% of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year which has materially affected or would materially affect Bellatrix.

Mr. Steven J. Pully, a director of the Corporation, was retained as a special advisor to a special committee of independent members of the Board (the "Special Committee") that was established to facilitate and lead the Corporation's refinancing efforts. As compensation for acting as a special advisor to the Special Committee, Mr. Pully earned a monthly retainer of $35,000 and earned a fee of $1.0 million as a result of the successful Second Lien Refinancing. Mr. Pully's engagement as special advisor ended December 31, 2018.

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51‑102 by Bellatrix during, or related to, Bellatrix's most recently completed financial year other than InSite, Bellatrix's independent reserves evaluators, and KPMG LLP, Bellatrix's auditors. InSite or its respective "designated professionals" (as defined in Item 16.2(1.1) of Form 51‑102F2 of National Instrument 51‑102 of the Canadian Securities Administrators) of InSite have not or are not to receive any registered or beneficial interest, direct or indirect, in any of Bellatrix's securities or other property of Bellatrix or of Bellatrix's associates or affiliates, either at the time InSite prepared the report, valuation, statement or opinion or any time thereafter. KPMG LLP are the auditors of Bellatrix and have confirmed that they are independent with respect to Bellatrix 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 Bellatrix under all relevant United States professional and regulatory standards.

In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of Bellatrix or of any associate or affiliate of Bellatrix.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Bellatrix is not a party to any legal proceeding nor was it a party to any legal proceeding during the 2018 financial year, nor is Bellatrix aware of any contemplated legal proceeding involving Bellatrix, its subsidiaries or any of its property which involves a claim for damages exclusive of interest and costs that may exceed 10% of the current assets of Bellatrix.

During the year ended December 31, 2018, there were no: (i) penalties or sanctions imposed against Bellatrix by a court relating to securities legislation or by a securities regulatory authority; (ii) penalties or sanctions imposed by a court or regulatory body against Bellatrix that would likely be considered important to a reasonable investor in making an investment decision, or (iii) settlement agreements Bellatrix entered into before a court relating to securities legislation or with a securities regulatory authority.

MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business (unless otherwise required by applicable securities requirements to be disclosed), the only material contracts that Bellatrix has entered into within the last financial year, or before the last financial year which are still in effect, which can be reasonably regarded as presently material are the:

64

(a) Note Purchase Agreement (see "Borrowings - Credit Facilities");

(b) First Lien Credit Agreement (see "Borrowings - Credit Facilities");

(c) Senior Notes Indenture (see "Borrowings - Senior Notes"); and

(d) the Debenture Indenture (see "Borrowings - Convertible Debentures").

A copy of the Note Purchase Agreement, First Lien Credit Agreement, Senior Note Indenture and the Debenture Indenture may be viewed on the SEDAR website at www.sedar.com.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of Bellatrix are KPMG LLP, Chartered Professional Accountants, Suite 3100, 205 - 5th Avenue S.W., Calgary, Alberta T2P 4B9.

Computershare Trust Company of Canada, at its principal offices in Calgary, Alberta and Toronto, Ontario is the transfer agent and registrar of the Common Shares. The co-transfer agent and registrar for the Common Shares in the United States is Computershare Investor Services US at its principal office in Golden, Colorado.

ADDITIONAL INFORMATION

Additional information relating to Bellatrix can be found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov and on our website at www.bxe.com.

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Bellatrix's securities and securities authorized for issuance under equity compensation plans is contained in Bellatrix's information circular for Bellatrix's most recent annual meeting of securityholders that involved the election of directors. Additional financial information is contained in Bellatrix's financial statements and the related management's discussion and analysis for Bellatrix's most recently completed financial year. For copies of our information circular, our comparative financial statements, including any interim comparative financial statements and additional copies of the Annual Information Form please contact:

Bellatrix Exploration Ltd.

Suite 1920, 800 - 5th Avenue S.W.

