40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 40-F

(Check One)

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

or 

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

For the fiscal year ended December 31, 2017

Commission file number 1-35644

BELLATRIX EXPLORATION LTD.

(Exact name of registrant as specified in its charter) 

Alberta, Canada (Province or other jurisdiction of incorporation or organization) 1311 (Primary Standard Industrial Classification Code Number (if applicable)) 98-1187740 (I.R.S. Employer Identification Number (if Applicable))

Suite 1920, 800 - 5th Avenue S.W., Calgary, Alberta, Canada T2P 3T6

(403) 266-8670

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

Puglisi & Associates, 850 Library Avenue, Suite 204, Newark, Delaware 19711

(302) 738-6680

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

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

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

Title of each class Common Shares Name of each exchange on which registered New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act.None

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

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

x Annual Information Form x Audited Annual Financial Statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 49,378,026

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the Registrant in connection with such Rule.

Yes o No x

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

Yes  x No o

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

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

FORM 40-F

Principal Documents

The following documents, filed as Exhibits to this Annual Report on Form 40-F of Bellatrix Exploration Ltd. (“Bellatrix”), are hereby incorporated by reference into this Annual Report on Form 40-F:

(a) Annual Information Form for the fiscal year ended December 31, 2017;

(b) Management’s Discussion and Analysis for the fiscal year ended December 31, 2017;

(c) Audited Consolidated Financial Statements for the fiscal year ended December 31, 2017. Bellatrix’s Audited Consolidated Financial Statements included in this Annual Report on Form 40-F have been prepared in accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board. Therefore, they are not comparable in all respects to financial statements of United States companies that are prepared in accordance with United States generally accepted accounting principles; and

(d) Supplementary Oil and Gas Information.

40-F 1

ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.

(a) Certifications. See Exhibits 31.1, 31.2, 32.1 and 32.2 to this Annual Report on Form 40-F.

(b) Disclosure Controls and Procedures. As of the end of Bellatrix’s fiscal year ended December 31, 2017, an evaluation of the effectiveness of Bellatrix’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by Bellatrix’s management, with the participation of its principal executive officer and principal financial officer. Based upon that evaluation, Bellatrix’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, Bellatrix’s disclosure controls and procedures are effective to ensure that information required to be disclosed by Bellatrix in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission (the “Commission”) rules and forms and (ii) accumulated and communicated to Bellatrix’s management, including its principal executive officer and principal financial officers, to allow timely decisions regarding required disclosure.

It should be noted that while Bellatrix’s principal executive officer and principal financial officer believe that Bellatrix’s disclosure controls and proc9edures provide a reasonable level of assurance that they are effective, they do not expect that Bellatrix’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c) Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included under the heading "Controls and Procedures - Management's Annual Report on Internal Control over Financial Reporting" in Bellatrix’s Management Discussion and Analysis for the fiscal year ended December 31, 2017, filed as Exhibit 13.2 to this Annual Report on Form 40-F.

(d) Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Independent Auditor’s Report of Registered Public Accounting Firm” that accompanies Bellatrix’s Audited Consolidated Financial Statements for the year ended December 31, 2017, filed as Exhibit 13.3 to this Annual Report on Form 40-F.

(e) Changes in Internal Control Over Financial Reporting. The required disclosure is included under the heading "Controls and Procedures - Management's Annual Report on Internal Control over Financial Reporting" in Bellatrix’s Management Discussion and Analysis for the fiscal year ended December 31, 2017, filed as Exhibit 13.2 to this Annual Report on Form 40-F.

Notices Pursuant to Regulation BTR.

None.

Audit Committee Financial Expert.

Bellatrix’s board of directors has determined that Keith S. Turnbull, a member of Bellatrix’s audit committee, qualifies as an “audit committee financial expert” (as such term is defined in Form 40-F) and is “independent” as that term is defined in the rules of the New York Stock Exchange.

Code of Ethics.

Bellatrix has adopted a “code of ethics” (as that term is defined in Form 40-F), entitled the “Code of Business Conduct and Ethics” (the “Code of Ethics”), for its directors, officers, employees and contractors.  In March 2018, the Code of Ethics was updated to reflect changes in Canadian law regarding facilitation payments, and to reflect other changes regarding accepting gifts, invitations and entertainment, and to incorporate other non-substantive amendments.

The Code of Ethics is available for viewing on Bellatrix’s website at www.bxe.com, and is available in print, free of charge, to any shareholder who requests it. Requests for copies of the Code of Ethics should be made by contacting: Bellatrix’s Investor Relations Department at (403) 266 8670 or by e-mail at investor.relations@bxe.com.

40-F 2

Bellatrix intends to disclose and summarize any amendment to, or waiver from, any provisions of the Code of Ethics that is required to be so disclosed and summarized, on its website at www.bxe.com.

Principal Accountant Fees and Services.

The required disclosure is included under the heading “Audit Committee Information−External Auditor Service Fees” in Bellatrix’s Annual Information Form for the fiscal year ended December 31, 2017, filed as Exhibit 13.1 to this Annual Report on Form 40-F.

Pre-Approval Policies and Procedures.

(a) The required disclosure is included under the heading “Audit Committee Information−Pre-Approval Policies and Procedures” in Bellatrix’s Annual Information Form for the fiscal year ended December 31, 2017, filed as Exhibit 13.1 to this Annual Report on Form 40-F.

(b) Of the fees reported under the heading “Audit Committee Information−External Auditor Service Fees” in Bellatrix’s Annual Information Form for the fiscal year ended December 31, 2017, filed as Exhibit 13.1 to this Annual Report on Form 40-F, none of the fees billed by KPMG LLP were approved by Bellatrix’s audit committee pursuant to the de minimis exception provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

Off-Balance Sheet Arrangements.

The required disclosure is included under the heading “Off-Balance Sheet Arrangements” in Bellatrix’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2017, filed as Exhibit 13.2 to this Annual Report on Form 40-F.

Tabular Disclosure of Contractual Obligations.

The required disclosure is included under the heading "Commitments" in Bellatrix’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2017, filed as Exhibit 13.2 to this Annual Report on Form 40-F.

Identification of the Audit Committee.

Bellatrix has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Keith S. Turnbull, Keith E. Macdonald and Thomas E. MacInnis.

Mine Safety Disclosure.

Not applicable.

New York Stock Exchange Disclosure

Presiding Director at Meetings of Non-Management Directors

Bellatrix schedules regular executive sessions in which Bellatrix’s “non-management directors” (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Mr. W.C. (Mickey) Dunn serves as the presiding director (the “Presiding Director”) at such sessions. Each of Bellatrix’s non-management directors is “independent” for the purposes of Canadian National Instrument 58-101 and the rules of the New York Stock Exchange.

Communication with Non-Management Directors

Shareholders may send communications to Bellatrix’s non-management directors by writing to the Presiding Director, c/o Corporate Secretary, Bellatrix Exploration Ltd. Suite 1920, 800 5th Ave SW Calgary, Alberta, Canada T2P 3T6. Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate.

40-F 3

According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specific topics. Such guidelines are required to be posted on the listed company’s website. Bellatrix operates under corporate governance principles that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual, and which are described under the heading “Statement of Corporate Governance Practices” in Bellatrix’s Information Circular prepared in connection with its annual meetings of shareholders. However, Bellatrix has not codified its corporate governance principles into formal guidelines for posting on its website.

Board Committee Mandates

The Mandates of Bellatrix’s audit committee, compensation committee, and corporate governance committee are each available for viewing on Bellatrix’s website at www.bxe.com.

NYSE Statement of Governance Differences

As a Canadian corporation listed on the New York Stock Exchange, Bellatrix is not required to comply with most of the NYSE’s corporate governance standards, so long as it complies with Canadian and Toronto Stock Exchange corporate governance requirements. In order to claim such an exemption, however, Bellatrix must disclose the significant difference between its corporate governance practices and those required to be followed by U.S. domestic companies under the New York Stock Exchange’s corporate governance standards.

Bellatrix has prepared a summary of the significant ways in which its corporate governance practices differ from those required to be followed by U.S. domestic companies under the New York Stock Exchange’s corporate governance standards, and that summary, entitled “Significant Differences in Bellatrix’s Corporate Governance Practices Compared to NYSE Corporate Governance Standards”, is available for viewing on Bellatrix’s website at www.bxe.com.

Bellatrix’s corporate governance practices meet or exceed all applicable Canadian requirements. They also incorporate some best practices derived from the New York Stock Exchange rules and comply with applicable United States securities laws and rules adopted by the Commission. Further information about Bellatrix’s corporate governance practices is included under the heading “Statement of Corporate Governance Practices” in Bellatrix’s Information Circular prepared in respect of its annual meetings of shareholders.

40-F 4

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A. Undertaking

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

B. Consent to Service of Process.

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

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

40-F 5

SIGNATURES

Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 13, 2018.

BELLATRIX EXPLORATION LTD.
/s/ Maxwell (Max) Lof
Name:	Maxwell (Max) Lof
Title:	Executive Vice-President and Chief Financial Officer

40-F 6

EXHIBIT INDEX

Exhibit	Description
13.1	Annual Information Form for the fiscal year ended December 31, 2017
13.2	Management’s Discussion and Analysis for the fiscal year ended December 31, 2017
13.3	Audited Consolidated Financial Statements for the fiscal year ended December 31, 2017, prepared in accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board
13.4	Supplementary Oil and Gas Information
14.1	Code of Ethics
23.1	Consent of KPMG LLP
23.2	Consent of InSite Petroleum Consultants
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

40-F 7

EX-13.1

Exhibit 13.1

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED

DECEMBER 31, 2017 

March 13, 2018

TABLE OF CONTENTS

	Page
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
Disclosure of Reserves Data	6
Reserves Data (Forecast Prices and Costs)	7
Reconciliation of Changes in Reserves	11
Additional Information Relating to Reserves Data	11
Undeveloped Reserves	12
Significant Factors or Uncertainties	13
Future Development Costs	13
Other Oil and Gas Information	14
Principal Properties	14
Oil and Natural Gas Wells	15
Developed and Undeveloped Lands	15
Forward Contracts and Marketing	15
Tax Horizon	16
Capital Expenditures	17
Exploration and Development Activities	17
Production Estimates	17
Production History	18
DIVIDENDS	19
RATINGS	19
DESCRIPTION OF SHARE CAPITAL	20
MARKET FOR SECURITIES	21
PRIOR SALES	23
ESCROWED SECURITIES	24
BORROWINGS	24
DIRECTORS AND OFFICERS	26
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	31
AUDIT COMMITTEE INFORMATION	31
INDUSTRY CONDITIONS	33
Pricing and Marketing in Canada	33
Crude Oil	33
Natural Gas	33
Natural Gas Liquids	34
Exports from Canada	34
Transportation Constraints and Market Access	34
The North American Free Trade Agreement and Other Trade Agreements	35
Land Tenure	36
Royalties and Incentives	36
General	36
Alberta	37
British Columbia	37
Saskatchewan	38
Freehold and Other Types of Non-Crown Royalties	38
Regulatory Authorities and Environmental Regulation	39
Liability Management Rating Programs	41
Climate Change Regulation	42
Accountability and Transparency	43
RISK FACTORS	43
HUMAN RESOURCES	59
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	59
INTERESTS OF EXPERTS	59
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	60
MATERIAL CONTRACTS	60
AUDITORS, TRANSFER AGENT AND REGISTRAR	61
ADDITIONAL INFORMATION	61

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, 2017 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 Mcfes 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:

"2018 capital budget" has the meaning ascribed to such term under the heading "General Development of our Business - 2018 Capital Budget";

"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;

"CNOR" means Canadian Non-Operated Resources Corp.;

"CNOR Joint Venture" has the meaning ascribed to such term under the heading "General Development of our Business -Joint Ventures - CNOR Joint Venture";

"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 "Borrowings - 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;

"EBITDA" means earnings before interest, taxes, depreciation and amortization. EBITDA is calculated based on terms and definitions set out in the agreement governing the Credit Facilities, which adjusts net income for financing costs, certain specific unrealized and non-cash transactions, acquisition and disposition activity and is calculated based on a trailing twelve month basis;

"GORR" means gross overriding royalty;

"Grafton" means Grafton Energy Co I Ltd.;

"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;

iii

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

"InSite Report" means the report prepared byInSite dated February 28, 2018evaluating our crude oil, natural gas liquids and natural gas reserves as at December 31, 2017;

"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:

(d) 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.

(e) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

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

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

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

"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;

"Senior Debt" means all debt of Bellatrix on a consolidated basis determined in accordance with Canadian generally accepted accounting principles and without duplication, excluding decommissioning liabilities, deferred tax liability and any unsecured or subordinated debt (Senior Notes and the liability component of the Convertible Debentures) and including outstanding letters of credit, bank debt, finance lease obligations, deferred lease inducements and net working capital deficiency (excess), calculated as working capital deficiency excluding current commodity contract assets and liabilities. Senior Debt is calculated based on terms and definitions set out in the agreement governing the Credit Facilities;

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

"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;

"Strachan Transaction" has the meaning ascribed to such term under the heading "General Development of our Business - Asset Acquisitions and Divestures - Non-Core Asset Dispositions";

"TSX" means the Toronto Stock Exchange; and

"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.

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, 2017.

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 2018 capital budget, expected timing for spending capital, expected costs and timing of bringing on stream wells, plants and facilities, 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, timing of bringing new wells on stream, production estimates, plans with respect to Bellatrix's facilities, drilling and completion plans, plans and timing for development of undeveloped proved and probable reserves, timing of when Bellatrix may be taxable, estimated abandonment and reclamation costs, plans regarding hedging, 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 (as defined herein) (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, 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 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.bellatrixexploration.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 assumes no obligation to update or review them to reflect new events or circumstances except as required by Applicable Securities Laws.

Forward-looking statements contained herein concerning the oil and gas industry and Bellatrix's general expectations concerning this industry are based on estimates prepared by management using data from publicly available industry sources as well as from reserve reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which Bellatrix believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While Bellatrix is not aware of any misstatements regarding any industry data presented herein, the industry involves risks and uncertainties and is subject to change based on various factors.

v

BACKGROUND

General

Bellatrix is a publicly traded 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, 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, 2017 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 and the NYSE under the symbol "BXE".

GENERAL DEVELOPMENT OF OUR BUSINESS

The following is a summary description of the development of our business since January 1, 2015.

Joint Ventures

Grafton Joint Venture

In 2013, Bellatrix entered into a joint venture with Grafton to accelerate the development of a portion of Bellatrix's undeveloped land holdings in the Willesden Green and Brazeau areas of West-Central Alberta (the "Grafton Joint Venture"). Under the agreement, Grafton earned 54% of Bellatrix's working interest in each well drilled in the well program until payout (being recovery of Grafton's capital investment plus an 8% return) on the total program, reverting to 33% of Bellatrix's working interest after payout. At any time after payout of the entire program, Grafton has the option to elect to convert all wells from the 33% working interest to a 17.5% GORR on Bellatrix's pre-joint venture working interest. If there is a change of control of Bellatrix, Grafton has the right to cause Bellatrix to acquire Grafton's earned working interest or GORR, as applicable, at the same price attributable to those particular assets as the transaction resulting in the change of control.

During the second quarter of 2015 the funding period for the initial $200 million commitment under the Grafton Joint Venture was extended to December 31, 2015 (from June 26, 2015) which funding obligation was satisfied by Bellatrix and Grafton by that date. On January 18, 2016, Bellatrix and Grafton agreed to extend the funding period for the remaining $50 million commitment under the Grafton Joint Venture to December 31, 2016 (from June 26, 2016).

In the second quarter of 2016, Bellatrix entered into an agreement with Grafton to acquire producing assets within Bellatrix’s core Ferrier area for $29.2 million with consideration payable in Common Shares. The acquired assets were originally earned by Grafton pursuant to the Grafton Joint Venture and consisted of Grafton’s interest in 18 gross wells and related lands, which were already operated by Bellatrix. The acquired assets produced an average of approximately 2,000 boe/d net to Grafton in May, 2016.

On December 5, 2016, pursuant to the terms of the Grafton Joint Venture, Grafton provided notice to Bellatrix to terminate the funding period and as a result Bellatrix and Grafton have no further obligations to drill any additional wells pursuant to the Grafton Joint Venture.

TCA Joint Venture

In 2013, Bellatrix entered into a joint venture partnership with TCA Energy Ltd., a Canadian incorporated special purpose vehicle for Troika Resources Private Equity Fund based in Seoul, South Korea. Pursuant to the agreement forming the joint venture, Bellatrix and TCA Energy Ltd. agreed to drill and develop lands in the Ferrier Cardium area of West Central Alberta. Effective November 10, 2015, Bellatrix and TCA Energy Ltd. agreed to discharge the remainder of the drilling program under the joint venture. As a result, Bellatrix has no further obligations to drill additional wells thereunder. A total of 49 gross wells (24.5 net), including 3 megabores that each earned two sections of land were successfully drilled under the joint venture.

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CNOR Joint Venture

In 2014, Bellatrix entered into a new multi-year joint venture arrangement with CNOR, a non-operated oil and gas company managed by Grafton Asset Management Inc. pursuant to which CNOR committed $250 million in capital towards future accelerated development of a portion of Bellatrix’s undeveloped land holdings (the "CNOR Joint Venture"). Unless otherwise specified in an approved development plan, CNOR would pay 50% of the drilling, completion, equipping and tie-in capital expenditures in order to earn 33% of Bellatrix’s working interest before payout, which would automatically convert to a 10.67% GORR on Bellatrix's pre-joint venture working interest after payout (being recovery of CNOR's capital investment plus an 8% return on investment). Under the terms of the agreement, commencing on or before October 1, 2015 Bellatrix was to propose development plans for approval by a management committee comprised of representatives of Bellatrix and CNOR. The deadline to propose an initial development plan was subsequently extended to October 1, 2017, and Bellatrix proposed an initial development plan on June 30, 2017.

On July 10, 2017, Grafton provided notice to Bellatrix that it had elected not to approve the first proposed development program. As a result, Bellatrix and Grafton have no further obligations to drill any additional wells pursuant to the CNOR Joint Venture.

Acquisitions and Divestures

Pipeline and Facility Dispositions

Pipeline Dispositions

In the second quarter of 2015, Bellatrix disposed of its 100% working interest in a newly constructed condensate pipeline to a midstream purchaser for gross proceeds of approximately $8.6 million. In the third quarter of 2015, Bellatrix disposed of its 80% working interest in a 7.1 km pipeline in the west Pembina area of Alberta to a midstream purchaser for gross proceeds of approximately $8.4 million. Under the terms of the sale agreement Bellatrix agreed to an extension of its firm service at a certain processing facility owned by the purchaser by an additional 12 months with a volume commitment in the extension period of 50 MMcf/d.

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 agreement. Bellatrix retained the option to repurchase the facilities at any time during the term of the agreement.

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 "Keyera Transaction"). A portion of the cash consideration paid by Keyera represents 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 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 the indebtedness of Bellatrix under its Credit Facilities.

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.

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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 (the "Strachan Transaction"). A portion of the cash proceeds were reinvested to maintain current production volume guidance with the remaining portion of the proceeds applied to reduce the indebtedness of Bellatrix under its Credit Facilities.

Borrowing and Financings

2015 Senior Note Offering

On May 21, 2015, Bellatrix completed a private offering of US$250 million of 8.5% Senior Notes. Bellatrix used the net proceeds of approximately $293 million from the Senior Note offering to partially repay borrowings outstanding under its Credit Facilities. For additional information relating to the Senior Notes, see "Borrowings - Senior Notes".

Shelf Prospectus Renewal

On May 31, 2016, Bellatrix filed a short form base shelf prospectus in each of the Provinces of Canada except Quebec, and in the United States, that will enable Bellatrix, from time to time until June 2018, 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") 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 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. 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".

Credit Facilities

In connection with the monetization of certain production facilities and non-core asset dispositions, Bellatrix’s borrowing base under its Credit Facilities was reduced a number of times in 2016. As at December 31, 2016, Bellatrix’s borrowing base under the Credit Facilities was $100 million with approximately $80 million of available liquidity (excluding letters of credit).

Effective May 9, 2017, Bellatrix amended and restated the terms of its Credit Facilities and the borrowing base under the Credit Facilities was increased from $100 million to $120 million, comprised of a $25 million operating facility and a $95 million syndicated facility provided by four financial institutions.

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

Other Developments

Commissioning and Operation of Phase 1 of the Bellatrix Alder Flats Gas Plant

During the second quarter of 2015, Bellatrix successfully completed construction of phase 1 of the Bellatrix Alder Flats Gas Plant ahead of schedule and on budget. Initial start-up of the Bellatrix Alder Flats Gas Plant commenced on May 22, 2015. Significant benefits of the new gas plant include reduced costs, enhanced gas liquids extraction, and improved operational reliability.

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Mutual Expiration of the Shareholder Agreement with Orange Capital LLC

On December 15, 2014, Bellatrix announced that Daniel Lewis and Steven J. Pully would be appointed directors of Bellatrix, effective January 1, 2015. In connection with the appointment of Messrs. Lewis and Pully, Bellatrix entered into an agreement with Orange Capital LLC, pursuant to which Orange Capital LLC agreed to abide by certain standstill provisions until November 30, 2015. In addition pursuant to the agreement, Bellatrix agreed to nominate Messrs. Lewis and Pully at the 2015 annual shareholders meeting of Bellatrix. On December 1, 2015, Bellatrix announced that Bellatrix and Orange Capital LLC mutually agreed to allow the expiration, as of November 30, 2015, of such shareholder agreement.

Share Consolidation and Regained Compliance with NYSE Continued Listing Standards

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. On February 3, 2017, Bellatrix announced that it had received an extension to regain compliance until Bellatrix’s upcoming 2017 annual shareholder meeting since Bellatrix would require shareholder approval for any corporate action designed to regain compliance.

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.

2018 Capital Budget

On December 14, 2017, Bellatrix announced a 2018 capital budget of between $65 to 80 million (the "2018 Capital Budget"), to achieve forecast average production volumes of between 35,000 to 37,000 boe/d. Bellatrix anticipates that the 2018 Capital Budget will be flexible throughout the year to utilize Bellatrix’s infrastructure, takeaway capacity and market egress. A portion of Bellatrix’s 2018 Capital Budget will be allocated to completion of construction of phase 2 of the Bellatrix Alder Flats Gas Plant.

Significant Acquisitions

The Corporation has not completed any acquisitions that would be considered significant pursuant to NI 51-102 since January 1, 2014.

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.

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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.

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 2017 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.

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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 February 28, 2018. The effective date of the Statement is December 31, 2017.

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, 2017. The Reserves Data summarizes our crude oil, natural gas liquids 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, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.

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Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2017

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	1,055.6	957.9	8.4	8.4	283,869.4	254,173.8	16,929.3	13,311.7
Proved Developed Non-Producing	0.8	0.7	—	—	4,155.8	3,514.8	143.5	101.0
Proved Undeveloped	1,856.5	1,544.4	112.5	95.3	448,493.6	399,208.5	28,338.7	24,102.0
Total Proved	2,912.8	2,503.0	120.9	103.7	736,518.8	656,897.1	45,411.5	37,514.7
Probable	1,373.5	1,106.3	200.4	164.1	274,326.1	241,408.4	16,836.7	13,584.5
Total Proved Plus Probable	4,286.3	3,609.3	321.3	267.8	1,010,844.9	898,305.5	62,248.2	51,099.2

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	823,018	602,740	475,315	394,372	339,087	823,018	602,380	475,315	394,372	339,087	8.39	1.40
Proved Developed Non–Producing	9,506	6,850	5,283	4,268	3,563	9,506	6,850	5,283	4,268	3,563	7.68	1.28
Proved Undeveloped	1,388,278	826,962	535,043	366,035	260,162	1,161,671	719,209	479,328	335,311	242,340	5.80	0.97
Total Proved	2,220,802	1,436,551	1,015,642	764,675	602,811	1,994,195	1,328,798	959,926	733,950	584,989	6.79	1.13
Probable	1,318,905	744,697	484,979	345,840	261,823	976,641	558,972	370,988	270,322	209,231	8.80	1.47
Total Proved Plus Probable	3,539,707	2,181,248	1,500,620	1,110,514	864,635	2,970,836	1,887,770	1,330,914	1,004,272	794,220	7.33	1.22

Note:

(1) Unit values are based upon net reserves.

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

AS OF DECEMBER 31, 2017

FORECAST PRICES AND COSTS 

Reserves Category	Revenue ($000s)	Royalties ($000s)	Operating Costs ($000s)	Capital Development Costs ($000s)	Abandonment and Reclamation Costs ($000s)	Future Net Revenue Before Income Taxes ($000s)	Income Tax ($000s)	Future Net Revenue After Income Taxes ($000s)
Proved Reserves	5,168,425	627,403	1,630,129	662,851	27,241	2,220,802	226,607	1,994,195
Proved Plus Probable	7,443,048	949,010	2,089,004	832,071	33,256	3,539,707	568,872	2,970,835

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FUTURE NET REVENUE

BY PRODUCTION GROUP⁽¹⁾ 

AS OF DECEMBER 31, 2017

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)	107,907	$7.04/BOE
	Heavy Crude Oil (including solution gas and other by-products)	941	$9.07/BOE
	Conventional Natural Gas (including by–products but excluding solution gas from oil wells)(3)	906,794	$6.76/BOE
	Natural Gas Liquids	—
	Total	1,015,642
Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by–products)	149,740	$6.98/BOE
	Heavy Crude Oil (including solution gas and other by-products)	2,873	$10.73/BOE
	Conventional Natural Gas (including by–products but excluding solution gas from oil wells)(3)	1,348,007	$7.37/BOE
	Natural Gas Liquids	—
	Total	1,500,620

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, natural gas liquids 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:

(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.

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(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.

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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 here reflects 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 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, 2017.

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, 2017, 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
2018	71.36	52.36	2.52	74.93	—	0.790
2019	73.44	55.44	2.93	77.12	2.0	0.800
2020	75.47	58.47	3.22	79.25	2.0	0.810
2021	80.49	64.49	3.51	84.52	2.0	0.820
2022	82.38	67.38	3.75	86.50	2.0	0.830
2023	84.22	69.22	3.85	88.43	2.0	0.840
2024	86.01	71.01	3.95	90.31	2.0	0.850
2025	88.85	73.85	4.11	93.29	2.0	0.850
2026	90.62	75.62	4.27	95.15	2.0	0.850
2027	92.43	77.43	4.35	97.06	2.0	0.850
Thereafter	+2.0%/yr	+2.4%/yr(4)	+2.0%/yr	+2.0%/yr

Notes:

(1)Natural gas liquids is 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.

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(4)Inflation rate is 2.4% until 2036 and 2.0% thereafter.

Weighted average historical prices realized by Bellatrix (before commodity price risk management contracts) for the year ended December 31, 2017, were $2.27/Mcf for natural gas, $62.93/Bbl for light and medium gravity crude oil and condensate, and $21.52/Bbl for natural gas liquids (excluding condensate).

Reconciliation of Changes in Reserves

The following table sets out the reconciliation of our gross reserves as at December 31, 2016 compared to December 31, 2017 based on forecast prices and costs by principal product type:

	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, 2016(2)	4,143.2	2,189.6	6,332.8	134.3	207.9	342.1
Discoveries	—	—	—	—	—	—
Extensions	—	—	—	—	—	—
Infill Drilling	202.2	(187.2)	15.0	—	—	—
Improved Recovery	—	—	—	—	—	—
Technical Revisions	172.3	84.8	257.1	(6.3)	(7.7)	(14.0)
Acquisitions	—	—	—	—	—	—
Dispositions	(1,307.9)	(760.6)	(2,068.5)	—	—	—
Economic Factors	(106.9)	46.8	(60.1)	(0.3)	0.3	—
Production	(190.0)	—	(190.0)	(6.8)	—	(6.8)
December 31, 2017(3)	2,912.8	1,373.4	4,286.3	120.9	200.4	321.3

	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, 2016(2)	36,182.8	15,938.6	52,121.4	707,641.0	310,819.3	1,018,460.3
Discoveries	—	—	—	—	—	—
Extensions	—	—	—	—	—	—
Infill Drilling	7,236.7	(658.0)	6,578.7	116,908.9	(3,860.7)	113,048.3
Improved Recovery	—	—	—	—	—	—
Technical Revisions	6,633.2	2,738.3	9,371.4	13,743.4	(6,044.5)	7,699.0
Acquisitions	3,152.5	867.1	4,019.5	48,073.9	12,562.7	60,636.6
Dispositions	(4,481.3)	(2,046.2)	(6,527.5)	(85,502.5)	(38,584.6)	(124,087.0)
Economic Factors	(163.9)	(3.0)	(166.9)	(3,887.2)	(566.2)	(4,453.5)
Production	(3,148.5)	—	(3,148.5)	(60,458.8)	—	(60,458.8)
December 31, 2017(3)	45,411.5	16,836.8	62,248.2	736,518.8	274,326.1	1,010,844.9

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 March 7, 2017 and effective as of December 31, 2016 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

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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, 2017, 2016 and 2015 and, in the aggregate, before that time based on forecast prices and costs.

Proved 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
2015	142.9	6,291.5	—	107.6	41,495.0	326,164.0	2,126.7	18,101.6
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	28,338.7

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
2015	109.1	4,216.2	—	200.0	39,428.0	254,565.0	2,058.6	15,469.3
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

Note:

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

Proved Undeveloped Reserves

A total of 448,494 MMcf of natural gas, 1,969 Mbbl of oil and 28,339 Mbbl of NGLs were assigned as proved undeveloped reserves as at December 31, 2017, representing approximately 61% 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 2018 and 2023. With respect to capital development costs associated with proved undeveloped reserves in the InSite Report, approximately 52% of the capital is scheduled to be spent over the next three years and 96% 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 gas in Brazeau, Ferrier and Willesden Green representing 93% 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

12

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 2018 capital budget.

Probable Undeveloped Reserves

A total of 112,167MMcf of natural gas, 765 Mbbl of oil and 6,945 Mbbl of NGLs were assigned as gross probable undeveloped reserves in 2017, representing approximately 41% of our total probable reserves or 11% 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 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 2018 to 2023. With respect to capital development costs associated with probable undeveloped reserves in the InSite Report, approximately 34% 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 have reduced risk and are 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 2018 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)
2018	67,377.8	69,430.8
2019	141,800.2	155,955.7
2020	137,882.3	178,843.2
2021	161,121.4	206,707.9
2022	127,924.3	186,413.7
Thereafter	26,730.0	34,673.7
Total: Undiscounted	662,836.0	832,025.0

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.

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As indicated under "General Development of our Business - 2018 Capital Budget", the Board set the capital budget for 2018 at between $65 and $80 million. It is expected that the 2018 capital budget will meet the development schedule contemplated by the InSite Report.

Other Oil and Gas Information

Principal Properties

The following is a description of Bellatrix's principal oil and natural gas properties as at December 31, 2017. Unless otherwise indicated, production stated is average daily production for the year ended December 31, 2017 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 natural gas liquids 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 2017 averaged 32,716 BOE/d, comprised of 74.8% natural gas, 19.5% natural gas liquids and 5.7% light oil and condensate. The Corporation 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. Approximately 63% of Bellatrix's net gas volumes from the area are delivered to the Bellatrix Alder Flats Gas Plant with the remaining gas volumes from the area delivered to third party non-operated gas plants for processing, including two major gas processing facilities in the area in which Bellatrix holds a minor working interest. Our land holdings in the area were 72,953 gross (53,997 net) acres of developed land and 21,209 gross (16,930) acres of undeveloped land as at December 31, 2017.

In Ferrier in 2017, Bellatrix participated in 23 gross (19.28 net) wells. The drilling program consisted of 21 gross (18.74 net) operated wells and 2 gross (0.54 net) non-operated wells, and all but one well were completed and tied in in 2017 with the remaining well completed and tied in in the first quarter of 2018. Of the 21 gross (18.74 net) wells, 18 gross (15.74 net) wells were Spirit River horizontal liquids-rich gas wells and 3 gross (3 net) wells were Cardium liquids-rich gas wells.

In the first quarter of 2018 in Ferrier, Bellatrix expects to drill, complete and tie-in 5 gross (5 net) operated Spirit River horizontal liquids-rich gas wells. For the remainder of 2018, Bellatrix plans to drill an additional 9 gross (7.37 net) Spirit River horizontal liquids-rich gas wells and 1 gross (1 net) Cardium liquids-rich gas well.

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 2,143 BOE/d for 2017, consisting of 79% natural gas, 14.3% natural gas liquids and 6.7% 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 41,280 gross ((22,456 net) acres of developed land and 10,882 gross (7,161 net) acres of undeveloped land as at December 31, 2017.

In Willesden Green in 2017, Bellatrix participated in 6 gross (3.05 net) wells. The drilling program consisted of 5 gross (2.75 net) operated Spirit River horizontal liquids-rich gas wells and 1 gross (0.30 net) non-operated Notikewin horizontal gas well.

To date in 2018 at Willesden Green, Bellatrix has participated in 1 gross (0.20 net) non-operated Spirit River horizontal liquids-rich gas well. This well is expected to be completed and tied-in prior to the 2018 spring break-up. Bellatrix plans to drill and complete an additional 1 gross (1 net) Spirit River horizontal well in the second half of 2018.

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, 2017.

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	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	192	93	71	29	932	500	309	207
Saskatchewan	4	1	—	—	—	—	20	20
British Columbia	—	—	1	0.4	6	0.6	2	1
Total	196	94	72	29.4	938	500.6	331	228

________________________________________________________________________________________________

Developed and Undeveloped Lands

The following table sets out our developed and undeveloped land holdings as at December 31, 2017.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Alberta	371,715	227,180	153,035	112,213	524,751	339,393
British Columbia	8,132	2,108	79,987	28,859	88,120	30,967
Saskatchewan	13,327	12,720	8,005	7,732	21,332	20,452
Total	393,174	242,008	241,028	148,804	634,202	390,812

Note:

(1)May not add due to rounding.

Bellatrix does not expect any material expiries in its core land holdings in 2018.

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, natural gas liquids and natural gas production. We hedged an average of 18% of total crude oil and natural gas liquids production and an average of 69% of total natural gas production during the twelve months ended December 31, 2017. The following provides details of the commodity price risk management arrangements outstanding as at December 31, 2017 and as of the date hereof.

As at December 31, 2017, Bellatrix had entered into commodity price risk management arrangements as follows:

Type	Period	Volume	Price	Index
Oil Fixed	January 1, 2018 - December 31, 2018	500 bbl/d	CAD 69.275	WTI - NYMEX
Oil Fixed	January 1, 2018 - December 31, 2018	500 bbl/d	CAD 71.000	WTI - NYMEX
Propane Swap	January 1, 2018 - December 31, 2018	500 bbl/d	47% of NYMEX WTI (USD)	Conway
Propane Swap	January 1, 2018 - December 31, 2018	500 bbl/d	47% of NYMEX WTI (USD)	Conway
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.690	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.700	AECO 5A

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Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.715	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.705	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.700	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.700	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.700	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.720	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	10,000 GJ/d	CAD 2.755	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	10,000 GJ/d	CAD 2.750	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.525	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.605	AECO 5A
Natural Gas Fixed	January 1, 2018 - December 31, 2018	5,000 GJ/d	CAD 2.620	AECO 5A
Natural Gas Swap	April 1, 2018 - October 31, 2018	10,000 MMBTU/d	NYMEX HENRY HUB - USD 1.235	AECO 7A (USD)
Natural Gas Swap	April 1, 2019 - October 31, 2020	10,000 MMBTU/d	NYMEX HENRY HUB - USD 1.235	AECO 7A (USD)

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 1,414 bbls/d at a cost of $3.73/bbl for an aggregate cost over five years of $9,628,942; and (ii) natural gas, from January 2018 to September 2020 by an average of 11,837 boe/d at a cost of $0.90/boe for an aggregate cost over the 33 month term of $10,696,734.

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 1,180 bbls/d at a cost of $3.14/bbl for an aggregate cost over five years of $6,773,352.

For Bellatrix’s proved plus probable reserves as estimated in the InSite Report, transportation commitments will exceed forecast production for: (i) NGLs, by 462 bbls/d from January 2018 to May 2019 for an aggregate cost of $3,126,683; and (ii) natural gas, by an average of 11,561 boe/d at a cost of $0.90/boe from January 2018 to September 2019 for an aggregate cost of $6,644,764.

Bellatrix's processing commitments will exceed forecast production for Bellatrix’s proved plus probable reserves, as estimated in the InSite Report, by 224 bbls/d at a cost of $3.14/bbl for an aggregate cost of $1,272,575.

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, 2017, 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 2017 fiscal year. Depending on production, commodity prices and capital spending levels, management believes that Bellatrix will not be taxable in 2018. The Corporation does not expect to pay current taxes until 2019 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.

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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, 2017:

	$000's
Property acquisition costs	4,121
Proved properties	114
Undeveloped properties	4,007
Exploration costs	818
Development costs	116,326
Dispositions	(48,798	)
Corporate Assets	1,986
Total	74,453

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, 2017.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Light and Medium Crude Oil	—	—	1.00	1.00
Conventional Natural Gas	—	—	32.00	22.84
Heavy Crude Oil	—	—	—	—
Service	—	—	—	—
Stratigraphic Test	—	—	—	—
Dry	—	—	—	—
Total	0.00	0.00	33.00	23.84

For additional details on the exploration and development activities during 2017, 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, 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.

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	394	10	153,477	8,831	34,815
Total Proved Plus Probable	402	11	164,156	9,458	37,230

Note:

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

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The Ferrier property in the west central area of Alberta accounts for 27,233 BOE/d, or 73% 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
	2017
	Dec. 31	Sept. 30		June 30	Mar. 31
Average Daily Production(1)
Light and Medium Crude Oil (Bbls/d) (2)	2,043	2,029		2,516	2,378
Conventional Natural Gas (Mcf/d)(3)	164,848	170,210		172,402	156,715
NGLs (Bbls/d) (4)	7,559	7,312		6,665	6,252
Combined (BOE/d)	37,077	37,709		37,914	34,750
Average Price Received
Light and Medium Crude Oil ($/Bbl) (2)	69.63	55.35		59.50	67.30
Conventional Natural Gas ($/Mcf)(3)	1.79	1.54		2.94	2.87
NGLs ($/Bbl) (4)	27.68	18.79		20.58	18.18
Combined ($/BOE)	17.42	13.56		20.94	20.83
Royalties Paid
Light and Medium Crude Oil ($/Bbl) (2)	10.47	11.79		11.27	10.42
Conventional Natural Gas ($/Mcf)(3)	0.02	(0.08	)	0.13	0.04
NGLs ($/Bbl) (4)	5.52	4.35		3.48	8.19
Combined ($/BOE)	1.78	1.12		1.92	2.36
Operating Expenses
Light and Medium Crude Oil ($/Bbl) (2)	8.79	8.20		8.27	9.92
Conventional Natural Gas ($/Mcf)(3)	1.29	1.30		1.38	1.56
NGLs ($/Bbl) (4)	7.76	7.82		8.30	9.33
Combined ($/BOE)	7.81	7.84		8.30	9.37
Netback Received before Transportation
Light and Medium Crude Oil ($/Bbl) (2)	50.38	35.37		39.95	46.96
Conventional Natural Gas ($/Mcf)(3)	0.47	0.31		1.43	1.28
NGLs ($/Bbl) (4)	14.41	6.62		8.80	0.66
Combined ($/BOE)	7.82	4.60		10.72	9.09
Transportation Costs
Light and Medium Crude Oil ($/Bbl) (2)(5)	6.00	7.41		4.27	1.02
Conventional Natural Gas ($/Mcf)(3)	0.17	0.17		0.18	0.21
NGLs ($/Bbl) (4)	4.14	4.37		4.94	—
Combined ($/BOE)	1.92	2.01		1.98	1.03

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Netback Received after Transportation (6)
Light and Medium Crude Oil ($/Bbl) (2)	44.38	27.95	35.68	45.95
Conventional Natural Gas ($/Mcf)(3)	0.31	0.14	1.25	1.06
NGLs ($/Bbl) (4)	10.27	2.24	3.86	0.66
Combined ($/BOE)	5.91	2.59	8.74	8.06

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, 2017. 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, 2017, approximately 43.50% of gross revenue from our assets was derived from crude oil and natural gas liquids production and 46.50% 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:

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Rating Agency	Corporate Rating	Senior Notes Rating	Trend/Outlook
Standard and Poor's Ratings Service ("S&P")	B	B+	Stable
Moody's Investor Service, Inc. ("Moody's")	B3	Caa1	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 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.

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,

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

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TSX

Period	High ($)(1)	Low ($)(1)	Volume(1)
2017
January	6.83	5.25	4,420,416
February	5.55	4.85	3,721,207
March	5.70	4.85	4,003,901
April	5.65	4.95	5,173,031
May	5.25	4.20	3,411,925
June	4.45	3.55	2,493,427
July(1)	3.90	2.90	4,401,432
August	3.38	2.77	3,222,639
September	3.84	2.93	3,004,129
October	3.52	2.87	2,044,163
November	3.49	2.29	6,334,351
December	2.50	1.85	14,681,336
2018
January	2.22	1.55	14,851,376
February	1.79	1.24	11,163,484
March (1 – 9)	1.64	1.42	2,109,663

NYSE

Period	High (US$)(1)	Low (US$)(1)	Volume(1)
2017
January	5.15	4.08	2,079,003
February	4.30	3.70	1,847,658
March	4.25	3.63	2,335,464
April	4.25	3.65	1,278,861
May	3.88	3.10	1,930,895
June	3.32	2.72	1,901,538
July(1)	3.05	2.24	2,313,824
August	2.68	2.23	1,838,693
September	3.10	2.41	929,910
October	2.80	2.24	911,314
November	2.73	1.78	2,087,387
December	1.98	1.44	4,884,715
2018
January	1.78	1.26	3,549,329
February	1.42	0.99	3,239,072
March (1 – 9)	1.27	1.11	482,255

Note:

(1) Effective July 1, 2017, Bellatrix completed a share consolidation on the basis of a consolidation ratio of five old Common Shares for one new Common Share with the Common Shares trading on a post-consolidation basis at the opening of

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trading on the TSX and NYSE on July 6, 2017. The trade prices and trading volumes prior to the share consolidation have been adjusted to reflect the consolidation.

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 ($)(1)	Low ($)(1)	Volume(1)
2017
January	103.50	100.50	1,616,000
February	101.00	100.00	3,448,000
March	102.00	97.50	1,144,000
April	101.50	100.00	1,132,000
May	100.00	98.50	522,000
June	98.26	91.02	994,000
July(1)	99.00	94.03	192,000
August	96.00	93.00	432,000
September	98.00	94.50	257,000
October	97.75	95.00	1,331,000
November	97.50	93.50	736,000
December	93.00	89.00	145,000
2018
January	93.00	90.00	666,000
February	86.50	72.00	904,000
March (1 – 9)	79.00	76.00	166,000

Note:

(1) Effective July 1, 2017, Bellatrix completed a share consolidation on the basis of a consolidation ratio of five old Common Shares for one new Common Share with the Common Shares trading on a post-consolidation basis at the opening of trading on the TSX and NYSE on July 6, 2017. The trade prices and trading volumes prior to the share consolidation have been adjusted to reflect the consolidation.

PRIOR SALES

Other than options to purchase Common Shares granted under the share option plan of Bellatrix and restricted awards and performance awards granted under the incentive award plan of Bellatrix, Bellatrix did not sell or issue any securities of Bellatrix that are not listed or quoted on any stock exchange or other marketplace. The following table sets out details of all options under the share option plan of Bellatrix and restricted awards and performance awards granted under the incentive award plan of Bellatrix during the year ended December 31, 2017:

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Date	Type of Security	Number of Securities	Price per Security ($)(1)
March 31, 2017	Restricted Awards	26,180	$5.15(2)
April 7, 2017	Options	60,000	$6.00(3)
April 7, 2017	Performance Awards	48,000	$5.15(2)
April 7, 2017	Restricted Awards	12,000	$5.15(2)
May 31, 2017	Restricted Awards	34,060	$4.75(2)
June 23, 2017	Options	125,000	$3.85(3)
June 23, 2017	Performance Awards	322,000	$3.85(2)
June 23, 2017	Restricted Awards	476,800	$3.85(2)
August 31, 2017	Restricted Awards	62,600	$2.87(2)
November 30, 2017	Restricted Awards	41,100	$2.40(2)

Notes:

(1) The number of securities and the price per security reflect the 5 for 1 consolidation of the Common Shares that was effective on July 1, 2017.

(2) 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 or performance awards as applicable.

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

Additional information relating to Bellatrix's share option plan and incentive award plan will be available in the management information circular for Bellatrix's upcoming annual meeting of shareholders of Bellatrix, which is currently scheduled to be held on 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 31, 2018, do not require any mandatory principal payments prior to maturity, can be further extended beyond May 31, 2018 with the consent of the lenders, and have a one year term-out period if not renewed. The Credit Facilities are available to finance Bellatrix's ongoing capital expenditures, working capital requirements and for general corporate purposes. The available Credit Facilities and related borrowing base are subject to semi-annual reviews 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 value of Bellatrix's oil and natural gas properties in accordance with the lenders' customary practices for oil and gas loans. Effective May 9, 2017, Bellatrix amended and restated the terms of its Credit Facilities and the borrowing base under the Credit Facilities was increased from $100 million to $120 million, comprised of a $25 million operating facility and a $95 million syndicated facility provided by four financial institutions. The semi-annual borrowing base review in November 2017 resulted in the borrowing base being reconfirmed at $120 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 1.0% and 3.5%, depending on the type of borrowing and Bellatrix's Senior Debt to EBITDA ratio. A standby fee is charged of between 0.5% to 0.875% on the undrawn portion of the Credit Facilities, depending on Bellatrix's Senior Debt to EBITDA ratio. The Credit Facilities are secured by a $1 billion debenture containing a first ranking charge and security interest. The Corporation has provided a negative pledge and undertaking to provide fixed charges over its properties in certain circumstances. The amount available under the Credit Facilities is not to exceed the borrowing base, which is currently $120 million. At December 31, 2017 Bellatrix had $52.1 million outstanding (excluding outstanding letters of credit) at a weighted average interest rate of 4.45%. The borrowing base will be subject to re-determination on or before May 31 and November 30 in each year prior to the maturity of the Credit Facilities, with the next semi-annual re-determination occurring on or before May 31, 2018.

The Credit Facilities contain market standard terms and conditions, and include, for instance, restrictions on asset dispositions and hedging. Generally, dispositions of properties to which Bellatrix is given lending value in the determination of the borrowing

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base require lender approval if the value attributed to all properties sold in a fiscal year exceeds 5% of the borrowing base in effect at the time of such disposition. In addition, asset dispositions are generally not permitted unless there would be no borrowing base shortfall as a result of such properties being sold. Hedging transactions must not be done for speculative purposes. The aggregate amount hedged under all oil and gas commodity swaps cannot exceed 80% of Bellatrix's average daily sales volume for the first year of a rolling 3 year period, 70% for the second year of such period or 60% for the third year of such period, with the average daily sales volume being based on our production for the previous fiscal quarter. The term of any commodity swap cannot exceed 3 years. The aggregate amount hedged under all interest rate swaps designed to hedge against fluctuations in interest rates of unsecured note debt, including the Senior Notes, cannot exceed the outstanding principal amount of the applicable unsecured note debt and such swaps cannot have a term exceeding the remaining term of the unsecured note debt. For interest rate swaps unrelated to any unsecured note debt, the aggregate amount hedged cannot exceed 60% of the amount of the commitment under the Credit Facilities and such swaps cannot exceed a term of 3 years. The aggregate amount hedged under all exchange rate swaps designed to hedge against fluctuations of foreign exchange rates of unsecured note debt cannot exceed the outstanding principal amount of the applicable unsecured note debt or have a term exceeding the remaining term of the applicable unsecured note debt. For exchange rate swaps unrelated to any unsecured note debt, the aggregate amount hedged cannot exceed 60% of Bellatrix's U.S. dollar revenue over the previous 3 months and such swaps cannot exceed a term of 3 years.

The Credit Facilities are subject to a single financial covenant, which was met at December 31, 2017. The financial covenant in the Credit Facilities provides that Bellatrix must maintain a consolidated Senior Debt to consolidated EBITDA ratio of not greater than 3.0 to 1, except upon a consummation of a material acquisition which results in Bellatrix being permitted for a period extending to and including the end of the second full fiscal quarter of Bellatrix following the fiscal quarter in which the applicable material acquisition is completed, to hold a consolidated Senior Debt to consolidated EBITDA ratio of not greater than 3.5 to 1. The Corporation calculates its financial covenant quarterly. The calculation for the financial covenant is based on specific definitions that are not in accordance with International Financial Reporting Standards and cannot be readily replicated by referring to Bellatrix's consolidated financial statements.

For a complete description of the terms of the Credit Facilities, copies of the agreement governing the Credit Facilities 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

The Senior Notes are governed by the Senior Note Indenture and bear interest at 8.500% 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 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: May 15, 2017 to May 14, 2018 at 104.25%; 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.

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.

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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 will 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 and Senior 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, 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, 2017), 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

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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: 53	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. From December 2004 to January 2012, Vice-President Engineering and Exploitation of Daylight Energy Ltd. From May 2000 to November 2004 Director, Northern Alberta of Calpine Canada.
Maxwell A. Lof, CFA Calgary, Alberta, Canada Age: 50	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 and Breaker Energy Ltd. from June 2004 to December 2009.
Charles R. Kraus, Esq. Calgary, Alberta, Canada Age: 42	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: 47	Chief Operating Officer	N/A	Chief Operating Officer since March 15, 2017. Prior thereto, Vice-President, Engineering of Bellatrix since October 2011. Prior thereto, held roles of Production Engineer, Production Manager, and Manager of Exploitation and Acquisitions of Bellatrix, and prior to November 1, 2009 of True Energy Inc. (as administrator of True Energy Trust), since January 2008.
Timothy A. Blair Cochrane, Alberta, Canada Age: 59	Vice-President, Land	N/A	Vice-President, Land of Bellatrix, and prior to November 1, 2009 of True Energy Inc. (as administrator of True Energy Trust), since October 2009.  Prior thereto, Vice-President, Land for Terra Energy Corp. from June 2004 to September 2009.
Chris D. Curry, CPA, CA Calgary, Alberta, Canada Age: 43	Vice-President, Finance	N/A	Vice-President, Finance of Bellatrix since November 2017. Prior thereto, Vice-President, Controller since May 2014. Prior thereto, held progressively senior finance roles over the previous 15 years at Native American Resource Partners, NuVista Energy Ltd., Enerplus Resources Fund and Precision Drilling Corporation.
Robert O. Lee, CET Cochrane, Alberta, Canada Age: 56	Vice-President, Marketing	N/A	Vice-President, Marketing since March 15, 2017. Prior thereto, Director, Marketing and Commercial of Bellatrix since December 2008. Prior thereto, Manager, Marketing of Bellatrix and prior to November 1, 2009 of True Energy Inc. (as administrator of True Energy Trust) since September 2007.

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Mark L. Stephen, P. Eng. Calgary, Alberta, Canada Age: 57	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 and prior thereto, Manager of Drilling and Completions from June 2011 to December 2013. Prior thereto, Vice-President of Operations at Orleans Energy Ltd. from April 2007 to May 2011.
Steve G. Toth, CFA Calgary, Alberta, Canada Age: 40	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.
W.C. (Mickey) Dunn Calgary, Alberta, Canada Age: 64	Chairman(2)(3)	August 31, 2000	Chairman of Bellatrix and prior to November 1, 2009 of True Energy Inc. (as administrator of True Energy Trust); previously director of Precision Drilling Inc. from 1992 to 2013; previously director of The Cash Store Financial Services Inc. from 2003 to 2014; previously director of Vero Energy Inc. from 2006 to 2010; previously President and Chief Executive Officer of Cardium Service and Supply Ltd. and Cardium Tool Services Inc. from 1981 to 1999, and Colorado Silica Sand Inc. from 1981 to 1996.
Murray L. Cobbe Calgary, Alberta, Canada Age: 68	Director(2)(5)	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: 67	Director(3)	August 31, 2000	Partner, Burnet, Duckworth & Palmer LLP (barristers and solicitors).
Lynn Kis, P. Eng. Calgary, Alberta, Canada Age: 67	Director(5)	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; prior thereto Director of Evaluations, Energy and Resources Advisory Services of AJM Deloitte from 2011 to 2013, and Vice President and Partner of AJM Petroleum Consultants from 2006 to 2011. Ms. Kis currently serves as a director of Painted Pony Energy Ltd.
Keith E. Macdonald, CPA, CA Calgary, Alberta, Canada Age: 61	Director(2)(4)(5)	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. Mr. Macdonald currently serves as 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.