Calgary, Alberta T2P 3T6

Tel: (403) 266-8670

Fax: (403) 264-8163

65

APPENDIX "A"

FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Management of Bellatrix Exploration Ltd. (the "Company") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.

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

The Reserves Committee of the board of directors of the Company has:

(a) reviewed the Company'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 Reserves Committee of the board of directors has reviewed the Company'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 Reserves Committee, approved

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing the reserves data and other oil and gas information;

(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators 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.

DATED as of this 21^st day of March, 2019.

(signed) "Brent A. Eshleman"	(signed) "Maxwell A. Lof"
Brent A. Eshleman, P.Eng.	Maxwell A. Lof, CFA
President and Chief Executive Officer	Executive Vice-President and Chief Financial Officer
(signed) "Murray B. Todd"	(signed) "Lynn Kis"
Murray B. Todd	Lynn Kis
Director	Director

APPENDIX "B"

FORM 51-101F2

REPORT ON RESERVES DATA

BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

To the board of directors of Bellatrix Exploration Ltd. (the "Company"):

1. We have evaluated the Company’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 the Company’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 shows 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 the Company evaluated for the year ended December 31, 2018, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s management and Board of Directors:

Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation	Location of Reserves (Country)	Net Present Value of Future Net Revenue ($ thousands CDN - before income taxes, 10% discount rate)
			Audited	Evaluated	Reviewed	Total
InSite Petroleum Consultants Ltd.	December 31, 2018	Canada	Nil	1,500,253.5	Nil	1,500,253.5

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 effective date of our report, entitled "Evaluation of the P&NG Reserves of Bellatrix Exploration Ltd. (As of December 31, 2018)".

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

Executed as to our report referred to above:

InSite Petroleum Consultants Ltd.

Calgary, Alberta

Execution Date: March 7, 2019

(signed) "Ron Bojechko"

Ron Bojechko, P.Eng.

Managing Director

B-1

APPENDIX "C"

MANDATE AND TERMS OF REFERENCE OF THE AUDIT COMMITTEE

AUDIT COMMITTEE MANDATE

Purpose

The Audit Committee (the “Committee”) is a committee of the board of directors (the “Board”) of Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) to which the Board has delegated its responsibility for the oversight of the following: (i) the nature and scope of the annual audit; (ii) the oversight of management's reporting on internal accounting standards and practices; (iii) the review of financial information, accounting systems and procedures including internal control over financial reporting; (iv) the Company’s compliance with legal and regulatory requirements; (v) the performance of the Company’s internal audit function, if any; (vi) the qualifications, independence and performance of the Company’s external auditors; and (vii) the quality and integrity of the Company’s financial reporting and financial statements.

In addition, the Board has charged the Committee with the responsibility of recommending, for approval of the Board, the audited financial statements, interim financial statements and other mandatory disclosure releases containing financial information.

The primary objectives of the Committee are as follows:

1.Assist the Board in meeting its responsibility in respect of the preparation and disclosure of the financial statements of the Company and related matters.

2.Oversee the accounting and financial reporting processes of Bellatrix and the audits of Bellatrix's financial statements.

3.Provide better communication between the Board and external auditors.

4.Review and enhance the external auditors' independence.

5.Increase the credibility and objectivity of financial reports.

6.Strengthen the role of the Board by facilitating in depth discussions between members of the Committee, management of Bellatrix ("Management") and external auditors.

The Committee, in its capacity as a committee of the Board and subject to the rights of shareholders of Bellatrix and applicable law, is directly responsible for overseeing the relationship of the external auditors with Bellatrix, including the appointment, termination, compensation, retention and oversight of the work of the external auditors engaged by Bellatrix (including resolution of disagreements or disputes between Management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for Bellatrix. The external auditors will report directly to the Committee.

Committee Membership and Structure

The Committee will be comprised of three (3) or more directors. All members of the Committee shall qualify as independent for purposes of (a) National Instrument 52-110 - Audit Committees ("NI 52-110") (unless the Board determines that an exemption contained in NI 52-110 is available and determines to rely thereon); (b) the rules of the New York Stock Exchange; and (c) Rule 10A-3 ("Rule 10A-3") under the United States Securities Exchange Act of 1934, as amended, (the "U.S. Exchange Act") (unless the Board determines that an exemption contained in Rule 10A-3 is available and determines to rely thereon).

C-1

No member of the Committee shall have participated in the preparation of the financial statements of Bellatrix or any current subsidiary of Bellatrix at any time during the prior three years.

At least one member of the Committee shall be an "audit committee financial expert" within the meaning of that term under the U.S. Exchange Act and the rules adopted by the United States Securities and Exchange Commission (the "SEC") thereunder, unless the Board determines that the Committee shall not include an audit committee financial expert and provides the necessary disclosure with respect to such determination as required under the U.S. Exchange Act and the rules of the SEC thereunder. If at least one member of the Committee is not determined to be an audit committee financial expert then at least one member of the Committee shall have accounting or related financial management expertise, as determined by the Board in this business judgment.

All of the members of the Committee must be financially literate, as such qualification is interpreted by the Board, and have the ability to read and understand a set of financial statements, including a balance sheet, income statement, and cash flow statement (or such other comparable statements as are required under generally accepted accounting principles), that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Bellatrix's financial statements, and shall meet any other financial literacy requirements for audit committee members that may be imposed from time to time under Canadian or United States securities laws or any applicable stock exchange rules, unless the Board determines that an exemption from such requirements in respect of any particular member is available and determines to rely thereon.

Members of the Committee shall be appointed annually by the Board and will serve at the Board’s discretion. Committee members may be removed from the Committee by the Board at any time, with our without cause, and vacancies will be filled through appointment by the Board. The Board shall appoint one member of the Committee as the Chair of the Committee (the "Chair").

Meetings and Administrative Matters

The Committee shall meet as often as necessary to carry out its responsibilities. The Committee Chair shall preside at each meeting. If the Committee Chair is not present at a meeting, the Committee members present at that meeting shall designate one of its members as the acting chair of such meeting.

Committee meetings may be held in person, by means of telephone, video, or other communication facilities so as to permit all persons participating in the meeting to hear each other, or by combination of any of the foregoing.

At all meetings of the Committee every question will be decided by a majority of the votes cast on the question. In case of an equality of votes, the Chair presiding at any meeting shall not be entitled to a second or casting vote.

A quorum for meetings of the Committee will be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee will be the same as those governing the Board unless otherwise determined by the Committee or the Board.

The Committee may invite such directors, officers and employees of the Company to its meetings as it deems appropriate to assist the Committee with the fulfilment of its duties and responsibilities. The Chief Financial Officer of Bellatrix will attend meetings of the Committee, unless otherwise excused from all or part of any such meeting by the Chair.

The Committee shall meet with the external auditors at least once per year (in connection with the preparation of the year-end financial statements) and at such other times as the external auditors and the Committee consider appropriate. For certainty, the Committee shall meet separately, periodically with the external auditors.

The Committee shall meet separately, periodically, with Management and with the internal auditors (if any) or other personnel responsible for the internal audit function (if any).

The Committee may also retain, at the expense of Bellatrix, persons having special expertise and/or obtain independent professional advice, including, without limitation, independent counsel or other advisors, as the Committee determines is necessary in order for the Committee to carry out its duties.

Bellatrix shall provide, without any further approval of the Board required, for appropriate funding, as determined by the Committee, in its capacity as a committee of the Board, for payment of: (i) compensation to any external auditors engaged for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for Bellatrix, (ii)

C-2

compensation to any advisors or other persons employed by the Committee; and (iii) ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.

Minutes and Board Reporting

The Committee shall appoint a secretary who need not be a member of the Committee. The secretary shall keep minutes of the meetings of the Committee. Minutes of Committee meetings shall be sent to all Committee members. The Committee shall make regular reports to the Board.