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Thomas E. MacInnis Calgary, Alberta, Canada Age: 46	Director(4)	February 6, 2017	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. Mr. MacInnis currently serves as a director of Claim Post Resources Inc.
Steven J. Pully, Esq., CPA, CFA Dallas, Texas, USA Age: 57	Director(2)(3)	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.
Murray B. Todd, B.Sc. P. Eng. Calgary, Alberta, Canada Age: 82	Director(5)	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: 68	Director(4)	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, Angle from March 2012 to December 2013, CE Franklin Ltd. from April 2010 to July 2012, and UNX Energy Corp. from May 2010 to April 2011.

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 Committee.

(3) Member of Corporate Governance Committee.

(4) Member of Audit Committee.

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

As at February 28, 2018, the directors and officers of Bellatrix, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 726,460 Common Shares, representing approximately 1.47% 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.

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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 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.

Charles R. Kraus, the Executive Vice-President, General Counsel and Corporate Secretary of Bellatrix, was an officer of Lone Pine Resources Inc. ("Lone Pine"), an oil and natural gas company, from September 6, 2011 until September 2, 2014. On September 25, 2013, Lone Pine commenced proceedings in the Court of Queen's Bench of Alberta under the CCAA and ancillary proceedings under Chapter 15 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. On January 31, 2014, Lone Pine completed its emergence from creditor protection under the CCAA and Chapter 15 of the United States Bankruptcy Code. Lone Pine, Lone Pine Resources Canada Ltd. and all other subsidiaries of Lone Pine were parties to the CCAA and Chapter 15 proceedings.

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.

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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.

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE

As a foreign private issuer listed on the NYSE, Bellatrix is not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic Canadian requirements. Bellatrix is, however, required to comply with the following NYSE rules: (i) Bellatrix must have an audit committee that satisfies the requirements of Rule 10A-3 under the United States Securities Exchange Act of 1934, as amended; (ii) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any non-compliance with the applicable NYSE rules; (iii) submit an executed Section 303A annual written affirmation to the NYSE, as well as a Section 303A interim affirmation each time certain changes occurs to the audit committee; and (iv) provide a brief description of any significant differences between its corporate governance practices and those followed by U.S. domestic issuers under NYSE listing standards. Bellatrix has reviewed the NYSE listing standards followed by U.S. domestic issuers listed under the NYSE and confirms that its corporate governance practices do not differ significantly from such standards.

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:

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Name and municipality of residence	Independent	Financially literate	Relevant education and experience
Keith E. Macdonald, CPA, CA	Yes	Yes	Mr. Macdonald is the President of Bamako Investment Management Ltd., a private holding and financial consulting company and has held such position since July 1994. Mr. Macdonald was the Chief Executive Officer and a director of EFLO Energy Inc. from March 2011 to January 2015 and previously a director of Madalena Energy Inc. from June 2010 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	Mr. Turnbull is a Chartered Accountant and has been a business consultant since his retirement as a Partner from KPMG LLP on December 31, 2009, after nearly 30 years of service. Mr. Turnbull 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. Mr. Turnbull is a member of the Alberta and Canadian Institute of Chartered Accountants and the Institute of Corporate Directors. Mr. Turnbull is currently a director and chair of the audit committee of Crown Point Energy Inc.
Thomas E. MacInnis Calgary, Alberta, Canada	Yes	Yes	Mr. MacInnis is an independent businessman and was previously the head of financial markets at National Bank Financial, Calgary from 2009 to 2017. Prior thereto, Mr. MacInnis was a founder and managing director of Tristone Capital. Mr. MacInnis 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. Mr. MacInnis is a member of the Institute of Corporate Directors. Mr. MacInnis 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. Mr. MacInnis 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.

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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 $833,530 in 2017 and $928,590 in 2016.

Audit - Related Fees

There were no audit-related feesbilled in 2017 or 2016 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 $51,044 in 2017 and $13,910 in 2016 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 2017 or 2016.

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. 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 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, which results in the market determining the price of crude oil. Worldwide supply and demand factors primarily determine 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

The price of natural gas sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. The price received by a natural gas producer depends, in part, on the price of competing natural gas supplies and other fuels, natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions,

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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 price of condensate 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 price depends, 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, which is no longer the case for natural gas and NGLs. For natural gas and NGLs, 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. All crude oil, natural gas and NGLs licences require the approval of the cabinet of the Canadian federal government.

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 the cabinet of the Canadian federal government. 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 other criteria prescribed by the NEB and the federal government.

Pursuant to the draft legislation introduced by the Government of Canada on February 8, 2018, if enacted the NEB will be replaced by the Canadian Energy Regulator ("CER") who will take on the NEB's responsibilities with respect to exports of crude oil, natural gas and NGL exports from Canada; however, at the present time it is not proposed that the legislative regime relating to exports of crude oil, natural gas and NGL exports from Canada will substantively change under the new regime.

The Corporation does not directly enter into contracts to export its production outside of Canada.

As discussed in more detail below, one major constraint to the export of crude oil, natural gas and NGLs outside of Canada is the deficit of overall pipeline and other transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline or other transportation projects are underway, many contemplated projects have been cancelled or are delayed due to regulatory hurdles, court challenges and economic and political factors. The transportation capacity deficit is not likely to be resolved quickly given the significant length of time required to complete major pipeline or other transportation projects 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, which may be done on a firm or interruptible basis. Due to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low pricing relative to other markets in the last several years. Transportation availability is highly variable across different areas and regions, which can determine the nature of transportation commitments available, the numbers of potential customers that can be reached in a cost-effective manner and the price received.

Developing a strong network of transportation infrastructure for crude oil, natural gas and NGLs, including by means of pipelines, rail, marine and trucks, in order to obtain better access to domestic and international markets has been a significant challenge to the Canadian crude oil and natural gas industry. Improved means of access to global markets, especially the Midwest United States and export shipping terminals on the west coast of Canada, would help to alleviate the pressures of pricing discussed. 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 shipping terminals on the west coast of Canada. While certain projects are proceeding, the

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regulatory approval process as well as economic and political factors for transportation and other export infrastructure has led to the delay of many pipeline projects or their cancellation altogether.

Under the Canadian constitution, interprovincial and international pipelines fall within the federal government's jurisdiction and require approval by both the NEB and the cabinet of the federal government. However, recent years have seen a perceived lack of policy and regulatory certainty at a federal level. Although the current federal government recently introduced draft legislation to amend the current federal approval processes, it is uncertain when the new legislation will be brought into force and whether any changes to the draft legislation will be made before the legislation is brought into force. It is also uncertain whether any new approval process adopted by the federal government will result in a more efficient approval process. The lack of regulatory certainty is likely to have an influence on investment decisions for major projects. Even when projects are approved on a federal level, such projects often face further delays due to interference by provincial and municipal governments as well as court challenges on various issues such as indigenous title, the government's duty to consult and accommodate indigenous peoples and the sufficiency of environmental review processes, which creates further uncertainty. 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.

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.

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, 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.

In 2017, the United States government announced its intention to renegotiate NAFTA. As a result, Canada, the United States and Mexico began renegotiating the terms of NAFTA in mid-2017. The United States has also suggested that it might give notice of the termination of NAFTA if it is not satisfied with the outcome of the renegotiations. If the United States does give notice of its intent to terminate or withdraw from NAFTA, the earliest such termination or withdrawal could occur would be six months after such notice is given. The renegotiations are still underway and theoutcomes of such negotiations remain unclear, but 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, any changes to, or termination of, NAFTA could have an impact on Western Canada's crude oil and natural gas industry at large, including Bellatrix's business.

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 oil and 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. The text of CPTPP has not been finalized or published and the agreement remains subject to ratification by the governments of each of the countries involved. While it is uncertain what effect CETA, CPTPP or any other trade agreements will have on the oil and gas industry in Canada, the

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lack of available infrastructure for the offshore export of oil and gas may limit the ability of Canadian oil and 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. 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 Alberta, British Columbia and Saskatchewan 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 the provinces of Alberta, British Columbia and Saskatchewan. In each of the provinces of Alberta, British Columbia and Saskatchewan approximately 19%, 6% and 30%, 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 oilsands 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.

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

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Alberta

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

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

Producers pay a flat royalty rate of 5% of gross revenue from each well that is subject to the Modernized Framework until the well reaches payout. Payout for a well is the point at which cumulative gross revenues from the well equals the Drilling and Completion Cost Allowance for the well set by the AER. After payout, producers pay an increased post-payout royalty on revenues of between 5% and 40%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 also required to pay annual rental payments, at a rate of $3.50 per hectare, and make monthly royalty payments in respect of crude oil and natural gas produced.

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

Freehold mineral taxes are levied for production from freehold mineral lands on an annual basis on calendar year production. Freehold mineral taxes are calculated using a tax formula that takes into consideration, among other things, the amount of production, the hours of production, the value of each unit of production, the tax rate and the percentages that the owners hold in the title. On average, in Alberta the tax levied is 4% of revenues reported from freehold mineral title properties. The freehold mineral taxes would be in addition to any royalty or other payment paid to the owner of such freehold mineral rights, which are established through private negotiation.

British Columbia

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

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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 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 "Resource Surcharge") 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. In addition, a mineral rights tax is charged to mineral rights holders paid on an annual basis at the rate of $1.50 per acre owned.

In addition to such surcharges and taxes, the Crown royalty payable in respect of crude oil depends on the type and vintage of crude oil, the quantity of crude oil produced in a month, the value of the crude oil produced and specified adjustment factors determined monthly by the provincial government. The ultimate royalty payable ranges from 5% to 20% depending on the classification of the crude oil, and additional marginal royalty rates may apply, between 30% and 45%, where average wellhead prices received are above base prices. 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 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 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 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.

In addition to the royalties payable to the mineral owners, 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

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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 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 and facility 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 of the federal government; (iv) analyzing further specified factors for projects such as alternatives to the project and social and indigenous issues in addition to health, environmental and economic impacts; and (v) overseeing an expanded follow-up, monitoring and enforcement process with increased involvement of indigenous peoples and communities. As to the proposed CER, many of its activities would be similar to the NEB, albeit with a different structure and the notable exception that the CER would no longer have primary responsibility in the consideration of the new major projects, instead focusing on the lifecycle regulation (e.g. overseeing construction, tolls and tariffs, operations and eventual winding down) of approved projects, while providing for expanded participation by communities and indigenous peoples. It is unclear when the new regulatory scheme will come into force or whether any amendments will be made prior to coming into force. Until then, the federal government's interim principles released on January 27, 2016 will continue to guide decision-making authorities for projects currently undergoing environmental assessment. The eventual effects of the proposed regulatory scheme on proponents of major projects remains unclear.

On May 12, 2017, the federal government introduced the Oil Tanker Moratorium Act in Parliament. This legislation is aimed at providing coastal protection in northern British Columbia by prohibiting crude oil tankers carrying more than 12,500 metric tonnes of crude oil or persistent crude oil products from stopping, loading, or unloading crude oil in that area. Parliament is still considering the bill, which passed second reading on October 4, 2017. If implemented, the legislation may prevent the building of pipelines

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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 resource development in Alberta. 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 "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 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.

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.

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Liability Management Rating Programs

Alberta

The AER administers the Licensee Liability Rating Program (the "AB LLR Program"). The AB LLR Program is a liability management program governing most conventional upstream crude oil and natural gas wells, facilities and pipelines. Alberta's Oil and Gas Conservation Act (the "OGCA") establishes an orphan fund (the "Orphan Fund") to pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program if a licensee or working interest participant ("WIP") becomes insolvent or is unable to meet its obligations. The Orphan Fund is funded by licensees in the AB LLR Program through a levy administered by the AER. The AB LLR Program is designed to minimize the risk to the Orphan Fund posed by unfunded liability of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines. The AB LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to provide the AER with a security deposit. The ratio of deemed assets to deemed liabilities is assessed once each month and where a security deposit is deemed to be required, the failure to post any required amounts may result in the initiation of enforcement action by the AER. The AER publishes the liability management rating for each licensee on a monthly basis on its public website.

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 OGCA, including the AB LLR Program, and the Bankruptcy and Insolvency Act (the "BIA"). This ruling meant that receivers and trustees have the right to renounce assets within insolvency proceedings, which was affirmed by a majority of the Alberta Court of Appeal. Such a conflict renders the AER's legislated authority unenforceable 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 insolvent. Effectively, this means that abandonment costs will be borne by the industry-funded Orphan Well Fund or the province in these instances because any financial resources of the insolvent licensee will first be used to satisfy secured creditors under the BIA. This decision is currently under appeal to the Supreme Court of Canada, with final resolution expected in 2018.

In response to Redwater, the AER issued several bulletins and interim rule changes to govern while the case is appealed and to allow the Government of Alberta to develop appropriate regulatory measures to adequately address environmental liabilities. The AER's Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, which deals with licence eligibility to operate wells and facilities, was amended and now requires extensive corporate governance and shareholder information, with a particular focus on any previous companies of directors and officers that have 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 are assessed on a non-routine basis and the AER now requires all transferees to demonstrate that they have a liability management rating ("LMR"), being the ratio of a licensee's assets to liabilities, of 2.0 or higher immediately following the transfer, or to otherwise prove that it can satisfy its abandonment and reclamation obligations. The AER may make further rule changes in response to Redwater at any time, especially as the case heads towards a final determination, which means that additional obligations and/or different requirements may be forthcoming.

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. The IWCP completed its second year on March 31, 2017. Overall, the AER has announced that licensees brought 19% of non-compliant wells in the IWCP into compliance with AER requirements in the second year of the IWCP.

British Columbia

The Commission oversees a similar 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 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

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are deemed non-compliant under the OGAAand enter the compliance and enforcement framework. The Commission has announced that it is working to determine how best to manage risks in light of the Redwater decision, so changes may be forthcoming.

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 an 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 regulatory environment of the crude oil and natural gas industry in Canada.

In general, there is some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as it is currently not possible to predict the extent of future requirements. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on Bellatrix'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 February, 2018, 174 of the 197 parties to the convention have ratified the Paris Agreement.

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. Four provinces currently have carbon pricing systems in place that would meet federal requirements (Alberta, British Columbia, Ontario and Quebec). The federal government will accept comments on the draft legislative proposals to implement the federal carbon pricing system until February 12, 2018.

On May 27, 2017, the federal government published draft regulations to reduce emissions of methane from the crude oil and natural gas sector. The proposed 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, by introducing new control measures. Among other things, the proposed 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. The levy is anticipated to increase again

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in 2021 in line with the federal legislation. On December 14, 2016, the Oil Sands Emissions Limit Act came into force, establishing an annual 100 megatonne limit for GHG emissions from all oil sands sites, excluding some attributable to upgraders, the electric energy portion of cogeneration and other prescribed emissions.

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

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

Alberta was also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta has committed $1.24 billion over 15 years to fund two large-scale carbon capture and storage projects that will begin commercializing the technology on the scale needed to be successful. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be, and to have always been the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.

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.

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 payments.

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RISK FACTORS

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.

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

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 and effective maintenance operations 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, the environment and personal injury. Particularly, Bellatrix may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to Bellatrix.

Oil and natural gas production operations are also subject to all the risks typically associated with such operations, 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 Bellatrix's business, financial condition, results of operations and prospects.

Weakness in the Oil and Gas Industry

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

Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by the OPEC, slowing growth in emerging economies, market volatility and disruptions in Asia, sovereign debt levels and political upheavals in various countries have caused significant weakness and volatility in commodity prices. These events and conditions have caused a significant decrease in the valuation of oil and gas companies and a decrease in confidence in the oil and gas industry. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation. In addition, the inability to get the necessary approvals to build pipelines, liquefied natural gas plants and other facilities to provide better access to markets for the oil and gas industry in Western Canada has led to

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additional downward price pressure on oil and gas produced in Western Canada and uncertainty and reduced confidence in the oil and gas industry in Western Canada. Lower commodity prices may also affect the volume and value of Bellatrix's reserves, rendering certain reserves uneconomic. In addition, lower commodity prices restrict Bellatrix's cash flow resulting in less funds from operations being available to fund Bellatrix's capital expenditure budget. Consequently, Bellatrix may not be able to replace its production with additional reserves and both Bellatrix's production and reserves could be reduced on a year over year basis. Any decrease in value of Bellatrix's reserves may reduce the borrowing base under its Credit Facilities, which, depending on the level of Bellatrix's indebtedness, could result in Bellatrix having to repay a portion of its indebtedness. In addition to possibly resulting in a decrease in the value of Bellatrix's economically recoverable reserves, lower commodity prices may also result in a decrease in the value of Bellatrix's infrastructure and facilities, all of which could also have the effect of requiring a write down of the carrying value of Bellatrix's oil and gas assets on its balance sheet and the recognition of an impairment charge in its income statement. Given the current market conditions and the lack of confidence in the Canadian oil and gas industry, Bellatrix may have difficulty raising additional funds or if it is able to do so, it may be on unfavourable and highly dilutive terms. If these conditions persist, Bellatrix's cash flow may not be sufficient to continue to fund its operations and to satisfy its obligations when due and Bellatrix'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 Bellatrix or at all. Similarly, there can be no assurance that Bellatrix 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 Bellatrix's control do, and will continue to, affect the marketability and price of oil and natural gas acquired, produced, or discovered by Bellatrix. 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. Deliverability uncertainties related to the distance Bellatrix's reserves are from pipelines, railway lines, processing and storage facilities; operational problems affecting pipelines, railway lines and 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 Bellatrix.

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 Bellatrix. 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 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 Bellatrix's ability to access such markets. A material decline in prices could result in a reduction of Bellatrix'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 Bellatrix'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 Bellatrix'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 Bellatrix's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on Bellatrix'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

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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 Bellatrix's performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices, or current perceptions of the oil and gas market. In certain jurisdictions institutions, including government sponsored entities, have determined to decrease their ownership in oil and gas entities which may impact the liquidity of certain securities and may put downward pressure on the trading price of those securities. Similarly, the market price of the Common Shares of Bellatrix could be subject to significant fluctuations in response to variations in Bellatrix's operating results, financial condition, liquidity and other internal factors. Accordingly, the price at which the Common Shares of Bellatrix will trade cannot be accurately predicted.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The anticipated benefits of acquisitions may not be achieved and Bellatrix 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 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 Bellatrix's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of Bellatrix. The integration of acquired businesses 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 assets required to provide such services. In this regard, non‑core assets may be periodically disposed of so Bellatrix 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 Bellatrix may realize less on disposition than their carrying value on the financial statements of Bellatrix.

Political Uncertainty

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

In the last several years, the United States and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. During the 2016 presidential campaign a number of election promises were made and the new American administration has begun taking steps to implement certain of these promises. The administration has announced withdrawal of the United States from the Trans-Pacific Partnership and Congress has passed sweeping tax reform, which, among other things, significantly reduces US corporate tax rates. This may affect competitiveness of other jurisdictions, including Canada. The North American Free Trade Agreement is currently under renegotiation and the result is uncertain at this time. The 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 administration in the United States will implement, and if implemented, how these actions may impact Canada and in particular the oil and gas industry. Any actions taken by the new United States administration may have a negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of Canadian oil and gas companies, including Bellatrix.

In addition to the political disruption in the United States, the citizens of the United Kingdom recently voted to withdraw from the European Union and the Government of the United Kingdom has begun taken steps to implement such withdrawal. 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 Bellatrix's ability to market its products internationally, increase costs for goods and services required for Bellatrix's operations, reduce access to skilled labour and negatively impact Bellatrix's business, operations, financial conditions and the market value of its Common Shares.

A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and gas industry including the balance between economic development and environmental policy 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 and other infrastructure projects.

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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.

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 Bellatrix 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 Bellatrix's financial performance. The Corporation's return on assets operated by others depends upon a number of factors that may be outside of Bellatrix'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 Bellatrix 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 Bellatrix has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations Bellatrix 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, Bellatrix potentially becoming subject to additional liabilities relating to such assets and Bellatrix having difficulty collecting revenue due from such operators or recovering amounts owing to Bellatrix from such operators for their share of abandonment and reclamation obligations. Any of these factors could have a material adverse affect on Bellatrix's financial and operational results.

Project Risks

The success of Bellatrix's operations may be negatively impacted by factors outside of its control resulting in operational delays, cost overruns and marketing challenges.

The Corporation manages a variety of small and large projects in the conduct of its business. Project delays may impact 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 Bellatrix'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 Bellatrix'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, Bellatrix could be unable to execute projects on time, on budget, or at all and may be unable to market the oil and natural gas that it produces effectively.

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Gathering and Processing Facilities and Pipeline Systems

Lack of capacity and/or regulatory constraints on gathering and processing facilities and pipeline may have a negative impact on Bellatrix's ability to produce and sell its oil and natural gas.

The Corporation delivers its products through gathering and processing facilities and by pipeline. The amount of oil and natural gas that Bellatrix can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities and pipeline systems. The lack of availability of capacity in any of the gathering and processing facilities and pipeline systems could result in Bellatrix's inability to realize the full economic potential of its production or in a reduction of the price offered for Bellatrix's production. The lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to transport produced oil and gas to market. 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 Bellatrix's production, operations and financial results. As a result, producers are increasingly turning to rail 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 Bellatrix's business and, in turn, Bellatrix's financial condition, operations and cash flows. Announcements and actions taken by the governments of British Columbia and Alberta 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 recently introduced draft legislation 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 of receipt of approvals of major projects remains unclear.

A portion of Bellatrix's production may, from time to time, be processed through facilities owned by third parties and over which Bellatrix 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 Bellatrix's ability to process its production and deliver the same for sale.

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 Bellatrix. 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 Bellatrix. 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 enjoy technological advantages and may in the future allow them to implement new technologies before Bellatrix. There can be no assurance that Bellatrix will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If Bellatrix does implement such technologies, there is no assurance that Bellatrix will do so successfully. One or more of the technologies currently utilized by Bellatrix or implemented in the future may become obsolete. In such case, Bellatrix's business, financial condition and results of operations could be affected adversely and materially. If

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Bellatrix is unable to utilize 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 Bellatrix'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 affect on the demand for oil and gas products. The Corporation cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on Bellatrix's business, financial condition, results of operations and cash flows by decreasing Bellatrix'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 Bellatrix'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 and transportation). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes, royalties and the exportation of oil and natural gas. 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 Bellatrix's costs, either of which may have a material adverse effect on Bellatrix's business, financial condition, results of operations and prospects. Recently, the federal government and certain provincial governments have taken steps to initiate protocols and regulations to limit the release of methane from oil and gas operations. Such draft regulations and protocols may require additional expenditures or otherwise negatively impact Bellatrix's operations, which may affect Bellatrix's profitability. See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Climate Change Regulations".

In order to conduct oil and natural gas operations, Bellatrix 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 Bellatrix 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 Bellatrix's business, financial condition and the market value of its Common Shares or its assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity.

Royalty Regimes

Changes to royalty regimes may negatively impact Bellatrix's cash flows.

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

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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 Bellatrix'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 Bellatrix is ultimately able to produce from its reserves.

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 operations, the implementation of a response plan to address potential events, and the suspension of operations if a seismic event above a particular threshold occurs. The AER continues to monitor seismic activity around the province and may extend these requirements to other areas of the province if necessary.

Disposal of Fluids Used in Operations

Regulations regarding the disposal of fluids used in Bellatrix'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 Bellatrix's costs of compliance.

Environmental

Compliance with environmental regulations requires the dedication of a portion of Bellatrix'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 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 Bellatrix to incur costs to remedy such discharge. Although Bellatrix 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 Bellatrix's business, financial condition, results of operations and prospects.

Carbon Pricing Risk

Taxes on carbon emissions affect the demand for oil and natural gas, Bellatrix's operating expenses and may impair Bellatrix'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 alternatives 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 Bellatrix's operating expenses, each of which may have a material adverse effect on Bellatrix's profitability and financial condition. Further, the imposition of carbon taxes puts Bellatrix at a disadvantage with its counterparts who operate in jurisdictions where there are less costly carbon regulations.

Liability Management

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Liability management programs enacted by regulators in the western provinces may prevent or interfere with Bellatrix'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 Bellatrix's deemed assets to deemed liabilities or other changes to the requirements of liability management programs may result in significant increases to Bellatrix's compliance obligations. In addition, the liability management regime may prevent or interfere with Bellatrix's ability to acquire or dispose of assets, as both the vendor and the purchaser of oil and gas assets must be in compliance with the liability management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the transfer of such assets. The recent Alberta Court of Queen's Bench decision, Redwater Energy Corporation (Re), found an operational conflict between the Bankruptcy and Insolvency Act and the AER's abandonment and reclamation powers when the licensee is insolvent, which was affirmed by a majority of the Alberta Court of Appeal, and has been appealed by the AER to the Supreme Court of Canada for final determination. In response to the decision, the AER issued interim rules to administer the liability management program and until the Government of Alberta can develop new regulatory measures to adequately address environmental liabilities. There remains a great deal of uncertainty as to what new regulatory measures will be developed by the provinces or in concert with the federal government, as the final ruling will become binding in all Canadian jurisdictions. 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 Bellatrix.

The Corporation's exploration and production facilities and other operations and activities emit greenhouse gases which may require Bellatrix to comply with GHG emissions legislation at the provincial or federal level. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. As a signatory to the UNFCCand 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. 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 direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on Bellatrix's business, financial condition, results of operations and prospects. Some of Bellatrix'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 Bellatrix's operating expenses and in the long-term reducing the demand for oil and gas production resulting in a decrease in Bellatrix'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".

Variations in Foreign Exchange Rates and Interest Rates

Variations in foreign exchange rates and interest rates could adversely affect Bellatrix'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 Bellatrix's production revenues. Accordingly, exchange rates between Canada and the United States could affect the future value of Bellatrix'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 Bellatrix receives for its oil and natural gas production, it could also result in an increase in the price for certain goods used for Bellatrix's operations, which may have a negative impact on Bellatrix's financial results.

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

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An increase in interest rates could result in a significant increase in the amount Bellatrix 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 and could 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, 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, Bellatrix's ability to do so is dependent on, among other factors:

• the overall state of the capital markets;

• Bellatrix'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 Bellatrix's securities in particular.

Further, if Bellatrix's revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing. 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 Bellatrix. The Corporation may be required to seek additional equity financing on terms that are highly dilutive to existing shareholders. The inability of Bellatrix to access sufficient capital for its operations could have a material adverse effect on Bellatrix'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, Bellatrix 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 Bellatrix 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 gas industry and/or global economic and political volatility, Bellatrix may from time to time have restricted access to capital and increased borrowing costs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing.

As a result of global economic and political volatility, Bellatrix may from time to time have restricted access to capital and increased borrowing costs. Failure to obtain such financing on a timely basis could cause Bellatrix to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If Bellatrix's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect Bellatrix'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, Bellatrix'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 Bellatrix'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 Bellatrix's capital expenditure plans may result in a delay in development or production on Bellatrix's properties.

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Credit Facility 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 its Credit Facilities 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 Credit Facilities, 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 Credit Facilities 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. As a result of the depressed commodity prices experienced in the last two years, Bellatrix's borrowing base was reduced in 2016. 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.

Issuance of and Refinancing Debt

Increased debt levels may impair Bellatrix's ability to borrow additional capital on a timely basis to fund opportunities as they arise.

From time to time, Bellatrix 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 Bellatrix's debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, Bellatrix may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither Bellatrix's articles nor its by‑laws limit the amount of indebtedness that Bellatrix may incur.The level of Bellatrix's indebtedness from time to time could impair Bellatrix's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

To the extent that external sources of capital become limited or unavailable or only available on onerous terms, Bellatrix’s ability to obtain additional financing or refinance existing debt may be impaired, and our assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result.

Hedging

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

From time to time, Bellatrix 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 Bellatrix 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, Bellatrix'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 Bellatrix 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, Bellatrix will not benefit from the fluctuating exchange rate.

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Title to Assets

Defects in the title to Bellatrix's properties may result in a financial loss.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that a defect in the chain of title will not arise. The actual interest of Bellatrix in properties may accordingly vary from Bellatrix's records. If a title defect does exist, it is possible that Bellatrix may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on Bellatrix's business, financial condition, results of operations and prospects. There may be valid challenges to title or legislative changes, which affect Bellatrix's title to the oil and natural gas properties Bellatrix controls that could impair Bellatrix's activities on them and result in a reduction of the revenue received by Bellatrix.

Reserves Estimates

The Corporation's estimated proved and proved plus probable reserves are based on numerous factors and assumptions which may prove incorrect and which may affect Bellatrix.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in this document are estimates only. Generally, estimates of economically recoverable oil and natural gas reserves 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 the 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. Such variations could be material.

In accordance with Applicable Securities Laws, Bellatrix'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. 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 Bellatrix'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 Bellatrix.

The Corporation's involvement in the exploration for and development of oil and natural gas properties may result in Bellatrix becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards. Although Bellatrix maintains insurance in accordance with industry standards to address certain of these risks Bellatrix is not fully insured against all risks and 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, Bellatrix may elect not to

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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 Bellatrix. The occurrence of a significant event that Bellatrix is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on Bellatrix's business, financial condition, results of operations and prospects.

Geopolitical Risks

Global political events may adversely affect commodity prices which in turn affect Bellatrix's cash flow.

Political events throughout the world that cause disruptions in the supply of oil continuously affect the marketability and price of oil and natural gas acquired or discovered by Bellatrix. Conflicts, or conversely peaceful developments, arising outside of Canada, including changes in political regimes or the parties in power, have 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 Bellatrix's net production revenue.

Eco-Terrorism Risks

The Corporation's properties may be subject to terrorist attack

The Corporation's oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of Bellatrix's properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on Bellatrix'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 Bellatrix's Operations

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

Any environmental damage, loss of life, injury or damage to property caused by Bellatrix's operations could damage Bellatrix's reputation in the areas in which Bellatrix operates. Negative sentiment towards Bellatrix could result in a lack of willingness of municipal authorities to grant the necessary licenses or permits for Bellatrix to operate its business and in residents in the areas where Bellatrix is doing business opposing further operations in the area by Bellatrix. If Bellatrix develops a reputation of having an unsafe work site it may impact the ability of Bellatrix to attract and retain the necessary skilled employees and consultants to operate its business. Further, Bellatrix's reputation could be affected by actions and activities of other corporations operating in the oil and gas industry, over which Bellatrix has no control. In addition, environmental damage, loss of life, injury or damage to property caused by Bellatrix's operations caused by Bellatrix's operations could result in negative investor sentiment towards Bellatrix, which may result in limiting Bellatrix's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares.

Changing Investor Sentiment

Changing investor sentiment towards the oil and gas industry may impact Bellatrix'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, concerns of the impact of oil and gas operations on the environment, concerns of environmental damage relating to spills of petroleum products during transportation and concerns of indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board, management and employees of Bellatrix. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in Bellatrix or not investing in Bellatrix at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, Bellatrix, may result in limiting Bellatrix's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares.

Dilution

The Corporation may issue additional Common Shares, diluting current Shareholders.

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

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 Bellatrix 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. The inability of Bellatrix to deal with this growth may have a material adverse effect on Bellatrix'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 Bellatrix 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 Bellatrix's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on Bellatrix'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".

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, the cash flow, results of operations and financial condition of Bellatrix, the need for funds to finance ongoing operations and other considerations, as the Board considers relevant.

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The amount of and frequency at which future cash dividends are paid may vary and there is no assurance that Bellatrix will pay dividends in the future.

The amount of future cash dividends paid by Bellatrix, if any, will be subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends.

Litigation

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

In the normal course of Bellatrix'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, relating to personal injuries, including resulting from exposure to hazardous substances, property damage, property taxes, land and access rights, environmental issues, including claims relating to contamination or natural resource damages and contract disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to Bellatrix, and as a result, could have a material adverse effect on Bellatrix's assets, liabilities, business, financial condition and results of operations. Even if Bellatrix 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 effect on Bellatrix's financial condition.

Aboriginal Claims

Aboriginal Claims may affect Bellatrix

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 Bellatrix'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 Bellatrix's business and financial results.

Breach of Confidentiality

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

While discussing potential business relationships or other transactions with third parties, Bellatrix may disclose confidential information relating to the business, operations or affairs of Bellatrix. Although confidentiality agreements are generally signed by third parties prior to the disclosure of any confidential information, a breach could put Bellatrix at competitive risk and may cause significant damage to its business. The harm to Bellatrix'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, Bellatrix 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 Bellatrix'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, R.S.C. 1985, c. 1 (5^th Supp.) 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 Bellatrix, 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 Bellatrix. Furthermore, tax authorities having jurisdiction over Bellatrix may disagree with how Bellatrix calculates its income for tax purposes or could change administrative practices to Bellatrix's detriment.

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Seasonality and Extreme Weather Conditions

Oil and natural gas operations are subject to seasonal and extreme weather conditions and Bellatrix 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 Bellatrix'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 swampy terrain. In addition, extreme cold weather, heavy snowfall and heavy rainfall may restrict Bellatrix'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, Bellatrix may be exposed to third party credit risk from operators of properties in which Bellatrix has a working or royalty interest. Poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in Bellatrix's ongoing capital program, potentially delaying the program and the results of such program until Bellatrix 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 Bellatrix being unable to collect all or a portion of any money owing from such parties. Any of these factors could materially adversely affect Bellatrix's financial and operational results.

Conflicts of Interest

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

Certain directors or officers of Bellatrix 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 of 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 Bellatrix 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 Bellatrix's operations.

The Corporation's success depends in large measure on certain key personnel. The loss of the services of such key personnel may have a material adverse effect on Bellatrix's business, financial condition, results of operations and prospects. The Corporation does not have any key personnel insurance in effect for Bellatrix. The contributions of the existing management team to the immediate and near-term operations of Bellatrix 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 Bellatrix 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 Bellatrix.

Information Technology Systems and Cyber-Security

Breaches of Bellatrix's cyber-security and loss of, or access to, electronic data may adversely impact its 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,

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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, Bellatrix is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of Bellatrix’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. The Corporation applies technical and process controls in line with industry-accepted standards to protect our information assets and systems. Disruption of critical information technology services, or breaches of information security, could have a negative effect on our performance and earnings, as well as on our reputation. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on Bellatrix’s business, financial condition and results of operations.

Expansion into New Activities

Expanding Bellatrix's business exposes it to new risks and uncertainties.

The operations and expertise of Bellatrix's management are currently focused primarily on oil and gas production, exploration and development in the Western Canada Sedimentary Basin. In the future Bellatrix may acquire or move into new industry related activities or new geographical areas, may acquire different energy related assets and as a result may face unexpected risks or alternatively, significantly increase Bellatrix's exposure to one or more existing risk factors, which may in turn result in Bellatrix'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 Bellatrix's forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Additional information on the risks, assumption and uncertainties are found under the heading "Forward-Looking Statements" of this Annual Information Form.

.

HUMAN RESOURCES

As at December 31, 2017 Bellatrix employed 157 full-time employees (105 are located in the head office and 52 are field employees) and 38 consultants on afull-time equivalent basis. As at December 31, 2017, Bellatrix employed 5 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.

Orange Capital LLC acquired, through a fund managed or advised by it, approximately US$15 million of the Senior Notes pursuant to the offering of Senior Notes that closed on May 21, 2015 as described under "General Development of our Business - Borrowings and Financings - 2015 Note Offering". At the time of the Senior Note offering Orange Capital LLC had control or direction over approximately 31,031,114 Common Shares representing approximately 16.17% of the Common Shares issued and outstanding as at such date. Daniel Lewis, who at the time of the Senior Note offering was a director of Bellatrix and the Managing Member of Orange Capital LLC, abstained from voting on approving the terms of the Senior Notes. To the knowledge of Bellatrix, Orange Capital LLC no longer holds any Common Shares and Daniel Lewis is no longer a director of Bellatrix.

INTERESTS OF EXPERTS

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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 2017 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, 2017, 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 Senior Notes Indenture (see "Borrowings – Senior Notes"), the agreement governing the Credit Facilities (see "Borrowings – CreditFacilities"), and the Debenture Indenture (see "Borrowings – Convertible Debentures"). A copy of the Senior Note Indenture, Credit Facilities and the Debenture Indenture may be viewed on the SEDAR website at www.sedar.com.

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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

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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 13th day of March, 2018.

(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) "Murray L. Cobbe"
Murray B. Todd	Murray L. Cobbe
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, 2017. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2017, 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, 2017, 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, 2017	Canada	Nil	1,500,620.3	Nil	1,500,620.3

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, 2017)”.

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: February 28, 2018

(signed) "Ron Bojechko"

Ron Bojechko, P.Eng.

Managing Director

B-2

APPENDIX "C"

MANDATE AND TERMS OF REFERENCE OF THE AUDIT COMMITTEE

Role and Objective

The Audit Committee (the "Committee") is a committee of the board of directors (the "Board") of Bellatrix Exploration Ltd. ("Bellatrix" or the "Corporation") to which the Board has delegated its responsibility for the oversight of the following:

1.the nature and scope of the annual audit;

2.the oversight of management's reporting on internal accounting standards and practices;

3.the review of financial information, accounting systems and procedures including internal control over financial reporting;

4.the Corporation's compliance with legal and regulatory requirements;

5.the performance of the Corporation's internal audit function, if any;

6.the qualifications, independence and performance of the Corporation's external auditors; and

7.the quality and integrity of the Corporation's financial reporting and financial statements,

and 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. To assist directors of Bellatrix ("Directors") in meeting their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Corporation and related matters;

2. To oversee the accounting and financial reporting processes of Bellatrix and the audits of Bellatrix's financial statements;

3. To provide better communication between Directors and external auditors;

4. To review and enhance the external auditors' independence;

5. To increase the credibility and objectivity of financial reports; and

6. To strengthen the role of the outside Directors by facilitating in depth discussions between Directors on 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.

Membership of Committee

1. The Committee will be comprised of at least three (3) Directors or such greater number as the Board may determine from time to time and 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 "1934 Act") (unless the Board determines that an exemption contained in Rule 10A-3 is available and determines to rely thereon).

2. 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.

3. At least one member of the Committee shall be an "audit committee financial expert" within the meaning of that term under the 1934 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 1934 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.

4. The Board may from time to time designate one of the members of the Committee to be the Chair of the Committee.

5.  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.

Mandate and Responsibilities of Committee

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 Corporation 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 Corporation; and

(i) obtaining explanations of significant variances with comparative reporting periods;

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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 Corporation to analysts and rating agencies. Such discussion may be done generally, such as discussing the types of information to 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 Corporation;

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 Corporation'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 Corporation, 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

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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 Corporation's internal audit function (if any);

15. Review major issues regarding accounting principles and financial statement presentations, including any significant changes in the Corporation's selection or application of accounting principles, and major issues as to the adequacy of the Corporation'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 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 Corporation, including discussing the Corporation'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 Corporation;

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;

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26. To 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 Corporation is required to comply with ESTMA;

27. Report regularly to the Board;

28. Review periodically, as determined necessary, the Committee's Mandate and Terms of Reference and recommend to the Board and the Corporate Governance Committee of the Board amendments as the Committee believes are necessary or desirable.

The Committee has authority to communicate directly with the internal auditors (if any) and the external auditors of the Corporation. The Committee will also have the authority to investigate any financial activity of Bellatrix. All employees of Bellatrix are to cooperate as requested by the Committee.

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

Meetings and Administrative Matters

1. At all meetings of the Committee every resolution shall be decided by a majority of the votes cast. In case of an equality of votes, the Chairman of the meeting shall be entitled to a second or casting vote.

2. The Chair will preside at all meetings of the Committee, unless the Chair is not present, in which case the members of the Committee that are present will designate from among such members the Chair for purposes of the meeting.

3. 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.

4. Meetings of the Committee should be scheduled to take place at least quarterly. Minutes of all meetings of the Committee will be taken. 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 Chairman.

5. 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.

6. 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).

7. Agendas, approved by the Chair, will be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.

8. The Committee may invite such officers, directors and employees of the Corporation and its subsidiaries as it sees fit from time to time to attend at meetings of the Committee and assist in the discussion and consideration of the matters being considered by the Committee.

9. Minutes of the Committee will be recorded and maintained and circulated to Directors who are not members of the Committee or otherwise made available at a subsequent meeting of the Board.

10. The Committee may retain persons having special expertise and may obtain independent professional advice to assist in fulfilling its responsibilities at the expense of the Corporation as determined by the Committee.

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11. Any members of the Committee may be removed or replaced at any time by the Board and will cease to be a member of the Committee as soon as such member ceases to be a Director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy exists on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, following appointment as a member of the Committee each member will hold such office until the Committee is reconstituted.

12. Any issues arising from these meetings that bear on the relationship between the Board and Management should be communicated to the Chairman of the Board by the Committee Chair.

13. The performance of the Committee shall be evaluated annually by the Corporate Governance Committee of the Board.

March 14, 2017

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SCHEDULE "A" OF APPENDIX "C"

DEFINITION OF INDEPENDENT FOR PURPOSES OF

NATIONAL INSTRUMENT 52-110 — AUDIT COMMITTEES

As at October 6, 2014

1.Meaning of Independence –

(a) A director is independent if he or she has no direct or indirect material relationship with the issuer.

(b) For the purposes of subsection 1(a), a "material relationship" is a relationship which could, in the view of the issuer's board of directors, be reasonably expected to interfere with the exercise of a member's independent judgment.

(c) Despite subsection 1(b), the following individuals are considered to have a material relationship with an issuer:

(i) an individual who is, or has been within the last three years, an employee or executive officer of the issuer;

(ii) an individual whose immediate family member is, or has been within the last three years, an executive officer of the issuer;

(iii) an individual who:

(a) is a partner of a firm that is the issuer's internal or external auditor,

(b) is an employee of that firm, or

(c) was within the last three years a partner or employee of that firm and personally worked on the issuer's audit within that time;

(iv) an individual whose spouse, minor child or stepchild, or child or stepchild who shares a home with the individual:

(a) is a partner of a firm that is the issuer's internal or external auditor,

(b) is an employee of that firm and participates in its audit, assurance or tax compliance (but not tax planning) practice, or

(c) was within the last three years a partner or employee of that firm and personally worked on the issuer's audit within that time;

(v) an individual who, or whose immediate family member, is or has been within the last three years, an executive officer of an entity if any of the issuer's current executive officers serves or served at that same time on the entity's compensation committee; and

(vi) an individual who received, or whose immediate family member who is employed as an executive officer of the issuer received, more than CDN$75,000 in direct compensation from the issuer during any 12 month period within the last three years.

(d) Despite subsection 1(c), an individual will not be considered to have a material relation-ship with the issuer solely because

(i) he or she had a relationship identified in subsection 1(c) if that relationship ended before March 30, 2004; or

(ii) he or she had a relationship identified in subsection 1(c) by virtue of subsection (8) if that relationship ended before June 30, 2005.

(e) For the purposes of clauses 1(c)(iii) and 1(c)(iv), a partner does not include a fixed income partner whose interest in the firm that is the internal or external auditor is limited to the receipt of fixed amounts of compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service.

(f) For the purposes of clause 1(c)(vi), direct compensation does not include:

(i) remuneration for acting as a member of the board of directors or of any board committee of the issuer, and

(ii) the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the issuer if the compensation is not contingent in any way on continued service.

(g) Despite subsection 1(c), an individual will not be considered to have a material relation-ship with the issuer solely because the individual or his or her immediate family member

(i) has previously acted as an interim chief executive officer of the issuer, or

(ii) acts, or has previously acted, as a chair or vice-chair of the board of directors or of any board committee of the issuer on a part-time basis.

(h) For the purpose of determination of independence, an issuer includes a subsidiary entity of the issuer and a parent of the issuer.

2.Additional Independence Requirements —

(a) Despite any determination made under paragraph 1 above, an individual who

(i) accepts, directly or indirectly, any consulting, advisory or other compensatory fee from the issuer or any subsidiary entity of the issuer, other than as remuneration for acting in his or her capacity as a member of the board of directors or any board committee, or as a part-time chair or vice-chair of the board or any board committee; or

(ii) is an affiliated entity of the issuer or any of its subsidiary entities,

is considered to have a material relationship with the issuer.

(b) For the purposes of subsection 2(a), the indirect acceptance by an individual of any consulting, advisory or other compensatory fee includes acceptance of a fee by

(i) an individual's spouse, minor child or stepchild, or a child or stepchild who shares the individual's home; or

(ii) an entity in which such individual is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and

which provides accounting, consulting, legal, investment banking or financial advisory services to the issuer or any subsidiary entity of the issuer.

(c) For the purposes of subsection 2(a), compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the issuer if the compensation is not contingent in any way on continued service.

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SCHEDULE "B" OF APPENDIX "c"

DEFINITION OF INDEPENDENT FOR PURPOSES OF THE NEW YORK STOCK EXCHANGE

As at October 6, 2014

For purposes of the independence rules of the New York Stock Exchange and this Schedule B, an "independent director" means a director, other than an executive officer or employee of the company, who meets the criteria contained in Section 303A.02 of the New York Stock Exchange Listed Company Manual and set forth in this Schedule B. In particular, no director qualifies as "independent" unless the company's board of directors affirmatively determines that the director has no material relationship with the company (either directly or as a partner, shareholder or officer of an organization that has a relationship with the company).

In addition, in affirmatively determining the independence of any director who will serve on the compensation committee of the company's board of directors, the board of directors must consider all factors specifically relevant to determining whether a director has a relationship to the company which is material to that director's ability to be independent from management in connection with the duties of a compensation committee member, including, but not limited to: (A) the source of compensation of such director, including any consulting, advisory or other compensatory fee paid by the company to such director; and (B) whether such director is affiliated with the company, a subsidiary of the company or an affiliate of a subsidiary of the company.

For certainty, but without limitation, a director is not independent under the rules of the New York Stock Exchange if:

1. The director is, or has been within the last three years, an employee of the company, or an immediate family member is, or has been within the last three years, an executive officer, of the company, other than prior employment as an interim executive officer.

2. The director has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than US$120,000 in direct compensation from the company, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), other than:

(a) Compensation received by a director for former service as an interim Chairman or CEO or other executive officer; and

(b) Compensation received by an immediate family member for service as an employee of the company (other than an executive officer).

3. (A) The director is a current partner or employee of a firm that is the company's internal or external auditor; (B) the director has an immediate family member who is a current partner of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and personally works on the company's audit; or (D) the director or an immediate family member was within the last three years a partner or employee of such a firm and personally worked on the company's audit within that time.

4. The director or an immediate family member is, or has been with the last three years, employed as an executive officer of another company where any of the company's present executive officers at the same time serves or served on that company's compensation committee.

5. The director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, the company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of US$1 million, or 2% of such other company's consolidated gross revenues.

In the Schedule B, an "immediate family member" includes a person's spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than domestic employees) who shares such person's home. When applying the look-back provisions contained in the foregoing paragraphs and Section 303A.02(b) of the New York Stock Exchange Listed Company Manual, companies need not consider individuals who are no longer immediate family members as a result of legal separation or divorce, or those who have died or become incapacitated.

In addition, references in this Schedule B to the "company" include any parent or subsidiary in a consolidated group with the company or such other company as is relevant to any determination under the independence standards set forth in this Schedule B and Section 303A.02(b) of the New York Stock Exchange Listed Company Manual.

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SCHEDULE "C" OF APPENDIX "c"

DEFINITION OF INDEPENDENT FOR PURPOSES OF RULE 10A-3 UNDER THE UNITED STATES SECURITIES EXCHANGE ACT OF 1934

As at October 6, 2014

Additional Independence Requirements for purposes of the Audit Committee - Directors will not be considered independent for purposes of membership on the Audit Committee if:

1. The director is an Affiliate of the company or any subsidiary of the company (other than as a result of being a director of the company or such subsidiary);

2. the director is (i) both a director and an employee of an Affiliate of the company or (ii) an officer, general partner or managing member of an Affiliate of the company;

3. the director or his or her spouse, minor child or stepchild, or child or stepchild sharing a home with the director accepts any consulting, advisory or other compensatory fee from the company or any subsidiary of the company, apart from in his or her capacity as a member of the board or of any other committee of the board, and other fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the company (provided such compensation is not contingent in any way on continued service); or

4. the director is a partner, member, managing director, officer or person occupying a comparable position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the company) of a firm which provides consulting, legal, accounting, investment banking or financial advisory services to the company or any subsidiary of the company for fees, regardless of whether the director personally provided the services for which the fees are paid.

For the purposes of the above, an "Affiliate" of the company is a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the company, and includes, without limitation, officers of the company, and subsidiaries and sibling companies of the company. Although the determination of a person or entity's status as an Affiliate requires an analysis of all of the applicable facts and circumstances, a person shall not be deemed to be an "Affiliate" of the company if the person is (a) not the beneficial owner, directly or indirectly of more than 10% of any class of voting equity securities of the company and the person is not an officer of the company.

EX-13.2

Exhibit 13.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

March 13, 2018 – The following Management’s Discussion and Analysis of financial results (“MD&A”) as provided by the management of Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) should be read in conjunction with the audited financial statements of the Company for the years ended December 31, 2017 and 2016 as well as Bellatrix’s Annual Information Form (“AIF”) that is filed on SEDAR at www.sedar.com and on the Company’s website at www.bxe.com. The Company’s EDGAR filings and forms are available through the U.S. Securities and Exchange Commission at www.sec.gov. This commentary is based on information available to, and is dated as of March 13, 2018. The financial data presented is in Canadian dollars, except where indicated otherwise.

Overview and Description of the Business

Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) is a publicly traded 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, with highly concentrated operations in west central Alberta, principally focused on profitable development of the Spirit River liquids rich natural gas play.

Common shares of Bellatrix trade on the Toronto Stock Exchange (“TSX”) and on the New York Stock Exchange (“NYSE”) under the symbol “BXE”.

FOURTH QUARTER AND ANNUAL 2017 HIGHLIGHTS

	Three months ended December 31,						Year ended December 31,
	2017			2016			2017			2016
SELECTED FINANCIAL RESULTS
(CDN$000s except share and per share amounts)
Cash flow from operating activities	13,425			17,114			55,210			37,546
Per diluted share (1)		$0.27			$0.35			$1.12			$0.88
Adjusted funds flow (2)	15,700			8,437			58,240			40,916
Per diluted share (1)(2)		$0.32			$0.17			$1.18			$0.96
Net profit (loss)	(13,053		)	23,085			(91,363		)	(26,668		)
Per diluted share (1)		($0.26	)		$0.47			($1.85	)		($0.62	)
Capital – exploration and development	25,755			24,640			120,651			78,660
Total capital expenditures – net (3)	26,212			(137,940		)	65,084			(246,194		)
Credit Facilities	52,066			19,143			52,066			19,143
Senior Notes	305,409			324,691			305,409			324,691
Convertible Debentures (liability component)	39,426			37,420			39,426			37,420
Long term loan receivable	—			(8,775		)	—			(8,775		)
Adjusted working capital deficiency (4)	23,926			23,716			23,926			23,716
Total net debt (4)	420,827			396,195			420,827			396,195
Total assets	1,340,923			1,453,730			1,340,923			1,453,730
Total shareholders’ equity	774,022			863,418			774,022			863,418

Bellatrix Exploration Ltd. 1

SELECTED OPERATING RESULTS		Three months ended December 31,				Year ended December 31,
		2017		2016		2017		2016
Total revenue (5)		60,897		67,907		249,399		227,874
Average daily sales volumes
Crude oil, condensate and NGLs	(bbl/d)	9,602		8,993		9,192		9,935
Natural gas	(mcf/d)	164,848		137,372		166,078		154,453
Total oil equivalent	(boe/d)	37,077		31,888		36,872		35,677
Average realized prices
Crude oil and condensate	($/bbl)	69.64		58.12		62.93		48.41
NGLs (excluding condensate)	($/bbl)	27.68		18.87		21.52		13.14
Crude oil, condensate and NGLs	($/bbl)	36.61		31.08		31.61		25.27
Natural gas	($/mcf)	1.79		3.29		2.27		2.27
Natural gas (including risk management (6))	($/mcf)	2.70		3.13		2.85		2.64
Total oil equivalent	($/boe)	17.42		22.95		18.12		16.86
Total oil equivalent (including risk management (6))	($/boe)	20.80		22.19		20.45		18.38
Net wells drilled		1.9		5.0		23.9		12.9
Selected Key Operating Statistics
Operating netback (3)	($/boe)	6.34		8.87		6.69		6.39
Operating netback (3) (including risk management (6))	($/boe)	9.72		8.11		9.02		7.91
Transportation	($/boe)	1.92		1.07		1.75		0.93
Production expenses	($/boe)	7.81		10.57		8.31		8.70
General & administrative	($/boe)	2.57		1.72		2.18		1.53
Royalties as a % of sales (after transportation)		11	%	12	%	11	%	9	%
COMMON SHARES
Common shares outstanding (7)		49,378,026		49,317,165		49,378,026		49,317,165
Weighted average shares (1)		49,378,026		48,716,487		49,351,848		42,821,013
SHARE TRADING STATISTICS
TSX and Other (8)
(CDN$, except volumes) based on intra-day trading
High		3.52		7.00		6.83		9.95
Low		1.85		4.80		1.85		4.80
Close		2.15		6.40		2.15		6.40
Average daily volume		371,933		414,894		227,648		456,470
NYSE
(US$, except volumes) based on intra-day trading
High		2.80		5.35		5.15		7.40
Low		1.44		3.60		1.44		3.60
Close		1.72		4.72		1.72		4.72
Average daily volume		125,134		104,850		96,969		191,849

(1) Basic weighted average shares for the three months and year ended December 31, 2017 were 49,378,026 (2016: 48,716,487) and 49,351,848 (2016: 42,821,013), respectively. In computing weighted average diluted loss per share, weighted average diluted cash flow from operating activities per share, and weighted average diluted adjusted funds flow per share for the three months and year ended December 31, 2017, a total of nil (2016: nil) and nil (2016: nil) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options, and a total of nil (2016: nil) and nil (2016: nil) common shares issuable on conversion of the Convertible Debentures were added to the denominator for the three months and year resulting in diluted weighted average common shares of 49,378,026 (2016: 49,716,487) and 49,351,848 (2016: 42,821,013), respectively.

(2) The terms adjusted funds flow and adjusted funds flow per share are capital performance measures which should not be considered an alternative to, or more meaningful than, cash flow from operating activities and cash flow from operating activities per share as determined in accordance with GAAP as an indicator of the Company’s performance. Therefore reference to adjusted funds flow or adjusted funds flow per share may not be comparable with the calculation of similar measures for other entities. Management uses adjusted funds flow and adjusted funds flow per share to analyze operating performance and leverage and considers adjusted funds flow and adjusted funds flow per share to be key measures as they demonstrate the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The

Bellatrix Exploration Ltd. 2

reconciliation between cash flow from operating activities and adjusted funds flow can be found in the MD&A. Adjusted funds flow per share is calculated using the weighted average number of common shares for the period.

(3) Operating netbacks and total capital expenditures – net are considered non-GAAP measures. Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from total revenue. Total capital expenditures – net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation. The detailed calculations of operating netbacks are found in the MD&A.

(4) Total net debt is considered to be a capital performance measure and therefore may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, long-term risk management liabilities, decommissioning liabilities, and the deferred tax liability. Total net debt includes the adjusted working capital deficiency, long term loans receivable, Convertible Debentures (liability component), current Credit Facilities, Credit Facilities and Senior Notes (as defined below). The adjusted working capital deficiency is calculated as net working capital deficiency excluding current risk management contract assets and liabilities, current portion of other deferred liabilities, current portion of decommissioning liabilities and the current Credit Facilities. A reconciliation between total liabilities under GAAP and total net debt as calculated by the Company is found in this MD&A.

(5) Total revenue is considered to be a non-GAAP measure. Therefore reference to the non-GAAP measure of total revenue may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total revenue includes petroleum and natural gas sales and other income, and excludes commodity price risk management. Management believes this measure is a useful supplementary measure of the revenue generated by the Company.

(6) The Company has entered into various commodity price risk management contracts which are considered to be economic hedges. Per unit metrics after risk management include only the realized portion of gains or losses on commodity contracts. The Company does not apply hedge accounting to these contracts. As such, these contracts are revalued to fair value at the end of each reporting date. This results in recognition of unrealized gains or losses over the term of these contracts which is reflected each reporting period until these contracts are settled, at which time realized gains or losses are recorded. These unrealized gains or losses on commodity contracts are not included for purposes of per unit metrics calculations disclosed.

(7) Fully diluted common shares outstanding for the three months and year ended December 31, 2017 were 57,172,998 (2016: 58,063,029). This includes 1,622,132 (2016: 2,573,024) of share options outstanding and 6,172,840 (2016: 6,172,840) of shares issuable on conversion of the Convertible Debentures. Shares issuable on conversion of the Convertible Debentures are calculated by dividing the $50 million principal amount of the Convertible Debentures by the conversion price of $8.10 per share.

(8) TSX and Other includes the trading statistics for the TSX and other Canadian trading markets.

2017Fourth Quarter and Annual 2017 Financial and Operational Results

SALES VOLUMES

Sales volumes for the three months ended December 31, 2017 increased by 16% to an average of 37,077 boe/d compared to 31,888 boe/d in the fourth quarter of 2016. Production volumes in the fourth quarter of 2017 remained consistent with third quarter 2017 levels, concluding a strong full year achievement from the 2017 capital program. Total sales volumes between the three months ended December 31, 2017 and December 31, 2016 increased as a result of production volumes added through strong results from development drilling in 2017 in the Spirit River liquids rich natural gas play which more than offset natural volume declines and non-core dispositions of approximately 6,300 boe/d completed between the fourth quarter of 2016 and the third quarter of 2017.

Sales volumes for the year ended December 31, 2017 increased by 3% to an average of 36,872 boe/d compared to 35,677 boe/d in the 2016 year. The full year 2017 average production of 36,872 boe/d (74% natural gas weighted) surpassed the Company’s 2017 revised average annual guidance (mid-point) estimate of 36,000 boe/d. Bellatrix focused operational activity in 2017 on optimizing existing assets, offsetting base declines, mitigating downtime and enhancing cash flow. Several properties were evaluated and subsequently shut-in or converted to seasonal operations to improve overall corporate netbacks with minimal volume impact. By improving wellbore dynamics through optimization projects, daily rates were maximized and base production declines have flattened. Gathering system and facility optimization was achieved through system modelling and subsequent redirection of hydrocarbon flows which have maximized deliverability of production volumes and netbacks throughout the Company’s gathering system. These volumes were partially offset by the impact of system-wide curtailments of take-away capacity on the Nova Gas Transmission Ltd. (the "NGTL") system, third party plant constraints, natural production declines and the impact of non-core asset dispositions completed between the fourth quarter of 2016 and the third quarter of 2017.

Utilization remained strong at the Bellatrix O’Chiese Nees-Ohpawganu’ck deep-cut gas plant at Alder Flats (the “Alder Flats Plant”) with an average utilization rate of 99% in 2017.  The Alder Flats Plant continues to provide strategic benefits to Bellatrix including reduced operating costs, improved deep-cut liquids extraction, and reliability of processing including the ability to re-direct additional natural gas volumes during periods of third party facility constraints and unplanned downtime. Completion of Phase 2 of the Alder Flats Plant will add an incremental 30 MMcf/d ownership capacity net to Bellatrix's 25% working interest and improve revenue generation through additional higher margin natural gas liquids (“NGL”) extraction, resulting in an improvement in the Company’s average corporate liquid weighting to approximately 26% in 2018.

Bellatrix maintains several long term firm transportation (“FT”) agreements, ensuring market egress for current and forecast production, representing approximately 120% of current gross operated natural gas volumes at multiple receipt points on the NGTL system. The NGTL system has experienced, and is expected to experience further curtailments of both interruptible and firm service capacity as the operator continues work to expand capacity along the system. Having secured excess FT relative to Bellatrix's current production levels, these recent system wide curtailments have had minimal impact on Bellatrix's ability to deliver volumes in 2017.

Bellatrix Exploration Ltd. 3

Sales Volumes
		Three months ended December 31,		Year ended December 31,
		2017	2016	2017	2016
Crude oil and condensate	(bbl/d)	2,043	2,798	2,240	3,417
NGLs (excluding condensate)	(bbl/d)	7,559	6,195	6,952	6,518
Total crude oil, condensate and NGLs	(bbl/d)	9,602	8,993	9,192	9,935
Natural gas	(mcf/d)	164,848	137,372	166,078	154,453
Total sales volumes (6:1 conversion)	(boe/d)	37,077	31,888	36,872	35,677

Crude oil, condensate and NGL sales volumes increased by 7% in the fourth quarter of 2017, averaging 9,602 bbl/d compared to 8,993 bbl/d in the same period in 2016. Crude oil, condensate and NGL sales volumes decreased by 7% in the year ended December 31, 2017, averaging 9,192 bbl/d compared to 9,935 bbl/d in the same period of 2016. Sales of natural gas averaged 164.8 MMcf/d during the three months ended December 31, 2017, compared to 137.4 MMcf/d in the same period in 2016, an increase of 20%. Natural gas sales volumes increased 8% to 166.1 MMcf/d during the year ended December 31, 2017, compared to 154.5 MMcf/d in the same period in 2016. In 2017, the Company focused drilling activity on the Spirit River liquids-rich natural gas play, as well as capital investment in optimization activities to mitigate natural declines.

DRILLING ACTIVITY

	Three months ended December 31, 2017				Three months ended December 31, 2016
	Gross	Net	Success Rate		Gross	Net	Success Rate
Spirit River liquids-rich natural gas	2	1.9	100	%	5	5.0	100	%
Total	2	1.9	100	%	5	5.0	100	%

DRILLING ACTIVITY
	Year ended December 31, 2017				Year ended December 31, 2016
	Gross	Net	Success Rate		Gross	Net	Success Rate
Ellerslie	4	1.6	100	%	—	—	—
Cardium oil	3	3.0	100	%	—	—	—
Spirit River liquids-rich natural gas	26	19.3	100	%	19	12.9	100	%
Total	33	23.9	100	%	19	12.9	100	%

During the fourth quarter of 2017, Bellatrix drilled 2 gross (1.9 net) Spirit River liquids rich natural gas wells. In the year ended December 31, 2017 Bellatrix drilled and/or participated in 26 gross (19.3 net) Spirit River liquids rich natural gas wells, 3 gross (3.0 net) Cardium wells, and 4 gross (1.6 net) non-operated Ellerslie liquids rich natural gas wells. Seven of the wells drilled in the third quarter of 2017 were completed and brought on production in the fourth quarter. The Company continues to focus capital investment in its low cost Spirit River natural gas play and to take advantage of processing capacity at the Alder Flats Plant. Bellatrix’s drilling activity in 2017 was weighted 97% towards liquids rich natural gas wells and 3% towards oil wells.

By comparison, during the fourth quarter of 2016, Bellatrix drilled 5 gross (5.0 net) Spirit River liquids-rich gas wells. In the year ended December 31, 2016, Bellatrix drilled and/or participated in 19 gross (12.9 net) Spirit River liquids-rich gas wells. Bellatrix's drilling activity in 2016 was weighted 100% towards liquids rich natural gas wells.

Bellatrix Exploration Ltd. 4

COMMODITY PRICES

Average Commodity Prices
	Three months ended December 31,				Year ended December 31,
	2017	2016	% Change		2017	2016	% Change
Crude oil:
WTI (US$/bbl)	55.40	49.29	12		50.95	43.32	18
Canadian Light crude blend ($/bbl)	65.68	60.76	8		61.85	52.79	17
Bellatrix’s average realized prices ($/bbl)
Crude oil and condensate	69.64	58.12	20		62.93	48.41	30
NGLs (excluding condensate)	27.68	18.87	47		21.52	13.14	64
Total crude oil and NGLs	36.61	31.08	18		31.61	25.27	25
Crude oil and condensate (including risk management (1))	33.98	57.46	(41	)	30.50	47.81	(36	)
Natural gas:
NYMEX (US$/mmbtu)	2.93	2.98	(2	)	3.11	2.46	26
AECO daily index (CDN$/mcf)	1.69	3.09	(45	)	2.16	2.16	—
AECO monthly index (CDN$/mcf)	1.96	2.81	(30	)	2.43	2.09	16
Bellatrix’s average realized prices ($/mcf)
Natural gas	1.79	3.29	(46	)	2.27	2.27	—
Natural gas (including risk management)	2.70	3.13	(14	)	2.85	2.64	8
Exchange rate (CDN$/US$1.00)	1.2705	1.3347	(5	)	1.2966	1.3241	(2	)

(1) Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.

Alberta natural gas prices faced significant headwinds in the fourth quarter of 2017 compared to the fourth quarter of 2016 but prices increased compared to the third quarter of 2017, given a cold start to the winter heating season. Increased Alberta gas production ran up against export capacity constraints and has producers competing for a flat growth market in Alberta. United States gas prices in the fourth quarter showed some volatility as the winter heating season started strongly in November with NYMEX gas prices trading as high as US$3.18/MMMBtu before a warming trend dropped December prices. Overall, the NYMEX averaged US$2.93/MMBtu in the fourth quarter and averaged US$3.11/MMBtu in 2017, an increase from the 2016 average of US$2.46/MMBtu. Total United States natural gas production continued to grow at a rapid pace throughout 2017 and established new highs for United States domestic production. Total United States natural gas exports (excluding Canada) continued to grow through 2017, attributed to growing liquefied natural gas (“LNG”) shipments and increased exports to Mexico.

Bellatrix’s natural gas sales are priced with reference to the daily or monthly AECO indices. Bellatrix’s natural gas sold has a higher heat content than the industry average, which results in slightly higher realized prices per mcf than the AECO daily index. During the fourth quarter of 2017, the AECO daily reference price decreased by 45% and the AECO monthly reference price decreased by approximately 30% compared to the fourth quarter of 2016. Bellatrix’s natural gas average sales price before commodity price risk management contracts for the fourth quarter of 2017 decreased by 46% to $1.79/mcf compared to $3.29/mcf in the same period in 2016. Bellatrix’s natural gas average price after including commodity price risk management contracts for the three months ended December 31, 2017 averaged $2.70/mcf compared to $3.13/mcf in the comparative 2016 period. Despite the low prices in the second half of the year, the AECO daily reference price was about 26% higher and the AECO monthly reference price was consistent with 2016 indexed prices. Bellatrix’s natural gas average sales price before commodity price risk management contracts for the 2017 year was equal to 2016 at $2.27/mcf. Bellatrix’s natural gas average price after including commodity price risk management contracts for the year ended December 31, 2017 averaged $2.85/mcf compared to $2.64/mcf in 2016.

Bellatrix has diversified its natural gas price exposure through sales contracts that give the Company access to the Dawn, Chicago, and Malin natural gas pricing hubs. This long-term diversification strategy reduces Bellatrix's exposure to AECO pricing on approximately 26% of the Company's forecast 2018 natural gas volumes. In the first quarter of 2018, the Company increased its market diversification strategy into the Chicago and Dawn markets by approximately 15 MMcf/d into each market. The new sales begin November 2018 and continue until October 2020.  Bellatrix has 66.1 MMcf/d of its 2018 natural gas volumes hedged at an average fixed price of approximately $3.06/mcf; representing approximately 40% of forecast 2018 natural gas volumes. In combination, the market diversification sales and fixed price hedges cover approximately 67% of natural gas volumes in 2018 and reduces Bellatrix's exposure to AECO pricing.

Bellatrix Exploration Ltd. 5

Global crude oil prices strengthened in the fourth quarter of 2017 as the Organization of the Petroleum Exporting Countries (“OPEC”) members agreed to extend production cuts to support higher crude prices. This collaborative effort between OPEC and non-OPEC producing countries provided support to oil prices with cuts aimed at stabilizing the global supply/demand balance and reducing robust levels of global crude product inventories. The production cut announcements drove an increase in WTI pricing to close US$60.42/bbl at December 2017, up from the low point in the second quarter of 2017 of US$42.31/bbl.

In the fourth quarter of 2017 Bellatrix realized an average price of $69.64/bbl before commodity price risk management contracts for crude oil and condensate, an increase of 20% from the average price of $58.12/bbl received in the fourth quarter of 2016. WTI crude oil benchmark price increased by 15% between the third and fourth quarters of 2017. The WTI/Canadian Light sweet differential remained in a historically tight range, averaging -US$1.14/bbl for the quarter. During the year ended December 31, 2017, Bellatrix realized an average price for crude oil and condensate of $62.93/bbl before commodity price risk management contracts, an increase of 30% from the average price of $48.41/bbl received in the 2016 year. Bellatrix’s average realized price for NGLs (excluding condensate) increased by 47% to $27.68/bbl during the fourth quarter of 2017, compared to $18.87/bbl received in the comparative 2016 period. NGL pricing in Western Canada improved significantly through the fourth quarter of 2017 given stronger underlying light oil prices and improved individual market conditions for propane and butane products. Cold weather at the start of the fourth quarter of 2017 kept North American propane demand firm, while exports helped materially reduce robust storage levels resulting in much stronger propane prices through the fourth quarter of 2017. Butane prices also firmed materially in the fourth quarter of 2017, both in absolute terms and as a percentage of light oil, given strong gasoline blending demand and export demand. Bellatrix’s average realized price for NGLs (excluding condensate) increased by 64% to $21.52/bbl during the 2017 year, compared to $13.14/bbl received in 2016.

The average CDN$/US$1.00 foreign exchange rate decreased by 5% to 1.2705 for the quarter ended December 31, 2017, compared to an average rate of 1.3347 in the same period of 2016 and decreased by 2% to 1.2966 for the year ended December 31, 2017 from an average rate of 1.3241 in 2016. The Canadian dollar weakened relative to the U.S. dollar in the fourth quarter of 2017, as the US dollar was aided by strong economic data and the approval of the new tax reform bill. Subsequent to December 31, 2017, strong Canadian economic data supported the Bank of Canada's decision to increase interest rates earlier than market expectations, which has resulted in the strengthening of the Canadian dollar relative to the US dollar.

REVENUE

Total revenue of $60.9 million for the three months ended December 31, 2017 decreased by 10% compared to $67.9 million realized in the fourth quarter of 2016. The lower total revenue realized in the fourth quarter of 2017 compared to 2016 was primarily attributable to a 24% decline in realized average commodity prices, offset by a 16% increase in sales volumes in the period. Bellatrix’s total revenue was $249.4 million for the year ended December 31, 2017, an increase of 9% compared to $227.9 million realized in the year ended December 31, 2016. The increase in total revenue in the year ended December 31, 2017 compared to 2016 was a result of a 7% increase in realized average commodity prices as well as a 3% increase in sales volumes. Other income decreased in 2017 as a result of the disposition of certain production facilities in 2016 and working interest in the Alder Flats Plant.

Crude oil and NGL revenue before other income, royalties and commodity price risk management contracts for the three months ended December 31, 2017 increased by 26% to $32.3 million from $25.7 million realized during the same period in 2016. The increase in revenue realized between the periods was the result of an 18% increase in realized crude oil, condensate and NGL prices as well as a 7% increase in associated sales volumes. For the 2017 year, Bellatrix realized crude oil, condensate and NGL revenue before other income, royalties and commodity price risk management contracts of $106.1 million, a 15% increase from $91.9 million realized in 2016. The increase in revenue realized between the years was the result of a 25% increase in average crude oil, condensate and NGL prices, offset partially by a 7% decrease in associated sales volumes between periods.

For the three months and year ended December 31, 2017, total crude oil, condensate and NGL revenues contributed 54% and 43% of petroleum and natural gas sales, respectively, compared to 38% and 42% in the comparable 2016 periods.

Natural gas revenue before other income, royalties and commodity price risk management contracts decreased by 35% in the fourth quarter of 2017 to $27.1 million from $41.6 million during the same period in 2016. This was a result of a 46% decrease in average realized natural gas prices, partially offset by a 20% increase in associated sales volumes between the periods. For the year ended December 31, 2017, natural gas revenue before other income, royalties and commodity price risk management contracts was $137.8 million, an increase of 7% from $128.2 million realized in the 2016 year. The increase in revenue realized was attributable to an 8% increase in natural gas production volumes, as prices remained flat between the 2017 and 2016 years.

Bellatrix Exploration Ltd. 6

Revenue
	Three months ended December 31,		Year ended December 31,
($000s)	2017	2016	2017	2016
Crude oil and condensate	13,089	14,960	51,448	60,546
NGLs (excluding condensate)	19,252	10,752	54,602	31,352
Crude oil and NGLs	32,341	25,712	106,050	91,898
Natural gas	27,073	41,614	137,775	128,226
Petroleum and natural gas sales	59,414	67,326	243,825	220,124
Other income (1)	1,483	581	5,574	7,750
Total revenue	60,897	67,907	249,399	227,874

(1)Other income primarily consists of processing and other third party income.

COMMODITY PRICE RISK MANAGEMENT

The Company has a commodity price risk management policy which permits management to use various commodity price risk management strategies including fixed price contracts, collars, and the purchase of floor price options and other derivative financial instruments and physical delivery sales contracts to reduce the impact of price volatility for a maximum of 36 months beyond the transaction date. The program is designed to provide price protection on a portion of the Company’s future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Company seeks to provide a measure of stability to adjusted funds flow, as well as to ensure Bellatrix realizes positive economic returns from its capital development and acquisition activities. The Company plans to continue its commodity price risk management strategies, focusing on maintaining sufficient cash flow to fund Bellatrix’s capital expenditure program. Any remaining production is realized at market prices.

As at December 31, 2017, the Company has entered into commodity price risk management arrangements as follows:

Natural gas fixed price arrangements

Type		Period	Volume	Price			Index
Natural gas fixed	Financial	January 1, 2018 to December 31, 2018	75,000 GJ/d	$	2.69	CDN	AECO

Natural gas basis differential arrangements

Type		Period	Volume	Price			Index
Natural gas	Financial	April 1, 2018 to October 31, 2018	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX
Natural gas	Financial	April 1, 2019 to October 31, 2020	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX

NGL fixed differential arrangements

Type		Period	Volume	Fixed Differential	Index
Propane	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	47% of NYMEX WTI	OPIS Conway Propane

Crude oil fixed price arrangements

Type		Period	Volume	Price			Index
Oil	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	$	70.14	CDN	WTI - NYMEX

When the Company has outstanding commodity price risk management contracts at a reporting date, the fair value, or mark-to-market value, of these contracts is reflected in its financial statements as an unrealized asset or liability. Fair value is based on the estimated amount that would have been received or paid, after any adjustments for credit risk, to settle the contracts as at the reporting date and would differ from what would eventually be realized. Changes in the fair value of the commodity contracts are recognized in the Company’s Statements of Profit (Loss) and Comprehensive Income (Loss).

Bellatrix Exploration Ltd. 7

The following are summaries of the gain (loss) on commodity price risk management contracts for the three months ended December 31, 2017 and 2016:

Commodity contracts
Three months ended December 31, 2017
($000s)	Crude Oil		Natural Gas	NGL's		Total
Realized cash gain (loss) on contracts	—		13,848	(2,324	)	11,524
Unrealized gain (loss) on contracts (1)	(1,550	)	7,246	1,630		7,326
Total gain (loss) on commodity contracts	(1,550	)	21,094	(694	)	18,850

(1) Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts during the period. 

Commodity contracts
Three months ended December 31, 2016
($000s)	Crude Oil		Natural Gas		NGL's	Total
Realized cash gain (loss) on contracts	(170	)	(2,070	)	—	(2,240	)
Unrealized gain (loss) on contracts (1)	219		(25,525	)	—	(25,306	)
Total gain (loss) on commodity contracts	49		(27,595	)	—	(27,546	)

(1) Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts during the period. 

The following are summaries of the gain (loss) on commodity price risk management contracts for years ended December 31, 2017 and 2016:

Commodity contracts
Year ended December 31, 2017
($000s)	Crude Oil		Natural Gas	NGL's		Total
Realized cash gain (loss) on contracts	—		35,048	(3,724	)	31,324
Unrealized gain (loss) on contracts (1)	(1,550	)	49,706	(2,918	)	45,238
Total gain (loss) on commodity contracts	(1,550	)	84,754	(6,642	)	76,562

 (1) Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts during the period. 

Commodity contracts
Year ended December 31, 2016
($000s)	Crude Oil		Natural Gas		NGL's	Total
Realized cash gain (loss) on contracts	(754	)	20,646		—	19,892
Unrealized gain (loss) on contracts (1)	390		(29,915	)	—	(29,525	)
Total gain (loss) on commodity contracts	(364	)	(9,269	)	—	(9,633	)

 (1) Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts during the period. 

ROYALTIES

Bellatrix pays royalties to the respective provincial governments and landowners where it operates. Each province that Bellatrix operates in has established a separate and distinct royalty regime which impacts Bellatrix’s average corporate royalty rate. The Company’s royalties are primarily paid in the province of Alberta.

In 2017, the Government of Alberta implemented the Modernized Royalty Framework (“MRF”) which included, for conventional activity, no changes to the royalty structure of wells drilled prior to 2017 for a 10 year period from the MRF implementation date and improved transparency concerning disclosure of royalty information. The MRF includes the replacement of royalty credits and holidays on conventional wells through a drilling and completion cost allowance based on a revenue minus cost framework, a post-payout royalty rate based on commodity prices, and the reduction of royalty rates for mature wells. For wells drilled prior to 2017

Bellatrix Exploration Ltd. 8

in Alberta, crown royalty rates are based on reference commodity prices, production levels and well depths, and are offset by certain incentive programs.

In the fourth quarter of 2017, the Company incurred $6.1 million in royalties, compared to $7.7 million in the fourth quarter of 2016. As a percentage of petroleum and natural gas sales revenue (after transportation costs), royalties were 11% in the three months ended December 31, 2017, and 12% in the comparative 2016 period. Reduced average corporate royalty rates period over period reflect the impact from dispositions of higher royalty rate properties and the changes in commodity prices.

For the year ended December 31, 2017, royalties incurred totaled $24.0 million compared to $18.6 million incurred in the 2016 year. Overall royalties as a percentage of revenue (after transportation costs) in 2017 were 11% compared to 9% in 2016. Higher average corporate royalties in 2017 reflect the impact from higher crude oil and NGL commodity prices, as well as decreased gas cost allowance (“GCA”) credits in 2017 resulting from the infrastructure and facilities dispositions in 2016.

Royalties by Commodity Type
	Three months ended December 31,		Year ended December 31,
($000s, except where noted)	2017	2016	2017	2016
Crude oil, condensate, and NGLs	5,804	5,716	22,365	19,303
$/bbl	6.57	6.91	6.67	5.31
Average crude oil, condensate and NGL royalty rate (%)	18	22	21	21
Natural Gas	263	2,023	1,596	(667	)
$/mcf	0.02	0.16	0.03	(0.01	)
Average natural gas royalty rate (%)	1	5	1	(1	)
Total	6,067	7,739	23,961	18,636
Total $/boe	1.78	2.64	1.78	1.43
Average total royalty rate (%)	11	12	11	9

Royalties by Type
	Three months ended December 31,		Year ended December 31,
($000s)	2017	2016	2017	2016
Crown and IOGC royalties	3,293	2,167	15,489	7,132
Freehold & GORR	2,774	5,572	8,472	11,504
Total	6,067	7,739	23,961	18,636

The Company’s crude oil, condensate, NGL, and natural gas royalties were impacted by wells drilled on lands with higher Indian Oil and Gas Canada (“IOGC”) royalty and dispositions of properties with higher freehold and gross overriding royalty ("GORR") rates in 2016 and 2017.

EXPENSES

	Three months ended December 31,			Year ended December 31,
($000s)	2017		2016	2017	2016
Production	26,657		31,021	111,816	113,589
Transportation	6,537		3,143	23,549	12,108
Royalties	6,067		7,739	23,961	18,636
General and administrative	8,761		5,038	29,377	19,919
Interest and financing charges (1)	9,628		11,201	37,953	46,350
Share-based compensation	(630	)	1,113	532	3,784

(1) Excludes financing charges in relation to the Company’s accretion of decommissioning liabilities, unrealized foreign exchange gain (loss), and realized foreign exchange gain (loss).

Bellatrix Exploration Ltd. 9

EXPENSES PER BOE

	Three months ended December 31,			Year ended December 31,
($/boe)	2017		2016	2017	2016
Production	7.81		10.57	8.31	8.70
Transportation	1.92		1.07	1.75	0.93
Royalties	1.78		2.64	1.78	1.43
General and administrative	2.57		1.72	2.18	1.53
Interest and financing charges (1)	2.82		3.82	2.82	3.55
Share-based compensation	(0.18	)	0.38	0.04	0.29

(1) Excludes financing charges in relation to the Company’s accretion of decommissioning liabilities, unrealized foreign exchange gain (loss), and realized foreign exchange gain (loss).

PRODUCTION EXPENSES

Production expenses for the three months and year ended December 31, 2017 totaled $26.7 million ($7.81/boe) and $111.8 million ($8.31/boe) compared to $31.0 million ($10.57/boe) and $113.6 million ($8.70/boe) in the comparative 2016 periods, respectively.Production expenses in the fourth quarter of 2017 remained consistent with the third quarter of 2017 of $27.2 million ($7.84/boe).The variance in production expense on a per boe basis between the fourth quarter and year ended December 31, 2017 and the comparative periods in 2016, are a result of continued cost suppression activity focused on increased operational efficiencies, field optimization work, and increased competitive pricing of contract services. Bellatrix executed a strong optimization program in 2017, resulting in mitigation of downtime, moderating base declines and reducing production expenses. Production expenditures for 2017 averaged $8.31/boe, below the revised full year guidance of $8.50/boe.

Bellatrix has set a production expenditure guidance range of $7.50/boe to $7.90/boe for 2018, which represents a 5% to 10% decrease on a per unit basis compared to the $8.31/boe production expenses incurred in the 2017 year. Completion of Phase 2 of the Alder Flats Plant will add an incremental 30 MMcf/d ownership capacity net to Bellatrix's 25% working interest, and forecasted 2018 production is expected to deliver a reduction in operating costs.

Production Expenses by Commodity Type
	Three months ended December 31,		Year ended December 31,
($000s, except where noted)	2017	2016	2017	2016
Crude oil, condensate and NGLs	7,047	8,545	28,143	30,977
$/bbl	7.98	10.33	8.39	8.52
Natural gas	19,610	22,476	83,673	82,612
$/mcf	1.29	1.78	1.38	1.46
Total production expenses	26,657	31,021	111,816	113,589
Total $/boe	7.81	10.57	8.31	8.70

TRANSPORTATION

Transportation expenses for the three months and year ended December 31, 2017 were $6.5 million ($1.92/boe) and $23.5 million ($1.75/boe) compared to $3.1 million ($1.07/boe) and $12.1 million ($0.93/boe) in the same periods in 2016, respectively. The increase in transportation costs per boe in the year ended December 31, 2017 compared to the same period of 2016 was primarily due to secured transportation agreements previously entered into for Phase 2 of the Alder Flats Plant which were based on the initial expected start-up date for the expansion in 2017.  Due to the deferred start-up of Phase 2 relative to initial plans, Bellatrix maintains excess transportation capacity for the months leading up to its expected start up in the second quarter of 2018.  Upon completion of the Phase 2 plant expansion, Bellatrix expects to utilize the additional transportation capacity thereby reducing transportation costs on a per boe basis.

Bellatrix Exploration Ltd. 10

OPERATING NETBACK

Operating Netback – Corporate
	Three months ended December 31,				Year ended December 31,
($/boe)	2017		2016		2017		2016
Total Revenue (1)	17.85		23.15		18.53		17.45
Production	(7.81	)	(10.57	)	(8.31	)	(8.70	)
Transportation	(1.92	)	(1.07	)	(1.75	)	(0.93	)
Royalties	(1.78	)	(2.64	)	(1.78	)	(1.43	)
Operating netback(2)	6.34		8.87		6.69		6.39
Risk management gain (loss)(3)	3.38		(0.76	)	2.33		1.52
Operating netback after risk management	9.72		8.11		9.02		7.91

(1)Total Revenue includes petroleum and natural gas sales and other income.

(2)Operating netbacks is considered to be a non-GAAP measure. Operating netbacks are calculated by subtracting royalties, transportation, and production expenses from total revenue.

(3)Risk management includes realized gains or losses on commodity contracts and excludes unrealized gains or losses on commodity contracts.

During the three months ended December 31, 2017, the Company’s corporate operating netback, before commodity risk management contracts, decreased by 29% to $6.34/boe compared to $8.87/boe in the fourth quarter of 2016. The reduced netback realized in the fourth quarter of 2017 was primarily the result of 24% lower average realized combined commodity prices offset by a 16% increase in sales volumes and increased transportation expenses and is partially offset by decreased production and royalty expenses. After including commodity risk management contracts, the corporate operating netback for the three months ended December 31, 2017 was $9.72/boe compared to $8.11/boe in the fourth quarter of 2016.

For the year ended December 31, 2017, the corporate operating netback before commodity risk management contracts was $6.69/boe, an increase of 5% compared to $6.39/boe in 2016. The increased netback realized in 2017 was primarily the result of 7% higher average realized combined commodity prices and decreased production expenses, partially offset by increased transportation and royalty expenses. After including commodity risk management contracts, the corporate operating netback for the year ended December 31, 2017 was $9.02/boe compared to $7.91/boe in 2016.

Operating Netback – Crude Oil, Condensate, and NGLs
	Three months ended December 31,				Year ended December 31,
($/bbl)	2017		2016		2017		2016
Sales	36.61		31.08		31.61		25.27
Production	(7.98	)	(10.33	)	(8.39	)	(8.52	)
Transportation	(4.54	)	(0.27	)	(3.73	)	(0.35	)
Royalties	(6.57	)	(6.91	)	(6.67	)	(5.31	)
Operating netback (1)	17.52		13.57		12.82		11.09
Risk management gain (loss) (2)	(2.63	)	(0.21	)	(1.11	)	(0.21	)
Operating netback after risk management	14.89		13.36		11.71		10.88

(1)Operating netbacks is considered to be a non-GAAP measure. Operating netbacks are calculated by subtracting royalties, transportation, and production expenses from total revenue.

(2)Risk management includes realized gains or losses on commodity contracts and excludes unrealized gains or losses on commodity contracts.

The operating netback before commodity price risk management contracts for crude oil, condensate and NGLs during the fourth quarter of 2017 averaged $17.52/bbl, an increase of 29% from the $13.57/bbl realized during the same period in 2016. The increase between the periods was primarily a result of 18% stronger crude oil, condensate and NGL commodity prices and a decrease in production and royalty expenses, offset partially by increased transportation expenses. After including commodity price risk management contracts, the operating netback for crude oil, condensate, and NGLs for the three months ended December 31, 2017 was $14.89/bbl compared to $13.36/bbl in the same period in 2016.

The operating netback for crude oil, condensate, and NGLs increased by 16% to $12.82/bbl for the year ended December 31, 2017, from $11.09/bbl realized in the 2016 year. The higher netback was primarily attributable to 25% stronger crude oil, condensate, and NGL commodity prices and decreased production expenses, partially offset by higher transportation and royalty expenses. After

Bellatrix Exploration Ltd. 11

including commodity price risk management contracts, the operating netback for crude oil, condensate, and NGLs for the year ended December 31, 2017 was $11.71/bbl compared to $10.88/bbl in 2016.

Operating Netback – Natural Gas
	Three months ended December 31,				Year ended December 31,
($/mcf)	2017		2016		2017		2016
Sales	1.79		3.29		2.27		2.27
Production	(1.29	)	(1.78	)	(1.38	)	(1.46	)
Transportation	(0.17	)	(0.23	)	(0.18	)	(0.19	)
Royalties	(0.02	)	(0.16	)	(0.03	)	0.01
Operating netback(1)	0.31		1.12		0.68		0.63
Risk management gain (loss)(2)	0.91		(0.16	)	0.58		0.37
Operating netback after risk management	1.22		0.96		1.26		1.00

(1)Operating netbacks is considered to be a non-GAAP measure. Operating netbacks are calculated by subtracting royalties, transportation, and production expenses from total revenue. The detailed calculations of operating netbacks are found in the MD&A.

(2)Risk management includes realized gains or losses on commodity contracts and excludes unrealized gains or losses on commodity contracts.

The operating netback for natural gas before commodity price risk management contracts during the fourth quarter of 2017 of $0.31/mcf was 72% lower than the $1.12/mcf recorded in the same period in 2016. The reduction to the realized netback between the fourth quarters of 2017 and 2016 was driven by a 46% decrease in natural gas prices offset by reductions in production, transportation and royalty expenses. After including commodity risk management contracts, the operating netback for natural gas for the fourth quarter of 2017 was $1.22/mcf compared to $0.96/mcf in the same period in 2016.

For the year ended December 31, 2017, the operating netback for natural gas was $0.68/mcf, an increase of 8% from $0.63/mcf realized in 2016. The higher netback between the years reflected flat prices, lower production and transportation expenses, partially offset by higher royalty expenses. After including commodity risk management contracts, the operating netback for natural gas for the year ended December 31, 2017 was $1.26/mcf compared to $1.00/mcf in the 2016 year.

GENERAL AND ADMINISTRATIVE

Bellatrix incurred higher gross general and administrative (“G&A”) expenses (before capitalized G&A and recoveries) in the fourth quarter and the year ended December 31, 2017 when compared to the same periods of 2016 by 45% and 28%, respectively. Net G&A expenses (after capitalized costs and recoveries) for the three months and year ended December 31, 2017 were $8.8 million ($2.57/boe) and $29.4 million ($2.18/boe) compared to $5.0 million ($1.72/boe) and $19.9 million ($1.53/boe) in the comparative 2016 periods, an increase of 74% and 47%, respectively. The overall increase to net G&A for the year ended December 31, 2017 compared to the same period in 2016 was primarily attributable to an increase in gross G&A expenses related to executive changes.

General and Administrative Expenses
	Three months ended December 31,				Year ended December 31,
($000s, except where noted)	2017		2016		2017		2016
Gross expenses	12,210		8,428		43,638		33,547
Capitalized	(1,770	)	(1,577	)	(7,594	)	(7,027	)
Recoveries	(1,679	)	(1,813	)	(6,667	)	(6,601	)
G&A expenses	8,761		5,038		29,377		19,919
G&A expenses, per unit ($/boe)	2.57		1.72		2.18		1.53

INTEREST AND FINANCING CHARGES

For the three months and year ended December 31, 2017, Bellatrix recorded $9.6 million ($2.82/boe) and $38.0 million ($2.82/boe) of interest and financing charges related to the Credit Facilities, Convertible Debentures and Senior Notes (each as defined below), compared to $11.2 million ($3.82/boe) and $46.4 million ($3.55/boe) during the same periods in 2016, respectively.

Bellatrix Exploration Ltd. 12

The decrease in interest and financing charges in the three months and year ended December 31, 2017 compared to 2016 was primarily attributed to reduced interest expense resulting from the material reduction in amounts outstanding on Credit Facilities throughout 2016 and 2017.

Interest and Financing Charges(1)
	Three months ended December 31,		Year ended December 31,
($000s, except where noted)	2017	2016	2017	2016
Interest on Credit Facilities	779	2,124	2,194	13,516
Interest on Convertible Debentures	1,383	1,313	5,381	2,063
Interest on Senior Notes	7,466	7,764	30,378	30,771
Interest and financing charges	9,628	11,201	37,953	46,350
Interest and financing charges ($/boe)	2.82	3.82	2.82	3.55

(1) Excludes financing charges in relation to the Company’s accretion of decommissioning liabilities, unrealized foreign exchange gain (loss), and realized foreign exchange gain (loss).

Bellatrix’s total net debt at December 31, 2017 of $420.8 million represents an increase of $24.6 million from the December 31, 2016 level of $396.2 million. Total net debt at December 31, 2017 of $420.8 million included $52.1 million of Credit Facilities, $39.4 million of Convertible Debentures (liability component), $305.4 million of Senior Notes (includes $22.1 million of unrealized foreign exchange gain recognized on the mark-to-market of the United States dollar denominated Senior Notes in the year ended December 31, 2017), and an adjusted working capital deficiency of $23.9 million.

Reconciliation of Total Liabilities to Total Net Debt
	As at December 31,
($000s)	2017		2016
Total liabilities per financial statements	566,901		590,312
Current liabilities (excluding current Credit Facilities amounts )	(100,489	)	(118,695	)
Decommissioning liabilities	(58,687	)	(62,844	)
Other deferred liabilities	(7,402	)	(24,873	)
Risk management contract liability	(3,422	)	(2,646	)
Long term loans receivable	—		(8,775	)
Adjusted working capital
Current assets	(81,291	)	(54,979	)
Current liabilities	100,489		137,838
Current Credit Facilities amounts	—		(19,143	)
Current portion of other deferred liabilities	(20,790	)	(26,064	)
Current portion of decommissioning liability	(1,924	)	—
Current portion of risk management contract asset	31,910		—
Current portion of risk management contract liability	(4,468	)	(13,936	)
	23,926		23,716
Total net debt (1)	420,827		396,195
Convertible Debentures (liability component)	(39,426	)	(37,420	)
Net debt (1)	381,401		358,775

(1)Total net debt is considered to be a capital performance measure and therefore may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, long-term risk management contract liabilities, decommissioning liabilities, and the deferred tax liability. Total net debt includes the adjusted working capital deficiency, long term loans receivable, Convertible Debentures (liability component), current Credit Facilities, Credit Facilities and Senior Notes. The adjusted working capital deficiency is a non-GAAP measure calculated as net working capital deficiency excluding current risk management assets and liabilities, current portion of other deferred liabilities, current portion of decommissioning liability and the current Credit Facilities. Net debt excludes the liability component of the Convertible Debentures.

Bellatrix Exploration Ltd. 13

SHARE-BASED COMPENSATION

Bellatrix has an Award Incentive Plan (the “Award Plan”) where the Company may grant restricted awards (“RAs”) and performance awards (“PAs”) to officers, employees, and other service providers. Awards under the Award Plan may be settled in cash, in common shares of the Company, or a combination thereof. In the case of PAs, settlement is subject to a “payout multiplier” (the payout multiplier shall be based on such corporate performance measures as determined by the Board of Directors (or the Compensation Committee) of the Company) and may range between zero and two times. Under Bellatrix’s Deferred Share Unit Plan, the Company may grant deferred share units ("DSUs") to non-employee directors.

Effective July 1, 2017, the Company consolidated its common shares on the basis of 1 new common share for every 5 old common shares outstanding. The number of outstanding share options, DSUs, RAs and PAs have also been adjusted proportionately. The corresponding exercise prices have increased by the same ratio.

The following table summarizes the DSUs, RAs, and PAs movement for the year ended December 31, 2017:

	Share Options		DSUs		RAs		PAs
Balance, December 31, 2016	2,573,024		377,667		426,395		303,335
Granted	185,000		260,381		652,740		370,000
Exercised	(877,956	)	(120,150	)	(175,833	)	(61,920	)
Forfeited	(257,936	)	—		(79,815	)	(38,360	)
Balance, December 31, 2017	1,622,132		517,898		823,487		573,055

The following table provides a summary of the Company’s share-based compensation plans for the three months and year ended December 31, 2017 and December 31, 2016.

	Three months ended December 31,			Year ended December 31,
($000s)	2017		2016	2017		2016
Share options expense	159		635	1,074		2,565
DSUs expense (recovery)	(694	)	94	(583	)	834
RAs expense (recovery)	(24	)	254	178		241
PAs expense (recovery)	(71	)	130	(137	)	144
Share-based compensation expense (recovery)	(630	)	1,113	532		3,784

Lower share-based compensation expense in the year ended December 31, 2017 compared to the year ended December 31, 2016 is a result of a decrease in the Company’s share price offset by amortization of awards issued in 2017.

DEPLETION AND DEPRECIATION

Depletion and Depreciation

Depletion and depreciation expense for the three months and year ended December 31, 2017, was $27.8 million ($8.15/boe) and $120.7 million ($8.96/boe) compared to $26.9 million ($9.16/boe) and $136.5 million ($10.45/boe), recognized in the comparative 2016 periods, respectively. The decrease in the Company’s depletion and depreciation expense, on a per boe basis between the periods, can be attributed to the lower capital cost base stemming from the non-core asset dispositions in 2017 and the fourth quarter of 2016 and increased reserve base in 2017 from the 2017 successful execution of the drilling capital program.

For the year ended December 31, 2017, Bellatrix has included a total of $832 million (2016: $950 million) for future development costs in the depletion calculation and excluded from the depletion calculation a total of $46.6 million (2016: $46.0 million) for estimated salvage in the depletion and depreciation calculations.

Depletion and Depreciation
	Three months ended December 31,		Year ended December 31,
($000s, except where noted)	2017	2016	2017	2016
Depletion and Depreciation	27,797	26,886	120,652	136,518
Depletion and Depreciation per unit ($/boe)	8.15	9.16	8.96	10.45

Bellatrix Exploration Ltd. 14

IMPAIRMENT LOSS (REVERSAL) AND (GAIN) LOSS ON DISPOSITIONS

Impairment Loss (Reversal) and (Gain) Loss on Dispositions
	Three months ended December 31,				Year ended December 31,
($000s, except where noted)	2017		2016		2017	2016
Impairment loss (reversal) - E&E and PP&E	13,150		(264,000	)	13,150	(264,000	)
(Gain) loss on dispositions (1)	(126	)	171,584		56,672	170,667
Impairment loss (reversal) and (gain) loss on dispositions	13,024		(92,416	)	69,822	(93,333	)

(1) Refer to the “Capital Expenditures” section in the MD&A for further discussion on (gain) loss on dispositions

Impairment Loss (Reversal)

Exploration & Evaluation Assets

As at December 31, 2016 and 2017, Bellatrix did not identify indicators of impairment or impairment reversal with respect to its Exploration and Evaluation (“E&E”) assets.

Property, Plant and Equipment

Bellatrix performed an assessment of possible indicators of impairment or impairment reversal on all of the Company’s Cash Generated Units ("CGUs"). At December 31, 2017, impairment indicators were identified for the Company’s non-core North Alberta CGU and non-core South Alberta CGU, primarily as a result of a lack of active capital development plans in the CGUs. No impairment indicators were identified in the Company’s core Central Alberta CGU in 2017.

For the year ended December 31, 2017, a non-cash impairment loss of $12.2 million was recognized in the Company’s non-core North Alberta CGU. The estimated recoverable amount of the North Alberta CGU as at December 31, 2016 was $5.3 million. A non-cash impairment loss of $1.0 million was recognized in the Company’s non-core South Alberta CGU. The estimated recoverable amount of the South Alberta CGU was $1.4 million.

The recoverable amount of the North Alberta and South Alberta CGUs as at December 31, 2017 was determined using a value in use ("VIU") approach, as Bellatrix determined that VIU was greater than fair value less costs to sell ("FVLCS"). VIU was calculated as the net present value of the before-tax cash flows from proved plus probable oil and gas reserves of each CGU based on reserves estimated by Bellatrix’s independent reserve evaluator at December 31, 2017, adjusted for the net present value of the before-tax abandonment and reclamation costs on proved plus probable undeveloped oil and gas reserves.

The value in use of each CGU was based on before-tax discount rates ranging from 15-20%.

A 1% increase to the discount rates applied in the impairment calculation for the North Alberta CGU and South Alberta CGU would result in an increase in impairment loss of approximately $0.3 million and $0.1 million, respectively for the year ended December 31, 2017, whereas a 1% decrease to the discount rates applied would result in a corresponding decrease to the impairment loss recognized.

For the year ended December 31, 2016, a non-cash impairment reversal of $307.0 million was recognized in the Company’s core Central Alberta CGU, representing the maximum amount of impairment reversal able to be taken based on prior impairment loss less depletion and dispositions. The estimated recoverable amount of the Central Alberta CGU as at December 31, 2016 was $1.3 billion. A non-cash impairment loss of $43 million was recognized in the Company's non-core South Central CGU. The estimated recoverable amount of the South Central CGU was $64 million. No impairment was recognized in the Company's non-core North Alberta and South Alberta CGUs in 2016.

FOREIGN EXCHANGE

Bellatrix incurs gains and losses in relation to the foreign currency translation of its United States dollar denominated Senior Notes. The Senior Notes are translated from the United States dollar to Canadian dollar using the closing foreign exchange rate for the period. Unrealized foreign exchange gains or losses are included in earnings in the period related to the translation of the outstanding balance of the Senior Notes at the end of the period. Realized foreign exchange gains and losses are recognized as the Senior Notes and other minor foreign currency based transactions are translated and settled during the period.

Bellatrix Exploration Ltd. 15

	Three months ended December 31,				Year ended December 31,
($000s)	2017		2016		2017		2016
Realized gain (loss) on foreign exchange	(313	)	(228	)	(797	)	277
Unrealized gain (loss) on foreign exchange (1) (2)	(364	)	(7,411	)	22,165		9,939
Unrealized gain (loss) on foreign exchange contracts	212		1,005		(3,867	)	(2,021	)
Gain (loss) on foreign exchange	(465	)	(6,634	)	17,501		8,195

(1) Exchange rate (CDN$/US$1.00) at December 31, 2017 was 1.2518.

(2) Exchange rate (CDN$/US$1.00) at December 31, 2016 was 1.3427.

For the three months ended December 31, 2017, Bellatrix recorded a foreign exchange loss of $0.5 million (2016: $6.6 million loss) due to the impact of the change in the CDN$/US$ exchange rate at December 31, 2017 compared to September 30, 2017 (CDN$/US$1.00 was 1.251 at September 30, 2017) on the Company’s United States dollar denominated Senior Notes. The change in rate resulted in an unrealized loss of $0.4 million in the three months ended December 31, 2017 (2016: $7.4 million loss), partially offset by the change in the fair value of its United States foreign exchange forward contract which resulted in an unrealized gain of $0.2 million (2016: 1.0 million gain).

For the year ended December 31, 2017, Bellatrix recorded a foreign exchange gain of $17.5 million (2016: $8.2 million gain). This was due to the impact of the change in the CDN$/US$ exchange rate at December 31, 2017 compared to December 31, 2016 on the Company’s United States dollar denominated Senior Notes. The change in rate resulted in an unrealized gain of $22.2 million in the year ended December 31, 2017 (2016: $9.9 million gain), partially offset by the change in the fair value of its United States foreign exchange forward contract which resulted in an unrealized loss of $3.9 million (2016 $2.0 million loss).

The Company may utilize foreign exchange derivative contracts to manage foreign exchange risks to maintain cash flow stability. Foreign exchange derivative transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors. The aggregate amount hedged under all foreign exchange derivative contracts is limited to the outstanding principal amount of the Senior Notes and the term of foreign exchange contracts is limited to the remaining term of the related Senior Notes.

As at December 31, 2017, the Company had the following United States foreign exchange forward purchase contracts outstanding:

Type	Value Date	Notional Amount ($000s USD)		Foreign Exchange Rate		Settlement ($000s CDN)
Fixed	May 14, 2020	$	32,500	$	1.3076	$	42,497
Fixed	May 14, 2020	$	30,000	$	1.3080	$	39,240

INCOME TAXES

Deferred income taxes arise from differences between the accounting and tax basis of the Company’s assets and liabilities. For the year ended December 31, 2017, the Company recognized a deferred income tax expense of $15.4 million, compared to a recovery of $6.9 million during 2016. The change in the deferred income tax expense recognized in 2017 compared to the deferred tax recovery recognized in 2016 was primarily attributable to the completion of the non-core property disposition in the second quarter of 2017. At December 31, 2017 the Company had a total deferred tax asset balance of $48.3 million. The Company recognized a net deferred tax asset based on the independently evaluated reserve report as cash flows are expected to be sufficient to realize the deferred tax asset. The Company has not recognized a deferred tax asset for the deductible temporary difference associated with $163.4 million (2016: $nil) of Canadian resource pools that are restricted through successor rules and $5.2 million (2016: $14.6 million) of unrealized allowable capital losses on marketable securities and USD denominated Senior Notes.

Bellatrix Exploration Ltd. 16

At December 31, 2017, Bellatrix had approximately $1.35 billion in tax pools available for deduction against future income as follows:

Tax Pools

		December 31,	December 31,
($000s)	Rate %	2017	2016
Intangible resource pools:
Canadian exploration expenses	100	79,500	114,600
Canadian development expenses	30	611,500	705,200
Canadian oil and gas property expenses	10	70,500	104,600
Foreign resource expenses	10	600	600
Alberta non-capital losses greater than Federal non-capital losses	(Alberta) 100	16,400	16,400
Undepreciated capital cost (1)	6 – 100	413,500	344,500
Non-capital losses (expire through 2033)	100	144,100	144,100
Financing costs	20 Straight-Line	14,900	21,900
		1,351,000	1,451,900

(1) Approximately $380 million of undepreciated capital cost pools are class 41, which is claimed at a 25% rate.

NET PROFIT (LOSS)

For the three months ended December 31, 2017, Bellatrix recognized a net loss of $13.1 million ($0.26 per basic share and diluted share), compared to a net profit of $23.1 million ($0.47 per basic share and diluted share) in the fourth quarter of 2016. The decrease in net profit (loss) recorded in the fourth quarter of 2017 compared to the same period in 2016 was primarily the result of a non-cash impairment reversal recognized in the fourth quarter of 2016 of $264 million with no equivalent reversals in 2017 offset partially by a loss on property disposition recognized in the fourth quarter of 2016 with no equivalent costs in 2017 and an increase in realized and unrealized gain on commodity contracts in 2017.

For the year ended December 31, 2017, Bellatrix recognized a net loss of $91.4 million ($1.85 per basic and diluted share), compared to a net loss of $26.7 million ($0.62 per basic share and diluted share) in the same period in 2016. The increase in net loss recorded in 2017 compared to 2016 was primarily the result of a non-cash impairment reversal recognized in the year ended December 31, 2016 with no equivalent reversals in 2017, partially offset by a decrease in the loss on property dispositions, an increase in revenue from improved commodity prices and sales volumes and an increase in realized and unrealized gain on commodity contracts in 2017.