Other Administrative Matters

The Committee has authority to communicate directly with the internal auditors (if any) and the external auditors of the Company. The Committee will also have the authority to investigate any financial activity of Bellatrix.

Any issues airising from meetings of the Committee that bear on the relationship between the Board and management should be communicated to the Chairman of the Board by the Committee Chair.

The Committee shall review and assess the adequancy of this Mandate at least annually, and shall recommend any proposed changes to the Compensation and Governance Committee and to the Board for approval.

Specific Responsibilities

It is the responsibility of the Committee to:

1.Oversee the work of the external auditors.

2.Satisfy itself on behalf of the Board with respect to Bellatrix's internal control systems identifying, monitoring and mitigating business risks; and ensuring compliance with legal, ethical and regulatory requirements.

3.Review and discuss with Management all significant commitments and business risks related to such commitments including, without limitation, commitments associated with farm-in agreements, joint-venture agreements, leases, marketing or transportation arrangements or agreements and all other operational or land agreements, contracts or arrangements.

4.Review and discuss with Management and the external auditors the annual and interim financial statements of the Company and related management's discussion and analysis ("MD&A") prior to their submission to the Board for approval and inclusion in securities law filings. The process should include but not be limited to:

a. reviewing changes in accounting principles and policies, or in their application, which may have a material impact on the current or future years' financial statements;

b. reviewing significant accruals, reserves or other significant estimates;

c. reviewing accounting treatment of unusual or non-recurring transactions;

d. ascertaining compliance with covenants under loan agreements;

e. reviewing disclosure requirements for commitments and contingencies;

f. reviewing adjustments raised by the external auditors, whether or not included in the financial statements;

g. reviewing unresolved differences between Management and the external auditors;

h. reviewing the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the financial statements of the Company; and

i. obtaining explanations of significant variances with comparative reporting periods.

5.Review the financial statements, prospectuses, MD&A, annual information forms ("AIF"), annual reports filed with the SEC, and all public disclosure containing audited or unaudited financial information (including, without limitation, annual and interim press releases and any other press releases disclosing earnings or financial results) before release and prior to Board approval. The Committee shall meet to review and discuss the financial statements and MD&A with Management and the external auditor. The Committee must be satisfied that adequate procedures are in place for the review of Bellatrix's disclosure of all other financial information and will periodically assess the accuracy of those procedures.

6.Review and discuss earnings releases, as well as financial information and earnings guidance provided by the Company to analysts and rating agencies. Such discussion may be done generally, such as discussing the types of information to

C-3

be disclosed and the type of presentation to be made. The Committee shall pay particular attention to any use of "pro forma" or "adjusted" non-GAAP information.

7.Meet with the external auditors annually prior to commencement of the audit to discuss planning and staffing of the audit.

8.At least annually, obtain and review a report by the external auditors describing: such auditors' internal quality-control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of such external 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 such external auditors, and any steps taken to deal with any such issues; and (to assess the external auditors' independence) all relationships between the external auditors and the Company.

9.Review analyses prepared by Management and/or the external auditors setting forth significant financial reporting issues and judgments made in connection with the preparation of the Company's financial statements, including analyses of the effects of alternative GAAP methods on the financial statements.

10.On an annual basis, review and discuss with the external auditors all relationships such auditors have with Bellatrix and its affiliates in order to determine the auditors' independence, including without limitation:

a. requesting, receiving and reviewing, on a periodic basis but at least annually, a formal written statement, consistent with applicable accounting standards, from the external auditors delineating all relationships that may reasonably be thought to bear on the independence of the external auditors with respect to Bellatrix;

b. discussing with the external auditors any disclosed relationships or services that may affect the objectivity and independence of the external auditors; and

c. taking, or recommending that the Board take, appropriate action to oversee the independence of the external auditors and to take appropriate action in response to the external auditors' report to satisfy itself of the external auditors' independence;

11.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.