CASH FLOW FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW

As detailed previously in this MD&A, adjusted funds flow is a capital performance measure that does not have any standardized meaning under GAAP. Bellatrix’s method of calculating adjusted funds flow may differ from that of other companies, and accordingly, may not be comparable to measures used by other companies. Bellatrix considers adjusted funds flow to be a key measure of operating performance as it demonstrates Bellatrix's ability to generate the necessary funds for sustaining capital, future growth through capital investment, and to repay debt. Management believes that such a measure provides an insightful assessment of Bellatrix's operations on a continuing basis by eliminating certain non-cash charges and actual settlements of decommissioning liabilities, the extent and timing of which, in the opinion of Management, is discretionary. Adjusted funds flow is not a standardized measure and therefore may not be comparable with the calculation of similar measures by other entities.

Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow
	Three months ended December 31,			Year ended December 31,
($000s)	2017	2016		2017	2016
Cash flow from operating activities	13,425	17,114		55,210	37,546
Decommissioning costs incurred	1,255	606		2,758	2,927
Change in non-cash working capital	1,020	(9,283	)	272	443
Adjusted funds flow	15,700	8,437		58,240	40,916

Bellatrix’s cash flow from operating activities for the three months ended December 31, 2017 decreased by 22% to $13.4 million ($0.27 per basic share and diluted share) from $17.1 million ($0.35 per basic share and diluted share) generated in the fourth

Bellatrix Exploration Ltd. 17

quarter of 2016. The decrease in cash flow from operating activities between the fourth quarters of 2016 and 2017 was mainly attributable to change in non-cash working capital and decreased revenue in the quarter, offset partially by increased realized gain on commodity contracts and decreased production and royalty expenses. Bellatrix’s cash flow from operating activities for the year ended December 31, 2017 increased by 47% to $55.2 million ($1.12 per basic and diluted share) from $37.5 million ($0.96 per basic and diluted share) generated during 2016. The increase in cash flow from operating activities between 2016 and 2017 was principally due to increased revenue due to a 7% increase in realized prices, a 3% increase in sales volumes and an increase in realized gain on commodity contracts. This was partially offset by increased royalty, transportation and general and administrative expenses.

Bellatrix generated adjusted funds flow of $15.7 million ($0.32 per basic share and diluted share) in the fourth quarter of 2017, an increase of 86% from $8.4 million ($0.17 per basic share and diluted share) generated in the comparative 2016 period. The increase in adjusted funds flow between 2016 and 2017 was principally due to a 16% increase in sales volumes, a decrease in production expenses and an increase in the realized gains on commodity contracts, offset partially by an increase in transportation and general and administrative expenses as well as a 6% decrease in sales price. Bellatrix generated adjusted funds flow of $58.2 million ($1.18 per basic share and diluted share) in the year ended December 31, 2017, an increase of 42% from $40.9 million ($0.88 per basic and diluted share) generated in 2016. The increase in adjusted funds flow between 2016 and 2017 was principally due to increased revenue due to a 7% increase in realized prices, a 3% increase in sales volumes and an increase in realized gain on commodity contracts. This was partially offset by increased royalty, transportation and general and administrative expenses.

Bellatrix maintains a commodity price risk management program to provide a measure of stability to adjusted funds flow. Unrealized mark–to–market gains or losses are non-cash adjustments to the fair market value of the contract over its entire term and are included in the calculation of net profit (loss).

Cash Flow from Operating Activities, Adjusted Funds Flow, and Net Profit (Loss)
	Three months ended December 31,			Year ended December 31,
($000s, except per share amounts)	2017		2016	2017		2016
Cash flow from operating activities	13,425		17,114	55,210		37,546
Basic   ($/share)	0.27		0.35	1.12		0.88
Diluted ($/share)	0.27		0.35	1.12		0.88
Adjusted funds flow	15,700		8,437	58,240		40,916
Basic   ($/share)	0.32		0.17	1.18		0.96
Diluted ($/share)	0.32		0.17	1.18		0.96
Net profit (loss)	(13,053	)	23,085	(91,363	)	(26,668	)
Basic   ($/share)	(0.26	)	0.47	(1.85	)	(0.62	)
Diluted ($/share)	(0.26	)	0.47	(1.85	)	(0.62	)

CAPITAL EXPENDITURES

In 2017, Bellatrix’s strategic priority continued to be focused on profitable resource development in the Spirit River liquids rich play while maintaining financial strength and liquidity. During the three months ended December 31, 2017, Bellatrix invested $25.8 million in exploration and development projects, compared to $24.6 million in the same period in 2016. During the year ended December 31, 2017, Bellatrix invested $120.7 million in exploration and development projects, compared to $78.7 million in the same period in 2016.

Bellatrix Exploration Ltd. 18

Capital Expenditures
	Three months ended December 31,				Year ended December 31,
($000s)	2017		2016		2017		2016
Lease acquisitions and retention	187		768		3,507		2,635
Geological and geophysical	446		258		818		336
Drilling and completion costs	22,226		22,994		102,388		62,958
Facilities and equipment	2,896		620		13,938		12,731
Capital – exploration and development(1)	25,755		24,640		120,651		78,660
Capital – corporate assets	338		172		1,985		230
Property acquisitions	114		(13	)	614		(9	)
Total capital expenditures – cash	26,207		24,799		123,250		78,881
Property dispositions – cash (2)	(56	)	(105,206	)	(48,798	)	(299,058	)
Total net capital expenditures – cash	26,151		(80,407	)	74,452		(220,177	)
Property acquisitions – non-cash	—		—		—		29,178
Property disposition – non-cash (4)	—		(21,309	)	(3,465	)	(21,309	)
Other – non-cash (3)	61		(36,224	)	(5,904	)	(33,886	)
Total capital expenditures – net (4)	26,212		(137,940	)	65,083		(246,194	)

(1) Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the period.

(2) Property dispositions – cash does not include transaction costs.

(3) Other includes non-cash adjustments for the current period’s decommissioning liabilities and share based compensation.

(4) Refer to "Non-GAAP measures" for the term "total capital expenditures – net"

In the fourth quarter of 2017, capital spending on exploration and development activities of $25.8 million was focused primarily on drilling and completing two gross (1.9 net) Spirit River liquids rich natural gas wells spud in the fourth quarter of 2017 and completing and bringing on production seven wells spud in a prior quarter of 2017 and the construction of Phase 2 expansion project of the Alder Flats Plant.

Bellatrix continues to advance the Phase 2 expansion project of the Alder Flats Plant which is expected to more than double the inlet capacity of the Alder Flats Plant from 110 MMcf/d currently to 230 MMcf/d. The project remains on schedule and under budget, and is scheduled for completion early in the second quarter of 2018 at a remaining net 25% estimated cost to Bellatrix of approximately $3 million (excluding received partner prepayment). The Phase 2 project represents the last stage of our multi-year infrastructure build out. Major mechanical construction was completed in December and electrical and instrumentation installation activity was completed in early 2018. Pre-commissioning activity has commenced with full commissioning of the Phase 2 expansion expected in March of 2018. Completion of Phase 2 of the Alder Flats Plant will add an incremental 30 MMcf/d ownership capacity net to Bellatrix's 25% working interest. A deferred capital obligation for the Alder Flats Plant of $4.8 million was outstanding at December 31, 2017.

During the third quarter of 2017, Bellatrix completed the sale of certain non-core oil and gas properties in the West Pembina area of Alberta for gross proceeds of $16.0 million effective July 1, 2017. Proceeds from the sale were used to further reduce amounts outstanding under the Company's Credit Facilities. During the second quarter of 2017, Bellatrix completed the sale of certain non-core oil and gas properties in the Strachan area of Alberta for gross proceeds of $34.5 million effective April 1, 2017. Additionally in the second quarter of 2017, Bellatrix transferred certain production facilities and infrastructure to a third party midstream company in exchange for proceeds of $20 million. All of the work has been completed for the facilities and infrastructure with the compressor station being commissioned in December 2017 on schedule and on budget. Under the terms of the agreement, Bellatrix will have exclusive access to, and operatorship of, the infrastructure.

The 2018 capital budget of $65 to $80 million will be directed primarily towards drilling, completion and tie-in activity and investment in strategic infrastructure projects.

Bellatrix Exploration Ltd. 19

DECOMMISSIONING LIABILITIES

($000s)	2017		2016
Balance, beginning of year	62,844		96,423
Incurred on development activities	1,501		911
Acquired through business combinations	—		552
Revisions on estimates	3,210		(5,219	)
Decommissioning costs incurred	(2,758	)
Reversed on dispositions	(5,473	)	(31,536	)
Accretion expense	1,287		1,713
Balance, end of year	60,611		62,844

The $3.2 million increase in decommissioning liabilities between December 31, 2017 and December 31, 2016 resulting from revisions on estimates was due to decreased long-term market interest rates which decreases the long-term discount rates applied to the valuation of the liabilities. In addition, changes to estimates also resulted from the revisions to timing and amounts of future decommissioning cash flows for certain wells and facilities made to better reflect anticipated abandonment timelines and future cash outlays. 

Environmental stewardship is a core value at Bellatrix and abandonment and reclamation activities continue to be made in a prudent, responsible manner with the oversight of the Reserve, Safety and Environment Committee of the Board. Ongoing abandonment expenditures for all of Bellatrix’s assets are funded entirely out of cash flow from operating activities. Bellatrix’s Liability Management Rating is well within the Alberta Energy Regulator’s ("AER"), the British Columbia Oil and Gas Commission's ("BCOGC") and the Saskatchewan Ministry of Economy ("MOE") requirements.

DEBT

Credit Facilities

At December 31, 2017, the Company had $52.1 million outstanding under its syndicated revolving credit facilities (the “Credit Facilities”) at a weighted average interest rate of 4.45%. In addition, total outstanding letters of credit were $13 million. Pursuant to the most recent borrowing base redetermination in November 2017, the total commitments under the Credit Facilities were reconfirmed at $120 million. The Credit Facilities are available on an extendible revolving term basis and consist of a $25 million operating facility and a $95 million syndicated facility. The Credit Facilities have an initial term of one year and are extendible annually at the option of the Company, subject to lender approval, with a one year term-out period if not renewed. Availability under the Credit Facilities is subject to a borrowing base test, which is subject to redetermination in May and November of each year. The Credit Facilities mature on May 31, 2019, if not renewed.

For the year ended December 31, 2017, the 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% to 3.5%, depending on the type of borrowing and the Company’s Senior Debt to Bank EBITDA ratio (defined below). A standby fee is charged between 0.5% and 0.875% on the undrawn portion of the Credit Facilities, depending on the Company’s Senior Debt to Bank EBITDA ratio. The Credit Facilities are secured by a $1.0 billion debenture containing a first ranking charge and security interest. The Company has provided a negative pledge and undertaking to provide fixed charges over its properties in certain circumstances.

The agreement governing the Credit Facilities contains market standard terms and conditions, and includes, for instance, restrictions on asset dispositions and hedging. Generally, dispositions of properties to which the Company is given lending value, in the determination of the borrowing base, require lender approval if the net present value discounted at 10% attributed to all properties sold in a fiscal year exceeds 5% of the borrowing base in effect at the time of such disposition. In addition, asset dispositions are generally not permitted unless there would be no borrowing base shortfall as a result of such properties being sold. Commodity risk management transactions must not be done for speculative purposes. The term of any contract for commodity swaps cannot exceed 3 years. The aggregate amount hedged under all oil and gas commodity swaps cannot exceed 80% of the Company’s average daily sales volume for the first year of a rolling 3 year period, 70% for the second year of such period or 60% for the third year of such period, with the average daily sales volume being based on the Company’s production for the previous fiscal quarter. The aggregate amount hedged under all interest rate swaps, relating to unsecured note debt, cannot exceed the outstanding principal amount of any unsecured note debt or have a term exceeding the remaining term of the unsecured note debt. For interest rate swaps, unrelated to any unsecured note debt, the aggregate amount hedged cannot exceed 60% of the amount of the commitment under the Credit Facilities or exceed a term of three years. The aggregate amount hedged under all exchange rate swaps, relating to unsecured note debt, cannot exceed the outstanding principal amount of any unsecured note debt or have a term exceeding the remaining term of the unsecured note debt.

Bellatrix Exploration Ltd. 20

A copy of the agreement governing the Credit Facilities has been filed with Canadian and US securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), through the SEC website (www.sec.gov).

Convertible Debentures

At December 31, 2017 Bellatrix had outstanding $50 million principal amount of 6.75% convertible unsecured subordinated debentures (the “Convertible Debentures”). The Convertible Debentures are governed by the terms of an indenture dated August 9, 2016 between the Company and Computershare Trust Company of Canada (the “Debenture Indenture”). The Convertible Debentures bear interest at a rate of 6.75% per annum, payable semiannually in arrears on September 30 and March 31 of each year. The maturity date of the Convertible Debentures is September 30, 2021 (the “Debenture Maturity Date”). Each $1,000 principal amount of Convertible Debenture is convertible at the option of the holder into approximately 123.4568 common shares of Bellatrix (representing a conversion price of $8.10) prior to 5:00 p.m. (Calgary time) on the earlier of: (i) the last business day immediately prior to the Debenture Maturity Date, (ii) the last business day immediately preceding any Redemption Date (as defined in the Debenture Indenture), and (iii) if called for repurchase pursuant to a mandatory repurchase as a result of a Change of Control (as defined in the Debenture Indenture) on the last business day preceding the date of payment. The Convertible Debentures are not redeemable prior to September 30, 2019, except in limited circumstances following a Change of Control. On and after September 30, 2019 and up to and including September 30, 2020, the Convertible Debentures may be redeemed in whole or in part from time to time at the Company’s option, on not more than 60 days’ and not less than 30 days’ prior written notice, at a price equal to their principal amount plus accrued and unpaid interest, provided that the volume weighted average trading price of the common shares on the TSX for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the conversion price. On or after September 30, 2020 and prior to the Debenture Maturity Date, the Convertible Debentures may be redeemed in whole or in part from time to time at the Company’s option, on not more than 60 days' and not less than 30 days' prior written notice at a price equal to their principal amount plus accrued and unpaid interest. The Convertible Debentures are direct, subordinated unsecured obligations of the Company, subordinated to the Credit Facilities, the Senior Notes and any other senior indebtedness.

On a redemption date or on the Debenture Maturity Date, as applicable, subject to required regulatory approvals and provided that no Event of Default (as defined in the Debenture Indenture) has occurred and is continuing, Bellatrix may, at its option, on not more than 60 days' and not less than 40 days' prior notice, elect to satisfy its obligation to repay, in whole or in part, the principal amount of the Convertible Debentures which are to be redeemed or which will mature by issuing and delivering freely tradable common shares of the Company to the holders of the Convertible Debentures. Payment for such Convertible Debentures subject to the election would be satisfied by delivering that number of common shares obtained by dividing the principal amount of the Convertible Debentures subject to the election which are to be redeemed or which will mature by 95% of the current market price of the common shares on such redemption date or Debenture Maturity Date, as applicable. Any accrued and unpaid interest will be paid in cash.

Senior Notes

At December 31, 2017, the Company had outstanding US$250 million of 8.50% senior unsecured notes due May 15, 2020 (the “Senior Notes”). The Senior Notes are governed by the terms of an indenture dated May 21, 2015 between the Company and U.S. Bank National Association (the "Note Indenture"). Interest is payable on the Senior Notes semi-annually and the Senior Notes are redeemable at the Company's option, in whole or in part at specified redemption prices. The Senior Notes are redeemable at the following redemption prices (expressed as a percentage of the principal amount of the Senior Notes): May 15, 2017 to May 14, 2018 at 104.250%, May 15, 2018 to May 14, 2019 at 102.125%, May 15, 2019 and thereafter at 100.000%. The Senior Notes are carried at amortized cost, net of debt issuance costs of $7.7 million, which accrete up to the principal balance at maturity using the effective interest rate of 9.6%. The Senior Notes were initially recognized at fair value, net of debt issue costs, and have subsequently been carried at amortized cost.

($000s)	Amount
Balance, December 31, 2015	332,024
Unrealized foreign exchange gain (1) (2)	(9,879	)
Amortization of discount and debt issue costs	2,601
	324,746
Debt issue costs	(55	)
Balance, December 31, 2016	324,691
Unrealized foreign exchange gain (1) (2)	(22,079	)
Amortization of discount and debt issue costs	2,797
Balance, December 31, 2017	305,409

(1) Exchange rate (CDN$/US$1.00) at December 31, 2017 was 1.2518 (December 31, 2016: 1.3427).

(2) Amount does not include unrealized loss on foreign exchange contracts of $3.9 million (December 31, 2016: $2.0 million loss).

Bellatrix Exploration Ltd. 21

Bellatrix is aware that the Company's outstanding Senior Notes have recently been trading at a discount to par value. In order to reduce future cash interest payments, as well as future amounts due at maturity or upon redemption, Bellatrix may, from time to time, seek to purchase such debt for cash, in exchange for common shares, or for a combination of cash and common shares, in each case in open market purchases and/or privately negotiated transactions. Bellatrix will evaluate any such transactions in light of then-existing market conditions, taking into account the Company's current liquidity and prospects for future access to capital. The amounts involved in any such transactions, individually or in the aggregate, may be material. Any such purchases would require the consent of the lenders under our Credit Facility.

Covenants

The agreement governing the Credit Facilities contains a single maintenance financial covenant (referred to below as the Senior Debt Covenant), which requires that the Company maintain a ratio of outstanding Senior Debt to earnings before interest, taxes, depletion, depreciation and amortization (“Bank EBITDA”), as defined by the terms of the agreement governing the Credit Facilities and adjusted for non-cash charges, for a trailing 12-month period of not more than 3.0 times (3.5 times for the two fiscal quarters immediately following a material acquisition) (the “Senior Debt Covenant”). As at December 31, 2017, the Company was in compliance with the Senior Debt Covenant with a Senior Debt to Bank EBITDA ratio of 1.22 times.

The following table lists the covenant under the Credit Facilities and the Company’s compliance therewith as at December 31, 2017:

	Covenant as at, December 31, 2017	Position at December 31, 2017
Credit Facilities – Senior Debt Covenant	Maximum Ratio
Senior Debt(1)to Bank EBITDA (2) for the last four fiscal quarters	3.00x	1.22x

(1)“Senior Debt” is defined as Consolidated Total Debt, including outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred financing obligations, deferred capital obligations and net working capital deficiency. Excluded from the calculation is any unsecured or subordinated debt (Senior Notes and Convertible Debentures (liability component)), decommissioning liabilities, deferred gain and deferred tax liability. “Consolidated Total Debt” is defined as determined on a consolidated basis in accordance with GAAP and without duplication, all Debt of the Borrower. The Company’s calculation of Consolidated Total Debt excludes decommissioning liabilities and deferred tax liability. The calculation includes outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred capital obligations, deferred financing obligations and net working capital deficiency (excess), calculated as working capital deficiency excluding current risk management contract assets and liabilities and current portion of decommissioning liability. Senior Debt at December 31, 2017 was $104.0 million.

(2) “Bank EBITDA” refers to earnings before interest, taxes, depletion, depreciation, amortization and other non-cash charges. Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income (loss) for financing costs, certain specific unrealized and non-cash transactions, and acquisition and disposition activity and is calculated based on a trailing twelve month basis. Bank EBITDA for the trailing twelve months ended December 31, 2017 was $85.1 million.

The Note Indenture does not contain any maintenance financial covenants, but does contain covenants limiting the Company’s ability to incur additional indebtedness, including borrowings under the Credit Facilities, unless one of two alternative tests are satisfied. The first test applies to all future indebtedness and requires that, after giving effect to the incurrence of additional indebtedness, the Company’s fixed charge coverage ratio (the ratio of cash flow to fixed charges (both as defined in the Note Indenture) over the trailing four fiscal quarters) will be at least 2.25 to 1.0. The second test allows the Company to incur additional indebtedness, irrespective of the fixed charge coverage ratio test, as long as the additional indebtedness is incurred under bank facilities (as defined in the Note Indenture, and which includes the Credit Facilities) and generally, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $675 million, and (ii) 35% of adjusted consolidated net tangible assets, or ("ACNTA"), plus $150 million. ACNTA is defined in the Note Indenture and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to the Company’s unevaluated properties. As a result, the Company can currently incur up to $675 million under bank facilities (which include the Credit Facilities), subject to the maximum borrowing base of the Credit Facilities, without reference to limitations that would otherwise apply due to the fixed charge coverage ratio test.

The following table lists the incurrence covenant under the Note Indenture and the Company’s position therewith as at December 31, 2017:

	Covenant as at, December 31, 2017	Position at December 31, 2017
Senior Notes – Incurrence Covenant	Minimum Ratio
Fixed charge coverage (1)	2.25x	2.12x

(1) Fixed charge coverage is computed as the ratio of fixed charges (as defined in the Note Indenture, fixed charges generally includes interest expense plus paid or accrued dividends, if any) to trailing twelve month cash flow (as defined in the indenture governing the Note Indenture, cash flow includes the net loss and adds back provision for taxes, fixed charges, depletion, and various other non-recurring expenses and charges). For the trailing twelve months ended December 31, 2017, fixed charges were $36.6 million and cash flow was $77.8 million.

Bellatrix Exploration Ltd. 22

Bellatrix currently has commitments associated with the Credit Facilities outlined above and the commitments outlined under the “Commitments” section.

LIQUIDITY AND CAPITAL RESOURCES

As an oil and gas company, Bellatrix has a declining asset base and therefore relies on ongoing development and acquisitions to replace production and add additional reserves. Future oil and natural gas production and reserves are highly dependent on the success of exploiting the Company’s existing asset base and in identifying or acquiring additional reserves. To the extent Bellatrix is successful or unsuccessful in these activities, cash flow could be increased or decreased. In addition, the Company’s cash flow depends on a number of factors, including commodity prices, sales volumes, production expenses, taxes, and royalties.

Bellatrix remains highly focused on key business objectives of maintaining financial strength and liquidity, and optimizing capital investments in the current challenging commodity price environment.In December 2017, Bellatrix’s Board of Directors approved a 2018 capital budget of between $65 and $80 million. Bellatrix continually monitors its capital spending program in light of prevailing commodity prices and the United States/Canadian dollar exchange rate with the aim of ensuring the Company will be able to meet future anticipated obligations incurred from normal ongoing operations and reclamation expenditures with adjusted funds flow and borrowings under its Credit Facilities, as necessary.

Bellatrix typically uses three markets to raise capital: The reserve-based lending market, the equity market and the debt market. At December 31, 2017, the Company had $52.1 million outstanding under the Company’s Credit Facilities (excluding letters of credit) at a weighted average interest rate of 4.45%. At December 31, 2017, the borrowing base under the Company’s Credit Facilities was $120 million, providing the Company with approximately $55 million, after deducting letters of credit, of available liquidity. The Credit Facilities have an initial term of one year that is extendible annually at the option of the Company, subject to lender approval, with a one year term-out period if not renewed (refer to “Credit Facilities” above).

Total net debt at December 31, 2017 includes Credit Facilities, Convertible Debentures (liability component), Senior Notes, and the net balance of an adjusted working capital deficiency of $23.9 million. Total net debt excludes unrealized risk management contract assets and liabilities, deferred taxes, other deferred liabilities and decommissioning liabilities. Total net debt levels of $420.8 million at December 31, 2017 increased by $24.6 million from $396.2 million at December 31, 2016. The increase in total net debt reflects an increase of $33 million in amounts outstanding under the Credit Facilities, offset partially by a decrease in the Senior Notes of $19.3 million, resulting from an unrealized foreign exchange gain in the year ended December 31, 2017.

Debt to Adjusted Funds Flow Ratio
	Year ended December 31,
($000s, except where noted)	2017	2016
Shareholders’ equity	774,022	863,418
Current Credit Facilities	—	19,143
Credit Facilities	52,066	—
Loans receivable (long term)	—	(8,775	)
Adjusted working capital deficiency (1)	23,926	23,716
Subtotal	75,992	34,084
Senior Notes (2)	305,409	324,691
Net debt (1)	381,401	358,775
Convertible Debentures (liability component)	39,426	37,420
Total net debt (1) at year end	420,827	396,195
Debt to adjusted funds flow ratio (annualized) (3) (4)
Adjusted funds flow (4) (annualized)	62,800	33,748
Net debt (1) to periods adjusted funds flow ratio (annualized) (3)	6.1x	10.6x
Total net debt to periods adjusted funds flow ratio (annualized) (3)	6.7x	11.7x
Debt to adjusted funds flow ratio (4)
Adjusted funds flow for the year (4)	58,240	40,916
Net debt (1) to adjusted funds flow ratio (4) for the year	6.5x	8.8x
Total net debt (1) to adjusted funds flow ratio (4) for the year	7.2x	9.7x

(1)Net debt and total net debt as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, long-term risk management liabilities, decommissioning liabilities, and the deferred tax liability. Total net debt includes the adjusted working capital

Bellatrix Exploration Ltd. 23

deficiency, Convertible Debentures (liability component), current Credit Facilities, non-current credit facilities, long term loan receivable and Senior Notes. The adjusted working capital deficiency as presented does not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company calculated adjusted working capital deficiency as net working capital deficiency excluding current risk management contract assets and liabilities, current portion of other deferred liabilities, current portion of Credit Facilities and the current portion of decommissioning liabilities. Net debt excludes the liability component of Convertible Debentures that is included in total net debt.

(2) For the year ended December 31, 2017, includes unrealized foreign exchange gain of $22.2 million (2016: $9.9 million) and does not include an unrealized gain of $3.9 million (2016: $2.0 million) on foreign exchange contracts.

(3) For the years ended December 31, 2017 and 2016, total net debt to period’s adjusted funds flow ratio (annualized) is calculated based upon fourth quarter adjusted funds flow annualized.

(4) Adjusted funds flow as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Adjusted funds flow is calculated as cash flow from operating activities, excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs. 

As at December 31, 2017 the Company’s ratio of total net debt to annualized adjusted funds flow (based on fourth quarter adjusted funds flow) was 6.7 times.The total net debt to annualized adjusted funds flow ratio as at December 31, 2017 decreased from that at December 31, 2016 of11.7 times primarily due to an increase in 2017 adjusted funds flow resulting from an increase in average realized commodity prices and gains on commodity contracts. The Company continues to preserve liquidity through the priority use of adjusted funds flow.

 Liquidity Risk

Liquidity risk is the risk that Bellatrix will not be able to meet its financial obligations as they become due. Bellatrix actively manages its liquidity through daily and longer-term cash, debt, and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through its Credit Facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic risk management opportunities, and maintaining sufficient cash flows to ensure compliance with the Credit Facilities and Senior Debt Covenant described above. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses.

Future liquidity depends primarily on cash flow generated from operations, availability under the Credit Facilities and Bellatrix’s ability to comply with the Senior Debt Covenant and other covenants contained therein (as outlined above in “Covenants”), and the ability to access debt and equity markets.

Amounts outstanding under the Credit Facilities were $52.1 million at December 31, 2017. Bellatrix also has Senior Notes and Convertible Debentures outstanding with fixed interest rates (as outlined above in “Senior Notes” and “Convertible Debentures”), which mature on May 15, 2020 and September 30, 2021, respectively.

Effective July 1, 2017, the Company consolidated its common shares on the basis of 1 new common share for every 5 old common shares outstanding. The number of outstanding share options, DSUs, RAs and PAs have also been adjusted proportionately. The corresponding exercise prices have increased by the same ratio. The conversion price and ratio on the Convertible Debentures have also been adjusted proportionately.

As at March 13, 2018, there was $50 million principal amount of Convertible Debentures outstanding which are convertible, at the option of the holder, into approximately 6,172,840 common shares of the Company based on a conversion price of $8.10 per share. The Company may elect to issue common shares of the Company to satisfy the obligation to repay, in whole or in part, the principal amount of the Convertible Debentures upon redemption or maturity of the Convertible Debentures (any accrued and unpaid interest on such redemption or maturity will be paid in cash). The exact number of common shares of the Company that may be issuable on redemption or maturity would be determined by dividing the principal amount of the Convertible Debentures by 95% of the current market price of the common shares on the redemption date or maturity date, as applicable.

From time to time, the Company accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. As at December 31, 2017, the Company has the ability to offer to sell up to an additional $470.8 million in securities under its $500 million Shelf Prospectus, which expires on June 30, 2018. Management expects to renew the Shelf Prospectus before expiry.

There can be no assurance that future debt or equity financing, additional credit under the Credit Facilities, 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 Bellatrix.

As at March 13, 2018, Bellatrix had outstanding a total of 1,583,865 options at an average exercise price of $15.77 per share and had 49,378,026 common shares outstanding. Additionally, Bellatrix had 517,898 DSUs, 573,055 PAs and 809,386 RAs outstanding as of March 13, 2018. Awards under the Award Plan may be settled in cash, in common shares of the Company, or a combination thereof.

Bellatrix Exploration Ltd. 24

Credit Risk

Credit risk is the risk of financial loss to Bellatrix if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from Bellatrix’s trade receivables from joint venture partners, petroleum and natural gas marketers, and financial derivative counterparties.

A substantial portion of Bellatrix’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Bellatrix currently sells substantially all of its production to ten primary purchasers under standard industry sale and payment terms. The most significant 60 day exposure to a single counterparty is approximately $11.2 million. Purchasers of Bellatrix’s natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. Bellatrix has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in Bellatrix mitigating its exposures to certain counterparties by obtaining financial assurances or reducing credit where it is deemed warranted and permitted under contractual terms.

Bellatrix may be exposed to third party credit risk through its contractual arrangements with its current or future partners and joint venture partners, marketers of its petroleum and natural gas production, derivative counterparties and other parties. In the event such entities fail to meet their contractual obligations to Bellatrix, such failures may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner’s willingness to participate in Bellatrix’s ongoing capital program, potentially delaying the program and the results of such program until Bellatrix finds a suitable alternative partner.

ENVIRONMENTAL INITIATIVES IMPACTING BELLATRIX

Bellatrix operates in jurisdictions that have regulated greenhouse gas (“GHG”) emissions and other air pollutants. While some regulations are in effect, further changes and amendments are at various stages of review, discussion and implementation. There is uncertainty around how any future federal legislation will harmonize with provincial regulation, as well as the timing and effects of regulations. Climate change regulation at both the federal and provincial level has the potential to significantly affect the regulatory environment of the crude oil and natural gas industry in Canada. Such regulations impose certain costs and risks on the industry, and there remains some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as Bellatrix is unable to predict additional legislation or amendments that governments may enact in the future. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Company's operations and cash flow.

Additional information is available in Bellatrix’s Annual Information Form ("AIF") that is filed on SEDAR at www.sedar.com.

COMMITMENTS

 The Company had the following commitments as at December 31, 2017:

Liabilities ($000s)	Total	< 1 Year	1-3 Years	3-5 Years	More than 5 years
Accounts payable and accrued liabilities	73,307	73,307	—	—	—
Risk management liability	7,890	4,468	3,422	—	—
Credit Facilities – principal	52,066	—	52,066	—	—
Convertible Debentures (liability component)	39,426	—	—	39,426	—
Senior Notes	305,409	—	305,409	—	—
Decommissioning liabilities	60,611	1,924	2,414	1,980	54,293
Deferred capital obligation	4,755	4,755	—	—	—
Deferred financing obligation	1,505	1,505	—	—	—
Finance lease obligation	6,891	1,170	947	928	3,846
Total	551,860	87,129	364,258	42,334	58,139

Off-Balance Sheet Arrangements

The Company has certain fixed-term lease agreements, primarily compressor and office space leases, which were entered into in the normal course of operations. Additionally, Bellatrix leases certain production facilities from a third party midstream company. Bellatrix maintains operatorship and preferential access to the facilities for its operated production volumes and retains, at its sole discretion, the option to repurchase the facilities at any time during the agreement period. Pursuant to the agreement, Bellatrix will pay an annual rental fee over the duration of the agreement.

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During 2016, Bellatrix completed the Alder Flats Plant Sale transaction. As part of the transaction, Bellatrix and Keyera Partnership ("Keyera") entered into a midstream services and governance agreement pursuant to which Bellatrix will have exclusive access to the purchased capacity (approximately 80.5 MMcf/d post commissioning of Phase 2) for a term of 10 years, and will remain the operator of the Alder Flats Plant.  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 Alder Flats Plant.

All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses, depending on the nature of the lease. The lease agreements for office space do not currently provide for early termination. No asset or liability value has been assigned to these leases in the balance sheet as of December 31, 2017.

The Company’s contractual obligations and commitments as at December 31, 2017 were as follows:

($000s)	1 Year		2-3 Years		4-5 Years		More than 5 years		Total
Operating leases (1)	$	24,835	$	48,748	$	40,811	$	30,934	$	145,328
Transportation and processing agreements (2)	$	62,207	$	97,788	$	69,481	$	128,873	$	358,349

(1) Operating leases is comprised of the Company’s commitment for office space, net of recoveries and gross operating leases for field equipment. The Company is committed to payments under fixed term operating leases for office space which do not currently provide for early termination.

(2) Transportation agreements is comprised of commitments to third parties to transport natural gas. Processing agreements is comprised of commitments to process natural gas and natural gas liquids through processing facilities.

2017 OPERATIONAL PERFORMANCE

Strong fourth quarter and full year 2017 operational results once again confirm the high quality nature of Bellatrix’s asset base, strategic infrastructure ownership and control, combined with ample takeaway capacity and market egress.

In 2017, Bellatrix drilled and/or participated in 26 gross (19.3 net) Spirit River liquids rich natural gas wells, 3 gross (3.0 net) Cardium wells and 4 gross (1.6 net) Ellerslie wells. Bellatrix's operated drilling activity in 2017 included a total of 101,040 meters drilled 35,297 meters of which was horizontal length. All-in (drill, complete, equip and tie-in) well costs in 2017 for our operated Spirit River program averaged $3.8 million, meaningfully below the $4.0 million budgeted cost level during the year.

Efficiency improvements continued in 2017, which provide the foundation for continued cost suppression. In 2017, Bellatrix averaged 13.5 days from spud to rig release, an 8% improvement year over year. These operational efficiencies achieved through 2017 are enduring and Bellatrix continues to improve on the Company's already industry leading well cost and performance metrics year to date in 2018.

Bellatrix delivered strong operational performance in 2017 relative to guidance expectations as summarized below:

	2017 Results		2017 Guidance		Actual Versus Guidance
Production (boe/d)
2017 Average daily production	36,872		36,000		2	%
Average product mix
Natural gas (%)	75		76		(1	)%
Crude oil, condensate and NGLs (%)	25		24		1	%
Capital expenditures ($000’s)
Total net capital expenditures(1)	122,636		120,000		2	%
Property disposition - cash(2)	(48,798	)	(50,500	)	(3	)%
Total net capital expenditures after property disposition - cash	73,838		69,500		6	%
Production expense ($/boe)	8.31		8.50		(2	)%

(1)Capital spending includes exploration and development capital projects and corporate assets, and excludes property acquisitions and dispositions. Net capital spending also excludes the previously received prepayment portion of Bellatrix’s partners 35% share of the cost of construction of Phase 2 of the Alder Flats Plant during calendar 2017.

(2)Production expenses before net processing revenue/fees.

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OUTLOOK AND 2018 CORPORATE GUIDANCE

On December 14, 2017 Bellatrix’s Board of Directors approved the 2018 capital budget of between $65 to $80 million, designed to achieve average production volumes of between 35,000 to 37,000 boe/d. The 2018 capital budget will remain flexible throughout the year, and given continued weakness in the forward strip natural gas prices, Bellatrix intends on managing our capital investment program near the lower end of the capital guidance range.

Development activity in 2018 focuses on achievement of the following strategic objectives:

• Completing construction of Phase 2 of the Bellatrix Alder Flats deep cut gas plant with commissioning planned to commence early in the second quarter of 2018.

• Optimizing forecast return on invested capital through a flexible drilling program focused on Spirit River liquids rich natural gas investment opportunities and higher liquids weighted opportunities in the Cardium play.

• Maintaining a flexible approach to capital investment with the potential to accelerate or decelerate capital expenditures throughout the year.

• Enhancing adjusted funds flow through optimal delivery of production volumes during periods of stronger commodity prices by leveraging Bellatrix’s controlled infrastructure and firm service delivery capacity.

• Preserving liquidity and balance sheet strength.

• Continuing to work on cost suppression activities through ongoing technological and operationally focused initiatives.

Bellatrix’s 2018 guidance estimates are outlined in the following table.

	2018 Guidance
Production (boe/d)
2018 Average daily production	35,000 - 37,000
Average product mix
Natural gas (%)	74
Crude oil, condensate and NGLs (%)	26
Net capital expenditures ($000) (1)	$65,000 - $80,000
Production expense ($/boe) (2)	$7.50 - $7.90

(1)Net capital spending includes exploration and development capital projects and corporate assets, and excludes property acquisitions and dispositions.

(2)Production expenses before net processing revenue/fees

FINANCIAL REPORTING UPDATE

Future Accounting Pronouncements

The following pronouncements from the International Accounting Standards Board (“IASB”) are applicable to Bellatrix and will become effective for future reporting periods, but have not yet been adopted:

IFRS 9 - “Financial Instruments”, which is the result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. This standard is effective for annual periods beginning on or after January 1, 2018 with different transitional arrangements depending on the date of initial application.

The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the requirements of IAS 39; however, where the fair value option is applied to financial liabilities, any change in fair value resulting from an entity's own credit risk is recorded in other comprehensive income rather than the statement of income. Bellatrix has determined the adoption of IFRS 9 will not result in any material changes to the classification of financial assets and liabilities or to the measurement and carrying values of the Company's financial instruments.

In addition, IFRS 9 introduces a new expected credit loss model for calculating impairment of financial assets, replacing the incurred loss impairment model required by IAS 39. Bellatrix has determined that the new impairment model will not result in material changes to the valuation of its financial assets on the adoption of IFRS 9. Bellatrix does not currently apply hedge accounting to its financial instrument contacts and does not currently intend to apply hedge accounting to any of its derivative contracts upon adoption of IFRS 9.

IFRS 15 - “Revenue from Contracts with Customers”, provides a five-step model to be applied to all revenue contracts with customers. The standard specifies when an entity will recognize revenue and provides guidance regarding disclosures relating to revenue

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recognition. IFRS 15 is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018.

Bellatrix intends to adopt IFRS 15 using a modified transition approach on January 1, 2018. The Company has completed reviewing its various revenue streams and underlying contracts with customers. It has been concluded the adoption of IFRS 15 will not have a material impact on Bellatrix's net income and financial position. However, Bellatrix will expand the disclosures in the notes to its financial statements as prescribed by IFRS 15, including disclosing the Company's disaggregated revenue streams by product type.

IFRS 16 - "Leases”, replaces IAS 17 Leases. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. All contracts that meet the definition of a lease under IFRS 16, including those presently accounted for as operating leases, will be recorded on the balance sheet. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. The extent of the impact of the adoption of IFRS 16 has not yet been determined.

BUSINESS RISKS AND UNCERTAINTIES

Bellatrix's production and exploration activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers to the much larger integrated petroleum companies.

Bellatrix is subject to the various types of business risks and uncertainties including:

• financial risks, which includes commodity price risk, counterparty risks and risks related to the Company's financing arrangements;

• finding and developing oil and natural gas reserves at economic costs; and

• operational risks such as risks related to health and safety, transportation and processing restrictions, project execution and the environment.

A description of the risk factors and uncertainties affecting Bellatrix can be found under the heading "Forward Looking Statements" and a full discussion of the material risk factors affecting Bellatrix can be found in the Company’s AIF and Form 40-F for the year ended December 31, 2017, which 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).

The following explains how material risks and uncertainties impact Bellatrix’s business:

Exploration, Development and Production Risks

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 Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the Company's existing reserves, and the production from them, will decline over time as the Company produces from such reserves. A future increase in the Company's reserves will depend on both the ability of the Company 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 Company will be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of the Company 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 Company 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 as well as 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.

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 and effective maintenance operations 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, the environment and personal injury. Particularly, the Company may explore for and produce sour natural

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gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Company.

Oil and natural gas production operations are also subject to all the risks typically associated with such operations, 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 Company's business, financial condition, results of operations and prospects.

Prices, Markets and Marketing

Numerous factors beyond the Company's control do, and will continue to, affect the marketability and price of oil and natural gas acquired, produced, or discovered by the Company. The Company'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. Deliverability uncertainties related to the distance the Company's reserves are from pipelines, railway lines, processing and storage facilities; operational problems affecting pipelines, railway lines and 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 Company.

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 Company. 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 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 Company's ability to access such markets. A material decline in prices could result in a reduction of the Company'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 Company's reserves. The Company might also elect not to produce from certain wells at lower prices.

All these factors could result in a material decrease in the Company'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 Company's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Company'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.

Project Risks

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

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Because of these factors, the Company could be unable to execute projects on time, on budget, or at all and may be unable to market the oil and natural gas that it produces effectively.

Gathering and Processing Facilities and Pipeline Systems

The Company delivers its products through gathering and processing facilities and by pipeline. The amount of oil and natural gas that the Company can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities and pipeline systems. The lack of availability of capacity in any of the gathering and processing facilities and pipeline systems could result in the Company's inability to realize the full economic potential of its production or in a reduction of the price offered for the Company's production. The lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to transport produced oil and gas to market. 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 Company's production, operations and financial results. As a result, producers are increasingly turning to rail 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 Company's business and, in turn, the Company's financial condition, operations and cash flows. Announcements and actions taken by the governments of British Columbia and Alberta 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 recently introduced draft legislation 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 of receipt of approvals of major projects remains unclear.

A portion of the Company's production may, from time to time, be processed through facilities owned by third parties and over which the Company 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 Company's ability to process its production and deliver the same for sale.

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.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Company considers acquisitions and dispositions of 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 Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses 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 assets required to provide such services. In this regard, non‑core assets may be periodically disposed of so the Company 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 Company may realize less on disposition than their carrying value on the financial statements of the Company.

Substantial Capital Requirements

The Company 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 Company's ability to do so is dependent on, among other factors:

• the overall state of the capital markets;

• the Company'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 Company's securities in particular.

Further, if the Company's revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing. 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 Company. The Company may be required to seek additional equity financing on terms that

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are highly dilutive to existing shareholders. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business financial condition, results of operations and prospects.

Additional Funding Requirements

The Company's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times and from time to time, the Company 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 Company 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 gas industry and/or global economic and political volatility, the Company may from time to time have restricted access to capital and increased borrowing costs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing.

As a result of global economic and political volatility, the Company may from time to time have restricted access to capital and increased borrowing costs. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Company's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Company'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 Company'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 Company'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 Company's capital expenditure plans may result in a delay in development or production on the Company's properties.

Credit Facility Arrangements

The Company is required to comply with covenants under its Credit Facilities and in the event that the Company does not comply with these covenants, the Company's access to capital could be restricted or repayment could be required. Even if the Company is able to obtain new financing, it may not be on commercially reasonable terms or terms that are acceptable to the Company. Events beyond the Company's control may contribute to the failure of the Company to comply with such covenants. A failure to comply with covenants could result in default under the Company's Credit Facilities, which could result in the Company being required to repay amounts owing thereunder. The acceleration of the Company's indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the Company's Credit Facilities may impose operating and financial restrictions on the Company that could include restrictions on, the payment of dividends, repurchase or making of other distributions with respect to the Company'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 Company's lenders use the Company's reserves, commodity prices, applicable discount rate and other factors, to periodically determine the Company's borrowing base. As a result of the depressed commodity prices experienced in the last two years, the Company's borrowing base was reduced in 2016. 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 the Company's borrowing base, reducing the funds available to the Company under the Credit Facilities. This could result in the requirement to repay a portion, or all, of the Company's indebtedness.

Third Party Credit Risk

The Company 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 Company may be exposed to third party credit risk from operators of properties in which the Company has a working or royalty interest. Poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company 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 Company being unable to collect all or portion of any money owing from such parties. Any of these factors could materially adversely affect the Company's financial and operational results

Hedging Activities

From time to time, the Company 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 Company 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 Company's hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:

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• 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 Company 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 Company will not benefit from the fluctuating exchange rate.

Reliance on Joint Venture Partners

The Company 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.

Operational Dependence

Other companies operate some of the assets in which the Company has an interest. The Company has limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Company's financial performance. The Company's return on assets operated by others depends upon a number of factors that may be outside of the Company'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 Company 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 Company has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations the Company 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 Company potentially becoming subject to additional liabilities relating to such assets and the Company having difficulty collecting revenue due from such operators or recovering amounts owing to the Company from such operators for their share of abandonment and reclamation obligations. Any of these factors could have a material adverse affect on the Company's financial and operational results.

Information Technology Systems and Cyber-Security

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, 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, 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. The Corporation applies technical and process controls in line with industry-accepted standards to protect our information assets and systems. Disruption of critical information technology services, or breaches of information security, could have a negative effect on our performance and earnings, as well as on our reputation. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Corporation’s business, financial condition and results of operations.

Royalty Regimes

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

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Environmental

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 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 Company to incur costs to remedy such discharge. Although the Company 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 Company's business, financial condition, results of operations and prospects.

Variations in Foreign Exchange Rates and Interest Rates

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 Company's production revenues. Accordingly, exchange rates between Canada and the United States could affect the future value of the Company'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 Company receives for its oil and natural gas production, it could also result in an increase in the price for certain goods used for the Company's operations, which may have a negative impact on the Company's financial results.

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

An increase in interest rates could result in a significant increase in the amount the Company 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 and could negatively impact the market price of the Common Sharesof the Company.

Reserves Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in this document are estimates only. Generally, estimates of economically recoverable oil and natural gas reserves 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 the 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 Company'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. Such variations could be material.

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In accordance with Applicable Securities Laws, the Company'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. 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 Company's reserves since that date.

Income Taxes

The Company files all required income tax returns and believes that it is in full compliance with the provisions of the Income Tax Act, R.S.C. 1985, c. 1 (5^th Supp.) 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 Company, 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 Company. Furthermore, tax authorities having jurisdiction over the Company may disagree with how the Company calculates its income for tax purposes or could change administrative practices to the Company's detriment.

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICIES

The reader is advised that the critical accounting estimates, policies, and practices as described herein continue to be critical in determining Bellatrix’s financial results.

The reader is cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. The following discussion outlines accounting policies and practices that are critical to determining Bellatrix’s financial results.

Critical Accounting Judgments

Oil and Gas Reserves

Reserves and resources are used in the units of production calculation for depletion, depreciation and amortization, and the impairment analysis which affect net profit or loss. There are numerous uncertainties inherent in estimating oil and gas reserves. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net profit as further information becomes available and as the economic environment changes.

Identification of CGUs

Bellatrix’s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, geology, production profile and infrastructure of their assets.

Impairment Indicators and Impairment Reversal

Judgment is required to assess when impairment indicators exist and impairment testing is required with respect to exploration and evaluation assets and property, plant and equipment.

Joint Arrangements

Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint control, the Company considers whether unanimous consent is required to direct the activities that significantly affect the returns of the arrangement, such as the capital and operating activities of the arrangement. Additionally, the Company assesses the rights and obligations arising from the arrangement by considering its governance structure, legal form, and terms agreed upon by the parties sharing control, including the contractual rights of each partner, dispute resolution procedures, termination provisions, and procedures for subsequent transactions in its determination of joint control.

Once joint control has been established, judgment is also required to classify the joint arrangement. The type of joint arrangement is determined through analysis of the rights and obligations arising from the arrangement by considering its legal structure, legal form and terms agreed upon by the parties sharing control. An arrangement that is not structured through a separate vehicle in which the controlling parties have rights to the assets, revenues and substantially all of the economic benefits generated through

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the arrangement, in addition to obligations for the liabilities and expenses, is classified as a joint operation. An arrangement in which these criteria are not met is classified as a joint venture.

Non-monetary Transactions

Judgment is required to determine whether non-monetary transactions have commercial substance.

Critical Estimates and Assumptions

Recoverability of asset carrying values

The Company assesses its oil and gas properties, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date. 

The assessment of any impairment of property, plant and equipment is dependent upon estimates of recoverable amount that take into account factors such as reserves, future estimated commodity prices, royalties and costs, economic and market conditions, timing of cash flows, the useful lives of assets and their related salvage values. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company’s assets in future periods.

Decommissioning obligations

Provisions for decommissioning obligations associated with the Company’s drilling operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology. 

Income taxes

Deferred tax assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.

Business combinations

The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or goodwill. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.

Bellatrix has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates. For further information on the determination of certain estimates inherent in the financial statements, refer to Note 4 “Critical Judgments and Accounting Estimates” in the financial statements as at and for the year ended December 31, 2017.

LEGAL, ENVIRONMENTAL REMEDIATION AND OTHER CONTINGENT MATTERS

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favor, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceeding related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position or results of operations.

The Company reviews legal, environmental remediation and other contingent matters to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. The Company’s management monitors known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by the circumstances.

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With the above risks and uncertainties the reader is cautioned that future events and results may vary substantially from that which Bellatrix currently foresees.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company’s President and Chief Executive Officer (“CEO”) and Executive Vice President and Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures (as defined in Rules 13(a) - 15(e) and 15(d) – 15(e) under the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”) and National Instrument 52-109, Certification of Disclosure in Issuer’s Annual and Interim Filings (“NI 52-109”)) to provide reasonable assurance that: (i) material information relating to the Company is made known to the CEO and CFO by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings (as these terms are defined in NI 52-109) or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision the effectiveness of the Company’s disclosure controls and procedures at the financial year end of the Company. Based on the evaluation, the officers concluded that Bellatrix’s disclosure controls and procedures were effective as at December 31, 2017.

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting (as defined in Rules 13(a) – 15(f) and 15(d) – 15(f) under the Exchange Act and NI 52-109). Internal control over the Company’s financial reporting is a process designed by, or designed under the supervision of, our President and CEO and our Executive Vice President and CFO, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for the external purposes in accordance with GAAP.

Under the supervision and with the participation of management, including our CEO and our CFO, an evaluation of the effectiveness of the Company’s internal control over financial reporting was conducted as of December 31, 2017 based on the criteria described in “Internal Control – Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that, as of December 31, 2017, the Company’s internal control over financial reporting was effective.

The effectiveness of internal control over financial reporting as of December 31, 2017 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm, which is included with the financial statements for the year ended December 31, 2017.

Changes in Internal Control over Financial Reporting

The Company is required to disclose herein any change in the Company’s internal control over financial reporting that occurred during the period commencing on October 1, 2017 and ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. There has been no change in the Company’s internal control over financial reporting that occurred during the period commencing October 1, 2017 and ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Limitations of the Effectiveness of Controls 

It should be noted that a control system, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure controls and procedures and internal controls over financial reporting will prevent all errors or fraud.

CEO AND CFO CERTIFICATIONS

The Company’s President and CEO and the Executive Vice President and CFO have attested to the quality of the public disclosure in our fiscal 2017 reports filed with the Canadian securities regulators and the SEC, and have filed certifications with them.

SENSITIVITY ANALYSIS

The table below shows sensitivities to adjusted funds flow as a result of product price, exchange rate, and interest rate changes. This determination is based on actual average prices received for the fourth quarter of 2017 and average production volumes of 37,077 boe/d during that period, as well as the same level of debt outstanding as at December 31, 2017. Diluted weighted average shares are based upon the fourth quarter of 2017. These sensitivities are approximations only, and not necessarily valid under

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other significantly different production levels or product mixes. Commodity price risk management activities can significantly affect these sensitivities. Changes in any of these parameters will affect funds flow as shown in the table below:

	Adjusted Funds Flow (1) (Annualized)	Adjusted Funds Flow (1) (Per Diluted Share)
Sensitivity Analysis	($000s)	($)
Change of US $1/bbl (2)	3,700	0.07
Change of $0.10/ mcf (2)	6,000	0.12
Change in prime of 1%	500	0.01
Change of US $0.01 CDN/ US exchange rate	800	0.02

(1) Refer to "Non-GAAP measures" in respect of the term "adjusted funds flow".

(2)Commodity price risk management activities are excluded from adjusted funds flow sensitivity calculations.

SELECTED QUARTERLY INFORMATION

The following table sets forth selected financial information of the Company for the quarters in 2017 and 2016.

2017 – Quarter ended (unaudited) ($000s, except per share amounts)	March 31		June 30			Sept. 30			Dec. 31
Total revenue (1)	66,024		74,325			48,153			60,897
Cash flow from operating activities	8,258		10,495			23,031			13,425
Cash flow from operating activities per share
Basic	$	0.17	$	0.21		$	0.47		$	0.27
Diluted	$	0.14	$	0.21		$	0.47		$	0.27
Adjusted funds flow (1)	14,891		19,347			8,300			15,700
Adjusted funds flow per share (1)
Basic	$	0.30	$	0.39		$	0.17		$	0.32
Diluted	$	0.26	$	0.39		$	0.17		$	0.32
Net profit (loss)	13,049		(69,236		)	(22,124		)	(13,053		)
Net profit (loss) per share
Basic	$	0.26	$	(1.40	)	$	(0.45	)	$	(0.26	)
Diluted	$	0.23	$	(1.40	)	$	(0.45	)	$	(0.26	)
Total net capital expenditures - cash	49,805		(25,741		)	24,238			26,151

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2016 – Quarter ended (unaudited) ($000s, except per share amounts)	March 31		June 30			Sept. 30			Dec. 31
Total revenue (1)	55,158		48,285			56,524			67,907
Cash flow from operating activities	10,333		7,675			2,425			17,114
Cash flow from operating activities per share
Basic	$	0.27	$	0.20		$	0.05		$	0.35
Diluted	$	0.27	$	0.20		$	0.05		$	0.35
Adjusted funds flow (1)	12,876		9,048			10,556			8,437
Adjusted funds flow per share (1)
Basic	$	0.34	$	0.23		$	0.23		$	0.17
Diluted	$	0.34	$	0.23		$	0.23		$	0.17
Net profit (loss)	19,347		(55,193		)	(13,907		)	23,085
Net profit (loss) per share
Basic	$	0.50	$	(1.42	)	$	(0.31	)	$	0.47
Diluted	$	0.50	$	(1.42	)	$	(0.31	)	$	0.47
Total net capital expenditures - cash	28,927		(69,917		)	(98,781		)	(80,407		)

(1)Refer to “Capital performance measures” and “Non-GAAP measures” in respect of the terms “adjusted funds flow”, “adjusted funds flow per share”, and “total revenue.” 

In the fourth quarter of 2017, sales volumes increased from 37,077 boe/d compared to 31,888 boe/d in the comparative 2016 period. The Company's total revenue generated in the quarter decreased to $60.9 million in the fourth quarter of 2017 from $67.9 million in the fourth quarter of 2016 as a result of a 24% decline in realized average commodity prices. In the three months ended December 31, 2017, the Company's total cash capital expenditures were $26.2 million compared to $24.8 million in the comparative 2016 period. Bellatrix focused its capital activity in the fourth quarter on drilling and completion projects and on the construction of the Phase 2 expansion project of the Alder Flats Plant. Bellatrix drilled 2 gross (1.9 net) Spirit River liquids rich natural gas wells.

In the third quarter of 2017, Bellatrix reduced amounts outstanding under its Credit Facilities to $8.3 million. Total net debt was $399.8 million at September 30, 2017. Bellatrix incurred $39.7 million of total cash capital expenditures in the third quarter of 2017 compared to $17.2 million in the comparative 2016 period. Bellatrix focused its capital activity in the third quarter primarily on drilling and completion projects and on expenditures related to the construction of Phase 2 of the Alder Flats Plant. The Company drilled and/or participated in 13 gross (8.4 net) Spirit River liquids rich gas wells, 1 gross (1.0 net) Cardium well, and 2 gross (0.8 net) non-operated Ellerslie liquids rich natural gas wells compared to 4 gross (2.3 net) Spirit River liquids rich gas wells in the comparative 2016 period. Sales volumes increased to 37,710 boe/d in the third quarter of 2017 compared to 34,409 boe/d in the comparative 2016 period.

In the second quarter of 2017, Bellatrix reduced amounts outstanding on its Credit Facilities and reduced its working capital deficiency by approximately $45.8 million from the first quarter of 2017 through the use of proceeds from the non-core Strachan asset sale. In the three months ended June 30, 2017, the Company’s total net cash capital expenditures were negative $25.7 million, compared to negative $69.9 million in the second quarter of 2016, primarily as a result of the smaller asset dispositions in the second quarter of 2017 compared to 2016. Total revenue increased 54% to $74.3 million in the three months ended June 30, 2017 from $48.3 million in the three months ended June 30, 2016 due to improved commodity prices in the period. The Company drilled 2 gross (1.2 net) wells, compared to nil wells drilled in the comparative 2016 period. Drilling in the first half of 2017 was offset by non-core property dispositions in the fourth quarter of 2016 and sales volumes remained consistent at 37,916 boe/d in the second quarter of 2017 compared to 38,000 boe/d in the comparative 2016 period.

In the first quarter of 2017, Bellatrix drilled and/or participated in 13 gross (10.6 net) wells. Total net cash capital expenditures were $49.8 million in the three months ended March 31, 2017, compared to a negative $80.4 million in the three months ended December 31, 2016, as a result of non-core property sale in the fourth quarter of 2016. The non-core property sales also reduced sales volumes by 10% from 38,467 in the first quarter of 2016 to 34,750 in the first quarter of 2017. Total revenue increased 20% to $66.0 million in the three months ended March 31, 2017, from $55.2 million in the three months ended March 31, 2016 due to improved commodity prices in the period, partially offset by decreased sales volumes.

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SELECTED ANNUAL INFORMATION

The following table sets forth selected financial information of the Company for the most recently completed year ending December 31, 2017 and for comparative 2016 and 2015 years.

Years ended December 31, ($000s, except per share amounts)	2017			2016			2015
Total revenue (1)	249,399			227,874			333,318
Cash flow from operating activities	55,210			37,546			103,075
Cash flow from operating activities per share
Basic	$	1.12		$	0.88		$	2.70
Diluted	$	1.12		$	0.88		$	2.70
Adjusted funds flow (1)	58,240			40,916			109,485
Adjusted funds flow per share (1)
Basic	$	1.18		$	0.96		$	2.85
Diluted	$	1.18		$	0.96		$	2.85
Net profit (loss)	(91,363		)	(26,668		)	(444,208		)
Net profit (loss) per share
Basic	$	(1.85	)	$	(0.62	)	$	(11.55	)
Diluted	$	(1.85	)	$	(0.62	)	$	(11.55	)
Total net capital expenditures – cash	74,452			(220,178		)	144,191
Total assets	1,340,923			1,453,730			1,703,212
Total net debt (1)	420,827			396,195			717,645
Non-current financial (assets) liabilities
Future income taxes	(48,298		)	(63,713		)	(59,255		)
Decommissioning liabilities	58,687			62,844			96,423
Sales volumes (boe/d)	36,872			35,677			41,441

(1) Refer to “Capital performance measures” and “Non-GAAP measures” in respect of the terms “adjusted funds flow”, “adjusted funds flow per share”, “total net debt” and “total revenue.”

CONVERSION: The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe conversions in this report are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.

NON-GAAP MEASURES: Throughout Bellatrix’s MD&A, the Company uses terms that are commonly used in the oil and natural gas industry, but do not have a standardized meaning presented by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to the calculations of similar measures for other entities. Management believes that the presentation of these non-GAAP measures provide useful information to investors and shareholders as the measure provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.

Operating netbacks are calculated by subtracting royalties, transportation, and operating expenses from total revenue. Management believes this measure is a useful supplemental measure of the amount of total revenue received after transportation, royalties and operating expenses. The Company’s calculation of total revenue includes petroleum and natural gas sales and other income, and excludes commodity price risk management. Total capital expenditures – net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation. Bellatrix’s method of calculating these measures may differ from other entities, and accordingly, may not be comparable to measures used by other companies.

CAPITAL PERFORMANCE MEASURES: In addition to the non-GAAP measures described above, there are also terms that have been reconciled in the Company’s financial statements to the most comparable IFRS measures. These terms do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculations of similar measures for other entities. These terms have been referenced in the Company’s MD&A and financial statements. These terms are used by management to analyze operating performance on a comparable basis with prior periods and to analyze the liquidity of the Company.

This MD&A contains the term “adjusted funds flow” which should not be considered an alternative to, or more meaningful than “cash flow from operating activities” as determined in accordance with GAAP as an indicator of the Company’s performance. Therefore

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reference to adjusted funds flow or adjusted funds flow per share may not be comparable with the calculation of similar measures for other entities. Management uses adjusted funds flow to analyze operating performance and leverage and considers adjusted funds flow to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. Adjusted funds flow is calculated as cash flow from operating activities, excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs. The reconciliation between cash flow from operating activities and adjusted funds flow can be found in this MD&A. Adjusted funds flow per share is calculated using the weighted average number of shares for the period.

This MD&A also contains the terms “net debt”, “total net debt”, and “adjusted working capital deficiency”, which also are not recognized measures under GAAP. Therefore reference to total net debt, net debt and adjusted working capital deficiency may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, deferred capital obligations, long-term risk management contract liabilities, decommissioning liabilities, and deferred tax liabilities. Total net debt includes the adjusted working capital deficiency, long term loans receivable, the liability component of the Convertible Debentures (as defined below), current Credit Facilities and long term Credit Facilities. Net debt excludes the liability component of the Convertible Debentures. The adjusted working capital deficiency is a non-GAAP measure calculated as net working capital deficiency excluding current risk management contract assets and liabilities, current portion of other deferred liabilities, current portion of decommissioning liability and the current Credit Facilities. Management believes these measures are useful supplementary measures of the total amount of current and long-term debt.

FORWARD LOOKING STATEMENTS: Certain information contained herein and in the accompanying report to shareholders may contain forward looking statements within the meaning of applicable securities laws. The use of any of the words “position”, “continue”, “opportunity”, “expect”, “plan”, “maintain”, “estimate”, “assume”, “target”, “believe” “forecast”, “intend”, “strategy”, “will”, “elect”, “anticipate”, “enhance” and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this document contains forward-looking statements concerning management's assessment of future plans, the expectation that operational efficiencies achieved through 2017 will be enduring, the percent of forecast 2018 natural gas volumes hedged, the percent of forecast 2018 natural gas volumes subject to AECO pricing, the percent of forecast 2018 natural gas production volumes subject to hedges or market diversification in 2018 and 2019, the expectation that the Company's risk management strategy provides reduced price volatility, the expectation that the Phase 2 expansion project of the Alder Flats Plant remains on time and on budget, the capacity of the Alder Flats Plant upon completion of Phase 2, expected timing for full commissioning of the Phase 2 expansion, Bellatrix's expected net ownership capacity from Phase 2 of the Alder Flats Plant, expected benefits of completion of the Alder Flats Plant including reductions in production expenditures, increased liquids extraction and expected improvements in corporate profit margins and cash flow, expected capital costs remaining for the Phase 2 expansion, the expectation that after completion of Phase 2 of the Alder Flats Plant the majority of Bellatrix's 2018 capital investment will be utilized directly in drilling, completion and production addition activities with minimal capital required for facilities and infrastructure projects over the near term, forecast 2018 production expenditure, expected details of the Company's 2018 capital budget, Bellatrix's intent to remain highly focused on key business objectives of maintaining financial strength and liquidity, and optimizing capital investments in the current challenging commodity price environment, the intent of Bellatrix to continually monitor its capital spending program in light of prevailing commodity prices and the United States/Canadian dollar exchange rate with the aim of ensuring the Company will be able to meet future anticipated obligations incurred from normal ongoing operations and reclamation expenditures with adjusted funds flow and borrowings under its Credit Facilities, as necessary, the expected future sources to raise capital, the intent that the 2018 capital budget will remain flexible throughout the year, the intent that Bellatrix will manage the Company's capital investment program near the lower end of the capital guidance range, Bellatrix's strategic objectives for the Company's planned 2018 development activity, the intent that the 2018 drilling program will be focused on Spirit River liquids rich natural gas investment opportunities and higher liquids weighted opportunities in the Cardium play, the expectation that Bellatrix will be able to accelerate or decelerate capital expenditures throughout the year, the expectation that the Company may enhance adjusted funds flow in 2018 through optimal delivery of production volumes during periods of stronger commodity prices by leveraging Bellatrix’s controlled infrastructure and firm service delivery capacity, guidance relating to 2018 average daily production, average production mix, net capital expenditures and production expense, Bellatrix's strategic priority continued to be focused on profitable resource development in the Spirit River liquids rich play while maintaining financial strength and liquidity, expected sensitivities to changes in commodity prices, interest rates and exchange rates. To the extent that any forward-looking information contained herein constitute a financial outlook, they were approved by management on March 13, 2018 and are included herein to provide readers with an understanding of the anticipated funds available to Bellatrix to fund its operations and readers are cautioned that the information may not be appropriate for other purposes. Forward-looking statements necessarily involve risks, including, without limitation, 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, actions taken by the Company's lenders that reduce the Company's available credit and ability to access sufficient capital from internal and external sources. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix’s future operations. Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance

Bellatrix Exploration Ltd. 40

should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company 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 the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company 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 the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. 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). Furthermore, the forward looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

Bellatrix Exploration Ltd. 41

EX-13.3

Exhibit 13.3

MANAGEMENT'S REPORT TO SHAREHOLDERS

Management’s Responsibility for Financial Statements

The management of Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) is responsible for the preparation and integrity of the accompanying financial statements and all other information contained in this report. The financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include amounts that are based on management's informed judgments and estimates where necessary.

The Company has established internal accounting control systems which are designed to safeguard assets from loss or unauthorized use and ensure the accuracy of the Company’s accounting records. The Board of Directors, through its Audit Committee, monitors management's financial and accounting policies and practices and the preparation of these financial statements. The Audit Committee meets periodically with the external auditors and management to review the work of each and the propriety of the discharge of their responsibilities.

The Audit Committee reviews the financial statements of the Company with management and the external auditors prior to submission to the Board of Directors for final approval. The external auditors have full and free access to the Audit Committee to discuss auditing and financial reporting matters. The Audit Committee reviews the independence of the external auditors and pre-approves audit and permitted non-audit services. The shareholders have appointed KPMG LLP as the external auditors of the Company. The Report of Independent Registered Public Accounting Firm to the Board of Directors and shareholders, which describes the scope of their examination and expresses their opinion, is included with the financial statements for the year ended December 31, 2017.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13(a) – 15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification and Disclosure in Issuer's Annual and Interim filings. Internal control over financial reporting is designed by, or designed under the supervision of, our President and CEO and our Executive Vice President and CFO, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Under the supervision and with the participation of our management, including our President and CEO and our Executive Vice President and CFO, an evaluation of the design and effectiveness of our internal control over financial reporting was conducted as of December 31, 2017 based on the framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control – Integrated Framework (2013). Based on this evaluation, management concluded that as of December 31, 2017 the Company did maintain effective internal control over financial reporting.

The effectiveness of internal control over financial reporting as of December 31, 2017 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm, which is included with the financial statements for the year ended December 31, 2017.

(signed) “Brent A. Eshleman”	(signed) “Maxwell (Max) Lof”
Brent A. Eshleman, P.Eng.	Maxwell (Max) Lof
President and CEO	Executive Vice President and CFO

March 13, 2018

Bellatrix Exploration Ltd. 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Bellatrix Exploration Ltd.

Opinion on the Financial Statements

We have audited the accompanying financial statements of Bellatrix Exploration Ltd. (the “Company”), which comprise the balance sheets as at December 31, 2017 and December 31, 2016, the statements of profit (loss) and comprehensive income (loss), shareholders’ equity and cash flows for the years then ended, and the related notes, comprising a summary of significant accounting policies and other explanatory information (collectively referred to as the 'financial statements').

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2017 and December 31, 2016, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Report on Internal Control Over Financial Reporting

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the Company’s internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 13, 2018 expressed an unqualified (unmodified) opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

A - Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

B - Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement, whether due to error or fraud. Those standards also require that we comply with ethical requirements, including independence. We are required to be independent with respect to the Company in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada, the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We are a public accounting firm registered with the PCAOB.

An audit includes performing procedures to assess the risks of material misstatements of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included obtaining and examining, on a test basis, audit evidence regarding the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of thefinancial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances.

An audit also includes evaluating the appropriateness of accounting policies and principles used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a reasonable basis for our audit opinion.

(signed) "KPMG LLP"

Chartered Professional Accountants

We have served as the Company's auditors since 1996.

Calgary, Canada

March 13, 2018

Bellatrix Exploration Ltd. 2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Bellatrix Exploration Ltd.

Opinion on Internal Control Over Financial Reporting

We have audited Bellatrix Exploration Ltd.’s (the “Company”) internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Report on the Financial Statements

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements of the Company, which comprise the balance sheets as at December 31, 2017 and December 31, 2016, the statements of profit (loss) and comprehensive income (loss), shareholders’ equity and cash flows for the years then ended, and the related notes, comprising a summary of significant accounting policies and other explanatory information (collectively referred to as the “financial statements”), and our report dated March 13, 2018 expressed an unmodified (unqualified) opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB and in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

(signed) "KPMG LLP"

Chartered Professional Accountants

Calgary, Canada

March 13, 2018

Bellatrix Exploration Ltd. 3

BELLATRIX EXPLORATION LTD.

BALANCE SHEETS

(expressed in Canadian dollars)

As at December 31,

($000s)	2017			2016
ASSETS
Current assets
Accounts receivable (note 17)	$	45,672		$	39,227
Current portion of loans receivable (note 7)	—			6,225
Deposits and prepaid expenses	3,709			5,205
Marketable securities	—			4,322
Current portion of risk management asset (note 17)	31,910			—
	81,291			54,979
Risk management asset (note 17)	1,213			445
Loans receivable (note 7)	—			8,775
Deferred taxes (note 13)	48,298			63,713
Exploration and evaluation assets (note 6)	22,731			29,246
Property, plant and equipment (note 7)	1,187,390			1,296,572
Total assets	$	1,340,923		$	1,453,730
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	73,307		$	78,695
Current portion of other deferred liabilities (note 10)	20,790			26,064
Current portion of risk management liability (note 17)	4,468			13,936
Current portion of Credit Facilities (note 8)	—			19,143
Current portion of decommissioning liability (note 9)	1,924			—
	100,489			137,838
Credit Facilities (note 8)	52,066			—
Convertible Debentures (liability component) (note 8)	39,426			37,420
Senior Notes (note 8)	305,409			324,691
Risk management liability (note 17)	3,422			2,646
Other deferred liabilities (note 10)	7,402			24,873
Decommissioning liabilities (note 9)	58,687			62,844
Total liabilities	566,901			590,312
SHAREHOLDERS’ EQUITY
Shareholders’ capital (note 11)	1,068,377			1,068,084
Convertible Debentures (equity component) (note 8)	7,818			7,818
Contributed surplus	56,092			54,418
Retained earnings (deficit)	(358,265		)	(266,902		)
Total shareholders’ equity	774,022			863,418
Total liabilities and shareholders’ equity	$	1,340,923		$	1,453,730

COMMITMENTS(note 18)

See accompanying notes to the financial statements.

On behalf of the Board of Directors

(signed) “Keith S. Turnbull”	(signed) “W.C. (Mickey) Dunn”
Keith S. Turnbull, B.Sc., CPA, CA	W.C. (Mickey) Dunn
Director, Chairman Audit Committee	Director, Chairman of the Board

Bellatrix Exploration Ltd. 4

BELLATRIX EXPLORATION LTD.

STATEMENTS OF PROFIT (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(expressed in Canadian dollars)

For the years ended December 31,

($000s, except per share amounts)	2017			2016
REVENUES
Petroleum and natural gas sales	$	243,825		$	220,124
Royalties	(23,961		)	(18,636		)
Other income	5,574			7,750
Total revenues net of royalties	225,438			209,238
Realized gain on commodity contracts (note 17)	31,324			19,892
Unrealized gain (loss) on commodity contracts (note 17)	45,238			(29,525		)
Revenues net of royalties and commodity contracts	302,000			199,605
EXPENSES
Production	111,816			113,589
Transportation	23,549			12,108
General and administrative	29,377			19,919
Loss on marketable securities	461			678
Share-based compensation (note 12)	532			3,784
Depletion and depreciation (note 7)	120,652			136,518
Impairment (reversal) (note 7)	13,150			(264,000		)
Loss (gain) on dispositions (note 7)	56,672			170,667
	356,209			193,263
NET PROFIT (LOSS) BEFORE FINANCE AND TAXES	(54,209		)	6,342
Finance expenses (note 14)	39,240			48,063
Realized (gain) loss on foreign exchange (note 15)	797			(277		)
Unrealized (gain) loss on foreign exchange (note 15)	(18,298		)	(7,918		)
NET PROFIT (LOSS) BEFORE TAXES	(75,948		)	(33,526		)
TAXES
Deferred tax expense (recovery) (note 13)	15,415			(6,858		)
NET PROFIT (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$	(91,363	)	$	(26,668	)
Net profit (loss) per share (note 16)
Basic	$(1.85)			$(0.62)
Diluted	$(1.85)			$(0.62)

See accompanying notes to the financial statements.

Bellatrix Exploration Ltd. 5

BELLATRIX EXPLORATION LTD.

STATEMENTS OF SHAREHOLDERS’ EQUITY

(expressed in Canadian dollars)

For the year ended December 31,

($000s)	2017			2016
SHAREHOLDERS’ CAPITAL
Common shares (note 11)
Balance, beginning of year	$	1,068,084		$	1,000,100
Issued for property acquisition, net of issue costs and tax effect	—			29,080
Issued for cash on equity issue	—			40,400
Share issue costs on equity issue, net of tax effect	4			(1,781		)
Share-based compensation awards	289			285
Balance, end of year	1,068,377			1,068,084
CONVERTIBLE DEBENTURES (EQUITY COMPONENT) (note 8)
Balance, beginning of year	7,818			—
Conversion feature of Convertible Debentures issued, net of tax effect	—			7,818
Balance, end of year	7,818			7,818
CONTRIBUTED SURPLUS
Balance, beginning of year	54,418			50,706
Share-based compensation expense (note 12)	2,233			4,463
Adjustment of share-based compensation expense for forfeitures of unvested share options	(559		)	(751		)
Balance, end of year	56,092			54,418
RETAINED EARNINGS (DEFICIT)
Balance, beginning of year	(266,902		)	(240,234		)
Net profit (loss)	(91,363		)	(26,668		)
Balance, end of year	(358,265		)	(266,902		)
TOTAL SHAREHOLDERS’ EQUITY	$	774,022		$	863,418

See accompanying notes to the financial statements.

Bellatrix Exploration Ltd. 6

BELLATRIX EXPLORATION LTD.

STATEMENTS OF CASH FLOWS

(expressed in Canadian dollars)

For the year ended December 31,

($000s)	2017			2016
Cash provided from (used in):
CASH FLOW FROM (USED IN) OPERATING ACTIVITIES
Net profit (loss)	$	(91,363	)	$	(26,668	)
Adjustments for:
Depletion and depreciation (note 7)	120,652			136,518
Impairment (reversal) and (gain) loss on dispositions (note 7)	69,822			(93,333		)
Accretion on decommissioning obligations (note 9)	1,287			1,713
Non-cash financing and accretion (note 8)	4,803			3,323
Share-based compensation (note 12)	699			3,936
Unrealized (gain) loss on commodity contracts (note 17)	(45,238		)	29,525
Unrealized foreign exchange (gain) loss (note 15)	(18,298		)	(7,918		)
Loss on marketable securities	461			678
Deferred tax expense (recovery) (note 13)	15,415			(6,858		)
Decommissioning costs incurred (note 9)	(2,758		)	(2,927		)
Change in non-cash working capital (note 20)	(272		)	(443		)
	55,210			37,546
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
Issuance of share capital, net of issue costs (note 11)	4			37,825
Issuance of Convertible Debentures, net of issue costs (note 8)	—			47,610
Issuance of Senior Notes, net of issue costs (note 8)	—			(55		)
Settlement of share based payments	(1,246		)	(730		)
Advances from (repayment of) loans and borrowings	32,923			(321,601		)
Financing obligations (note 10)	(7,558		)	(3,997		)
Deferred lease inducements (note 10)	(366		)	(340		)
Deferred capital obligations (note 10)	(14,693		)	(3,291		)
Change in non-cash working capital (note 20)	16,353			601
	25,417			(243,978		)
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
Expenditure on exploration and evaluation assets (note 6)	(1,664		)	(2,349		)
Additions to property, plant and equipment (note 7)	(121,586		)	(76,531		)
Proceeds on sale of property, plant and equipment	48,370			296,638
Proceeds on sale of marketable securities	3,861			—
Change in non-cash working capital (note 20)	(9,608		)	(11,326		)
	(80,627		)	206,432
Change in cash	—			—
Cash, beginning of year	—			—
Cash, end of year	$	—		$	—
Cash paid:
Interest	$	33,930		$	40,464
Taxes	—			—

See accompanying notes to the financial statements.

Bellatrix Exploration Ltd. 7

NOTES TO THE FINANCIAL STATEMENTS

(expressed in Canadian dollars)

1. CORPORATE INFORMATION

Bellatrix Exploration Ltd. (the “Company” or “Bellatrix”) is a publicly traded 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 with highly concentrated operations in west central Alberta, principally focused on profitable development of the Spirit River liquids rich natural gas play.

Common shares of Bellatrix trade on the Toronto Stock Exchange (“TSX”) and on the New York Stock Exchange (“NYSE”) under the symbol “BXE”.

Bellatrix was incorporated in Alberta, Canada and the Company’s registered office and principal place of business is located at 1920, 800 – 5th Avenue SW, Calgary, Alberta, Canada, T2P 3T6.

2. BASIS OF PREPARATION 

a. Statement of compliance

These financial statements (“financial statements”) were authorized by the Board of Directors on March 13, 2018. The Company prepared these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). 

b. Basis of measurement

The financial statements are presented in Canadian dollars, the Company’s functional currency, and have been prepared on the historical cost basis except for derivative financial instruments, marketable securities and liabilities for cash-settled share-based payment arrangements measured at fair value. The financial statements have, in management’s opinion, been properly prepared using careful judgment and reasonable limits of materiality, and within the framework of the significant policies summarized in note 3. Significant estimates and judgments used in the preparation of the financial statements are detailed in note 4.

3. SIGNIFICANT ACCOUNTING POLICIES

a. Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title to the products transfers to the purchasers based on volumes delivered and contracted delivery points and prices. Revenue is measured at the fair value of the consideration received or receivable. Revenue from the sale of crude oil, natural gas, condensate and natural gas liquids (“NGLs”) (prior to deduction of transportation costs) is recognized when all of the following conditions have been satisfied:

• Bellatrix has transferred the significant risks and rewards of ownership of the goods to the purchaser;

• Bellatrix retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;

• the amount of revenue can be measured reliably;

• it is probable that the economic benefits associated with the transaction will flow to Bellatrix; and

• the costs incurred or to be incurred in respect of the transaction can be measured reliably.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements and is included with petroleum and natural gas sales.

Capital processing charges to other entities for use of facilities owned by the Company are recognized as revenue as they accrue in accordance with the terms of the service agreements and are presented as other income.

b. Transportation

Costs paid by Bellatrix for the transportation of crude oil, natural gas, condensate and NGLs to the point of title transfer are recognized when the transportation is provided.

Bellatrix Exploration Ltd. 8

c. Joint Interests

A portion of the Company’s exploration and development activities are conducted jointly with others. The joint interests are accounted for on a proportionate consolidation basis and as a result, the financial statements reflect only the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows from these activities.

d. Property, Plant and Equipment and Exploration and Evaluation Assets

I. Pre-exploration expenditures

Expenditures made by the Company before acquiring the legal right to explore in a specific area do not meet the definition of an asset and therefore are expensed by the Company as incurred.

II. Exploration and evaluation expenditures

Once the legal right to explore has been acquired, costs incurred are capitalized as intangible exploration and evaluation assets (“E&E). These costs include, but are not limited to, exploration license expenditures, leasehold property acquisition costs, evaluation costs, including drilling costs directly attributable to an identifiable well and directly attributable general and administrative costs. These costs are accumulated in cost centres by property and are not subject to depletion, until technical feasibility and commercial viability have been determined. 

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, or if facts and circumstances suggest that the carrying amount is unlikely to be recovered. 

III. Developing and production costs

Items of property, plant and equipment (“PP&E”), which include oil and gas development and production assets, are measured at cost less accumulated depletion, depreciation and accumulated impairment losses net of recoveries.

Gains and losses on disposal of an item of PP&E, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of PP&E, and are recognized within the Statements of Profit (Loss) and Comprehensive Income (Loss).

IV. Joint arrangements

The Company has entered into certain joint arrangements whereby the joint arrangement partner will earn a working interest on certain properties through the payment of a pre-determined portion of the costs of drilling, completing and equipping. A gain on disposition for each well is recognized to account for the disposal of the pre-payout working interest earned by the partner on the well, as described under "Dispositions" below. Bellatrix has property, plant and equipment assets that are subject to these arrangements. 

V. Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a well, field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

VI. Depletion and depreciation

Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes in relation to total estimated proven and probable reserves as determined annually by independent engineers in accordance with National Instrument 51-101, Standards of Disclosure of Oil and Gas Activities. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Calculations for depletion are based on total capitalized costs plus estimated future development costs of proven and probable undeveloped reserves less the estimated net realizable value of production equipment and facilities after the proved and probable reserves are fully produced.

Bellatrix Exploration Ltd. 9

Depreciation is recognized on significant facilities to expense the cost of significant components of assets less their residual values over their useful lives. Phase 1 of the Alder Flats Plant and associated equipment are depreciated using the straight-line method over estimated useful lives as follows:

• General plant and processing equipment - 40 years

• Other properties and equipment - 10 years

• Turnarounds - 5 years

Costs of facilities under construction related to Phase II of the Alder Flats Plant as at December 31, 2017 were excluded from depreciation calculations.

Depreciation of office furniture and equipment is provided for on a 20% declining balance basis.

Depreciation methods, useful lives and residual values are reviewed at each reporting date and, if necessary, any changes would be accounted for prospectively.

VII. Dispositions

Gains on disposal of an item of PP&E or E&E are determined by comparing the proceeds from disposal with the carrying amount of PP&E or E&E and are recognized separately in the Statements of Profit (Loss) and Comprehensive Income (Loss). Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reasonably measured. Where the exchange is measured at fair value, a gain or loss is recognized in the Statements of Profit (Loss) and Comprehensive Income (Loss).

e. Impairment and Impairment Reversal

I. Financial assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. All impairment losses are recognized in profit or loss.

II. Non-financial assets

Developing and producing assets are assessed for impairment if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. The impairment test is performed at the asset or CGU level.

The recoverable amount of an asset or a cash-generating unit ("CGU") is the greater of its value in use (“VIU”) and its fair value less costs to sell (“FVLCS”). FVLCS is determined to be the amount for which the asset could be sold in an arm’s length transaction. FVLCS can be determined by using an observable market metric or by using discounted future net cash flows of proved and probable reserves using forecasted prices and costs. VIU is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in the Company’s Statement of Profit (Loss) and Comprehensive Income (Loss) in the period in which it occurs.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

E&E assets are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to producing assets (oil and natural gas interests in PP&E). E&E assets are grouped together with the Company’s CGU’s when they are assessed for impairment.

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f. Provisions

Provisions are recognized when the Company has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Provisions are determined by discounting the expected cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability, if the risks have not been incorporated into the estimate of cash flows. The increase in the provision due to the passage of time is recognized within finance expense.

I. Decommissioning liabilities

The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. A provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation at the balance sheet date. Changes in the present value of the estimated expenditure are reflected as an adjustment to the liability and the relevant asset. The accretion or unwinding of the discount on the decommissioning provision is recognized as a finance expense. Actual costs incurred upon settlement of the decommissioning liabilities are charged against the provision to the extent the provision was recognized.

II. Environmental liabilities

The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Any amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

g. Share-based Payments 

I. Equity-settled transactions

Bellatrix accounts for options issued under the Company’s share option plan by reference to the fair value of the equity instruments granted. The fair value of each share option is estimated on the date of the grant using the Black-Scholes options pricing model and charged to earnings over the vesting period with a corresponding increase to contributed surplus. The Company estimates a forfeiture rate on the grant date and the rate is adjusted to reflect the actual number of options that actually vest. The expected life of the options granted is adjusted, based on the Company’s best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.

II. Cash-settled transactions

The Company’s Deferred Share Unit Plan (the “DSU Plan”) is accounted for as a cash settled share based payment plan in which the fair value of the amount payable under the DSU Plan is recognized as an expense with a corresponding increase in liabilities. The liability is remeasured at each reporting date and at settlement date. Any changes in the fair value of the liability are recognized in profit or loss.

Awards under the Award Incentive Plan ("Award Plan") may be settled in cash, in common shares of the Company, or a combination thereof. The Company’s Restricted and Performance Award Plan is accounted for as a cash settled share based payment plan in which the fair value of the amounts payable under the Award Plan are recognized incrementally as an expense over the vesting period, with a corresponding change in liabilities. 

h. Income Taxes

Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity. 

I. Current tax

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid, to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted, or substantively enacted, by the date of the statement of financial position.

Bellatrix Exploration Ltd. 11

II. Deferred tax 

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted, or substantively enacted, by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

i. Financial Instruments

All financial instruments, including all derivatives, are recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in income. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income and reclassified to income when derecognized or impaired. The Company has the following classifications:

Financial Assets and Liabilities	Category	Subsequent Measurement
Accounts receivable	Loans and receivables	Amortized cost
Loans receivable	Loans and receivables	Amortized cost
Marketable securities	Held-for-trading	Fair value through profit or loss; Level 1
Commodity risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Foreign exchange risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Accounts payable and accrued liabilities	Other liabilities	Amortized cost
Deferred share units	Other liabilities	Fair value through profit or loss; Level 1
Restricted awards	Other liabilities	Fair value through profit or loss; Level 1
Performance awards	Other liabilities	Fair value through profit or loss; Level 2
Credit Facilities	Other liabilities	Amortized cost
Senior Notes	Other liabilities	Amortized cost
Convertible Debentures	Other liabilities	Amortized cost
Deferred capital obligation	Other liabilities	Amortized cost
Finance lease obligation	Other liabilities	Amortized cost

Financial instruments measured at fair value on the balance sheet require classification into one of the following levels of the fair value hierarchy:

Level 1 – Valuation based on quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 – Valuation based on inputs other than quoted prices included in level 1, that are observable directly or indirectly.

Level 3 – Valuation based on inputs that are not based on observable market data.

The fair value hierarchy level at which a fair value measurement is categorized is determined on the basis of the lowest level input that is significant to the fair value measurement in its entirety. The Company has categorized its financial instruments that are fair valued on the balance sheet according to the fair value hierarchy.

Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument using the effective interest rate method.

The Company utilizes financial derivatives and commodity sales contracts requiring physical delivery to manage the price risk attributable to anticipated sale of petroleum and natural gas production and foreign exchange exposures. The Company does not enter into derivative financial instruments for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, financial derivatives are classified as fair value through profit or loss and are recorded on the balance sheet at fair value, with fair value changes recorded in profit or loss.

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The derivative financial instruments are initiated within the guidelines of the Company’s corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet, to specific firm commitments, or forecasted transactions.

The Company accounts for its commodity sales and purchase contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items, in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, physical sales and purchase contracts are not recorded at fair value on the balance sheet. Settlements on these physical sales and purchase contracts are recognized in petroleum and natural gas sales.

j. Compound Financial Instruments

The Company's compound financial instruments are comprised of its Convertible Debentures that can be converted to common shares at the option of the holder. The number of shares to be issued does not vary with changes in fair value. 

The liability component of the Convertible Debentures is recognized initially at the fair value of a similar liability that does not have an equity conversion option. The equity component is recognized initially as the difference between the fair value of the Convertible Debenture and the fair value of the liability component. Any directly attributable transaction costs are allocated to the liability and equity components in proportion to their initial carrying amounts.

Subsequent to initial recognition, the liability component of the Convertible Debentures is measured at amortized cost using the effective interest method. The equity component of the Convertible Debentures is not re-measured subsequent to initial recognition.

k. Lease Obligations

Leases which effectively transfer substantially all of the risks and rewards of ownership to the Company are classified as finance leases and are accounted for as an acquisition of an asset and an assumption of an obligation at the inception of the lease, measured as the present value of minimum lease payments to a maximum of the asset’s fair value. The asset is amortized in accordance with the Company’s depletion and depreciation policy. The obligations recorded under finance lease payments are reduced by the lease payments made.

Assets held under other leases are classified as operating leases and are not recognized in the balance sheet. Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. Lease incentives received from landlords are deferred and recognized as an integral part of the total lease expense, over the term of the lease.

l. Basic and Diluted per Share Calculations

Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. The Company uses the treasury share method to determine the dilutive effect of share options. Under the treasury share method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted per share amounts.

m. Finance Income and Expenses

Finance income is recognized as it accrues in profit or loss, using the effective interest method. Finance expense comprises interest expense on borrowings, amortization of financing costs and discounts, accretion of the discount on provisions and impairment losses recognized on financial assets.

n. Borrowing Costs

Borrowing costs incurred for the construction of qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use. All other borrowing costs are recognized in profit or loss using the effective interest method. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Company’s outstanding borrowings during the period.

o. Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with original maturities of three months or less.

p. Business Combinations

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities and contingent liabilities assumed are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the aggregate consideration transferred, measured at the acquisition date fair value. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in profit or loss. If the cost of the acquisition is more than the fair

Bellatrix Exploration Ltd. 13

value of the net assets acquired, the difference is recognized on the balance sheet as goodwill. Acquisition costs incurred are expensed.

q. Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses are translated at the period average rates of exchange. Translation gains and losses are included in earnings in the period in which they arise.

Bellatrix’s functional and presentation currency is Canadian dollars.

4. CRITICAL JUDGMENTS AND ACCOUNTING ESTIMATES

The financial statements of the Company have been prepared by management in accordance with IFRS. The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, and contingent liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period and accompanying notes. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.

a. Critical Accounting Judgments

I. Oil and Gas Reserves

Reserves and resources are used in the units of production calculation for depletion, depreciation and amortization, and the impairment analysis which affect net profit or loss. There are numerous uncertainties inherent in estimating oil and gas reserves. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net profit as further information becomes available and as the economic environment changes.

II. Identification of CGUs

Bellatrix’s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, geology, production profile and infrastructure of their assets.

III. Impairment Indicators and Impairment Reversal 

Judgment is required to assess when impairment indicators exist and impairment testing is required with respect to exploration and evaluation assets and property, plant and equipment.

IV. Joint Arrangements

Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint control, the Company considers whether unanimous consent is required to direct the activities that significantly affect the returns of the arrangement, such as the capital and operating activities of the arrangement. Additionally, the Company assesses the rights and obligations arising from the arrangement by considering its governance structure, legal form, and terms agreed upon by the parties sharing control, including the contractual rights of each partner, dispute resolution procedures, termination provisions, and procedures for subsequent transactions in its determination of joint control.

Once joint control has been established, judgment is also required to classify the joint arrangement. The type of joint arrangement is determined through analysis of the rights and obligations arising from the arrangement by considering its legal structure, legal form and terms agreed upon by the parties sharing control. An arrangement that is not structured through a separate vehicle in which the controlling parties have rights to the assets, revenues and substantially all of the economic benefits generated through the arrangement, in addition to obligations for the liabilities and expenses, is classified as a joint operation. An arrangement in which these criteria are not met is classified as a joint venture.

V. Non-monetary Transactions

Judgment is required to determine whether non-monetary transactions have commercial substance.

Bellatrix Exploration Ltd. 14

b. Critical Estimates and Assumptions

I. Recoverability of asset carrying values

The Company assesses its oil and gas properties, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date. 

The assessment of any impairment of property, plant and equipment is dependent upon estimates of recoverable amount that take into account factors such as reserves, future estimated commodity prices, royalties and costs, economic and market conditions, timing of cash flows, the useful lives of assets and their related salvage values. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company’s assets in future periods.

II. Decommissioning obligations

Provisions for decommissioning obligations associated with the Company’s drilling operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology. 

III. Income taxes 

Deferred tax assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.

IV. Business combinations 

The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or goodwill. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.

5. NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

The following pronouncements from the International Accounting Standards Board (“IASB”) are applicable to Bellatrix and will become effective for future reporting periods, but have not yet been adopted:

IFRS 9 - “Financial Instruments”, which is the result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. This standard is effective for annual periods beginning on or after January 1, 2018 with different transitional arrangements depending on the date of initial application.

The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the requirements of IAS 39; however, where the fair value option is applied to financial liabilities, any change in fair value resulting from an entity's own credit risk is recorded in other comprehensive income rather than the statement of income. Bellatrix has determined the adoption of IFRS 9 will not result in any material changes to the classification of financial assets and liabilities or to the measurement and carrying values of the Company's financial instruments.

In addition, IFRS 9 introduces a new expected credit loss model for calculating impairment of financial assets, replacing the incurred loss impairment model required by IAS 39. Bellatrix has determined that the new impairment model will not result in material changes to the valuation of its financial assets on the adoption of IFRS 9. Bellatrix does not currently apply hedge accounting to its financial instrument contacts and does not currently intend to apply hedge accounting to any of its derivative contracts upon adoption of IFRS 9.

IFRS 15 - “Revenue from Contracts with Customers”, provides a five-step model to be applied to all revenue contracts with customers. The standard specifies when an entity will recognize revenue and provides guidance regarding disclosures relating to revenue

Bellatrix Exploration Ltd. 15

recognition. IFRS 15 is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018.

Bellatrix intends to adopt IFRS 15 using a modified transition approach on January 1, 2018. The Company has completed reviewing its various revenue streams and underlying contracts with customers. It has been concluded the adoption of IFRS 15 will not have a material impact on Bellatrix's net income and financial position. However, Bellatrix will expand the disclosures in the notes to its financial statements as prescribed by IFRS 15, including disclosing the Company's disaggregated revenue streams by product type.

IFRS 16 - "Leases”, replaces IAS 17 Leases. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. All contracts that meet the definition of a lease under IFRS 16, including those presently accounted for as operating leases, will be recorded on the balance sheet. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. The extent of the impact of the adoption of IFRS 16 has not yet been determined.

6. EXPLORATION AND EVALUATION ASSETS

($000s)
Cost
Balance, December 31, 2015	$	87,919
Additions	2,349
Dispositions	(31,176		)
Transfer to oil and natural gas properties	(29,846		)
Balance, December 31, 2016	29,246
Additions	1,664
Dispositions	(7,843		)
Transfer to oil and natural gas properties	(336		)
Balance, December 31, 2017	$	22,731

Exploration and evaluation ("E&E") assets consist of Bellatrix's exploration projects which are pending the determination of proved or probable reserves and production.

7.PROPERTY, PLANT AND EQUIPMENT

($000s)	Oil and Natural  Gas Properties			Operated Facilities			Office Furniture and Equipment		Total
Cost
Balance, December 31, 2015	$	2,565,698		$	105,035		$	26,190	$	2,696,923
Additions	61,002			9,590			230		70,822
Acquisition	29,735			—			—		29,735
Transfer from exploration and evaluation assets	29,846			—			—		29,846
Joint venture wells	6,687			—			—		6,687
Disposals	(658,014		)	(58,565		)	—		(716,579		)
Balance, December 31, 2016	2,034,954			56,060			26,420		2,117,434
Additions	111,485			12,058			1,888		125,431
Transfer from exploration and evaluation assets	336			—			—		336
Disposals	(298,102		)	—			—		(298,102		)
Balance, December 31, 2017	$	1,848,673		$	68,118		$	28,308	$	1,945,099

Bellatrix Exploration Ltd. 16

($000s)	Oil and Natural  Gas Properties			Operated Facilities			Office Furniture and Equipment		Total
Accumulated depletion, depreciation and impairment losses
Balance, December 31, 2015	$	1,211,214		$	1,829		$	9,031	$	1,222,074
Charge for the year	131,468			1,862			3,188		136,518
Disposals	(272,026		)	(1,704		)	—		(273,730		)
Impairment (reversal)	(264,000		)	—			—		(264,000		)
Balance, December 31, 2016	806,656			1,987			12,219		820,862
Charge for the year	116,693			1,122			2,837		120,652
Disposals	(196,955		)	—			—		(196,955		)
Impairment	$	13,150		$	—		$	—	$	13,150
Balance, December 31, 2017	$	739,544		$	3,109		$	15,056	$	757,709
Carrying amounts
Balance, December 31, 2016	$	1,228,298		$	54,073		$	14,201	$	1,296,572
Balance, December 31, 2017	$	1,109,129		$	65,009		$	13,252	$	1,187,390

Bellatrix has included $832 million (2016: $950 million) for future development costs and excluded $46.6 million (2016: $46.0 million) for estimated salvage from the depletion and depreciation calculation for the three months ended December 31, 2017. Operated facilities include capital associated with Phase 1 of the Bellatrix O’Chiese Nees-Ohpawganu’ck deep-cut gas plant at Alder Flats (the “Alder Flats Plant”), as well as capital associated with Phase 2 and related infrastructure. Costs of facilities under construction of $39.7 million related to Phase 2 of the Alder Flats Plant as at December 31, 2017 were excluded from depreciation calculations.

Dispositions

During the third quarter of 2017, Bellatrix completed the sale of certain non-core oil and gas properties in the West Pembina area of Alberta for gross proceeds of $16.0 million, effective July 1, 2017. Bellatrix recorded a loss of $18.6 million on the sale.

During the second quarter of 2017, Bellatrix completed the sale of certain non-core oil and gas properties in the Strachan area of Alberta for gross proceeds of $34.5 million, effective April 1, 2017. Bellatrix recorded a loss of $37.0 million on the sale. Additionally, in the second quarter, Bellatrix transferred certain production facilities and infrastructure to a third party midstream company in exchange for proceeds of $20 million. Under the terms of the agreement, Bellatrix will have exclusive access to, and operatorship of, the infrastructure. Bellatrix recorded a deferred capital obligation of $20 million in the second quarter of 2017 for the production facilities. Work on the production facilities was completed in the fourth quarter of 2017 resulting in a deferred capital obligation of nil as at December 31, 2017.

During the second quarter of 2016, Bellatrix sold certain production facilities to a third party midstream company for proceeds of $75 million effective May 3, 2016. Pursuant to the agreement, Bellatrix maintains operatorship and preferential access to the facilities for its operated production volumes and will pay an annual rental fee over the eight years duration of the agreement. In addition, Bellatrix retains, at its sole discretion, the option to repurchase the facilities at any time during the agreement period. Payments for use of the facilities are treated as an operating lease and included in Bellatrix’s corporate commitments.

During the third quarter of 2016, Bellatrix completed a $112.5 million disposition of a 35% working interest in the Alder Flats Plant (“Alder Flats Plant Sale”) to Keyera Partnership ("Keyera"). As part of the transaction, Bellatrix and Keyera entered into a midstream services and governance agreement pursuant to which Bellatrix will have exclusive access to the purchased capacity (approximately 80.5 MMcf/d post commissioning of Phase 2) for a term of 10 years, and will remain the operator of the Alder Flats Plant.  In exchange for granting 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 Alder Flats Plant. Following completion of the transaction, Bellatrix retains a 25% interest in the Alder Flats Plant, and has the option to reacquire a 5% interest in the Alder Flats Plant near the end of the final year of the agreement at a cost of $8 million.

Bellatrix recorded a gain on disposition of $9.8 million in relation to the Company’s disposed working interest in Phase 1 of the Alder Flats Plant and a deferred gain of $10.7 million related to the prepayment for the working interest in Phase 2 of the Alder Flats Plant which is currently under construction. Bellatrix recorded a deferred capital obligation for the remaining Phase 2 costs to be incurred to construct and commission Phase 2, related to Keyera’s 35% working interest, and a deferred financing obligation. At December 31, 2017, the balances of these obligations are $4.8 million and $1.5 million, respectively and work on the Alder Flats Plant is expected to be completed in the second quarter of 2018.

Bellatrix Exploration Ltd. 17

During the fourth quarter of 2016, Bellatrix completed two asset dispositions. Firstly, Bellatrix completed the Pembina property sale for total consideration of $47 million, consisting of approximately $42 million in cash and 2,171,667 common shares of the purchaser with a fair value of $5 million at the time of sale. Bellatrix recorded a loss of $26.2 million on the disposition. Secondly, Bellatrix completed the Harmattan property sale for total consideration of $80 million including net cash proceeds of approximately $65 million, and a $15 million loan receivable bearing interest at 10%. Bellatrix recorded a loss of $147.7 million on the disposition. The net cash proceeds from the Pembina and the Harmattan property sales were used to reduce the Company's outstanding Credit Facilities.

For the year ended December 31, 2016, the Company recognized total net gains on disposition of $6.7 million, relating to gains on wells drilled under a joint venture agreement that was terminated in December 2016.

For the year ended December 31, 2017, the Company capitalized $7.6 million (2016: $7.0 million) of general and administrative expenses and $0.8 million (2016: $1.4 million) of share-based compensation costs directly related to exploration and development activities.

Business Combination

Bellatrix completed a property acquisition of complementary assets within its core Ferrier area for total consideration of $29.2 million in June 2016, paid through the issuance of 4,109,515 common shares of Bellatrix. Bellatrix assessed the property acquisition and determined it to constitute a business combination under IFRS. The acquired assets consisted of $29.7 million of oil and natural gas properties, the value of which was determined using observable market metrics in addition to $0.5 million of decommissioning liabilities assumed as a result of the acquisition.

Impairment Loss (Reversal)

Bellatrix performed an assessment of possible indicators of impairment or impairment reversal on all of the Company’s CGUs. At December 31, 2017, impairment indicators were identified for the Company’s non-core North Alberta CGU and non-core South Alberta CGU, primarily as a result of a lack of active development plans in the CGUs. No impairment indicators were identified in the Company’s core Central Alberta CGU in 2017.

For the year ended December 31, 2017, a non-cash impairment loss of $12.2 million was recognized in the Company’s non-core North Alberta CGU. The estimated recoverable amount of the North Alberta CGU as at December 31, 2017 was $5.3 million. A non-cash impairment loss of $1.0 million was recognized in the Company’s non-core South Alberta CGU. The estimated recoverable amount of the South Alberta CGU was $1.4 million.

The recoverable amount of the North Alberta and South Alberta CGUs as at December 31, 2017 was determined using a VIU approach, as Bellatrix determined that VIU was greater than FVLCS. VIU was calculated as the net present value of the before-tax cash flows from proved plus probable oil and gas reserves of each CGU based on reserves estimated by Bellatrix’s independent reserve evaluator at December 31, 2017, adjusted for the net present value of the before-tax abandonment and reclamation costs on proved plus probable undeveloped oil and gas reserves.

The VIU of each CGU was based on before-tax discount rates ranging from 15-20% and the following forward commodity price estimates:

Year	EdmontonCrude Ref Oil ($/bbl) (1)	AECO NaturalGas ($/MMBtu) (1)	Butane ($/bbl) (1)	Propane  ($/bbl) (1)	Condensate($/bbl) (1)	CDN$/US$ Exchange Rates(1)
2018	71.36	2.52	51.38	35.68	74.93	1.27
2019	73.44	2.93	52.88	36.72	77.12	1.25
2020	75.47	3.22	54.34	35.85	79.25	1.23
2021	80.49	3.51	57.96	36.22	84.52	1.22
2022	82.38	3.75	59.31	37.07	86.50	1.20
2023	84.22	3.85	60.64	37.90	88.43	1.19
2024	86.01	3.95	61.93	38.70	90.31	1.18
2025	88.85	4.11	63.97	39.98	93.29	1.18
2026	90.62	4.27	65.25	40.78	95.15	1.18
2027	92.43	4.35	66.55	41.60	97.06	1.18
Thereafter	+2% per year	+2% per year	+2% per year	+2% per year	+2% per year	1.18

(1)The InSite price forecasts, effective January 1, 2018.

Bellatrix Exploration Ltd. 18

A 1% increase to the discount rates applied in the impairment calculation for the North Alberta CGU and South Alberta CGU would result in an increase in impairment loss of approximately $0.3 million and $0.1 million, respectively for the year ended December 31, 2017, whereas a 1% decrease to the discount rates applied would result in a corresponding decrease to the impairment loss recognized.

At December 31, 2016, impairments reversal indicators were identified for the Company's core Central Alberta CGU, primarily as a result of a significant increase in the reserves evaluation due to a combination of actual well performance exceeding previous estimates resulting in strong positive technical revisions and infill drilling additions in 2016. Impairment indicators were identified for the Company's non-core South Central CGU given the Company was no longer focused on actively developing these assets. The South Central CGU assets were subsequently sold in the second quarter of 2017.

For the year ended December 31, 2016, a non-cash impairment reversal of $307.0 million was recognized in the Company’s core Central Alberta CGU, representing the maximum amount of impairment reversal able to be taken based on prior impairment loss less depletion and dispositions. The estimated recoverable amount of the Central Alberta CGU as at December 31, 2016 was $1.3 billion. A non-cash impairment loss of $43 million was recognized in the Company's non-core South Central CGU. The estimated recoverable amount of the South Central CGU was $64 million. No impairment was recognized in the Company's non-core North Alberta and South Alberta CGUs in 2016. The VIU determination of estimated recoverable amounts of each CGU was based on before-tax discount rates ranging from 10-20% and the following forward commodity price estimates:

Year	EdmontonCrude Ref Oil ($/bbl) (1)	AECO Gas ($/MMBtu)(1)	Butane ($/bbl)(1)	Propane($/bbl)(1)	Condensate($/bbl) (1)	CDN$/US$ Exchange Rates(1)
2017	68.33	3.47	47.83	23.92	75.17	1.33
2018	72.32	3.42	52.07	25.31	79.55	1.29
2019	76.05	3.59	54.75	26.62	83.65	1.25
2020	79.54	3.93	57.27	27.84	87.50	1.21
2021	82.82	4.01	59.63	28.99	91.11	1.18
2022	88.60	4.17	63.79	31.01	97.46	1.18
2023	90.37	4.27	65.07	31.63	99.41	1.18
2024	92.18	4.43	66.37	32.26	101.39	1.18
2025	94.02	4.52	67.69	32.91	103.42	1.18
2026	95.90	4.61	69.05	33.57	105.49	1.18
Thereafter	+2% per year	+2% per year	+2% per year	+2% per year	+2% per year	1.18

(1)The InSite price forecasts, effective January 1, 2017.