12.Review and discuss a report from the external auditors, at a minimum once quarterly and generally in conjunction with the review of any audit or review report prepared by the external auditors with respect to the annual or interim financial statements of the Company, regarding:

a. all critical accounting policies and practices to be used;

b. all alternative treatments of financial information within applicable generally accepted accounting principles that have been discussed with Management, including the ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditors; and

c. other material written communications between the external auditors and Management, such as any management letter or schedule of unadjusted differences.

13.Review and pre‑approve, subject to any de minimis exceptions available under applicable laws, all audit and permitted non-audit services, including the terms thereof and the fees related thereto, to be provided to Bellatrix or its subsidiaries by the external auditors and consider the impact on the independence of such auditors. The Committee may establish detailed policies and procedures for pre-approval of the provision of audit services and permitted non-audit services by the external auditors. To the extent permitted by applicable laws, the Committee may delegate to one or more independent members of the Committee the authority to pre-approve such audit and non-audit services, provided (i) that such delegation must be detailed as to the particular service to be provided, (ii) the Committee's responsibilities may not be delegated to Management of Bellatrix, (iii) the applicable member(s) must report to the Committee at the next scheduled meeting such pre-approval, and (iv) such member(s) comply with such other procedures as may be established by the Committee from time to time.

14.Review and discuss with the external auditors any audit problems or difficulties, including any difficulties encountered in the course of the audit work, restrictions on the scope of the external auditors' activities or on access to requested information, any significant disagreements with Management, and Management's response. The review should include discussion of the responsibilities, budget and staffing of the Company's internal audit function (if any).

15.Review major issues regarding accounting principles and financial statement presentations, including any significant changes in the Company's selection or application of accounting principles, and major issues as to the adequacy of the Company's internal controls and any special audit steps adopted in light of material control deficiencies.

16.Review with the external auditors the disclosures made to the Committee by Bellatrix's Chief Executive Officer and Chief Financial Officer during their certification process. In particular, the Committee shall review with the Chief Executive

C-4

Officer, Chief Financial Officer and external auditors: (i) all significant deficiencies and material weaknesses in the design or operation of Bellatrix's internal control over financial reporting that could adversely affect Bellatrix's ability to record, process, summarize and report financial information required to be disclosed by Bellatrix in the reports that it files or submits under any applicable Canadian securities laws or the 1934 Act within the required time periods, and (ii) any fraud, whether or not material, that involves Management or other employees who have a significant role in Bellatrix's internal control over financial reporting.

17.Annually discuss with the external auditors whether they have become aware of any illegal acts in the course of the audit of Bellatrix's financial statements.

18.Review with external auditors (and internal auditor if one is appointed by Bellatrix) their assessment, if any, of the internal controls of Bellatrix, their written reports containing recommendations for improvement, and Management's response and follow-up to any identified weaknesses. The Committee will also review annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of Bellatrix and its subsidiaries.

19.Review and discuss risk assessment and risk management policies and procedures of the Company, including discussing the Company's major financial and cyber security risk exposures and the steps Management has taken to monitor and control such exposures (e.g., hedging, litigation and insurance);

20.Establish procedures for:

a. the receipt, retention and treatment of complaints received by Bellatrix regarding accounting, internal accounting controls or auditing matters; and

b. the confidential, anonymous submission by employees of Bellatrix of concerns regarding questionable accounting or auditing matters.

21.Establish clear hiring policies regarding the hiring by Bellatrix of partners and employees and former partners and employees of the present and former external auditors of the Company.

22.Review and evaluate the lead partner of the external auditors.

23.Ensure the rotation of partners on the audit engagement team of the external auditors in accordance with applicable law.

24.Consider whether, in order to assure continuing auditor independence, there should be regular rotation of the external auditors firm.

25.Present its conclusions with respect to the external auditors to the Board.

26.Review and satisfy itself on behalf of the Board that management has adequate procedures in place for reporting and certification under the Extractive Sector Transparency Measures Act (Canada) ("ESTMA") when the Company is required to comply with ESTMA.

Approved by the Board of Directors effective as of August 2, 2018

C-5