8. DEBT

($000s)	2017		2016
Credit Facilities - current	$	—	$	19,143
Credit Facilities - non-current	52,066		—
Convertible Debentures (liability component)	39,426		37,420
Senior Notes (due on May 15, 2020)	305,409		324,691
Debt	$	396,901	$	381,254

Credit Facilities

At December 31, 2017, the Company had $52.1 million outstanding under its $120 million syndicated revolving credit facilities (the “Credit Facilities”) at a weighted average interest rate of 4.45%. In addition, total outstanding letters of credit were $13 million.The Credit Facilities are available on an extendible revolving term basis and consist of a $25 million operating facility and a $95 million syndicated facility. The Credit Facilities have an initial term of one year and are extendible annually at the option of the Company, subject to lender approval, with a one year term-out period if not renewed. Availability under the Credit Facilities is subject to a borrowing base test, which is subject to redetermination in May and November of each year. The Credit Facilities mature on May 31, 2019, if not renewed. The Company completed its most recent semi-annual borrowing base redetermination in November 2017.

For the year ended December 31, 2017, the 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 1.00% to 3.50%, depending

Bellatrix Exploration Ltd. 19

on the type of borrowing and the Company’s Senior Debt to Bank EBITDA ratio (defined below). A standby fee is charged between 0.50% and 0.875% on the undrawn portion of the Credit Facilities, depending on the Company’s Senior Debt to Bank EBITDA ratio (defined below). The Credit Facilities are secured by a $1.0 billion debenture containing a first ranking charge and security interest. The Company has provided a negative pledge and undertaking to provide fixed charges over its properties in certain circumstances.

Convertible Debentures

At December 31, 2017 Bellatrix had outstanding $50 million of 6.75% convertible unsecured subordinated debentures (the “Convertible Debentures”). The Convertible Debentures are governed by the terms of an indenture dated August 9, 2016 between the Company and Computershare Trust Company of Canada (the “Debenture Indenture”). The Convertible Debentures bear interest at a rate of 6.75% per annum, payable semiannually in arrears on September 30 and March 31 of each year. The maturity date of the Convertible Debentures is September 30, 2021 (the “Debenture Maturity Date”). Each $1,000 principal amount of Convertible Debenture is convertible at the option of the holder into approximately 123.4568 common shares of Bellatrix (representing a conversion price of $8.10) on the earlier of: (i) the last business day prior to the Debenture Maturity Date, (ii) the last business day immediately preceding any Redemption Date (as defined in the Debenture Indenture), and (iii) if called for repurchase pursuant to a mandatory repurchase as a result of a Change of Control (as defined in the Debenture Indenture) on the last business day preceding the date of payment. The Convertible Debentures are not redeemable prior to September 30, 2019, except in limited circumstances following a Change of Control. On and after September 30, 2019 and up to and including September 30, 2020, the Convertible Debentures may be redeemed in whole or in part from time to time at the Company’s option, on not more than 60 days and not less than 30 days prior written notice, at a price equal to their principal amount plus accrued and unpaid interest, provided that the volume weighted average trading price of the common shares on the TSX for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the conversion price. On or after September 30, 2020 and prior to the Debenture Maturity Date, the Convertible Debentures may be redeemed in whole or in part from time to time at the Company’s option, on not more than 60 days prior to the date fixed for redemption, at a price equal to their principal amount plus accrued and unpaid interest. The Convertible Debentures are direct, subordinated unsecured obligations of the Company, subordinated to the Credit Facilities, the Senior Notes and any other senior indebtedness.

On a redemption date or on the Debenture Maturity Date, as applicable, subject to required regulatory approvals and provided that no Event of Default (as defined in the Debenture Indenture) has occurred and is continuing, Bellatrix may, at its option, on not more than 60 days and not less than 40 days prior notice, elect to satisfy its obligation to repay, in whole or in part, the principal amount of the Convertible Debentures which are to be redeemed, or which will mature, by issuing and delivering freely tradable common shares of the Company to the holders of the Convertible Debentures. Payment for such Convertible Debentures, subject to the election, would be satisfied by delivering that number of common shares obtained by dividing the principal amount of the Convertible Debentures subject to the election which are to be redeemed, or which will mature, by 95% of the current market price of the common shares on such redemption date or Debenture Maturity Date, as applicable. Any accrued and unpaid interest will be paid in cash.

($000s)	Liability Component			Equity Component
Balance, December 31, 2015	$	—		$	—
Issuance of Convertible Debentures	$	38,540		$	11,460
Issue costs	$	(1,842	)	$	(548	)
Deferred income tax liability	$	—		$	(3,094	)
Effective interest on Convertible Debentures	$	722		$	—
Balance, December 31, 2016	$	37,420		$	7,818
Effective interest on Convertible Debentures	2,006			—
Balance, December 31, 2017	$	39,426		$	7,818

Senior Notes

At December 31, 2017, the Company had outstanding US$250 million of 8.50% senior unsecured notes due May 15, 2020 (the “Senior Notes”). The Senior Notes are governed by the terms of an indenture dated May 21, 2015 between the Company and U.S. National Bank Association (the "Note Indenture"). Interest is payable on the Senior Notes semi-annually and the Senior Notes are redeemable at the Company's option, in whole or in part at specified redemption prices. The Senior Notes are redeemable at the following redemption prices (expressed as a percentage of the principal amount of the Senior Notes): May 15, 2017 to May 14, 2018 at 104.250%, May 15, 2018 to May 14, 2019 at 102.125%, May 15, 2019 and thereafter at 100.000%. The Senior Notes are carried at amortized cost, net of debt issuance costs of $7.7 million, which accrete up to the principal balance at maturity using the effective interest rate of 9.6%. The Senior Notes were initially recognized at fair value, net of debt issue costs, and have subsequently been carried at amortized cost.

Bellatrix Exploration Ltd. 20

($000s)	Amount
Balance, December 31, 2015	$	332,024
Unrealized foreign exchange gain(1) (2)	(9,879		)
Amortization of discount and debt issue costs	2,601
	324,746
Debt issue costs	(55		)
Balance, December 31, 2016	$	324,691
Unrealized foreign exchange gain (3) (4)	(22,079		)
Amortization of discount and debt issue costs	2,797
Balance, December 31, 2017	$	305,409

(1) Exchange rate (CDN$/US$1.00) at December 31, 2016 was 1.3427.

(2) Amount does not include unrealized loss on foreign exchange contracts of $2.0 million.

(3) Exchange rate (CDN$/US$1.00) at December 31, 2017 was 1.2518.

(4) Amount does not include unrealized loss on foreign exchange contracts of $3.9 million.

Covenants

At December 31, 2017, the Credit Facilities contain a single financial covenant, which requires that the Company will not permit its ratio of outstanding Senior Debt to earnings before interest, taxes, depletion, depreciation and amortization (“Bank EBITDA”), as defined by the terms of the agreement governing the Credit Facilities (“Credit Agreement”) and adjusted for non-cash charges, for a trailing twelve month period to exceed a specified amount (the “Senior Debt Covenant”). Specifically, the Senior Debt Covenant requires that the Company maintain a Senior Debt to Bank EBITDA ratio of not more than 3.0 times (prior to the second quarter of 2017, the maximum Senior Debt to Bank EBITDA ratio was 3.5 times). The Company is in compliance with the covenant at December 31, 2017 as shown below.

	Covenant as at		Position at
	December 31, 2017		December 31, 2017
Credit Facilities – Senior Debt Covenant	Maximum Ratio
Senior Debt (1) to Bank EBITDA (2) for the last four fiscal quarters	3.00	x	1.22	x

(1)“Senior Debt” is defined as Consolidated Total Debt, including outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred financing obligations, deferred capital obligations and net working capital deficiency. Excluded from the calculation is any unsecured or subordinated debt (Senior Notes and Convertible Debentures (liability component)), decommissioning liabilities, deferred gain and deferred tax liability. “Consolidated Total Debt” is defined as determined on a consolidated basis in accordance with GAAP and without duplication, all Debt of the Borrower. The Company’s calculation of Consolidated Total Debt excludes decommissioning liabilities and deferred tax liability. The calculation includes outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred capital obligations, deferred financing obligations and net working capital deficiency (excess), calculated as working capital deficiency excluding current risk management contract assets and liabilities and current portion of decommissioning liability. Senior Debt at December 31, 2017 was $104.0 million.

(2)“Bank EBITDA” refers to earnings before interest, taxes, depletion, depreciation, amortization and other non-cash charges. Bank EBITDA is calculated based on terms and definitions set out in the agreement governing the credit facilities which adjusts net income for financing costs, certain specific unrealized and non-cash transactions, and acquisition and disposition activity and is calculated based on a trailing twelve month basis. Bank EBITDA for the trailing twelve months ended December 31, 2017 was $85.1 million.

The Senior Notes do not contain any maintenance financial covenants, but do contain covenants limiting the Company’s ability to incur additional indebtedness, including borrowings under the Credit Facilities, unless one of two alternative tests are satisfied. The first test applies to all future indebtedness and requires that, after giving effect to the incurrence of additional indebtedness, the Company’s fixed charge coverage ratio (which is the ratio of cash flow to fixed charges (both as defined in the Note Indenture) over the trailing four fiscal quarters) will be at least 2.25 to 1.0.

The second test allows the Company to incur additional indebtedness, irrespective of the fixed charge coverage ratio test, as long as the additional indebtedness is incurred under bank facilities (as defined in the Note Indenture, and which includes the Credit Facilities) and generally, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $675 million, and (ii) 35% of adjusted consolidated net tangible assets, or ACNTA, plus $150 million. ACNTA is defined in the Note Indenture and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to the Company’s unevaluated properties. As a result, the Company can currently incur up to $675 million under bank facilities (which include the Credit Facilities) subject to the maximum borrowing base of the Credit Facilities, without reference to limitations that would otherwise apply due to the fixed charge coverage ratio test.

Bellatrix Exploration Ltd. 21

	Covenant as at		Position at
	December 31, 2017		December 31, 2017
Senior Notes – Incurrence Test	Minimum Ratio
Fixed charge coverage (1)	2.25	x	2.12	x

(1)Fixed charge coverage is computed as the ratio of fixed charges (as defined in the Note Indenture, fixed charges generally includes interest expense plus paid or accrued dividends, if any) to trailing twelve month cash flow (as defined in the Note Indenture, cash flow includes the net profit (loss) and adds back provision for taxes, fixed charges, depletion, and various other non-recurring expenses and charges). For the trailing twelve months ended December 31, 2017, fixed charges were $36.6 million and cash flow was $77.8 million.

As at December 31, 2017, the Company has the ability to offer to sell up to an additional $470.8 million in securities under its $500 million Shelf Prospectus, which expires on June 30, 2018.

9. DECOMMISSIONING LIABILITIES

The Company’s decommissioning liabilities result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. At December 31, 2017, the Company estimated the total undiscounted amount of cash flows required to settle its decommissioning liabilities to be approximately $94.6 million (2016: $97.9 million) which will be incurred between 2018 and 2066. A risk-free rate between 1.66% and 2.20% (2016: 0.83% and 2.34%) and an inflation rate of 2.0% (2016: 2.0%) were used to calculate the fair value of the decommissioning liabilities as at December 31, 2017.

($000s)	2017			2016
Balance, beginning of year	$	62,844		$	96,423
Incurred on development activities	1,501			911
Acquired through business combinations	—			552
Revisions on estimates	3,210			(2,292		)
Decommissioning costs incurred	(2,758		)	(2,927		)
Reversed on dispositions	(5,473		)	(31,536		)
Accretion expense	1,287			1,713
Balance, end of year	$	60,611		$	62,844

The $3.2 million increase in decommissioning liabilities between December 31, 2017 and December 31, 2016 resulting from revisions on estimates were primarily due to decreased market interest rates which decreases the discount rates applied to the valuation of the liabilities. In addition, changes to estimates also resulted from the revisions to timing and amounts of future decommissioning cash flows for certain wells and facilities made to better reflect anticipated abandonment timelines and future cash outlays.

10. OTHER DEFERRED LIABILITIES

($000s)	Finance lease obligation			Deferred lease inducements			Deferred financing obligations(1)			Deferred gain(1)		Deferred Capital Obligation(1)			Total
Balance, December 31, 2016	$	8,429		$	2,387		$	7,525		$	10,706	$	21,890		$	50,937
Deferred lease inducements	—			(366		)	—			—		—			(366		)
Payments on finance lease	(1,538		)	—			—			—		—			(1,538		)
Drawdown deferred financing obligations	—			—			(6,020		)	—		—			(6,020		)
Drawdown deferred capital obligations	—			—			—			—		(14,693		)	(14,693		)
Change in estimate	$	—		$	—		$	—		$	2,314	$	(2,442	)	$	(128	)
Balance, December 31, 2017	$	6,891		$	2,021		$	1,505		$	13,020	$	4,755		$	28,192
Current portion of other deferred liabilities	$	1,170		$	340		$	1,505		$	13,020	$	4,755		$	20,790
Long term portion of other deferred liabilities	$	5,721		$	1,681		$	—		$	—	$	—		$	7,402

(1) Pursuant to the Alder Flats Plant Sale Bellatrix recognized a deferred capital obligation, deferred gain and a deferred financing obligation as part of the disposition (refer to note 7).

Bellatrix Exploration Ltd. 22

Finance Lease Obligations

Finance leases are for the use of certain constructed facilities. The agreements expire in years 2030 to 2032, or earlier if certain circumstances are met. At the end of the term of each agreement, the ownership of the facilities is transferred to the Company. Assets under these finance leases at December 31, 2017 totaled $15.3 million (2016: $15.3 million) with accumulated depreciation of $4.4 million (2016: $3.7 million).

The following is a schedule of future minimum lease payments under the finance lease obligations:

Year ending December 31,	($000s)
2018	$	2,138
2019	1,317
2020	1,240
2021	1,164
2022	1,088
Thereafter	6,525
Total lease payments	13,472
Amount representing implicit interest at 15.28%	(6,581		)
Total lease obligation at December 31, 2017	$	6,891

11. SHAREHOLDERS’ CAPITAL

Effective July 1, 2017, the Company consolidated its common shares on the basis of 1 new common share for every 5 old common shares outstanding. All figures in the financial statements have been adjusted to reflect the 5:1 consolidation. The number of outstanding share options, Deferred Share Units, Restricted Awards and Performance Awards have also been adjusted proportionately. The corresponding exercise prices have increased by the same ratio. The conversion price and ratio on the Convertible Debentures have also been adjusted proportionately.

Bellatrix is authorized to issue an unlimited number of common shares and 95,978,621 preferred shares. At December 31, 2017, no preferred shares have been issued. All shares issued are fully paid and have no par value. The common shareholders are entitled to dividends as may be declared by the Board of Directors from time to time; no dividends were declared by the Board of Directors during the years ended December 31, 2017 or 2016.

	2017			2016
	Number	Amount ($000s)		Number	Amount ($000s)
Common shares, opening balance	49,317,166	$	1,068,084	38,392,782	$	1,000,100
Shares issued on settlement of share-based compensation	60,860	289		55,953	285
Share issue costs on property acquisition, net of tax effect	—	—		—	(98		)
Issued for cash on equity issue (1)	—	—		6,758,916	40,400
Share issue costs on equity issue, net of tax effect	—	4		—	(1,781		)
Shares issued for property acquisition	—	—		4,109,515	29,178
Balance, end of year	49,378,026	$	1,068,377	49,317,166	$	1,068,084

(1)In August 2016, Bellatrix issued 5,000,000 subscription receipts at a price of $6.00 per subscription receipt for total gross proceeds of $30 million. Proceeds were used to reduce indebtedness under the Company’s credit facilities. Additionally, in October 2016, Bellatrix issued 1,694,915 common shares on a “flow-through” basis in respect of Canadian Development Expenses (“CDE”) at a price of $5.90 per share resulting in gross proceeds of $10 million.

Bellatrix Exploration Ltd. 23

12. SHARE-BASED COMPENSATION PLANS

The following tables provide a summary of the Company’s share-based compensation expense (recovery) for the years ended December 31, 2017 and December 31, 2016:

($000s)	2017			2016
Share options expense	$	1,074		$	2,565
Deferred share units expense (recovery)	(583		)	834
Restricted awards expense (recovery)	178			241
Performance awards expense (recovery)	(137		)	144
Share-based compensation expense included in general and administrative expense	$	532		$	3,784
Share-based compensation expense included in operating expense	$	167		$	152
Total share-based compensation expense	$	699		$	3,936

The following tables provide a summary of the Company’s share options expense for the years ended December 31, 2017 and December 31, 2016:

($000s)	2017		2016
Share options expense	$	1,074	$	2,565
Share options expense capitalized	600		1,147
Gross share option expense	$	1,674	$	3,712

The following table provides a summary of the Company’s share-based compensation liability balances within accounts payable and accrued liabilities:

($000s)	Deferred Share Units		Restricted Awards		Performance Awards		Total
Liability balance, December 31, 2017	$	1,212	$	754	$	457	$	2,423
Liability balance, December 31, 2016	$	2,360	$	1,038	$	751	$	4,149

a. Share Option Plan

Bellatrix has a share option plan whereby the Company may grant share options to its officers, employees, consultants, and other service providers. Under this plan, the exercise price of each share option is not less than the volume weighted average trading price of the Company’s share price for the five trading days immediately preceding the date of grant. The maximum term of an option grant is five years. Option grants are non-transferable or assignable except in accordance with the share option plan and the holding of share options shall not entitle a holder to any rights as a shareholder of Bellatrix. Share options, entitling the holder to purchase common shares of the Company, have been granted to officers, employees, consultants, and other service providers of Bellatrix. One third of the initial grant of share options normally vests on each of the first, second, and third anniversary from the date of grant.

Bellatrix Exploration Ltd. 24

The fair values of all share options granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of share options granted during the years ended December 31, 2017 and 2016, and the weighted average assumptions used in their determination are as noted below:

	2017		2016
Inputs:
Share price	$	4.27	$	5.10
Exercise price	$	4.55	$	5.10
Risk free interest rate (%)	0.9		0.6
Option life (years)	2.8		2.8
Option volatility (%)	71		73
Results:
Weighted average fair value of each share option granted	$	1.87	$	2.35

Bellatrix calculates volatility based on historical share price. Bellatrix incorporates an estimated forfeiture rate between 3% and 10% (2016: 3% to 10%) for stock options that will not vest, and adjusts for actual forfeitures as they occur.

The following tables summarize information regarding Bellatrix’s Share Option Plan:

Share Options Continuity
	Weighted Average Exercise Price		Number
Balance, December 31, 2015	$	28.45	2,569,273
Granted	$	5.10	581,820
Forfeited	$	30.43	(287,735	)
Expired	$	26.03	(290,334	)
Balance, December 31, 2016	$	23.22	2,573,024
Granted	$	4.55	185,000
Forfeited	$	35.10	(877,956	)
Expired	$	17.12	(257,936	)
Balance, December 31, 2017	$	15.62	1,622,132

As of December 31, 2017, a total of 4,937,803 common shares were reserved for issuance on exercise of share options, leaving an additional 3,315,671 available for future share option grants.

Share Options Outstanding, December 31, 2017

				Outstanding				Exercisable
Exercise Price				At December 31, 2017	Weighted  Average Exercise Price		Weighted Average Remaining Contractual Life	At December 31, 2017	Weighted Average Exercise Price
	$3.85	-	$4.47	125,000		$3.85	4.5	—	—
	$4.48	-	$5.55	494,832		$5.10	3.6	234,944		$5.10
	$5.56	-	$18.70	76,400		$7.78	3.9	10,928		$14.30
	$18.71	-	$19.52	624,000		$18.75	2.4	469,327		$18.75
	$19.53	-	$27.48	118,600		$20.30	1.9	118,600		$20.30
	$27.49	-	$37.95	67,800		$36.66	0.9	67,800		$36.66
	$37.96	-	$45.78	26,700		$39.01	1.0	26,700		$39.01
	$45.79	-	$50.20	88,800		$46.28	1.5	88,800		$46.28
	$3.85	-	$50.20	1,622,132		$15.62	2.8	1,017,099		$19.86

Bellatrix Exploration Ltd. 25

b. Deferred Share Unit Plan

Under Bellatrix’s Deferred Share Unit Plan, the Company may grant to non-employee directors, deferred share units (“DSUs”). Each DSU is a right to receive, on a deferred payment basis, a cash payment equivalent to the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the redemption date of such DSU. Participants of the DSU Plan may also elect to receive their annual remuneration in the form of DSUs. Subject to TSX and shareholder approval, Bellatrix may elect to deliver common shares from treasury in satisfaction, in whole or in part, of any payment to be made upon the redemption of the DSUs. The DSUs vest immediately and must be redeemed by December 1st of the calendar year immediately following the year in which the participant ceases to hold all positions with Bellatrix or earlier if the participant elects to have the DSUs redeemed at an earlier date (provided that the DSUs may not be redeemed prior to the date that the participant ceases to hold all positions with Bellatrix).

DSU Continuity
	Number
Balance, December 31, 2015	202,927
Granted	184,823
Exercised	(10,083	)
Balance, December 31, 2016	377,667
Granted	260,381
Exercised	(120,150	)
Balance, December 31, 2017	517,898

c. Award Plan

Bellatrix has an Award Incentive Plan (“Award Plan”) where the Company may grant Restricted Awards (“RAs”) and Performance Awards (“PAs”) to officers, employees, and other service providers. During 2016, the shareholders and the TSX approved the issuance of common shares on settlement of RAs and PAs under the Award Plan. As a result, awards under the Award Plan may be settled in cash, in common shares of the Company, or a combination thereof. In the case of PAs, settlement is subject to a “payout multiplier” (the payout multiplier shall be based on such corporate performance measures as determined by the Board of Directors (or the Compensation Committee) of the Company) and may range between zero and two times.

RAs granted to employees vest in equal annual amounts over the course of three years. Each RA entitles its holder to receive a cash payment equal to the weighted average trading price of the Company’s shares trading on the TSX for the five trading days preceding its vesting date. Unvested RAs are forfeited at the time the holder’s employment with the Company ends, except on death in which case they vest immediately. Bellatrix incorporates an estimated forfeiture rate between 3% and 10% for RAs that will not vest, and adjusts for actual forfeitures as they occur. Outstanding RAs are revalued at each financial reporting date to their fair market value at that time, determined by the weighted average trading price of the Company’s shares on the TSX for the five trading days preceding period end.

RA Continuity
	Number of RAs
Balance, December 31, 2015	318,762
Granted	284,771
Exercised	(113,457	)
Forfeited	(63,681	)
Balance, December 31, 2016	426,395
Granted	652,740
Exercised	(175,833	)
Forfeited	(79,815	)
Balance, December 31, 2017	823,487

PAs vest on the third anniversary date of their issuance. Each PA entitles its holder to receive a cash payment equal to the weighted average trading price of the Company’s shares trading on the TSX for the five trading days preceding its vesting date, multiplied by a payout multiplier determined by the Company’s Board of Directors based on determined corporate performance measures. Unvested PAs are forfeited at the time the holder’s employment with the Company ends. Bellatrix incorporates an estimated forfeiture

Bellatrix Exploration Ltd. 26

rate of 5% for PAs that will not vest, and adjusts for actual forfeitures as they occur. Outstanding PAs are revalued at each financial reporting date to their fair market value at that time, determined by the weighted average trading price of the Company’s shares on the TSX for the 5 trading days preceding period end.

PA Continuity
	Number of PAs
Balance, December 31, 2015	249,240
Granted	145,085
Exercised	(70,430	)
Forfeited	(20,560	)
Balance, December 31, 2016	303,335
Granted	370,000
Exercised	(61,920	)
Forfeited	(38,360	)
Balance, December 31, 2017	573,055

13. INCOME TAXES

Bellatrix is a corporation as defined under the Income Tax Act (Canada) and is subject to Canadian federal and provincial taxes. Bellatrix is subject to provincial taxes in Alberta, British Columbia, and Saskatchewan as the Company operates in those jurisdictions.

Deferred taxes reflect the tax effects of differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts reported for tax purposes. As at December 31, 2017, Bellatrix had approximately $1.35 billion in tax pools available for deduction against future income. Included in this tax basis are estimated non-capital loss carry forwards of approximately $144.1 million that expire in years through 2033.

The provision for income taxes differs from the expected amount calculated by applying the combined 2017 federal and provincial corporate income tax rate of 27.0% (2016: 27.0%) to net profit (loss) before taxes. This difference results from the following items:

($000s)	2017			2016
Expected income tax expense (recovery)	$	(20,506	)	$	(9,052	)
Change in unrecognized deferred tax asset	44,114			—
Unrealized foreign exchange (gain) loss	(4,947		)	(1,938		)
Share based compensation expense	610			856
Flow through share issuance	108			2,700
Other	(3,964		)	576
Deferred tax expense (recovery)	$	15,415		$	(6,858	)

Bellatrix Exploration Ltd. 27

The components of the net deferred tax asset at December 31, 2017 are as follows:

($000s)	2017			2016
Deferred tax liabilities:
Property, plant and equipment and exploration and evaluation assets	$	(6,845	)	$	(12,555	)
Risk management contract asset	(8,943		)	—
Convertible Debentures	(2,616		)	(3,028		)
Deferred tax assets:
Senior Notes	756			418
Finance lease obligation	1,860			2,276
Deferred capital obligation	—			5,910
Deferred financing obligation	406			2,032
Deferred gain on sale	3,515			2,890
Risk management contract liability	1,206			4,477
Decommissioning liabilities	16,365			16,967
Share issue costs	840			1,950
Non-capital losses	40,850			40,830
Other	904			1,546
Deferred tax asset (liability)	$	48,298		$	63,713

The Company recognized a net deferred tax asset based on the independently evaluated reserve report as cash flows are expected to be sufficient to realize the deferred tax asset. The Company has not recognized a deferred tax asset for the deductible temporary difference associated with $163.4 million (2016: nil) of Canadian resource pools that are restricted through successor rules and $5.2 million (2016: $14.6 million) of unrealized allowable capital losses on marketable securities and USD denominated Senior Notes.A continuity of the net deferred income tax asset (liability) for 2017 and 2016 is provided below:

($000s)	Balance, January 1, 2017			Recognized in profit (loss)			Recognized in equity		Balance, December 31, 2017
Property, plant and equipment and exploration and evaluation assets	$	(12,555	)	$	5,710		$	—	$	(6,845	)
Decommissioning liabilities	16,967			(602		)	—		16,365
Risk management contract asset	—			(8,943		)	—		(8,943		)
Risk management contract liability	4,477			(3,271		)	—		1,206
Share issue costs	1,950			(1,110		)	—		840
Non-capital losses	38,895			20			—		38,915
Finance lease obligation	2,276			(416		)	—		1,860
Deferred capital obligation	5,910			(5,910		)	—		—
Deferred financing obligation	2,032			(1,626		)	—		406
Deferred gain on sale	2,890			625			—		3,515
Alberta non-capital losses greater than Federal non-capital losses	1,935			—			—		1,935
Senior Notes	418			338			—		756
Convertible Debentures	(3,028		)	412			—		(2,616		)
Other	1,546			(642		)	—		904
Total	$	63,713		$	(15,415	)	$	—	$	48,298

Bellatrix Exploration Ltd. 28

($000s)	Balance, January 1, 2016			Recognized in profit (loss)			Recognized in equity			Balance, December 31, 2016
Property, plant and equipment and exploration and evaluation assets	$	(12,142	)	$	(413	)	$	—		$	(12,555	)
Decommissioning liabilities	26,034			(9,067		)	—			16,967
Risk management contract asset	(3,600		)	3,600			—			—
Risk management contract liability	105			4,372			—			4,477
Share issue costs	2,520			(1,264		)	694			1,950
Non-capital losses	40,766			(1,871		)	—			38,895
Finance lease obligation	2,717			(441		)	—			2,276
Deferred capital obligation	—			5,910			—			5,910
Deferred financing obligation	—			2,032			—			2,032
Deferred gain on sale	—			2,890			—			2,890
Alberta non-capital losses greater than Federal non-capital losses	1,935			—			—			1,935
Senior Notes	(65		)	483			—			418
Convertible Debentures	—			66			(3,094		)	(3,028		)
Other	985			561			—			1,546
Total	$	59,255		$	6,858		$	(2,400	)	$	63,713

14. FINANCE INCOME AND EXPENSES

($000s)	2017		2016
Interest on Credit Facilities (1)	$	2,194	$	13,516
Interest on Convertible Debentures (2)	5,381		2,063
Interest on Senior Notes (2)	30,378		30,771
Accretion on decommissioning liabilities (non-cash)	1,287		1,713
Finance expense	$	39,240	$	48,063

(1) Includes interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 1.00% to 3.50%, depending on the type of borrowing and the Company’s Senior Debt to EBITDA ratio. A standby fee is charged between 0.500% and 0.875% on the undrawn portion of the Credit Facilities, depending on the Company’s Senior Debt to EBITDA ratio.

(2) Includes amortized costs related to the issuance of the Senior Notes and Convertible Debentures (detailed in note 8).

15. FOREIGN EXCHANGE

Bellatrix incurs gains and losses in relation to the foreign currency translation of its Senior Notes. The Senior Notes are translated from United States dollars to Canadian dollars using the closing foreign exchange rate for the period. An unrealized foreign exchange gain or loss is included in earnings in the period related to the translation of the outstanding balance of the Senior Notes at the end of the period. Realized and unrealized foreign exchange gains and losses are recognized as Senior Notes and other minor foreign currency based transactions are translated and settled during the period.

($000s)	2017			2016
Realized gain (loss) on foreign exchange	$	(797	)	$	277
Unrealized gain (loss) on foreign exchange	22,165			9,939
Unrealized gain (loss) on foreign exchange contracts	(3,867		)	(2,021		)
Gain (loss) on foreign exchange	$	17,501		$	8,195

Bellatrix Exploration Ltd. 29

Bellatrix had the following United States dollar foreign exchange forward purchase contracts outstanding at December 31, 2017:

Type	Value Date	Notional Amount ($000s USD)		Foreign Exchange Rate		Settlement ($000s CDN)
Fixed	May 14, 2020	$	32,500	$	1.3076	$	42,497
Fixed	May 14, 2020	$	30,000	$	1.3080	$	39,240

16. PER SHARE AMOUNTS

The calculation of basic earnings per share for the year ended December 31, 2017 was based on a net loss of $91.4 million (2016: net loss of $26.7 million). 

	2017	2016
Basic common shares outstanding	49,378,026	49,317,165
Fully dilutive effect of:
Share options outstanding	1,622,132	2,573,024
Shares issuable on conversion of Convertible Debentures	6,172,840	6,172,840
Fully diluted common shares outstanding	57,172,998	58,063,029
Weighted average shares outstanding	49,351,848	42,821,013
Dilutive effect of share options (1)	—	—
Diluted weighted average shares outstanding	49,351,848	42,821,013

(1) For the year ended December 31, 2017, a total of 1,622,132 (2016: 2,573,024) share options and 6,172,840 (2016: 6,172,840) shares issuable on conversion of Convertible Debentures were excluded from the calculation as they were anti-dilutive.

17. FINANCIAL RISK MANAGEMENT

a. Overview

The Company has exposure to the following risks from its use of financial instruments:

•Credit risk

•Liquidity risk

•Market risk

▪Foreign exchange risk

▪Commodity price risk

▪Interest rate risk

This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these financial statements.

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies.

The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

b. Capital Management

The Company's policy is to maintain a strong capital base so as to maintain investor, creditor and market confidence and to sustain the future development of the business. The Company manages its capital structure and makes adjustments to it based on changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company considers its capital structure to include shareholders’ equity, Senior Notes, Credit Facilities, Convertible Debentures, and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue common shares, senior notes, convertible debentures or other debt instruments, adjust its capital spending, and/or dispose of certain assets to manage current and forecasted debt levels. Bellatrix does not pay dividends. 

Bellatrix remains highly focused on key business objectives of maintaining financial strength and liquidity, and optimizing capital investments in the current commodity price environment. In order to preserve liquidity and capital resources, in December 2017,

Bellatrix Exploration Ltd. 30

Bellatrix’s Board of Directors approved a 2018 net capital budget of between $65 million and $80 million. Bellatrix expects to be able to fund its 2018 capital program by reinvesting cash flow, supplemented by borrowing under its Credit Facilities. Bellatrix continually monitors its capital spending program in light of prevailing commodity prices and the United States/Canadian dollar exchange rate with the aim of ensuring the Company will be able to meet future anticipated obligations incurred from normal ongoing operations with adjusted funds flow and borrowings under its Credit Facilities, as necessary. Please refer to note 8 and ‘Liquidity Risk’ below for further discussion.

The Company monitors its capital structure based on the ratio of total net debt to annualized adjusted funds flow (defined below). This ratio is calculated as total net debt, defined as outstanding Credit Facilities, Convertible Debentures (liability component), and Senior Notes, long term loan receivable and plus or minus adjusted working capital (defined below), divided by adjusted funds flow (defined below) for the most recent calendar quarter, annualized (multiplied by four). The total net debt to annualized adjusted funds flow ratio may increase at certain times as a result of acquisitions, fluctuations in commodity prices, timing of capital expenditures and other factors. In order to facilitate the management of this ratio, the Company prepares capital expenditure budgets which are reviewed and updated as necessary depending on varying factors including current and forecast prices, successful capital deployment and general industry conditions. The budgets are approved by the Board of Directors.

The Company’s capital structure and its calculation of total net debt and the total net debt to adjusted funds flow ratio as defined by the Company is as follows:

Debt to Adjusted Funds Flow Ratio
	Year ended December 31,
($000s, except where noted)	2017		2016
Shareholders’ equity	774,022		863,418
Credit Facilities	52,066		19,143
Loans receivable (long term)	—		(8,775	)
Adjusted working capital deficiency (1)	23,926		23,716
Subtotal	75,992		34,084
Senior Notes (mature May 15, 2020) (2)	305,409		324,691
Net debt (1)	381,401		358,775
Convertible Debentures (liability component)	39,426		37,420
Total net debt (1) at year end	420,827		396,195
Debt to adjusted funds flow ratio (annualized)(3) (4)
Adjusted funds flow (4) (annualized)	62,800		33,748
Net debt (1) to periods adjusted funds flow ratio (annualized) (3)	6.1	x	10.6		x
Total net debt to periods adjusted funds flow ratio (annualized) (3)	6.7	x	11.7		x
Debt to adjusted funds flow ratio (4)
Adjusted funds flow for the year (4)	58,240		40,916
Net debt (1) to adjusted funds flow ratio (4) for the year	6.5	x	8.8		x
Total net debt (1) to adjusted funds flow ratio (4) for the year	7.2	x	9.7		x

(1)Net debt and total net debt as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, deferred capital obligation, long-term risk management contract liabilities, decommissioning liabilities, and the deferred tax liability. Total net debt includes the adjusted working capital deficiency, Convertible Debentures (liability component), current Credit Facilities, long term loan receivable and Senior Notes. The adjusted working capital deficiency as presented does not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company calculated adjusted working capital deficiency as net working capital deficiency excluding current risk management contract assets and liabilities, current portion of other deferred liabilities, current portion of deferred capital obligation, current portion of Credit Facilities and the current portion of decommissioning liability. Net debt excludes the liability component of Convertible Debentures that is included in total net debt.

(2)For the year ended December 31, 2017, Senior Notes includes an unrealized foreign exchange gain of $22.2 million (2016: $9.9 million gain) and does not include an unrealized loss of $3.9 million (2016: $2.0 millionloss) on foreign exchange contracts.

(3)For the years ended December 31, 2017 and 2016, net debt and total net debt to period’s adjusted funds flow ratio (annualized) is calculated based upon fourth quarter adjusted funds flow annualized.

(4)Adjusted funds flow as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Adjusted funds flow is calculated as cash flow from operating activities, excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.

Bellatrix Exploration Ltd. 31

c. Credit Risk

Credit risk is the risk of financial loss to Bellatrix if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from Bellatrix’s trade receivables from joint venture partners, petroleum and natural gas marketers, and financial derivative counterparties.

A substantial portion of Bellatrix’s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. Bellatrix currently sells substantially all of its production to ten primary purchasers under standard industry sale and payment terms. The most significant 60 day exposure to a single counterparty is approximately $11.2 million. Purchasers of Bellatrix’s natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. Bellatrix has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in Bellatrix mitigating its exposures to certain counterparties by obtaining financial assurances or reducing credit where it is deemed warranted and permitted under contractual terms.

Bellatrix may be exposed to third party credit risk through its contractual arrangements with its current or future partners and joint venture partners, marketers of its petroleum and natural gas production, derivative counterparties and other parties.

As at December 31, 2017, accounts receivable was comprised of the following:

Aging ($000s)	Not past due (less than 90 days)		Past due (90 days or more)			Total
Joint venture and other trade accounts receivable	$	13,627	$	5,186		$	18,813
Revenue and other accruals	27,312		436			27,748
Less: Allowance for doubtful accounts	—		(889		)	(889		)
Total accounts receivable	$	40,939	$	4,733		$	45,672

In order to determine the allowance for doubtful accounts, the Company conducts a qualitative analysis of each account comprising the individual balances within its accounts receivable, including the counterparty’s identity, customary pay practices, and the terms of the contract under which the obligation arose. Based on the review of the individual balances within the accounts receivable balance at December 31, 2017 and specifically the balances greater than 90 days, a provision of $0.9 million was made.

The carrying amount of accounts receivable and derivative assets represent the maximum credit exposure.

d. Liquidity Risk

Liquidity risk is the risk that Bellatrix will not be able to meet its financial obligations as they become due. Bellatrix actively manages its liquidity through daily and longer-term cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through its Credit Facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic risk management opportunities, and maintaining sufficient cash flows for compliance with the Senior Debt Covenant described in note 8. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses.

The Company prepares annual capital expenditure budgets which are regularly monitored and updated as necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has revolving reserve based Credit Facilities, as outlined in note 8, which are reviewed semi-annually by the lenders thereunder. The borrowing base under the Company’s Credit Facilities is $120 million providing the Company with approximately $55 million of available liquidity, after deducting outstanding letters of credit as at December 31, 2017. The next scheduled review of the borrowing base is May 2018. The Credit Facilities outline limitations based on percentages of the prior quarter’s sale volumes, which may be hedged through financial commodity price risk management contracts. Bellatrix also has Senior Notes and Convertible Debentures outstanding with fixed interest rates, as outlined in note 8, which mature on May 15, 2020 and September 30, 2021, respectively.

Future liquidity depends primarily on cash flow generated from operations, availability under the Credit Facilities and the ability to access debt and equity markets. From time to time, the Company accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. As at December 31, 2017, the Company has the ability to offer to sell up to an additional $470.8 million in securities under its $500 million Shelf Prospectus, which expires on June 30, 2018.

Bellatrix Exploration Ltd. 32

There can be no assurance that future debt or equity financing, additional credit under the Credit Facilities, 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 Bellatrix.

The following are the contractual maturities of financial liabilities as at December 31, 2017:

Liabilities ($000s)	Total		< 1 Year		1-3 Years		3-5 Years		More than 5 years
Accounts payable and accrued liabilities	$	73,307	$	73,307	$	—	$	—	$	—
Risk management liability	7,890		4,468		3,422		—		—
Credit Facilities	52,066		—		52,066		—		—
Convertible Debentures (1)	50,000		—		—		50,000		—
Senior Notes (1)	312,950		—		312,950		—		—
Deferred capital obligation	4,755		4,755		—		—		—
Deferred financing obligation	1,505		1,505		—		—		—
Finance lease obligation	6,891		1,170		947		928		3,846
Total	$	509,364	$	85,205	$	369,385	$	50,928	$	3,846

(1) Principal amount of the instruments

e. Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net profit or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

f. Foreign Exchange Risk

Foreign exchange risk is the risk that fluctuations in the Canadian/United States dollar foreign exchange rate may impact the Company’s cash flows and net profit (loss). The Company’s realized commodity prices for crude oil and natural gas are based upon United States dollar denominated commodity prices. Fluctuations in the Canadian/United States dollar foreign exchange rate may thus impact commodity prices received by the Company. In addition, the Company has United States dollar denominated Senior Notes and related interest obligations of which future cash payments are directly impacted by the exchange rate in effect on the payment date.

The Company may utilize foreign exchange derivative contracts to manage foreign exchange risks in order to maintain cash flow stability. Foreign exchange derivative transactions are in accordance with the risk management policy that has been approved by the Board of Directors. The aggregate amount hedged under all foreign exchange derivative contracts is limited to the outstanding principal amount of the Senior Notes or 60% of the Company’s United States dollar revenues over the previous three months. Additionally, the term of foreign exchange contracts is limited to the remaining term of the related Senior Notes or three years. See note 15 for the foreign exchange risk management contacts that the Company has entered at December 31, 2017.

For the year ended December 31, 2017, a $0.01 increase or decrease in the CDN$/US$ foreign exchange rate, with all other variables held constant, would impact the profit (loss) before income taxes by approximately $0.8 million.

g. Commodity Price Risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar, as outlined above, but also global economic events that dictate the levels of supply and demand.

The Company utilizes both financial derivatives and physical delivery sales contracts to manage commodity price risks. All such transactions are conducted in accordance with the commodity price risk management policy that has been approved by the Board of Directors.

The Company’s formal commodity price risk management policy permits management to use specified price risk management strategies including fixed price contracts, costless collars and the purchase of floor price options, other derivative financial instruments, and physical delivery sales contracts to reduce the impact of price volatility and ensure minimum prices for a maximum of thirty months beyond the current date. The program is designed to provide price protection on a portion of the Company’s future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By

Bellatrix Exploration Ltd. 33

doing this, the Company seeks to provide a measure of stability to cash flows from operating activities, as well as, to ensure Bellatrix realizes positive economic returns from its capital developments and acquisition activities.

For the year ended December 31, 2017, if the prices for AECO natural gas had increased or decreased by $0.10/mcf, with all other variables held constant, net loss before tax would have be impacted by $6.0 million. For the year ended December 31, 2017, if prices for WTI crude oil had increased or decreased by $1.00/bbl, with all other variables held constant, net profit would be impacted by $3.7 million.

As at December 31, 2017, the Company has entered into commodity price risk management arrangements as follows:

Natural gas fixed price arrangements

Type		Period	Volume	Price	Index
Natural gas fixed	Financial	January 1, 2018 to December 31, 2018	75,000 GJ/d	2.69	AECO

Natural gas basis differential arrangements

Type		Period	Volume	Price			Index
Natural gas	FInancial	April 1, 2018 to October 31, 2018	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX
Natural gas	Financial	April 1, 2019 to October 31, 2020	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX

Natural gas liquids fixed differential arrangements

Type		Period	Volume	Fixed Differential	Index
Propane	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	47% of NYMEX WTI	OPIS Conway Propane

Crude oil fixed price arrangements

Type		Period	Volume	Price			Index
Oil	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	$	70.14	CDN	WTI - NYMEX

h. Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Company is exposed to interest rate fluctuations on its Credit Facilities which bears a floating rate of interest. As at December 31, 2017, if interest rates had been 1% lower with all other variables held constant, net loss before income tax for the three months ended December 31, 2017 would have been approximately $0.5 million lower, due to lower interest expense. An equal and opposite impact would have occurred to net earnings had interest rates been 1% higher.

i. Fair Value

The Company’s financial instruments as at December 31, 2017 include accounts receivable, deposits, marketable securities, risk management assets and liabilities, accounts payable and accrued liabilities, finance lease obligations, deferred capital obligation, deferred financing obligation, Credit Facilities, Convertible Debentures and Senior Notes. The fair value of accounts receivable, deposits, accounts payable, accrued liabilities, deferred financing obligation and deferred capital obligation approximate their carrying amounts due to their short-terms to maturity.

The loan receivable was determined to bear interest at a market rate and accordingly the fair market value approximated the carrying value. Marketable securities were carried at fair value based on the market price at each reporting date, with changes in fair value recognized in profit or loss. The marketable securities are classified as level 1 within the fair value hierarchy.

The Company enters into risk management contracts under master netting arrangements. Under these arrangements, the amounts owed by each counterparty for commodity or foreign exchange contracts outstanding in the same currency or commodity are aggregated into a single net amount receivable or payable. If a default occurs, the net amount subject to a master netting arrangement is receivable or payable for settlement purposes. The carrying amounts of commodity and foreign exchange contracts held under master netting arrangements are recorded on a net basis. At December 31, 2017 and 2016, the impact of netting gross amounts is negligible.

The risk management assets and liabilities at December 31, 2017 include both commodity contracts and foreign exchange contracts. The fair value of commodity contracts is determined by discounting the difference between the contracted price and published forward price curves as at the balance sheet date, using the remaining contracted petroleum and natural gas volumes. The fair

Bellatrix Exploration Ltd. 34

value of foreign exchange contracts is determined based on the difference between the contracted forward rate and current forward rates, using the remaining settlement amount. The risk management contracts are classified as level 2 within the fair value hierarchy.

Credit Facilities bears interest at a floating market rate and the credit and market premiums therein are indicative of current rates; accordingly the fair market value approximates the carrying value.

The fair value of financial assets and liabilities, excluding working capital and Credit Facilities, is attributable to the following fair value hierarchy levels at December 31, 2017 and December 31, 2016:

($000s)		Fair Value
2017	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	33,123	—	33,123	—
Financial liabilities
Risk management liability	7,890	—	7,890	—
Convertible Debentures (1)	39,426	—	46,000	—
Senior Notes (2)	305,409	—	299,258	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $92.00 per Debenture as at December 31, 2017, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $95.63 per Senior Note as at December 31, 2017.

($000s)		Fair Value
2016	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	445	—	445	—
Financial liabilities
Risk management liability	16,582	—	16,582	—
Convertible Debentures (1)	37,420	—	50,825	—
Senior Notes (2)	324,691	—	332,318	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $101.65per Debenture as at December 31, 2016, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $99.00 per Senior Note as at December 31, 2016.

The following is a summary of the net risk management asset (liability) as at December 31, 2016 and December 31, 2017:

($000s)	2017			2016
Current portion commodity contract asset	$	31,910		$	—
Commodity contract asset (long term)	1,213			—
Foreign exchange contract asset (long term)	—			445
Current portion commodity contract liability	(4,468		)	(13,936		)
Commodity contract liability (long term)	—			(2,646		)
Foreign exchange contract liability (long term)	(3,422		)	—
Net risk management asset (liability)	$	25,233		$	(16,137	)

Bellatrix Exploration Ltd. 35

18. COMMITMENTS

The following is a summary of Bellatrix’s commitments as at December 31, 2017:

($000s)	1 Year		2-3 Years		4-5 Years		More than 5 years		Total
Operating leases (1)	$	24,835	$	48,748	$	40,811	$	30,934	$	145,328
Transportation and processing agreements (2)	$	62,207	$	97,788	$	69,481	$	128,873	$	358,349

(1) Operating leases is comprised of the Company’s commitment for office space, net of recoveries and gross operating leases for field equipment. The Company is committed to payments under fixed term operating leases for office space which do not currently provide for early termination.

(2) Transportation agreements is comprised of commitments to third parties to transport natural gas. Processing agreements is comprised of commitments to process natural gas and natural gas liquids through processing facilities.

Bellatrix is involved in litigation and claims arising in the normal course of operations. Such claims are not expected to have a material impact on Bellatrix’s results of operations or cash flows.

19. RELATED PARTY TRANSACTIONS

Key Management Compensation

Key management includes officers and directors (executive and non-executive) of the Company. The compensation paid or payable to key management for employee services is shown below:

($000s)	2017		2016
Short-term employee benefits (1)	$	4,901	$	3,933
Share-based compensation (2)	452		2,509
Total key management compensation	$	5,353	$	6,442

(1) Includes termination benefits for the year ended December 31, 2017 of $1.3 million (2016: nil)

(2) Share-based compensation includes share options, RAs, PAs, and DSUs.

20. SUPPLEMENTAL DISCLOSURES

Changes in Non-cash Working Capital

($000s)	2017			2016
Changes in non-cash working capital items:
Accounts receivable	$	(6,445	)	$	18,034
Loans receivable	15,000			—
Deposits and prepaid expenses	1,496			2,925
Accounts payable and accrued liabilities	(3,578		)	(32,127		)
	$	6,473		$	(11,168	)
Changes related to:
Operating activities	$	(272	)	$	(443	)
Financing activities	16,353			601
Investing activities	(9,608		)	(11,326		)
	$	6,473		$	(11,168	)

Statement of Profit (Loss) and Comprehensive Income (Loss) Presentation

A mixed presentation of nature and function was used for the Company’s presentation of operating expenses in the Statement of Profit (Loss) and Comprehensive Income (Loss) for the current and comparative years. General and administrative expenses are presented by their function. Other expenses, including production, transportation, depletion and gain (loss) on dispositions are presented by their nature. Such presentation is in accordance with industry practice.

Bellatrix Exploration Ltd. 36

Total employee compensation costs included in total production and general administrative expenses in the Statements of Profit (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2017 and 2016 are detailed in the following table:

($000s)	2017		2016
Production	$	7,860	$	8,360
General and administrative (1)	19,274		11,616
Employee compensation	$	27,134	$	19,976

(1) Amount shown is net of capitalization.

Bellatrix Exploration Ltd. 37

EX-13.4

EXHIBIT 13.4

BELLATRIX EXPLORATION LTD.

SUPPLEMENTARY OIL AND GAS INFORMATION - (UNAUDITED)

The following disclosures have been prepared by Bellatrix Exploration Ltd. (“Bellatrix”) in accordance with Accounting Standards Codification 932 “Extractive Activities - Oil and Gas” (“ASC 932”) issued by the Financial Accounting Standards Board. Bellatrix prepares its consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”), and prepares and files its reserves information under National Instrument 51-101 - Standards of Disclosure of Oil and Gas Activities (“NI 51-101”) which prescribes the standards for the preparation and disclosure of reserves and related information for companies subject to continuous disclosure obligations in Canada.  There are significant differences between reserves disclosure under NI 51-101 and the requirements of the United States Securities and Exchange Commission (the “SEC”), including the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission (“SEC”) requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs.  For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2017 and 2016, Bellatrix used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.  Therefore, the difference between the reported numbers under the two disclosure standards can be material.

NET PROVED OIL AND NATURAL GAS RESERVES

Bellatrix engaged an independent qualified reserve evaluator, InSite Petroleum Consultants Ltd. (“InSite”), to evaluate Bellatrix’s proved developed and proved undeveloped oil and natural gas reserves.  As at December 31, 2017, all of Bellatrix’s oil and natural gas reserves are located in Canada. The changes in our net proved reserve quantities are outlined below.

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

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

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

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

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

YEAR ENDED DECEMBER 31, 2017

CONSTANT PRICES AND COSTS

Net Proved Developed and  Proved Undeveloped Reserves (1)	Crude Oil  (mbbl)		Natural Gas  Liquids  (mbbl)		Natural Gas (mmcf)		Oil Equivalent  (mboe)
December 31, 2016	983.4		19,477.8		401,814		87,430.2
Revisions of previous estimates	827.6		10,211.6		122,084		31,386.5
Improved recovery	—		—		—		—
Purchases of minerals in place	—		2,572.1		42,505		9,656.2
Extensions and Discoveries	7.9		5,572.3		90,505		20,664.4
Production	(171.9	)	(2,048.5	)	(53,750	)	(11,178.7	)
Sales of minerals in place	(262.3	)	(1,617.9	)	(36,429	)	(7,951.7	)
December 31, 2017	1,384.7		34,167.4		566,729		130,007.0
Proved Developed Reserves
Beginning of year	943.6		8,631.7		196,841		42,382.1
End of year	848.0		12,544.2		233,956		52,384.8
Proved Undeveloped Reserves
Beginning of year	39.8		10,846.2		204,973		45,048.1
End of year	536.7		21,623.2		332,773		77,622.1
Total(2)	1,384.7		34,167.4		566,729		130,007.0

YEAR ENDED DECEMBER 31, 2016

CONSTANT PRICES AND COSTS

Net Proved Developed and  Proved Undeveloped Reserves (1)	Crude Oil  (mbbl)		Natural Gas  Liquids  (mbbl)		Natural Gas (mmcf)		Oil Equivalent  (mboe)
December 31, 2015	6,444.9		17,272.8		323,845		77,691.9
Revisions of previous estimates	(1,897.5	)	1,559.9		62,259		10,038.8
Improved recovery	—		—		—		—
Purchases of minerals in place	—		1,371.0		30,029		6,375.8
Extensions and Discoveries	19.0		3,440.0		66,415		14,528.2
Production	(652.0	)	(2,174.0	)	(56,892	)	(12,307.9	)
Sales of minerals in place	(2,931.0	)	(1,991.9	)	(23,842	)	(8,896.6	)
December 31, 2016	983.4		19,477.8		401,814		87,430.2
Proved Developed Reserves
Beginning of year	3,865.7		8,926.3		168,903		40,942.5
End of year	943.6		8,631.7		196,841		42,382.1
Proved Undeveloped Reserves
Beginning of year	2,579.2		8,346.5		154,942		36,749.4
End of year	39.8		10,846.2		204,973		45,048.1
Total (2)	983.4		19,477.8		401,814		87,430.2

____________________________________________________________________________

(1) Columns may not add due to rounding.

(2) Bellatrix does not file any estimates of total net proved crude oil or natural gas reserves with any U.S. federal authority or agency other than the SEC.

The reconciliation of Bellatrix reserves from 2016 to 2017 includes positive revisions of previous estimates of31,386.5mboe from the previous year. 19,379.8 mboe of the total, or 62%, was due to increases in constant pricing which enabled previously uneconomic wells to recover in the current year. The remaining 12,006.7 mboe, or 38%, was due to new wells exceeding previous expectations and existing wells outperforming the reserves assigned in the previous year. In 2017, there were no material changes caused by proved undeveloped locations becominguneconomic.

The reconciliation of Bellatrix reserves from 2015 to 2016 includes positive revisions of previous estimates of 10,038.8 mboe from the previous year. 9,668.2 mboe of the total, or 96%, was due to new wells exceeding previous expectations and existing wells outperforming the reserves assigned in the previous year, and the remaining revisions were due to a variety of immaterial factors, including gas shrinkage. In 2016, there were no material changes caused by proved undeveloped locations becoming uneconomic.

Bellatrix continued development of its Spirit River natural gas play in 2016 and 2017. The quantity of reserves attributed to Extensions and Discoveries was substantial at 19% and 24% of opening balance reserves for 2016 and 2017, respectively. In both years, producing extensions and additional reserves were due not only to the highly successful development program referenced above, but due to competitor development of offsetting lands helping to define the extent of the play and extend the proven component of the Company’s reserves over additional lands.

In 2016, the Corporation completed the partial acquisition/buy-up of its joint venture partner’s production during the year and in 2016 and 2017 also swapped lands with various other partners to consolidate and increase its operating position in its core Ferrier Spirit River play. Offsetting this activity, property divestments occurred in several non-core properties, including, in 2016, the divestment of its Pembina Cardium oil property, Harmattan Cardium oil property and Mannville gas property and, in 2017, the divestment of a portion of its West Pembina Cardium oil property and its Strachan gas property. Purchases and Sales largely offset each other at 8% and 11% (2016) and 11% and 9% (2017) of the opening reserve balance.

CAPITALIZED COSTS

As at December 31, (in thousands of Canadian dollars)	2017		2016
Proved oil and gas properties	1,916,791		2,091,014
Unproved oil and gas properties	22,731		29,246
Total capitalized costs	1,939,522		2,120,260
Accumulated depletion and depreciation	(742,653	)	(808,643	)
Net capitalized costs	1,196,869		1,311,617

COSTS INCURRED

For the years ended December 31, (in thousands of Canadian dollars)	2017		2016
Property acquisition (disposition) costs (1)
Proved oil and gas properties	(48,684	)	(299,067	)
Unproved oil and gas properties	4,007		2,635
Exploratory costs (2)	818		336
Development costs (3)	116,326		75,689
Capital expenditures	72,467		(220,407	)

____________________________________________________________________________

(1) Acquisitions are net of dispositions of properties.

(2) Cost of geological and geophysical capital expenditures and costs on exploratory plays.

(3) Includes equipping and facilities capital expenditures.

For the years ended December 31, (in thousands of Canadian dollars)	2017		2016
Revenue, net of royalties and commodity contracts	302,000		199,605
Production costs	(111,816	)	(113,589	)
Transportation costs	(23,549	)	(12,108	)
Depletion, depreciation and impairment	(133,802	)	127,482
Income taxes (1)	—		—
Results of operations	32,833		201,390

____________________________________________________________________________

(1) Bellatrix is currently not cash taxable.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN

The standardized measure of discounted future net cash flows is based on estimates made by InSite of net proved reserves. Future cash inflows are computed based on constant prices and cost assumptions applied against annual future production from proved crude oil and gas reserves. Future development and production costs are based on constant price assumptions and assume the continuation of existing economic conditions. Constant prices are the average of the first day prices of each month for the prior calendar 12 month period. Future income taxes are calculated by applying statutory income tax rates. Bellatrix is currently not cash taxable. The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.

Bellatrix cautions users of this information that the discounted future net cash flows relating to proved oil and gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10% is arbitrary and may not appropriately reflect future interest rates.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

(in thousands of Canadian dollars)	2017	2016
Future cash inflows	2,603,521	1,432,343
Future production costs (1)	1,256,836	812,069
Future development costs	467,117	253,612
Undiscounted pre-tax cash flows	879,568	366,662
Future income taxes (2)	—	—
Future net cash flows	879,568	366,662
Less 10% annual discount factor	428,986	182,690
Standardized measure of discounted future net cash flows	450,582	183,972

____________________________________________________________________________

(1) Future production costs include 11.3 million (2016) and $13.6 million (2017)related to future abandonment and reclamation costs associated with wells having attributed reserves and for dedicated facilities required to produce these reserves.  The estimate of future abandonment and reclamation costs excludes asset retirement obligations and reclamation costs relating to non-reserves wells and for non-dedicated gathering systems, batteries, plants and processing facilities.  The incremental asset retirement obligation not included in the disclosure of estimated future net revenue was $13.8 million on a discounted basis and $86.7 million on an undiscounted basis in 2016, and $11.8 million on a discounted basis and $81.0 million on an undiscounted basis in 2017.

(2)Bellatrix's available tax pools exceed Bellatrix's cash flows.

The reconciliation of changes in standardized measure of future cash flows discounted at 10% per year relating to proved oil and gas reserves is as follows:

(in thousands of Canadian dollars, all changes except income taxes pretax)	2017		2016
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at beginning of year	183,972		363,584
Net change in sales and transfer prices related to future production (1)	195,827		(299,773	)
Changes in estimated future development costs	(46,872	)	(7,556	)
Sales and transfers of oil and gas produced during the period (2)	(84,500	)	(83,540	)
Changes from extensions, discoveries, and improved recovery (3)	67,974		29,554
Changes from purchases of minerals in place (3)	41,144		19,074
Changes from dispositions of minerals in place (3)	(22,879	)	(71,118	)
Changes from revisions in quantity estimates (3)	59,774		151,507
Previously estimated development costs during the period	22,181		28,500
Accretion of discount(4)	18,397		36,358
Other (5)	15,564		17,383
Net change in income tax (6)	—		—
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at end of year	450,582		183,972

____________________________________________________________________________

(1)The effect of changes in prices and costs has been computed before the effects of changes in quantities.

(2)Company actual before income taxes, excluding general and administrative expenses.

(3)Stated at prices used in estimating proved oil and gas reserves and year-end costs.

(4)The increase in the value of a discounted instrument as time passes.  Calculated as 10% of net present value at the beginning of the period.

(5)Includes changes to actual prices received versus forecast, actual versus forecast production from the prior period, development timing, operating costs, and royalty rates.

(6)The net change in the estimate of future income taxes that will be due on future pretax net cash flows relating to proved oil and gas reserves.

EX-14.1

Exhibit 14.1

Bellatrix Exploration Ltd.

CODE OF BUSINESS CONDUCT AND ETHICS

I. Introduction

Bellatrix Exploration Ltd. expects that its directors, officers and employees will uphold the highest standards of professional and ethical conduct. Our reputation among our shareholders for honesty and integrity is key to the success of our business. We expect our directors, officers and employees to act honestly and fairly and we rely upon you to achieve results in an ethical and lawful manner. References in this Code to the "Corporation" or to "Bellatrix" means Bellatrix Exploration Ltd. and its subsidiaries as applicable.

This Code reflects our commitment to a culture of honesty, integrity and accountability and outlines the basic principles and policies with which all directors, officers and employees are expected to comply. Please read this Code carefully.

In addition to following this Code in all aspects of your business activities, you are expected to seek guidance in any case where there is a question about compliance with both the letter and spirit of our policies and applicable laws. This Code sets forth general principles and does not supersede the specific policies and procedures that are covered in other, more specific policies, such as the Disclosure, Confidentiality and Trading Policy. Violation of these policies or this Code may result in disciplinary actions up to and including discharge from the Corporation.

Your cooperation is necessary to the continued success of our business and the cultivation and maintenance of our reputation as a good corporate citizen.

II. Conflicts of Interest

A conflict of interest can arise when: (a) an individual's private interest interferes, or appears to interfere, in any way with the interests of the Corporation; (b) an individual takes actions or has interests that may make it difficult to perform his or her work effectively or discharge his or her duties; or (c) when a director, officer or employee, or a member of his or her family, receives improper personal benefits as a result of his or her position in the Corporation. Loans to, or guarantees of obligations of, such persons are likely to pose conflicts of interest, as are transactions of any kind between the Corporation and any other organization in which you or any member of your family have an interest.

Activities that could give rise to conflicts of interest are prohibited unless specifically approved in advance by the Board of Directors of the Corporation (the "Board"); provided that the foregoing shall not apply to directors of the Corporation acting as directors of other public or private companies who comply with the provisions of the Business Corporations Act (Alberta) in respect thereof and who advise the Chairman of the Board of the holding of such directorships. It is not always easy to determine whether a conflict of interest exists, so any potential conflicts of interests must be reported immediately to senior management.

III. Gifts and Entertainment

The exchange of gifts and entertainment is a common practice in most business communities and is designed to foster goodwill among business partners. However, if you receive a gift or invitation for entertainment, we expect that you will assess whether it might compromise or be seen to compromise your ability to make fair and objective business decisions. Generally, gifts and entertainment should be moderate, reasonable and in good taste with no obligation or sense of obligation.

Further, pursuant to the Corruption of Foreign Public Officials Act (Canada) and the Foreign Corrupt Practices Act (United States) it is illegal and will be considered a violation of this Code for any director, officer or employee of the Corporation to offer to foreign government officials anything of value, including money, gifts, favours or entertainment, in exchange for obtaining or retaining business or for any other business advantage. "Foreign government officials" include government employees, political candidates or even employees of businesses that are owned by a foreign government, so we expect that you will exercise good judgment when dealing with state-owned companies or companies

owned or controlled by foreign government officials. Agents and consultants are similarly prohibited from offering anything on the Corporation's behalf to foreign officials or political candidates.

IV. Political Activities and Contributions

We respect and support the right of our directors, officers and employees to participate in political activities. However, these activities should not be conducted on Corporation time or involve the use of any Corporation resources. Directors, officers and employees will not be reimbursed for personal political contributions nor should political contributions be seen to be made on behalf of the Corporation without the approval of the Chief Executive Officer or Chief Financial Officer.

V. Corporate Opportunities

Employees, officers and directors owe a duty to the Corporation to advance its legitimate interests when the opportunity to do so arises. As such, directors, officers and employees must not personally take opportunities for themselves that arise through the use of corporate property, information or position and from using corporate property, information or position for personal gain. Directors, officers and employees are also prohibited from competing with the Corporation; provided that the foregoing does not apply to directors solely as a result of them acting as directors of other companies which they do not control.

VI. Confidentiality

In the course of your employment you may become aware of confidential information. We expect that you will maintain the confidentiality of information entrusted to you by the Corporation or that otherwise comes into your possession in the course of your employment or in performing your duties to the Corporation. The obligation to maintain the confidentiality of confidential information continues even after you leave the Corporation.

Confidential information includes all non-public information, and information that suppliers and customers have entrusted to us.

VII. Protection and Proper Use of Corporation Assets

We have entrusted our directors, officers and employees with the protection of the Corporation's assets, to ensure their efficient use and to ensure such assets are only being used for legitimate business purposes. We expect that you will report any suspected incidents of fraud or theft, or if you become aware of any conditions that may negatively impact our assets.

VIII. Insider Trading

As a publicly traded company, the Corporation is governed by securities laws which provide, among other things, that the market must have equal access to all public information. In the course of your employment you may become aware of material information that is not yet publicly available. It is illegal to trade in securities of the Corporation while in possession of material non-public information regarding the Corporation and/or to "tip" or pass on inside information to any other person (including, but not limited to, spouses, live-in partners, and relatives) who might make an investment decision based on that information or pass the information on further. The Corporation’s Disclosure, Confidentiality and Trading Policy sets forth your obligations in respect of trading in the Corporation's securities.

IX. Compliance with Laws, Rules and Regulations

Compliance with both the letter and spirit of all laws, rules and regulations applicable to our business is critical to our reputation and continued success. We expect that all directors, officers, employees, contractors and consultants will respect and obey the laws of the cities, provinces, states and countries in which we operate and avoid even the appearance of impropriety.

X. Compliance with Environmental, Health and Safety Standards

The Corporation’s reputation is dependent on environmental, health and safety responsibility. We are all responsible for maintaining a safe workplace by following safety and health rules and practices. The Corporation is committed to keeping its workplaces free from hazards. Please report any concerns, incidents or areas for improvement immediately to a supervisor or other designated person. If you have any doubt as to the applicability or meaning of a

particular environmental, health or safety regulation, you should discuss the matter with a member of the Corporation's senior management.

In order to protect the safety of all Bellatrix stakeholders, we expect that you will report to work "fit-for-duty" and free from the influence of any substance that could prevent you from conducting work activities safely and effectively.

XI. Discrimination and Harassment

We value the diversity of our employees and are committed to providing equal opportunity in all aspects of employment. Abusive, harassing or offensive conduct is unacceptable, whether verbal, physical or visual. We expect that our directors, officers and employees will treat each other in a respectful manner and will avoid conduct that makes others feel uncomfortable. Employees are encouraged to speak to your supervisor or manager of human resources when a co‑worker's conduct makes them uncomfortable, and to report harassment when it occurs.

XII. Accuracy of Corporation Records and Reporting

As you are aware, full, fair, accurate, timely and understandable disclosure in our periodic reports, documents and other public communications is required by securities regulators and the stock exchanges on which our securities are listed, and is essential to the success of our business. In addition, honest and accurate recording and reporting of information is critical to our ability to make responsible business decisions. All officers and employees should exercise the highest standard of care in preparing such reports.

The Corporation's accounting records are relied upon to produce reports for the Corporation's management, shareholders, creditors, governmental agencies and others. Our financial statements and the books and records on which they are based must accurately reflect all corporate transactions and conform to all legal and accounting requirements and our system of internal controls.

The Corporation's accounting records must not contain any false or intentionally misleading entries. All transactions as to accounts, departments or accounting periods must be accurately classified and supported by accurate documentation in reasonable detail and recorded in the proper account and in the proper accounting period. Documents or records must be retained and may not be selectively destroyed or altered except in accordance with the Corporation’s records retention policy.

Business records and communications often become public through legal or regulatory investigations or the media. We should avoid exaggeration, derogatory remarks, legal conclusions or inappropriate characterizations of people and companies. This applies to communications of all kinds, including email and informal notes or interoffice memos. In addition, the Corporation’s auditors and independent engineers will from time to time require access to our documents and records and such documents and records need to be appropriately maintained and retained to facilitate such access and review.

XIII. Use of E-Mail and Internet Services

E-Mail systems and internet services are provided to help us do work. Incidental and occasional personal use is permitted, but never for personal gain or any improper purpose. For additional information, refer to the Corporation’s information technology acceptable use standards.

XIV. Directors Role in the Code of Business Conduct and Ethics

To the extent that management is unable to make a determination as to whether a breach of this Code has taken place, the Board will review any alleged breach of the Code to determine if a breach has occurred.

Any waiver of this Code for employees (other than executive officers) may be made by the Chief Executive Officer or Chief Financial Officer or by the Board; provided that, any waiver of this Code for executive officers or directors may be made only by the Board and shall be timely disclosed if, and in the manner, required by law, regulation or stock exchange rule. Conduct by a director or executive officer which constitutes a material departure from this Code shall be promptly disclosed if, and in the manner, required by law, regulation or stock exchange rule.

XV. Compliance Procedures and Reporting of any Illegal or Unethical Behaviour

We have a strong commitment to conduct our business in a lawful and ethical manner. You are encouraged to talk to your supervisor, manager or other appropriate personnel when in doubt about the best course of action in a particular situation and are required to promptly report violations of laws, rules, regulations or this Code. We prohibit retaliatory action against any employee who, in good faith, reports a possible violation.

In addition, this Code cannot, and is not intended to, address all of the situations you may encounter. There will be occasions where you are confronted by circumstances not covered by policy or procedure and where you must make a judgment as to the appropriate course of action. In those circumstances we encourage you to use your common sense, and to contact your supervisor, manager or a member of human resources for guidance.

If you do not feel comfortable discussing the matter with your supervisor or manager of human resources, please contact our CEO or General Counsel, or anonymously contact the Corporation’s toll-free whistleblower hotline for the confidential and anonymous submission of questions and complaints. For more information, please see the Corporation's Whistle Blower Procedures (available here: http://www.bxe.com/files/governance/BXE-Whistle-Blower-Procedures.pdf). In addition, for additional information on Corporation policies, procedures and standards refer to the Corporation’s Employee Handbook available on the Corporation’s intranet site.

March 13, 2018

EX-23.1

Exhibit 23.1

KPMG LLP

205 5th Avenue SW

Suite 3100

Calgary AB

T2P 4B9

Telephone (403) 691-8000

Fax (403) 691-8008

www.kpmg.ca 

Consent of Independent Registered Public Accounting Firm

To the Board of Directors of Bellatrix Exploration Ltd.

We consent to the use of our reports, each dated March 13, 2018, with respect to the financial statements and effectiveness of internal control over financial reporting included in this annual report on Form 40-F.

We also consent to the incorporation by reference of such reports in the Registration Statement (No. 333-211466) on Form F-10 of Bellatrix Exploration Ltd.

/s/ KPMG LLP

Chartered Professional Accountants

March 13, 2018

Calgary, Canada

EX-23.2

Exhibit 23.2

Suite 2000, 801 - 6th Ave SW

Calgary, Albert T2P 3W2

Web     insitepc.com

March 13, 2018

Re: Consent of Independent Petroleum Engineers

We refer to our report dated February 28, 2018 and effective as of December 31, 2017, evaluating the crude oil, natural gas and natural gas liquids reserves and the net present value of future net revenue attributable to certain of the oil and natural gas assets of Bellatrix Exploration Ltd. ("Bellatrix") effective as at December 31, 2017 (the "Report").

We hereby consent to the use and reference to our name and the Report, and the information derived from the Report, as described or incorporated by reference in: Bellatrix's Annual Report on Form 40-F for the year ended December 31, 2017, filed or to be filed with the United States Securities and Exchange Commission. We also consent to the incorporation by reference of such report in the Registration Statement (No. 333-211466) on Form F-10 of Bellatrix.

Sincerely,

INSITE PETROLEUM CONSULTANTS LTD.

/s/ Ron Bojechko P. Eng.

Ron Bojechko P. Eng.

Managing Director

EXPERIENCE COUNTS.

EX-31.1

EXHIBIT 31.1

CERTIFICATION REQUIRED BY RULE 13a-14(a) OR RULE 15d-14(a) UNDER THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT

TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Brent A. Eshleman, certify that:

1. I have reviewed this annual report on Form 40-F of Bellatrix Exploration Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent function): 

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:  March 13, 2018
	/s/ Brent A. Eshleman
	Name:	Brent A. Eshleman
	Title:	President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION REQUIRED BY RULE 13a-14(a) OR RULE 15d-14(a) UNDER THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT

TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Maxwell A. Lof, certify that:

1. I have reviewed this annual report on Form 40-F of Bellatrix Exploration Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: 

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:  March 13, 2018
	/s/ Maxwell A. Lof
	Name:	Maxwell A. Lof
	Title:	Executive Vice-President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Bellatrix Exploration Ltd. (the “Company”) on Form 40-F for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brent A. Eshleman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly represents, in all material respects, the financial condition and results of the operations of the Company.

Date:  March 13, 2018
	/s/ Brent A. Eshleman
	Name:	Brent A. Eshleman
	Title:	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Bellatrix Exploration Ltd. (the “Company”) on Form 40-F for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Maxwell A. (Max) Lof, Executive Vice-President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly represents, in all material respects, the financial condition and results of the operations of the Company.

Date:  March 13, 2018
	/s/ Maxwell A. Lof
	Name:	Maxwell A. Lof
	Title:	Executive Vice-President and Chief Financial Officer

XML

Document Entity Information Document	12 Months Ended
	Dec. 31, 2017 shares
Document And Entity Information [Abstract]
Entity Registrant Name	Bellatrix Exploration Ltd.
Entity Central Index	0001483405
Document Type	40-F
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Well Known Seasoned Issuer	No
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Entity Common Stock, Shares Outstanding	49,378,026

XML

BALANCE SHEETS - CAD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets
Accounts receivable (note 17)	$ 45,672	$ 39,227
Current portion of loans receivable (note 7)	0	6,225
Deposits and prepaid expenses	3,709	5,205
Marketable securities	0	4,322
Current portion of risk management asset (note 17)	31,910	0
Current assets	81,291	54,979
Non-current assets [abstract]
Risk management asset (note 17)	1,213	445
Loans receivable (note 7)	0	8,775
Deferred taxes (note 13)	48,298	63,713
Exploration and evaluation assets (note 6)	22,731	29,246
Property, plant and equipment (note 7)	1,187,390	1,296,572
Total assets	1,340,923	1,453,730
Current liabilities
Accounts payable and accrued liabilities	73,307	78,695
Current portion of other deferred liabilities (note 10)	20,790	26,064
Current portion of risk management liability (note 17)	4,468	13,936
Current portion of Credit Facilities (note 8)	0	19,143
Current portion of decommissioning liability (note 9)	1,924	0
Current liabilities	100,489	137,838
Non-current liabilities [abstract]
Credit Facilities (note 8)	52,066	0
Convertible Debentures (liability component) (note 8)	39,426	37,420
Senior Notes (note 8)	305,409	324,691
Risk management liability (note 17)	3,422	2,646
Other deferred liabilities (note 10)	7,402	24,873
Decommissioning liabilities (note 9)	58,687	62,844
Total liabilities	566,901	590,312
SHAREHOLDERS’ EQUITY
Shareholders’ capital (note 11)	1,068,377	1,068,084
Convertible Debentures (equity component) (note 8)	7,818	7,818
Contributed surplus	56,092	54,418
Retained earnings (deficit)	(358,265)	(266,902)
Total shareholders’ equity	774,022	863,418
Total liabilities and shareholders’ equity	$ 1,340,923	$ 1,453,730

XML

STATEMENTS OF PROFIT (LOSS) AND COMPREHENSIVE INCOME (LOSS) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
REVENUES
Petroleum and natural gas sales	$ 243,825	$ 220,124
Royalties	(23,961)	(18,636)
Other income	5,574	7,750
Total revenues net of royalties	225,438	209,238
Realized gain on commodity contracts (note 17)	31,324	19,892
Unrealized gain (loss) on commodity contracts (note 17)	45,238	(29,525)
Revenues net of royalties and commodity contracts	302,000	199,605
EXPENSES
Production	111,816	113,589
Transportation	23,549	12,108
General and administrative	29,377	19,919
Loss on marketable securities	461	678
Share-based compensation (note 12)	532	3,784
Depletion and depreciation (note 7)	120,652	136,518
Impairment (reversal) (note 7)	13,150	(264,000)
Loss (gain) on dispositions (note 7)	56,672	170,667
Expenses	356,209	193,263
NET PROFIT (LOSS) BEFORE FINANCE AND TAXES	(54,209)	6,342
Finance expenses (note 14)	39,240	48,063
Realized (gain) loss on foreign exchange (note 15)	797	(277)
Unrealized foreign exchange (gain) loss	(18,298)	(7,918)
NET PROFIT (LOSS) BEFORE TAXES	(75,948)	(33,526)
TAXES
Deferred tax expense (recovery) (note 13)	15,415	(6,858)
NET PROFIT (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$ (91,363)	$ (26,668)
Net profit (loss) per share (note 16)
Basic (in dollars per share)	$ (1.85)	$ (0.62)
Diluted (in dollars per share)	$ (1.85)	$ (0.62)

XML

STATEMENTS OF SHAREHOLDERS' EQUITY - CAD ($) $ in Thousands	Total	Shareholders' capital	Convertible debentures (equity component)	Contributed surplus	Retained earnings
Equity attributable to owners of parent, beginning of period at Dec. 31, 2015		$ 1,000,100	$ 0	$ 50,706	$ (240,234)
Issued for cash on equity issue		29,080
Issued for cash on equity issue		40,400
Share issue costs on equity issue, net of tax effect		(1,781)
Share-based compensation awards		285
Conversion feature of Convertible Debentures issued, net of tax effect			7,818
Share-based compensation expense (note 12)				4,463
Adjustment of share-based compensation expense for forfeitures of unvested share options				(751)
Net profit (loss)					(26,668)
Equity attributable to owners of parent, end of period at Dec. 31, 2016	$ 863,418	1,068,084	7,818	54,418	(266,902)
Issued for cash on equity issue		0
Issued for cash on equity issue		0
Share issue costs on equity issue, net of tax effect		4
Share-based compensation awards		289
Conversion feature of Convertible Debentures issued, net of tax effect			0
Share-based compensation expense (note 12)				2,233
Adjustment of share-based compensation expense for forfeitures of unvested share options				(559)
Net profit (loss)					(91,363)
Equity attributable to owners of parent, end of period at Dec. 31, 2017	$ 774,022	$ 1,068,377	$ 7,818	$ 56,092	$ (358,265)

XML

STATEMENTS OF CASH FLOWS - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
CASH FLOW FROM (USED IN) OPERATING ACTIVITIES
Net profit (loss)	$ (91,363)	$ (26,668)
Adjustments for:
Depletion and depreciation (note 7)	120,652	136,518
Impairment (reversal) and (gain) loss on dispositions (note 7)	69,822	(93,333)
Accretion on decommissioning obligations (note 9)	1,287	1,713
Non-cash financing and accretion (note 8)	4,803	3,323
Share-based compensation (note 12)	699	3,936
Unrealized (gain) loss on commodity contracts (note 17)	(45,238)	29,525
Unrealized foreign exchange (gain) loss (note 15)	(18,298)	(7,918)
Loss on marketable securities	461	678
Deferred tax expense (recovery) (note 13)	15,415	(6,858)
Decommissioning costs incurred (note 9)	(2,758)	(2,927)
Change in non-cash working capital (note 20)	(272)	(443)
Cash flows from (used in) operating activities	55,210	37,546
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
Issuance of share capital, net of issue costs (note 11)	4	37,825
Issuance of Convertible Debentures, net of issue costs (note 8)	0	47,610
Issuance of Senior Notes, net of issue costs (note 8)	0	(55)
Settlement of share based payments	(1,246)	(730)
Advances from (repayment of) loans and borrowings	32,923	(321,601)
Financing obligations (note 10)	(7,558)	(3,997)
Deferred lease inducements (note 10)	(366)	(340)
Drawdown deferred capital obligations	(14,693)	(3,291)
Change in non-cash working capital (note 20)	(16,353)	(601)
Cash flows from (used in) financing activities	25,417	(243,978)
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
Expenditure on exploration and evaluation assets (note 6)	(1,664)	(2,349)
Additions to property, plant and equipment (note 7)	(121,586)	(76,531)
Proceeds on sale of property, plant and equipment	48,370	296,638
Proceeds on sale of marketable securities	3,861	0
Change in non-cash working capital (note 20)	(9,608)	(11,326)
Cash flows from (used in) investing activities	(80,627)	206,432
Change in cash	0	0
Cash, beginning of year	0	0
Cash, end of year	0	0
Cash paid:
Interest	33,930	40,464
Taxes	$ 0	$ 0

XML

CORPORATE INFORMATION

12 Months Ended

Dec. 31, 2017

General Information About Financial Statements [Abstract]

CORPORATE INFORMATION

CORPORATE INFORMATION

Bellatrix Exploration Ltd. (the “Company” or “Bellatrix”) is a publicly traded 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 with highly concentrated operations in west central Alberta, principally focused on profitable development of the Spirit River liquids rich natural gas play.

Common shares of Bellatrix trade on the Toronto Stock Exchange (“TSX”) and on the New York Stock Exchange (“NYSE”) under the symbol “BXE”.

Bellatrix was incorporated in Alberta, Canada and the Company’s registered office and principal place of business is located at 1920, 800 – 5th Avenue SW, Calgary, Alberta, Canada, T2P 3T6.

XML

BASIS OF PREPARATION

12 Months Ended

Dec. 31, 2017

Disclosure Of Basis Of Preparation Of Financial Statements [Abstract]

BASIS OF PREPARATION

BASIS OF PREPARATION

a. Statement of compliance

These financial statements (“financial statements”) were authorized by the Board of Directors on March 13, 2018. The Company prepared these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”).

b. Basis of measurement

The financial statements are presented in Canadian dollars, the Company’s functional currency, and have been prepared on the historical cost basis except for derivative financial instruments, marketable securities and liabilities for cash-settled share-based payment arrangements measured at fair value. The financial statements have, in management’s opinion, been properly prepared using careful judgment and reasonable limits of materiality, and within the framework of the significant policies summarized in note 3. Significant estimates and judgments used in the preparation of the financial statements are detailed in note 4.

XML

SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title to the products transfers to the purchasers based on volumes delivered and contracted delivery points and prices. Revenue is measured at the fair value of the consideration received or receivable. Revenue from the sale of crude oil, natural gas, condensate and natural gas liquids (“NGLs”) (prior to deduction of transportation costs) is recognized when all of the following conditions have been satisfied:

• Bellatrix has transferred the significant risks and rewards of ownership of the goods to the purchaser;

• Bellatrix retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;

• the amount of revenue can be measured reliably;

• it is probable that the economic benefits associated with the transaction will flow to Bellatrix; and

• the costs incurred or to be incurred in respect of the transaction can be measured reliably.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements and is included with petroleum and natural gas sales.

Capital processing charges to other entities for use of facilities owned by the Company are recognized as revenue as they accrue in accordance with the terms of the service agreements and are presented as other income.

Transportation

Costs paid by Bellatrix for the transportation of crude oil, natural gas, condensate and NGLs to the point of title transfer are recognized when the transportation is provided.

Joint Interests

A portion of the Company’s exploration and development activities are conducted jointly with others. The joint interests are accounted for on a proportionate consolidation basis and as a result, the financial statements reflect only the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows from these activities.

Property, Plant and Equipment and Exploration and Evaluation Assets

I. Pre-exploration expenditures

Expenditures made by the Company before acquiring the legal right to explore in a specific area do not meet the definition of an asset and therefore are expensed by the Company as incurred.

II. Exploration and evaluation expenditures

Once the legal right to explore has been acquired, costs incurred are capitalized as intangible exploration and evaluation assets (“E&E). These costs include, but are not limited to, exploration license expenditures, leasehold property acquisition costs, evaluation costs, including drilling costs directly attributable to an identifiable well and directly attributable general and administrative costs. These costs are accumulated in cost centres by property and are not subject to depletion, until technical feasibility and commercial viability have been determined. 

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, or if facts and circumstances suggest that the carrying amount is unlikely to be recovered.

III. Developing and production costs

Items of property, plant and equipment (“PP&E”), which include oil and gas development and production assets, are measured at cost less accumulated depletion, depreciation and accumulated impairment losses net of recoveries.

Gains and losses on disposal of an item of PP&E, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of PP&E, and are recognized within the Statements of Profit (Loss) and Comprehensive Income (Loss).

IV. Joint arrangements

The Company has entered into certain joint arrangements whereby the joint arrangement partner will earn a working interest on certain properties through the payment of a pre-determined portion of the costs of drilling, completing and equipping. A gain on disposition for each well is recognized to account for the disposal of the pre-payout working interest earned by the partner on the well, as described under "Dispositions" below. Bellatrix has property, plant and equipment assets that are subject to these arrangements.

V. Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a well, field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

VI. Depletion and depreciation

Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes in relation to total estimated proven and probable reserves as determined annually by independent engineers in accordance with National Instrument 51-101, Standards of Disclosure of Oil and Gas Activities. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Calculations for depletion are based on total capitalized costs plus estimated future development costs of proven and probable undeveloped reserves less the estimated net realizable value of production equipment and facilities after the proved and probable reserves are fully produced.

Depreciation is recognized on significant facilities to expense the cost of significant components of assets less their residual values over their useful lives. Phase 1 of the Alder Flats Plant and associated equipment are depreciated using the straight-line method over estimated useful lives as follows:

• General plant and processing equipment - 40 years

• Other properties and equipment - 10 years

• Turnarounds - 5 years

Costs of facilities under construction related to Phase II of the Alder Flats Plant as at December 31, 2017 were excluded from depreciation calculations.

Depreciation of office furniture and equipment is provided for on a 20% declining balance basis.

Depreciation methods, useful lives and residual values are reviewed at each reporting date and, if necessary, any changes would be accounted for prospectively.

VII. Dispositions

Gains on disposal of an item of PP&E or E&E are determined by comparing the proceeds from disposal with the carrying amount of PP&E or E&E and are recognized separately in the Statements of Profit (Loss) and Comprehensive Income (Loss). Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reasonably measured. Where the exchange is measured at fair value, a gain or loss is recognized in the Statements of Profit (Loss) and Comprehensive Income (Loss).

Impairment and Impairment Reversal

I. Financial assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. All impairment losses are recognized in profit or loss.

II. Non-financial assets

Developing and producing assets are assessed for impairment if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. The impairment test is performed at the asset or CGU level.

The recoverable amount of an asset or a cash-generating unit ("CGU") is the greater of its value in use (“VIU”) and its fair value less costs to sell (“FVLCS”). FVLCS is determined to be the amount for which the asset could be sold in an arm’s length transaction. FVLCS can be determined by using an observable market metric or by using discounted future net cash flows of proved and probable reserves using forecasted prices and costs. VIU is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in the Company’s Statement of Profit (Loss) and Comprehensive Income (Loss) in the period in which it occurs.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

E&E assets are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to producing assets (oil and natural gas interests in PP&E). E&E assets are grouped together with the Company’s CGU’s when they are assessed for impairment.

Provisions

Provisions are recognized when the Company has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Provisions are determined by discounting the expected cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability, if the risks have not been incorporated into the estimate of cash flows. The increase in the provision due to the passage of time is recognized within finance expense.

I. Decommissioning liabilities

The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. A provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation at the balance sheet date. Changes in the present value of the estimated expenditure are reflected as an adjustment to the liability and the relevant asset. The accretion or unwinding of the discount on the decommissioning provision is recognized as a finance expense. Actual costs incurred upon settlement of the decommissioning liabilities are charged against the provision to the extent the provision was recognized.

II. Environmental liabilities

The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Any amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Share-based Payments

I. Equity-settled transactions

Bellatrix accounts for options issued under the Company’s share option plan by reference to the fair value of the equity instruments granted. The fair value of each share option is estimated on the date of the grant using the Black-Scholes options pricing model and charged to earnings over the vesting period with a corresponding increase to contributed surplus. The Company estimates a forfeiture rate on the grant date and the rate is adjusted to reflect the actual number of options that actually vest. The expected life of the options granted is adjusted, based on the Company’s best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.

II. Cash-settled transactions

The Company’s Deferred Share Unit Plan (the “DSU Plan”) is accounted for as a cash settled share based payment plan in which the fair value of the amount payable under the DSU Plan is recognized as an expense with a corresponding increase in liabilities. The liability is remeasured at each reporting date and at settlement date. Any changes in the fair value of the liability are recognized in profit or loss.

Awards under the Award Incentive Plan ("Award Plan") may be settled in cash, in common shares of the Company, or a combination thereof. The Company’s Restricted and Performance Award Plan is accounted for as a cash settled share based payment plan in which the fair value of the amounts payable under the Award Plan are recognized incrementally as an expense over the vesting period, with a corresponding change in liabilities.

Income Taxes

Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

I. Current tax

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid, to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted, or substantively enacted, by the date of the statement of financial position.

II. Deferred tax 

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted, or substantively enacted, by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Financial Instruments

All financial instruments, including all derivatives, are recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in income. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income and reclassified to income when derecognized or impaired. The Company has the following classifications:

Financial Assets and Liabilities	Category	Subsequent Measurement
Accounts receivable	Loans and receivables	Amortized cost
Loans receivable	Loans and receivables	Amortized cost
Marketable securities	Held-for-trading	Fair value through profit or loss; Level 1
Commodity risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Foreign exchange risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Accounts payable and accrued liabilities	Other liabilities	Amortized cost
Deferred share units	Other liabilities	Fair value through profit or loss; Level 1
Restricted awards	Other liabilities	Fair value through profit or loss; Level 1
Performance awards	Other liabilities	Fair value through profit or loss; Level 2
Credit Facilities	Other liabilities	Amortized cost
Senior Notes	Other liabilities	Amortized cost
Convertible Debentures	Other liabilities	Amortized cost
Deferred capital obligation	Other liabilities	Amortized cost
Finance lease obligation	Other liabilities	Amortized cost

Financial instruments measured at fair value on the balance sheet require classification into one of the following levels of the fair value hierarchy:

Level 1 – Valuation based on quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 – Valuation based on inputs other than quoted prices included in level 1, that are observable directly or indirectly.

Level 3 – Valuation based on inputs that are not based on observable market data.

The fair value hierarchy level at which a fair value measurement is categorized is determined on the basis of the lowest level input that is significant to the fair value measurement in its entirety. The Company has categorized its financial instruments that are fair valued on the balance sheet according to the fair value hierarchy.

Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument using the effective interest rate method.

The Company utilizes financial derivatives and commodity sales contracts requiring physical delivery to manage the price risk attributable to anticipated sale of petroleum and natural gas production and foreign exchange exposures. The Company does not enter into derivative financial instruments for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, financial derivatives are classified as fair value through profit or loss and are recorded on the balance sheet at fair value, with fair value changes recorded in profit or loss.

The derivative financial instruments are initiated within the guidelines of the Company’s corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet, to specific firm commitments, or forecasted transactions.

The Company accounts for its commodity sales and purchase contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items, in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, physical sales and purchase contracts are not recorded at fair value on the balance sheet. Settlements on these physical sales and purchase contracts are recognized in petroleum and natural gas sales.

Compound Financial Instruments

The Company's compound financial instruments are comprised of its Convertible Debentures that can be converted to common shares at the option of the holder. The number of shares to be issued does not vary with changes in fair value. 

The liability component of the Convertible Debentures is recognized initially at the fair value of a similar liability that does not have an equity conversion option. The equity component is recognized initially as the difference between the fair value of the Convertible Debenture and the fair value of the liability component. Any directly attributable transaction costs are allocated to the liability and equity components in proportion to their initial carrying amounts.

Subsequent to initial recognition, the liability component of the Convertible Debentures is measured at amortized cost using the effective interest method. The equity component of the Convertible Debentures is not re-measured subsequent to initial recognition.

Lease Obligations

Leases which effectively transfer substantially all of the risks and rewards of ownership to the Company are classified as finance leases and are accounted for as an acquisition of an asset and an assumption of an obligation at the inception of the lease, measured as the present value of minimum lease payments to a maximum of the asset’s fair value. The asset is amortized in accordance with the Company’s depletion and depreciation policy. The obligations recorded under finance lease payments are reduced by the lease payments made.

Assets held under other leases are classified as operating leases and are not recognized in the balance sheet. Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. Lease incentives received from landlords are deferred and recognized as an integral part of the total lease expense, over the term of the lease.

Basic and Diluted per Share Calculations

Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. The Company uses the treasury share method to determine the dilutive effect of share options. Under the treasury share method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted per share amounts.

Finance Income and Expenses

Finance income is recognized as it accrues in profit or loss, using the effective interest method. Finance expense comprises interest expense on borrowings, amortization of financing costs and discounts, accretion of the discount on provisions and impairment losses recognized on financial assets.

Borrowing Costs

Borrowing costs incurred for the construction of qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use. All other borrowing costs are recognized in profit or loss using the effective interest method. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Company’s outstanding borrowings during the period.

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with original maturities of three months or less.

Business Combinations

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities and contingent liabilities assumed are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the aggregate consideration transferred, measured at the acquisition date fair value. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in profit or loss. If the cost of the acquisition is more than the fair value of the net assets acquired, the difference is recognized on the balance sheet as goodwill. Acquisition costs incurred are expensed.

Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses are translated at the period average rates of exchange. Translation gains and losses are included in earnings in the period in which they arise.

Bellatrix’s functional and presentation currency is Canadian dollars.

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CRITICAL JUDGEMENTS AND ACCOUNTING ESTIMATES

12 Months Ended

Dec. 31, 2017

Changes In Accounting Policies, Accounting Estimates And Errors [Abstract]

CRITICAL JUDGEMENTS AND ACCOUNTING ESTIMATES

CRITICAL JUDGMENTS AND ACCOUNTING ESTIMATES

The financial statements of the Company have been prepared by management in accordance with IFRS. The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, and contingent liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period and accompanying notes. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.

a. Critical Accounting Judgments

I. Oil and Gas Reserves

Reserves and resources are used in the units of production calculation for depletion, depreciation and amortization, and the impairment analysis which affect net profit or loss. There are numerous uncertainties inherent in estimating oil and gas reserves. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net profit as further information becomes available and as the economic environment changes.

II. Identification of CGUs

Bellatrix’s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, geology, production profile and infrastructure of their assets.

III. Impairment Indicators and Impairment Reversal 

Judgment is required to assess when impairment indicators exist and impairment testing is required with respect to exploration and evaluation assets and property, plant and equipment.

IV. Joint Arrangements

Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint control, the Company considers whether unanimous consent is required to direct the activities that significantly affect the returns of the arrangement, such as the capital and operating activities of the arrangement. Additionally, the Company assesses the rights and obligations arising from the arrangement by considering its governance structure, legal form, and terms agreed upon by the parties sharing control, including the contractual rights of each partner, dispute resolution procedures, termination provisions, and procedures for subsequent transactions in its determination of joint control.

Once joint control has been established, judgment is also required to classify the joint arrangement. The type of joint arrangement is determined through analysis of the rights and obligations arising from the arrangement by considering its legal structure, legal form and terms agreed upon by the parties sharing control. An arrangement that is not structured through a separate vehicle in which the controlling parties have rights to the assets, revenues and substantially all of the economic benefits generated through the arrangement, in addition to obligations for the liabilities and expenses, is classified as a joint operation. An arrangement in which these criteria are not met is classified as a joint venture.

V. Non-monetary Transactions

Judgment is required to determine whether non-monetary transactions have commercial substance.

b. Critical Estimates and Assumptions

I. Recoverability of asset carrying values

The Company assesses its oil and gas properties, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date. 

The assessment of any impairment of property, plant and equipment is dependent upon estimates of recoverable amount that take into account factors such as reserves, future estimated commodity prices, royalties and costs, economic and market conditions, timing of cash flows, the useful lives of assets and their related salvage values. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company’s assets in future periods.

II. Decommissioning obligations

Provisions for decommissioning obligations associated with the Company’s drilling operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology.

III. Income taxes 

Deferred tax assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.

IV. Business combinations 

The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or goodwill. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.

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NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

12 Months Ended

Dec. 31, 2017

Changes In Accounting Policies, Accounting Estimates And Errors [Abstract]

NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

The following pronouncements from the International Accounting Standards Board (“IASB”) are applicable to Bellatrix and will become effective for future reporting periods, but have not yet been adopted:

IFRS 9 - “Financial Instruments”, which is the result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. This standard is effective for annual periods beginning on or after January 1, 2018 with different transitional arrangements depending on the date of initial application.

The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the requirements of IAS 39; however, where the fair value option is applied to financial liabilities, any change in fair value resulting from an entity's own credit risk is recorded in other comprehensive income rather than the statement of income. Bellatrix has determined the adoption of IFRS 9 will not result in any material changes to the classification of financial assets and liabilities or to the measurement and carrying values of the Company's financial instruments.

In addition, IFRS 9 introduces a new expected credit loss model for calculating impairment of financial assets, replacing the incurred loss impairment model required by IAS 39. Bellatrix has determined that the new impairment model will not result in material changes to the valuation of its financial assets on the adoption of IFRS 9. Bellatrix does not currently apply hedge accounting to its financial instrument contacts and does not currently intend to apply hedge accounting to any of its derivative contracts upon adoption of IFRS 9.

IFRS 15 - “Revenue from Contracts with Customers”, provides a five-step model to be applied to all revenue contracts with customers. The standard specifies when an entity will recognize revenue and provides guidance regarding disclosures relating to revenue recognition. IFRS 15 is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018.

Bellatrix intends to adopt IFRS 15 using a modified transition approach on January 1, 2018. The Company has completed reviewing its various revenue streams and underlying contracts with customers. It has been concluded the adoption of IFRS 15 will not have a material impact on Bellatrix's net income and financial position. However, Bellatrix will expand the disclosures in the notes to its financial statements as prescribed by IFRS 15, including disclosing the Company's disaggregated revenue streams by product type.

IFRS 16 - "Leases”, replaces IAS 17 Leases. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. All contracts that meet the definition of a lease under IFRS 16, including those presently accounted for as operating leases, will be recorded on the balance sheet. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. The extent of the impact of the adoption of IFRS 16 has not yet been determined.

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EXPLORATION AND EVALUATION ASSETS

12 Months Ended

Dec. 31, 2017

Exploration For And Evaluation Of Mineral Resources [Abstract]

EXPLORATION AND EVALUATION ASSETS

EXPLORATION AND EVALUATION ASSETS

($000s)
Cost
Balance, December 31, 2015	$	87,919
Additions	2,349
Dispositions	(31,176		)
Transfer to oil and natural gas properties	(29,846		)
Balance, December 31, 2016	29,246
Additions	1,664
Dispositions	(7,843		)
Transfer to oil and natural gas properties	(336		)
Balance, December 31, 2017	$	22,731

Exploration and evaluation ("E&E") assets consist of Bellatrix's exploration projects which are pending the determination of proved or probable reserves and production.

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2017

Property, plant and equipment [abstract]

PROPERTY, PLANT AND EQUIPMENT

ellatrix has included $832 million (2016: $950 million) for future development costs and excluded $46.6 million (2016: $46.0 million) for estimated salvage from the depletion and depreciation calculation for the three months ended December 31, 2017. Operated facilities include capital associated with Phase 1 of the Bellatrix O’Chiese Nees-Ohpawganu’ck deep-cut gas plant at Alder Flats (the “Alder Flats Plant”), as well as capital associated with Phase 2 and related infrastructure. Costs of facilities under construction of $39.7 million related to Phase 2 of the Alder Flats Plant as at December 31, 2017 were excluded from depreciation calculations.

Dispositions

During the third quarter of 2017, Bellatrix completed the sale of certain non-core oil and gas properties in the West Pembina area of Alberta for gross proceeds of $16.0 million, effective July 1, 2017. Bellatrix recorded a loss of $18.6 million on the sale.

During the second quarter of 2017, Bellatrix completed the sale of certain non-core oil and gas properties in the Strachan area of Alberta for gross proceeds of $34.5 million, effective April 1, 2017. Bellatrix recorded a loss of $37.0 million on the sale. Additionally, in the second quarter, Bellatrix transferred certain production facilities and infrastructure to a third party midstream company in exchange for proceeds of $20 million. Under the terms of the agreement, Bellatrix will have exclusive access to, and operatorship of, the infrastructure. Bellatrix recorded a deferred capital obligation of $20 million in the second quarter of 2017 for the production facilities. Work on the production facilities was completed in the fourth quarter of 2017 resulting in a deferred capital obligation of nil as at December 31, 2017.

During the second quarter of 2016, Bellatrix sold certain production facilities to a third party midstream company for proceeds of $75 million effective May 3, 2016. Pursuant to the agreement, Bellatrix maintains operatorship and preferential access to the facilities for its operated production volumes and will pay an annual rental fee over the eight years duration of the agreement. In addition, Bellatrix retains, at its sole discretion, the option to repurchase the facilities at any time during the agreement period. Payments for use of the facilities are treated as an operating lease and included in Bellatrix’s corporate commitments.

During the third quarter of 2016, Bellatrix completed a $112.5 million disposition of a 35% working interest in the Alder Flats Plant (“Alder Flats Plant Sale”) to Keyera Partnership ("Keyera"). As part of the transaction, Bellatrix and Keyera entered into a midstream services and governance agreement pursuant to which Bellatrix will have exclusive access to the purchased capacity (approximately 80.5 MMcf/d post commissioning of Phase 2) for a term of 10 years, and will remain the operator of the Alder Flats Plant.  In exchange for granting 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 Alder Flats Plant. Following completion of the transaction, Bellatrix retains a 25% interest in the Alder Flats Plant, and has the option to reacquire a 5% interest in the Alder Flats Plant near the end of the final year of the agreement at a cost of $8 million.

Bellatrix recorded a gain on disposition of $9.8 million in relation to the Company’s disposed working interest in Phase 1 of the Alder Flats Plant and a deferred gain of $10.7 million related to the prepayment for the working interest in Phase 2 of the Alder Flats Plant which is currently under construction. Bellatrix recorded a deferred capital obligation for the remaining Phase 2 costs to be incurred to construct and commission Phase 2, related to Keyera’s 35% working interest, and a deferred financing obligation. At December 31, 2017, the balances of these obligations are $4.8 million and $1.5 million, respectively and work on the Alder Flats Plant is expected to be completed in the second quarter of 2018.

During the fourth quarter of 2016, Bellatrix completed two asset dispositions. Firstly, Bellatrix completed the Pembina property sale for total consideration of $47 million, consisting of approximately $42 million in cash and 2,171,667 common shares of the purchaser with a fair value of $5 million at the time of sale. Bellatrix recorded a loss of $26.2 million on the disposition. Secondly, Bellatrix completed the Harmattan property sale for total consideration of $80 million including net cash proceeds of approximately $65 million, and a $15 million loan receivable bearing interest at 10%. Bellatrix recorded a loss of $147.7 million on the disposition. The net cash proceeds from the Pembina and the Harmattan property sales were used to reduce the Company's outstanding Credit Facilities.

For the year ended December 31, 2016, the Company recognized total net gains on disposition of $6.7 million, relating to gains on wells drilled under a joint venture agreement that was terminated in December 2016.

For the year ended December 31, 2017, the Company capitalized $7.6 million (2016: $7.0 million) of general and administrative expenses and $0.8 million (2016: $1.4 million) of share-based compensation costs directly related to exploration and development activities.

Business Combination

Bellatrix completed a property acquisition of complementary assets within its core Ferrier area for total consideration of $29.2 million in June 2016, paid through the issuance of 4,109,515 common shares of Bellatrix. Bellatrix assessed the property acquisition and determined it to constitute a business combination under IFRS. The acquired assets consisted of $29.7 million of oil and natural gas properties, the value of which was determined using observable market metrics in addition to $0.5 million of decommissioning liabilities assumed as a result of the acquisition.

Impairment Loss (Reversal)

Bellatrix performed an assessment of possible indicators of impairment or impairment reversal on all of the Company’s CGUs. At December 31, 2017, impairment indicators were identified for the Company’s non-core North Alberta CGU and non-core South Alberta CGU, primarily as a result of a lack of active development plans in the CGUs. No impairment indicators were identified in the Company’s core Central Alberta CGU in 2017.

For the year ended December 31, 2017, a non-cash impairment loss of $12.2 million was recognized in the Company’s non-core North Alberta CGU. The estimated recoverable amount of the North Alberta CGU as at December 31, 2017 was $5.3 million. A non-cash impairment loss of $1.0 million was recognized in the Company’s non-core South Alberta CGU. The estimated recoverable amount of the South Alberta CGU was $1.4 million.

The recoverable amount of the North Alberta and South Alberta CGUs as at December 31, 2017 was determined using a VIU approach, as Bellatrix determined that VIU was greater than FVLCS. VIU was calculated as the net present value of the before-tax cash flows from proved plus probable oil and gas reserves of each CGU based on reserves estimated by Bellatrix’s independent reserve evaluator at December 31, 2017, adjusted for the net present value of the before-tax abandonment and reclamation costs on proved plus probable undeveloped oil and gas reserves.

The VIU of each CGU was based on before-tax discount rates ranging from 15-20% and the following forward commodity price estimates:

Year	EdmontonCrude Ref Oil ($/bbl) (1)	AECO NaturalGas ($/MMBtu) (1)	Butane ($/bbl) (1)	Propane  ($/bbl) (1)	Condensate($/bbl) (1)	CDN$/US$ Exchange Rates(1)
2018	71.36	2.52	51.38	35.68	74.93	1.27
2019	73.44	2.93	52.88	36.72	77.12	1.25
2020	75.47	3.22	54.34	35.85	79.25	1.23
2021	80.49	3.51	57.96	36.22	84.52	1.22
2022	82.38	3.75	59.31	37.07	86.50	1.20
2023	84.22	3.85	60.64	37.90	88.43	1.19
2024	86.01	3.95	61.93	38.70	90.31	1.18
2025	88.85	4.11	63.97	39.98	93.29	1.18
2026	90.62	4.27	65.25	40.78	95.15	1.18
2027	92.43	4.35	66.55	41.60	97.06	1.18
Thereafter	+2% per year	+2% per year	+2% per year	+2% per year	+2% per year	1.18

(1)The InSite price forecasts, effective January 1, 2018.

A 1% increase to the discount rates applied in the impairment calculation for the North Alberta CGU and South Alberta CGU would result in an increase in impairment loss of approximately $0.3 million and $0.1 million, respectively for the year ended December 31, 2017, whereas a 1% decrease to the discount rates applied would result in a corresponding decrease to the impairment loss recognized.

At December 31, 2016, impairments reversal indicators were identified for the Company's core Central Alberta CGU, primarily as a result of a significant increase in the reserves evaluation due to a combination of actual well performance exceeding previous estimates resulting in strong positive technical revisions and infill drilling additions in 2016. Impairment indicators were identified for the Company's non-core South Central CGU given the Company was no longer focused on actively developing these assets. The South Central CGU assets were subsequently sold in the second quarter of 2017.

For the year ended December 31, 2016, a non-cash impairment reversal of $307.0 million was recognized in the Company’s core Central Alberta CGU, representing the maximum amount of impairment reversal able to be taken based on prior impairment loss less depletion and dispositions. The estimated recoverable amount of the Central Alberta CGU as at December 31, 2016 was $1.3 billion. A non-cash impairment loss of $43 million was recognized in the Company's non-core South Central CGU. The estimated recoverable amount of the South Central CGU was $64 million. No impairment was recognized in the Company's non-core North Alberta and South Alberta CGUs in 2016. The VIU determination of estimated recoverable amounts of each CGU was based on before-tax discount rates ranging from 10-20% and the following forward commodity price estimates:

Year	EdmontonCrude Ref Oil ($/bbl) (1)	AECO Gas ($/MMBtu)(1)	Butane ($/bbl)(1)	Propane($/bbl)(1)	Condensate($/bbl) (1)	CDN$/US$ Exchange Rates(1)
2017	68.33	3.47	47.83	23.92	75.17	1.33
2018	72.32	3.42	52.07	25.31	79.55	1.29
2019	76.05	3.59	54.75	26.62	83.65	1.25
2020	79.54	3.93	57.27	27.84	87.50	1.21
2021	82.82	4.01	59.63	28.99	91.11	1.18
2022	88.60	4.17	63.79	31.01	97.46	1.18
2023	90.37	4.27	65.07	31.63	99.41	1.18
2024	92.18	4.43	66.37	32.26	101.39	1.18
2025	94.02	4.52	67.69	32.91	103.42	1.18
2026	95.90	4.61	69.05	33.57	105.49	1.18
Thereafter	+2% per year	+2% per year	+2% per year	+2% per year	+2% per year	1.18

(1)The InSite price forecasts, effective January 1, 2017.

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DEBT

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

DEBT

DEBT

($000s)	2017		2016
Credit Facilities - current	$	—	$	19,143
Credit Facilities - non-current	52,066		—
Convertible Debentures (liability component)	39,426		37,420
Senior Notes (due on May 15, 2020)	305,409		324,691
Debt	$	396,901	$	381,254

Credit Facilities

At December 31, 2017, the Company had $52.1 million outstanding under its $120 million syndicated revolving credit facilities (the “Credit Facilities”) at a weighted average interest rate of 4.45%. In addition, total outstanding letters of credit were $13 million.The Credit Facilities are available on an extendible revolving term basis and consist of a $25 million operating facility and a $95 million syndicated facility. The Credit Facilities have an initial term of one year and are extendible annually at the option of the Company, subject to lender approval, with a one year term-out period if not renewed. Availability under the Credit Facilities is subject to a borrowing base test, which is subject to redetermination in May and November of each year. The Credit Facilities mature on May 31, 2019, if not renewed. The Company completed its most recent semi-annual borrowing base redetermination in November 2017.

For the year ended December 31, 2017, the 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 1.00% to 3.50%, depending on the type of borrowing and the Company’s Senior Debt to Bank EBITDA ratio (defined below). A standby fee is charged between 0.50% and 0.875% on the undrawn portion of the Credit Facilities, depending on the Company’s Senior Debt to Bank EBITDA ratio (defined below). The Credit Facilities are secured by a $1.0 billion debenture containing a first ranking charge and security interest. The Company has provided a negative pledge and undertaking to provide fixed charges over its properties in certain circumstances.

Convertible Debentures

At December 31, 2017 Bellatrix had outstanding $50 million of 6.75% convertible unsecured subordinated debentures (the “Convertible Debentures”). The Convertible Debentures are governed by the terms of an indenture dated August 9, 2016 between the Company and Computershare Trust Company of Canada (the “Debenture Indenture”). The Convertible Debentures bear interest at a rate of 6.75% per annum, payable semiannually in arrears on September 30 and March 31 of each year. The maturity date of the Convertible Debentures is September 30, 2021 (the “Debenture Maturity Date”). Each $1,000 principal amount of Convertible Debenture is convertible at the option of the holder into approximately 123.4568 common shares of Bellatrix (representing a conversion price of $8.10) on the earlier of: (i) the last business day prior to the Debenture Maturity Date, (ii) the last business day immediately preceding any Redemption Date (as defined in the Debenture Indenture), and (iii) if called for repurchase pursuant to a mandatory repurchase as a result of a Change of Control (as defined in the Debenture Indenture) on the last business day preceding the date of payment. The Convertible Debentures are not redeemable prior to September 30, 2019, except in limited circumstances following a Change of Control. On and after September 30, 2019 and up to and including September 30, 2020, the Convertible Debentures may be redeemed in whole or in part from time to time at the Company’s option, on not more than 60 days and not less than 30 days prior written notice, at a price equal to their principal amount plus accrued and unpaid interest, provided that the volume weighted average trading price of the common shares on the TSX for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the conversion price. On or after September 30, 2020 and prior to the Debenture Maturity Date, the Convertible Debentures may be redeemed in whole or in part from time to time at the Company’s option, on not more than 60 days prior to the date fixed for redemption, at a price equal to their principal amount plus accrued and unpaid interest. The Convertible Debentures are direct, subordinated unsecured obligations of the Company, subordinated to the Credit Facilities, the Senior Notes and any other senior indebtedness.

On a redemption date or on the Debenture Maturity Date, as applicable, subject to required regulatory approvals and provided that no Event of Default (as defined in the Debenture Indenture) has occurred and is continuing, Bellatrix may, at its option, on not more than 60 days and not less than 40 days prior notice, elect to satisfy its obligation to repay, in whole or in part, the principal amount of the Convertible Debentures which are to be redeemed, or which will mature, by issuing and delivering freely tradable common shares of the Company to the holders of the Convertible Debentures. Payment for such Convertible Debentures, subject to the election, would be satisfied by delivering that number of common shares obtained by dividing the principal amount of the Convertible Debentures subject to the election which are to be redeemed, or which will mature, by 95% of the current market price of the common shares on such redemption date or Debenture Maturity Date, as applicable. Any accrued and unpaid interest will be paid in cash.

($000s)	Liability Component			Equity Component
Balance, December 31, 2015	$	—		$	—
Issuance of Convertible Debentures	$	38,540		$	11,460
Issue costs	$	(1,842	)	$	(548	)
Deferred income tax liability	$	—		$	(3,094	)
Effective interest on Convertible Debentures	$	722		$	—
Balance, December 31, 2016	$	37,420		$	7,818
Effective interest on Convertible Debentures	2,006			—
Balance, December 31, 2017	$	39,426		$	7,818

Senior Notes

At December 31, 2017, the Company had outstanding US$250 million of 8.50% senior unsecured notes due May 15, 2020 (the “Senior Notes”). The Senior Notes are governed by the terms of an indenture dated May 21, 2015 between the Company and U.S. National Bank Association (the "Note Indenture"). Interest is payable on the Senior Notes semi-annually and the Senior Notes are redeemable at the Company's option, in whole or in part at specified redemption prices. The Senior Notes are redeemable at the following redemption prices (expressed as a percentage of the principal amount of the Senior Notes): May 15, 2017 to May 14, 2018 at 104.250%, May 15, 2018 to May 14, 2019 at 102.125%, May 15, 2019 and thereafter at 100.000%. The Senior Notes are carried at amortized cost, net of debt issuance costs of $7.7 million, which accrete up to the principal balance at maturity using the effective interest rate of 9.6%. The Senior Notes were initially recognized at fair value, net of debt issue costs, and have subsequently been carried at amortized cost.

($000s)	Amount
Balance, December 31, 2015	$	332,024
Unrealized foreign exchange gain(1) (2)	(9,879		)
Amortization of discount and debt issue costs	2,601
	324,746
Debt issue costs	(55		)
Balance, December 31, 2016	$	324,691
Unrealized foreign exchange gain (3) (4)	(22,079		)
Amortization of discount and debt issue costs	2,797
Balance, December 31, 2017	$	305,409

(1) Exchange rate (CDN$/US$1.00) at December 31, 2016 was 1.3427.

(2) Amount does not include unrealized loss on foreign exchange contracts of $2.0 million.

(3) Exchange rate (CDN$/US$1.00) at December 31, 2017 was 1.2518.

(4) Amount does not include unrealized loss on foreign exchange contracts of $3.9 million.

Covenants

At December 31, 2017, the Credit Facilities contain a single financial covenant, which requires that the Company will not permit its ratio of outstanding Senior Debt to earnings before interest, taxes, depletion, depreciation and amortization (“Bank EBITDA”), as defined by the terms of the agreement governing the Credit Facilities (“Credit Agreement”) and adjusted for non-cash charges, for a trailing twelve month period to exceed a specified amount (the “Senior Debt Covenant”). Specifically, the Senior Debt Covenant requires that the Company maintain a Senior Debt to Bank EBITDA ratio of not more than 3.0 times (prior to the second quarter of 2017, the maximum Senior Debt to Bank EBITDA ratio was 3.5 times). The Company is in compliance with the covenant at December 31, 2017 as shown below.

	Covenant as at		Position at
	December 31, 2017		December 31, 2017
Credit Facilities – Senior Debt Covenant	Maximum Ratio
Senior Debt (1) to Bank EBITDA (2) for the last four fiscal quarters	3.00	x	1.22	x

(1)“Senior Debt” is defined as Consolidated Total Debt, including outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred financing obligations, deferred capital obligations and net working capital deficiency. Excluded from the calculation is any unsecured or subordinated debt (Senior Notes and Convertible Debentures (liability component)), decommissioning liabilities, deferred gain and deferred tax liability. “Consolidated Total Debt” is defined as determined on a consolidated basis in accordance with GAAP and without duplication, all Debt of the Borrower. The Company’s calculation of Consolidated Total Debt excludes decommissioning liabilities and deferred tax liability. The calculation includes outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred capital obligations, deferred financing obligations and net working capital deficiency (excess), calculated as working capital deficiency excluding current risk management contract assets and liabilities and current portion of decommissioning liability. Senior Debt at December 31, 2017 was $104.0 million.

(2)“Bank EBITDA” refers to earnings before interest, taxes, depletion, depreciation, amortization and other non-cash charges. Bank EBITDA is calculated based on terms and definitions set out in the agreement governing the credit facilities which adjusts net income for financing costs, certain specific unrealized and non-cash transactions, and acquisition and disposition activity and is calculated based on a trailing twelve month basis. Bank EBITDA for the trailing twelve months ended December 31, 2017 was $85.1 million.

The Senior Notes do not contain any maintenance financial covenants, but do contain covenants limiting the Company’s ability to incur additional indebtedness, including borrowings under the Credit Facilities, unless one of two alternative tests are satisfied. The first test applies to all future indebtedness and requires that, after giving effect to the incurrence of additional indebtedness, the Company’s fixed charge coverage ratio (which is the ratio of cash flow to fixed charges (both as defined in the Note Indenture) over the trailing four fiscal quarters) will be at least 2.25 to 1.0.

The second test allows the Company to incur additional indebtedness, irrespective of the fixed charge coverage ratio test, as long as the additional indebtedness is incurred under bank facilities (as defined in the Note Indenture, and which includes the Credit Facilities) and generally, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $675 million, and (ii) 35% of adjusted consolidated net tangible assets, or ACNTA, plus $150 million. ACNTA is defined in the Note Indenture and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to the Company’s unevaluated properties. As a result, the Company can currently incur up to $675 million under bank facilities (which include the Credit Facilities) subject to the maximum borrowing base of the Credit Facilities, without reference to limitations that would otherwise apply due to the fixed charge coverage ratio test.

	Covenant as at		Position at
	December 31, 2017		December 31, 2017
Senior Notes – Incurrence Test	Minimum Ratio
Fixed charge coverage (1)	2.25	x	2.12	x

(1)Fixed charge coverage is computed as the ratio of fixed charges (as defined in the Note Indenture, fixed charges generally includes interest expense plus paid or accrued dividends, if any) to trailing twelve month cash flow (as defined in the Note Indenture, cash flow includes the net profit (loss) and adds back provision for taxes, fixed charges, depletion, and various other non-recurring expenses and charges). For the trailing twelve months ended December 31, 2017, fixed charges were $36.6 million and cash flow was $77.8 million.

As at December 31, 2017, the Company has the ability to offer to sell up to an additional $470.8 million in securities under its $500 million Shelf Prospectus, which expires on June 30, 2018.

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DECOMMISSIONING LIABILITIES

12 Months Ended

Dec. 31, 2017

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

DECOMMISSIONING LIABILITIES

DECOMMISSIONING LIABILITIES

The Company’s decommissioning liabilities result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. At December 31, 2017, the Company estimated the total undiscounted amount of cash flows required to settle its decommissioning liabilities to be approximately $94.6 million (2016: $97.9 million) which will be incurred between 2018 and 2066. A risk-free rate between 1.66% and 2.20% (2016: 0.83% and 2.34%) and an inflation rate of 2.0% (2016: 2.0%) were used to calculate the fair value of the decommissioning liabilities as at December 31, 2017.

($000s)	2017			2016
Balance, beginning of year	$	62,844		$	96,423
Incurred on development activities	1,501			911
Acquired through business combinations	—			552
Revisions on estimates	3,210			(2,292		)
Decommissioning costs incurred	(2,758		)	(2,927		)
Reversed on dispositions	(5,473		)	(31,536		)
Accretion expense	1,287			1,713
Balance, end of year	$	60,611		$	62,844

The $3.2 million increase in decommissioning liabilities between December 31, 2017 and December 31, 2016 resulting from revisions on estimates were primarily due to decreased market interest rates which decreases the discount rates applied to the valuation of the liabilities. In addition, changes to estimates also resulted from the revisions to timing and amounts of future decommissioning cash flows for certain wells and facilities made to better reflect anticipated abandonment timelines and future cash outlays.

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OTHER DEFERRED LIABILITIES

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

OTHER DEFERRED LIABILITIES

OTHER DEFERRED LIABILITIES

($000s)	Finance lease obligation			Deferred lease inducements			Deferred financing obligations(1)			Deferred gain(1)		Deferred Capital Obligation(1)			Total
Balance, December 31, 2016	$	8,429		$	2,387		$	7,525		$	10,706	$	21,890		$	50,937
Deferred lease inducements	—			(366		)	—			—		—			(366		)
Payments on finance lease	(1,538		)	—			—			—		—			(1,538		)
Drawdown deferred financing obligations	—			—			(6,020		)	—		—			(6,020		)
Drawdown deferred capital obligations	—			—			—			—		(14,693		)	(14,693		)
Change in estimate	$	—		$	—		$	—		$	2,314	$	(2,442	)	$	(128	)
Balance, December 31, 2017	$	6,891		$	2,021		$	1,505		$	13,020	$	4,755		$	28,192
Current portion of other deferred liabilities	$	1,170		$	340		$	1,505		$	13,020	$	4,755		$	20,790
Long term portion of other deferred liabilities	$	5,721		$	1,681		$	—		$	—	$	—		$	7,402

(1) Pursuant to the Alder Flats Plant Sale Bellatrix recognized a deferred capital obligation, deferred gain and a deferred financing obligation as part of the disposition (refer to note 7).

Finance Lease Obligations

Finance leases are for the use of certain constructed facilities. The agreements expire in years 2030 to 2032, or earlier if certain circumstances are met. At the end of the term of each agreement, the ownership of the facilities is transferred to the Company. Assets under these finance leases at December 31, 2017 totaled $15.3 million (2016: $15.3 million) with accumulated depreciation of $4.4 million (2016: $3.7 million).

The following is a schedule of future minimum lease payments under the finance lease obligations:

Year ending December 31,	($000s)
2018	$	2,138
2019	1,317
2020	1,240
2021	1,164
2022	1,088
Thereafter	6,525
Total lease payments	13,472
Amount representing implicit interest at 15.28%	(6,581		)
Total lease obligation at December 31, 2017	$	6,891

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SHAREHOLDERS' CAPITAL

12 Months Ended

Dec. 31, 2017

Disclosure of share capital, reserves and other equity interest [Abstract]

SHAREHOLDERS' CAPITAL

SHAREHOLDERS’ CAPITAL

Effective July 1, 2017, the Company consolidated its common shares on the basis of 1 new common share for every 5 old common shares outstanding. All figures in the financial statements have been adjusted to reflect the 5:1 consolidation. The number of outstanding share options, Deferred Share Units, Restricted Awards and Performance Awards have also been adjusted proportionately. The corresponding exercise prices have increased by the same ratio. The conversion price and ratio on the Convertible Debentures have also been adjusted proportionately.

Bellatrix is authorized to issue an unlimited number of common shares and 95,978,621 preferred shares. At December 31, 2017, no preferred shares have been issued. All shares issued are fully paid and have no par value. The common shareholders are entitled to dividends as may be declared by the Board of Directors from time to time; no dividends were declared by the Board of Directors during the years ended December 31, 2017 or 2016.

	2017			2016
	Number	Amount ($000s)		Number	Amount ($000s)
Common shares, opening balance	49,317,166	$	1,068,084	38,392,782	$	1,000,100
Shares issued on settlement of share-based compensation	60,860	289		55,953	285
Share issue costs on property acquisition, net of tax effect	—	—		—	(98		)
Issued for cash on equity issue (1)	—	—		6,758,916	40,400
Share issue costs on equity issue, net of tax effect	—	4		—	(1,781		)
Shares issued for property acquisition	—	—		4,109,515	29,178
Balance, end of year	49,378,026	$	1,068,377	49,317,166	$	1,068,084

(1)In August 2016, Bellatrix issued 5,000,000 subscription receipts at a price of $6.00 per subscription receipt for total gross proceeds of $30 million. Proceeds were used to reduce indebtedness under the Company’s credit facilities. Additionally, in October 2016, Bellatrix issued 1,694,915 common shares on a “flow-through” basis in respect of Canadian Development Expenses (“CDE”) at a price of $5.90 per share resulting in gross proceeds of $10 million.

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SHARE-BASED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2017

Share-Based Payment Arrangements [Abstract]

SHARE-BASED COMPENSATION PLANS

SHARE-BASED COMPENSATION PLANS

The following tables provide a summary of the Company’s share-based compensation expense (recovery) for the years ended December 31, 2017 and December 31, 2016:

($000s)	2017			2016
Share options expense	$	1,074		$	2,565
Deferred share units expense (recovery)	(583		)	834
Restricted awards expense (recovery)	178			241
Performance awards expense (recovery)	(137		)	144
Share-based compensation expense included in general and administrative expense	$	532		$	3,784
Share-based compensation expense included in operating expense	$	167		$	152
Total share-based compensation expense	$	699		$	3,936

The following tables provide a summary of the Company’s share options expense for the years ended December 31, 2017 and December 31, 2016:

($000s)	2017		2016
Share options expense	$	1,074	$	2,565
Share options expense capitalized	600		1,147
Gross share option expense	$	1,674	$	3,712

The following table provides a summary of the Company’s share-based compensation liability balances within accounts payable and accrued liabilities:

($000s)	Deferred Share Units		Restricted Awards		Performance Awards		Total
Liability balance, December 31, 2017	$	1,212	$	754	$	457	$	2,423
Liability balance, December 31, 2016	$	2,360	$	1,038	$	751	$	4,149

a. Share Option Plan

Bellatrix has a share option plan whereby the Company may grant share options to its officers, employees, consultants, and other service providers. Under this plan, the exercise price of each share option is not less than the volume weighted average trading price of the Company’s share price for the five trading days immediately preceding the date of grant. The maximum term of an option grant is five years. Option grants are non-transferable or assignable except in accordance with the share option plan and the holding of share options shall not entitle a holder to any rights as a shareholder of Bellatrix. Share options, entitling the holder to purchase common shares of the Company, have been granted to officers, employees, consultants, and other service providers of Bellatrix. One third of the initial grant of share options normally vests on each of the first, second, and third anniversary from the date of grant.

The fair values of all share options granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of share options granted during the years ended December 31, 2017 and 2016, and the weighted average assumptions used in their determination are as noted below:

	2017		2016
Inputs:
Share price	$	4.27	$	5.10
Exercise price	$	4.55	$	5.10
Risk free interest rate (%)	0.9		0.6
Option life (years)	2.8		2.8
Option volatility (%)	71		73
Results:
Weighted average fair value of each share option granted	$	1.87	$	2.35

Bellatrix calculates volatility based on historical share price. Bellatrix incorporates an estimated forfeiture rate between 3% and 10% (2016: 3% to 10%) for stock options that will not vest, and adjusts for actual forfeitures as they occur.

The following tables summarize information regarding Bellatrix’s Share Option Plan:

Share Options Continuity
	Weighted Average Exercise Price		Number
Balance, December 31, 2015	$	28.45	2,569,273
Granted	$	5.10	581,820
Forfeited	$	30.43	(287,735	)
Expired	$	26.03	(290,334	)
Balance, December 31, 2016	$	23.22	2,573,024
Granted	$	4.55	185,000
Forfeited	$	35.10	(877,956	)
Expired	$	17.12	(257,936	)
Balance, December 31, 2017	$	15.62	1,622,132

As of December 31, 2017, a total of 4,937,803 common shares were reserved for issuance on exercise of share options, leaving an additional 3,315,671 available for future share option grants.

Share Options Outstanding, December 31, 2017

				Outstanding				Exercisable
Exercise Price				At December 31, 2017	Weighted  Average Exercise Price		Weighted Average Remaining Contractual Life	At December 31, 2017	Weighted Average Exercise Price
	$3.85	-	$4.47	125,000		$3.85	4.5	—	—
	$4.48	-	$5.55	494,832		$5.10	3.6	234,944		$5.10
	$5.56	-	$18.70	76,400		$7.78	3.9	10,928		$14.30
	$18.71	-	$19.52	624,000		$18.75	2.4	469,327		$18.75
	$19.53	-	$27.48	118,600		$20.30	1.9	118,600		$20.30
	$27.49	-	$37.95	67,800		$36.66	0.9	67,800		$36.66
	$37.96	-	$45.78	26,700		$39.01	1.0	26,700		$39.01
	$45.79	-	$50.20	88,800		$46.28	1.5	88,800		$46.28
	$3.85	-	$50.20	1,622,132		$15.62	2.8	1,017,099		$19.86

b. Deferred Share Unit Plan

Under Bellatrix’s Deferred Share Unit Plan, the Company may grant to non-employee directors, deferred share units (“DSUs”). Each DSU is a right to receive, on a deferred payment basis, a cash payment equivalent to the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the redemption date of such DSU. Participants of the DSU Plan may also elect to receive their annual remuneration in the form of DSUs. Subject to TSX and shareholder approval, Bellatrix may elect to deliver common shares from treasury in satisfaction, in whole or in part, of any payment to be made upon the redemption of the DSUs. The DSUs vest immediately and must be redeemed by December 1st of the calendar year immediately following the year in which the participant ceases to hold all positions with Bellatrix or earlier if the participant elects to have the DSUs redeemed at an earlier date (provided that the DSUs may not be redeemed prior to the date that the participant ceases to hold all positions with Bellatrix).

DSU Continuity
	Number
Balance, December 31, 2015	202,927
Granted	184,823
Exercised	(10,083	)
Balance, December 31, 2016	377,667
Granted	260,381
Exercised	(120,150	)
Balance, December 31, 2017	517,898

c. Award Plan

Bellatrix has an Award Incentive Plan (“Award Plan”) where the Company may grant Restricted Awards (“RAs”) and Performance Awards (“PAs”) to officers, employees, and other service providers. During 2016, the shareholders and the TSX approved the issuance of common shares on settlement of RAs and PAs under the Award Plan. As a result, awards under the Award Plan may be settled in cash, in common shares of the Company, or a combination thereof. In the case of PAs, settlement is subject to a “payout multiplier” (the payout multiplier shall be based on such corporate performance measures as determined by the Board of Directors (or the Compensation Committee) of the Company) and may range between zero and two times.

RAs granted to employees vest in equal annual amounts over the course of three years. Each RA entitles its holder to receive a cash payment equal to the weighted average trading price of the Company’s shares trading on the TSX for the five trading days preceding its vesting date. Unvested RAs are forfeited at the time the holder’s employment with the Company ends, except on death in which case they vest immediately. Bellatrix incorporates an estimated forfeiture rate between 3% and 10% for RAs that will not vest, and adjusts for actual forfeitures as they occur. Outstanding RAs are revalued at each financial reporting date to their fair market value at that time, determined by the weighted average trading price of the Company’s shares on the TSX for the five trading days preceding period end.

RA Continuity
	Number of RAs
Balance, December 31, 2015	318,762
Granted	284,771
Exercised	(113,457	)
Forfeited	(63,681	)
Balance, December 31, 2016	426,395
Granted	652,740
Exercised	(175,833	)
Forfeited	(79,815	)
Balance, December 31, 2017	823,487

PAs vest on the third anniversary date of their issuance. Each PA entitles its holder to receive a cash payment equal to the weighted average trading price of the Company’s shares trading on the TSX for the five trading days preceding its vesting date, multiplied by a payout multiplier determined by the Company’s Board of Directors based on determined corporate performance measures. Unvested PAs are forfeited at the time the holder’s employment with the Company ends. Bellatrix incorporates an estimated forfeiture rate of 5% for PAs that will not vest, and adjusts for actual forfeitures as they occur. Outstanding PAs are revalued at each financial reporting date to their fair market value at that time, determined by the weighted average trading price of the Company’s shares on the TSX for the 5 trading days preceding period end.

PA Continuity
	Number of PAs
Balance, December 31, 2015	249,240
Granted	145,085
Exercised	(70,430	)
Forfeited	(20,560	)
Balance, December 31, 2016	303,335
Granted	370,000
Exercised	(61,920	)
Forfeited	(38,360	)
Balance, December 31, 2017	573,055

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INCOME TAXES

12 Months Ended

Dec. 31, 2017

Income Taxes [Abstract]

INCOME TAXES

INCOME TAXES

Bellatrix is a corporation as defined under the Income Tax Act (Canada) and is subject to Canadian federal and provincial taxes. Bellatrix is subject to provincial taxes in Alberta, British Columbia, and Saskatchewan as the Company operates in those jurisdictions.

Deferred taxes reflect the tax effects of differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts reported for tax purposes. As at December 31, 2017, Bellatrix had approximately $1.35 billion in tax pools available for deduction against future income. Included in this tax basis are estimated non-capital loss carry forwards of approximately $144.1 million that expire in years through 2033.

The provision for income taxes differs from the expected amount calculated by applying the combined 2017 federal and provincial corporate income tax rate of 27.0% (2016: 27.0%) to net profit (loss) before taxes. This difference results from the following items:

($000s)	2017			2016
Expected income tax expense (recovery)	$	(20,506	)	$	(9,052	)
Change in unrecognized deferred tax asset	44,114			—
Unrealized foreign exchange (gain) loss	(4,947		)	(1,938		)
Share based compensation expense	610			856
Flow through share issuance	108			2,700
Other	(3,964		)	576
Deferred tax expense (recovery)	$	15,415		$	(6,858	)

The components of the net deferred tax asset at December 31, 2017 are as follows:

($000s)	2017			2016
Deferred tax liabilities:
Property, plant and equipment and exploration and evaluation assets	$	(6,845	)	$	(12,555	)
Risk management contract asset	(8,943		)	—
Convertible Debentures	(2,616		)	(3,028		)
Deferred tax assets:
Senior Notes	756			418
Finance lease obligation	1,860			2,276
Deferred capital obligation	—			5,910
Deferred financing obligation	406			2,032
Deferred gain on sale	3,515			2,890
Risk management contract liability	1,206			4,477
Decommissioning liabilities	16,365			16,967
Share issue costs	840			1,950
Non-capital losses	40,850			40,830
Other	904			1,546
Deferred tax asset (liability)	$	48,298		$	63,713

The Company recognized a net deferred tax asset based on the independently evaluated reserve report as cash flows are expected to be sufficient to realize the deferred tax asset. The Company has not recognized a deferred tax asset for the deductible temporary difference associated with $163.4 million (2016: nil) of Canadian resource pools that are restricted through successor rules and $5.2 million (2016: $14.6 million) of unrealized allowable capital losses on marketable securities and USD denominated Senior Notes.A continuity of the net deferred income tax asset (liability) for 2017 and 2016 is provided below:

($000s)	Balance, January 1, 2017			Recognized in profit (loss)			Recognized in equity		Balance, December 31, 2017
Property, plant and equipment and exploration and evaluation assets	$	(12,555	)	$	5,710		$	—	$	(6,845	)
Decommissioning liabilities	16,967			(602		)	—		16,365
Risk management contract asset	—			(8,943		)	—		(8,943		)
Risk management contract liability	4,477			(3,271		)	—		1,206
Share issue costs	1,950			(1,110		)	—		840
Non-capital losses	38,895			20			—		38,915
Finance lease obligation	2,276			(416		)	—		1,860
Deferred capital obligation	5,910			(5,910		)	—		—
Deferred financing obligation	2,032			(1,626		)	—		406
Deferred gain on sale	2,890			625			—		3,515
Alberta non-capital losses greater than Federal non-capital losses	1,935			—			—		1,935
Senior Notes	418			338			—		756
Convertible Debentures	(3,028		)	412			—		(2,616		)
Other	1,546			(642		)	—		904
Total	$	63,713		$	(15,415	)	$	—	$	48,298

($000s)	Balance, January 1, 2016			Recognized in profit (loss)			Recognized in equity			Balance, December 31, 2016
Property, plant and equipment and exploration and evaluation assets	$	(12,142	)	$	(413	)	$	—		$	(12,555	)
Decommissioning liabilities	26,034			(9,067		)	—			16,967
Risk management contract asset	(3,600		)	3,600			—			—
Risk management contract liability	105			4,372			—			4,477
Share issue costs	2,520			(1,264		)	694			1,950
Non-capital losses	40,766			(1,871		)	—			38,895
Finance lease obligation	2,717			(441		)	—			2,276
Deferred capital obligation	—			5,910			—			5,910
Deferred financing obligation	—			2,032			—			2,032
Deferred gain on sale	—			2,890			—			2,890
Alberta non-capital losses greater than Federal non-capital losses	1,935			—			—			1,935
Senior Notes	(65		)	483			—			418
Convertible Debentures	—			66			(3,094		)	(3,028		)
Other	985			561			—			1,546
Total	$	59,255		$	6,858		$	(2,400	)	$	63,713

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FINANCE INCOME AND EXPENSES

12 Months Ended

Dec. 31, 2017

Borrowing costs [abstract]

FINANCE INCOME AND EXPENSES

FINANCE INCOME AND EXPENSES

($000s)	2017		2016
Interest on Credit Facilities (1)	$	2,194	$	13,516
Interest on Convertible Debentures (2)	5,381		2,063
Interest on Senior Notes (2)	30,378		30,771
Accretion on decommissioning liabilities (non-cash)	1,287		1,713
Finance expense	$	39,240	$	48,063

(1) Includes interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 1.00% to 3.50%, depending on the type of borrowing and the Company’s Senior Debt to EBITDA ratio. A standby fee is charged between 0.500% and 0.875% on the undrawn portion of the Credit Facilities, depending on the Company’s Senior Debt to EBITDA ratio.

(2) Includes amortized costs related to the issuance of the Senior Notes and Convertible Debentures (detailed in note 8).

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FOREIGN EXCHANGE

12 Months Ended

Dec. 31, 2017

Effect Of Changes In Foreign Exchange Rates [Abstract]

FOREIGN EXCHANGE

FOREIGN EXCHANGE

Bellatrix incurs gains and losses in relation to the foreign currency translation of its Senior Notes. The Senior Notes are translated from United States dollars to Canadian dollars using the closing foreign exchange rate for the period. An unrealized foreign exchange gain or loss is included in earnings in the period related to the translation of the outstanding balance of the Senior Notes at the end of the period. Realized and unrealized foreign exchange gains and losses are recognized as Senior Notes and other minor foreign currency based transactions are translated and settled during the period.

($000s)	2017			2016
Realized gain (loss) on foreign exchange	$	(797	)	$	277
Unrealized gain (loss) on foreign exchange	22,165			9,939
Unrealized gain (loss) on foreign exchange contracts	(3,867		)	(2,021		)
Gain (loss) on foreign exchange	$	17,501		$	8,195

Bellatrix had the following United States dollar foreign exchange forward purchase contracts outstanding at December 31, 2017:

Type	Value Date	Notional Amount ($000s USD)		Foreign Exchange Rate		Settlement ($000s CDN)
Fixed	May 14, 2020	$	32,500	$	1.3076	$	42,497
Fixed	May 14, 2020	$	30,000	$	1.3080	$	39,240

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PER SHARE AMOUNTS

12 Months Ended

Dec. 31, 2017

Earnings per share [abstract]

PER SHARE AMOUNTS

PER SHARE AMOUNTS

The calculation of basic earnings per share for the year ended December 31, 2017 was based on a net loss of $91.4 million (2016: net loss of $26.7 million). 

	2017	2016
Basic common shares outstanding	49,378,026	49,317,165
Fully dilutive effect of:
Share options outstanding	1,622,132	2,573,024
Shares issuable on conversion of Convertible Debentures	6,172,840	6,172,840
Fully diluted common shares outstanding	57,172,998	58,063,029
Weighted average shares outstanding	49,351,848	42,821,013
Dilutive effect of share options (1)	—	—
Diluted weighted average shares outstanding	49,351,848	42,821,013

(1) For the year ended December 31, 2017, a total of 1,622,132 (2016: 2,573,024) share options and 6,172,840 (2016: 6,172,840) shares issuable on conversion of Convertible Debentures were excluded from the calculation as they were anti-dilutive.

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FINANCIAL RISK MANAGEMENT

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

FINANCIAL RISK MANAGEMENT

FINANCIAL RISK MANAGEMENT

a. Overview

The Company has exposure to the following risks from its use of financial instruments:

•Credit risk

•Liquidity risk

•Market risk

▪Foreign exchange risk

▪Commodity price risk

▪Interest rate risk

This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these financial statements.

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies.

The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

b. Capital Management

The Company's policy is to maintain a strong capital base so as to maintain investor, creditor and market confidence and to sustain the future development of the business. The Company manages its capital structure and makes adjustments to it based on changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company considers its capital structure to include shareholders’ equity, Senior Notes, Credit Facilities, Convertible Debentures, and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue common shares, senior notes, convertible debentures or other debt instruments, adjust its capital spending, and/or dispose of certain assets to manage current and forecasted debt levels. Bellatrix does not pay dividends. 

Bellatrix remains highly focused on key business objectives of maintaining financial strength and liquidity, and optimizing capital investments in the current commodity price environment. In order to preserve liquidity and capital resources, in December 2017, Bellatrix’s Board of Directors approved a 2018 net capital budget of between $65 million and $80 million. Bellatrix expects to be able to fund its 2018 capital program by reinvesting cash flow, supplemented by borrowing under its Credit Facilities. Bellatrix continually monitors its capital spending program in light of prevailing commodity prices and the United States/Canadian dollar exchange rate with the aim of ensuring the Company will be able to meet future anticipated obligations incurred from normal ongoing operations with adjusted funds flow and borrowings under its Credit Facilities, as necessary. Please refer to note 8 and ‘Liquidity Risk’ below for further discussion.

The Company monitors its capital structure based on the ratio of total net debt to annualized adjusted funds flow (defined below). This ratio is calculated as total net debt, defined as outstanding Credit Facilities, Convertible Debentures (liability component), and Senior Notes, long term loan receivable and plus or minus adjusted working capital (defined below), divided by adjusted funds flow (defined below) for the most recent calendar quarter, annualized (multiplied by four). The total net debt to annualized adjusted funds flow ratio may increase at certain times as a result of acquisitions, fluctuations in commodity prices, timing of capital expenditures and other factors. In order to facilitate the management of this ratio, the Company prepares capital expenditure budgets which are reviewed and updated as necessary depending on varying factors including current and forecast prices, successful capital deployment and general industry conditions. The budgets are approved by the Board of Directors.

The Company’s capital structure and its calculation of total net debt and the total net debt to adjusted funds flow ratio as defined by the Company is as follows:

Debt to Adjusted Funds Flow Ratio
	Year ended December 31,
($000s, except where noted)	2017		2016
Shareholders’ equity	774,022		863,418
Credit Facilities	52,066		19,143
Loans receivable (long term)	—		(8,775	)
Adjusted working capital deficiency (1)	23,926		23,716
Subtotal	75,992		34,084
Senior Notes (mature May 15, 2020) (2)	305,409		324,691
Net debt (1)	381,401		358,775
Convertible Debentures (liability component)	39,426		37,420
Total net debt (1) at year end	420,827		396,195
Debt to adjusted funds flow ratio (annualized)(3) (4)
Adjusted funds flow (4) (annualized)	62,800		33,748
Net debt (1) to periods adjusted funds flow ratio (annualized) (3)	6.1	x	10.6		x
Total net debt to periods adjusted funds flow ratio (annualized) (3)	6.7	x	11.7		x
Debt to adjusted funds flow ratio (4)
Adjusted funds flow for the year (4)	58,240		40,916
Net debt (1) to adjusted funds flow ratio (4) for the year	6.5	x	8.8		x
Total net debt (1) to adjusted funds flow ratio (4) for the year	7.2	x	9.7		x

(1)Net debt and total net debt as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, deferred capital obligation, long-term risk management contract liabilities, decommissioning liabilities, and the deferred tax liability. Total net debt includes the adjusted working capital deficiency, Convertible Debentures (liability component), current Credit Facilities, long term loan receivable and Senior Notes. The adjusted working capital deficiency as presented does not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company calculated adjusted working capital deficiency as net working capital deficiency excluding current risk management contract assets and liabilities, current portion of other deferred liabilities, current portion of deferred capital obligation, current portion of Credit Facilities and the current portion of decommissioning liability. Net debt excludes the liability component of Convertible Debentures that is included in total net debt.

(2)For the year ended December 31, 2017, Senior Notes includes an unrealized foreign exchange gain of $22.2 million (2016: $9.9 million gain) and does not include an unrealized loss of $3.9 million (2016: $2.0 millionloss) on foreign exchange contracts.

(3)For the years ended December 31, 2017 and 2016, net debt and total net debt to period’s adjusted funds flow ratio (annualized) is calculated based upon fourth quarter adjusted funds flow annualized.

(4)Adjusted funds flow as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Adjusted funds flow is calculated as cash flow from operating activities, excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.

c. Credit Risk

Credit risk is the risk of financial loss to Bellatrix if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from Bellatrix’s trade receivables from joint venture partners, petroleum and natural gas marketers, and financial derivative counterparties.

A substantial portion of Bellatrix’s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. Bellatrix currently sells substantially all of its production to ten primary purchasers under standard industry sale and payment terms. The most significant 60 day exposure to a single counterparty is approximately $11.2 million. Purchasers of Bellatrix’s natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. Bellatrix has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in Bellatrix mitigating its exposures to certain counterparties by obtaining financial assurances or reducing credit where it is deemed warranted and permitted under contractual terms.

Bellatrix may be exposed to third party credit risk through its contractual arrangements with its current or future partners and joint venture partners, marketers of its petroleum and natural gas production, derivative counterparties and other parties.

As at December 31, 2017, accounts receivable was comprised of the following:

Aging ($000s)	Not past due (less than 90 days)		Past due (90 days or more)			Total
Joint venture and other trade accounts receivable	$	13,627	$	5,186		$	18,813
Revenue and other accruals	27,312		436			27,748
Less: Allowance for doubtful accounts	—		(889		)	(889		)
Total accounts receivable	$	40,939	$	4,733		$	45,672

In order to determine the allowance for doubtful accounts, the Company conducts a qualitative analysis of each account comprising the individual balances within its accounts receivable, including the counterparty’s identity, customary pay practices, and the terms of the contract under which the obligation arose. Based on the review of the individual balances within the accounts receivable balance at December 31, 2017 and specifically the balances greater than 90 days, a provision of $0.9 million was made.

The carrying amount of accounts receivable and derivative assets represent the maximum credit exposure.

Liquidity Risk

Liquidity risk is the risk that Bellatrix will not be able to meet its financial obligations as they become due. Bellatrix actively manages its liquidity through daily and longer-term cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through its Credit Facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic risk management opportunities, and maintaining sufficient cash flows for compliance with the Senior Debt Covenant described in note 8. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses.

The Company prepares annual capital expenditure budgets which are regularly monitored and updated as necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has revolving reserve based Credit Facilities, as outlined in note 8, which are reviewed semi-annually by the lenders thereunder. The borrowing base under the Company’s Credit Facilities is $120 million providing the Company with approximately $55 million of available liquidity, after deducting outstanding letters of credit as at December 31, 2017. The next scheduled review of the borrowing base is May 2018. The Credit Facilities outline limitations based on percentages of the prior quarter’s sale volumes, which may be hedged through financial commodity price risk management contracts. Bellatrix also has Senior Notes and Convertible Debentures outstanding with fixed interest rates, as outlined in note 8, which mature on May 15, 2020 and September 30, 2021, respectively.

Future liquidity depends primarily on cash flow generated from operations, availability under the Credit Facilities and the ability to access debt and equity markets. From time to time, the Company accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. As at December 31, 2017, the Company has the ability to offer to sell up to an additional $470.8 million in securities under its $500 million Shelf Prospectus, which expires on June 30, 2018.

There can be no assurance that future debt or equity financing, additional credit under the Credit Facilities, 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 Bellatrix.

The following are the contractual maturities of financial liabilities as at December 31, 2017:

Liabilities ($000s)	Total		< 1 Year		1-3 Years		3-5 Years		More than 5 years
Accounts payable and accrued liabilities	$	73,307	$	73,307	$	—	$	—	$	—
Risk management liability	7,890		4,468		3,422		—		—
Credit Facilities	52,066		—		52,066		—		—
Convertible Debentures (1)	50,000		—		—		50,000		—
Senior Notes (1)	312,950		—		312,950		—		—
Deferred capital obligation	4,755		4,755		—		—		—
Deferred financing obligation	1,505		1,505		—		—		—
Finance lease obligation	6,891		1,170		947		928		3,846
Total	$	509,364	$	85,205	$	369,385	$	50,928	$	3,846

(1) Principal amount of the instruments

e. Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net profit or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

f. Foreign Exchange Risk

Foreign exchange risk is the risk that fluctuations in the Canadian/United States dollar foreign exchange rate may impact the Company’s cash flows and net profit (loss). The Company’s realized commodity prices for crude oil and natural gas are based upon United States dollar denominated commodity prices. Fluctuations in the Canadian/United States dollar foreign exchange rate may thus impact commodity prices received by the Company. In addition, the Company has United States dollar denominated Senior Notes and related interest obligations of which future cash payments are directly impacted by the exchange rate in effect on the payment date.

The Company may utilize foreign exchange derivative contracts to manage foreign exchange risks in order to maintain cash flow stability. Foreign exchange derivative transactions are in accordance with the risk management policy that has been approved by the Board of Directors. The aggregate amount hedged under all foreign exchange derivative contracts is limited to the outstanding principal amount of the Senior Notes or 60% of the Company’s United States dollar revenues over the previous three months. Additionally, the term of foreign exchange contracts is limited to the remaining term of the related Senior Notes or three years. See note 15 for the foreign exchange risk management contacts that the Company has entered at December 31, 2017.

For the year ended December 31, 2017, a $0.01 increase or decrease in the CDN$/US$ foreign exchange rate, with all other variables held constant, would impact the profit (loss) before income taxes by approximately $0.8 million.

. Commodity Price Risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar, as outlined above, but also global economic events that dictate the levels of supply and demand.

The Company utilizes both financial derivatives and physical delivery sales contracts to manage commodity price risks. All such transactions are conducted in accordance with the commodity price risk management policy that has been approved by the Board of Directors.

The Company’s formal commodity price risk management policy permits management to use specified price risk management strategies including fixed price contracts, costless collars and the purchase of floor price options, other derivative financial instruments, and physical delivery sales contracts to reduce the impact of price volatility and ensure minimum prices for a maximum of thirty months beyond the current date. The program is designed to provide price protection on a portion of the Company’s future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Company seeks to provide a measure of stability to cash flows from operating activities, as well as, to ensure Bellatrix realizes positive economic returns from its capital developments and acquisition activities.

For the year ended December 31, 2017, if the prices for AECO natural gas had increased or decreased by $0.10/mcf, with all other variables held constant, net loss before tax would have be impacted by $6.0 million. For the year ended December 31, 2017, if prices for WTI crude oil had increased or decreased by $1.00/bbl, with all other variables held constant, net profit would be impacted by $3.7 million.

As at December 31, 2017, the Company has entered into commodity price risk management arrangements as follows:

Natural gas fixed price arrangements

Type		Period	Volume	Price	Index
Natural gas fixed	Financial	January 1, 2018 to December 31, 2018	75,000 GJ/d	2.69	AECO

Natural gas basis differential arrangements

Type		Period	Volume	Price			Index
Natural gas	FInancial	April 1, 2018 to October 31, 2018	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX
Natural gas	Financial	April 1, 2019 to October 31, 2020	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX

Natural gas liquids fixed differential arrangements

Type		Period	Volume	Fixed Differential	Index
Propane	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	47% of NYMEX WTI	OPIS Conway Propane

Crude oil fixed price arrangements

Type		Period	Volume	Price			Index
Oil	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	$	70.14	CDN	WTI - NYMEX

h. Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Company is exposed to interest rate fluctuations on its Credit Facilities which bears a floating rate of interest. As at December 31, 2017, if interest rates had been 1% lower with all other variables held constant, net loss before income tax for the three months ended December 31, 2017 would have been approximately $0.5 million lower, due to lower interest expense. An equal and opposite impact would have occurred to net earnings had interest rates been 1% higher.

i. Fair Value

The Company’s financial instruments as at December 31, 2017 include accounts receivable, deposits, marketable securities, risk management assets and liabilities, accounts payable and accrued liabilities, finance lease obligations, deferred capital obligation, deferred financing obligation, Credit Facilities, Convertible Debentures and Senior Notes. The fair value of accounts receivable, deposits, accounts payable, accrued liabilities, deferred financing obligation and deferred capital obligation approximate their carrying amounts due to their short-terms to maturity.

The loan receivable was determined to bear interest at a market rate and accordingly the fair market value approximated the carrying value. Marketable securities were carried at fair value based on the market price at each reporting date, with changes in fair value recognized in profit or loss. The marketable securities are classified as level 1 within the fair value hierarchy.

The Company enters into risk management contracts under master netting arrangements. Under these arrangements, the amounts owed by each counterparty for commodity or foreign exchange contracts outstanding in the same currency or commodity are aggregated into a single net amount receivable or payable. If a default occurs, the net amount subject to a master netting arrangement is receivable or payable for settlement purposes. The carrying amounts of commodity and foreign exchange contracts held under master netting arrangements are recorded on a net basis. At December 31, 2017 and 2016, the impact of netting gross amounts is negligible.

The risk management assets and liabilities at December 31, 2017 include both commodity contracts and foreign exchange contracts. The fair value of commodity contracts is determined by discounting the difference between the contracted price and published forward price curves as at the balance sheet date, using the remaining contracted petroleum and natural gas volumes. The fair value of foreign exchange contracts is determined based on the difference between the contracted forward rate and current forward rates, using the remaining settlement amount. The risk management contracts are classified as level 2 within the fair value hierarchy.

Credit Facilities bears interest at a floating market rate and the credit and market premiums therein are indicative of current rates; accordingly the fair market value approximates the carrying value.

The fair value of financial assets and liabilities, excluding working capital and Credit Facilities, is attributable to the following fair value hierarchy levels at December 31, 2017 and December 31, 2016:

($000s)		Fair Value
2017	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	33,123	—	33,123	—
Financial liabilities
Risk management liability	7,890	—	7,890	—
Convertible Debentures (1)	39,426	—	46,000	—
Senior Notes (2)	305,409	—	299,258	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $92.00 per Debenture as at December 31, 2017, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $95.63 per Senior Note as at December 31, 2017.

($000s)		Fair Value
2016	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	445	—	445	—
Financial liabilities
Risk management liability	16,582	—	16,582	—
Convertible Debentures (1)	37,420	—	50,825	—
Senior Notes (2)	324,691	—	332,318	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $101.65per Debenture as at December 31, 2016, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $99.00 per Senior Note as at December 31, 2016.

The following is a summary of the net risk management asset (liability) as at December 31, 2016 and December 31, 2017:

($000s)	2017			2016
Current portion commodity contract asset	$	31,910		$	—
Commodity contract asset (long term)	1,213			—
Foreign exchange contract asset (long term)	—			445
Current portion commodity contract liability	(4,468		)	(13,936		)
Commodity contract liability (long term)	—			(2,646		)
Foreign exchange contract liability (long term)	(3,422		)	—
Net risk management asset (liability)	$	25,233		$	(16,137	)

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COMMITMENTS

12 Months Ended

Dec. 31, 2017

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

COMMITMENTS

COMMITMENTS

The following is a summary of Bellatrix’s commitments as at December 31, 2017:

($000s)	1 Year		2-3 Years		4-5 Years		More than 5 years		Total
Operating leases (1)	$	24,835	$	48,748	$	40,811	$	30,934	$	145,328
Transportation and processing agreements (2)	$	62,207	$	97,788	$	69,481	$	128,873	$	358,349

(1) Operating leases is comprised of the Company’s commitment for office space, net of recoveries and gross operating leases for field equipment. The Company is committed to payments under fixed term operating leases for office space which do not currently provide for early termination.

(2) Transportation agreements is comprised of commitments to third parties to transport natural gas. Processing agreements is comprised of commitments to process natural gas and natural gas liquids through processing facilities.

Bellatrix is involved in litigation and claims arising in the normal course of operations. Such claims are not expected to have a material impact on Bellatrix’s results of operations or cash flows.

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2017

Related Party [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

Key Management Compensation

Key management includes officers and directors (executive and non-executive) of the Company. The compensation paid or payable to key management for employee services is shown below:

($000s)	2017		2016
Short-term employee benefits (1)	$	4,901	$	3,933
Share-based compensation (2)	452		2,509
Total key management compensation	$	5,353	$	6,442

(1) Includes termination benefits for the year ended December 31, 2017 of $1.3 million (2016: nil)

(2) Share-based compensation includes share options, RAs, PAs, and DSUs.

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SUPPLEMENTAL DISCLOSURES

12 Months Ended

Dec. 31, 2017

Disclosure Of Supplemental Disclosures [Abstract]

SUPPLEMENTAL DISCLOSURES

SUPPLEMENTAL DISCLOSURES

Changes in Non-cash Working Capital

($000s)	2017			2016
Changes in non-cash working capital items:
Accounts receivable	$	(6,445	)	$	18,034
Loans receivable	15,000			—
Deposits and prepaid expenses	1,496			2,925
Accounts payable and accrued liabilities	(3,578		)	(32,127		)
	$	6,473		$	(11,168	)
Changes related to:
Operating activities	$	(272	)	$	(443	)
Financing activities	16,353			601
Investing activities	(9,608		)	(11,326		)
	$	6,473		$	(11,168	)

Statement of Profit (Loss) and Comprehensive Income (Loss) Presentation

A mixed presentation of nature and function was used for the Company’s presentation of operating expenses in the Statement of Profit (Loss) and Comprehensive Income (Loss) for the current and comparative years. General and administrative expenses are presented by their function. Other expenses, including production, transportation, depletion and gain (loss) on dispositions are presented by their nature. Such presentation is in accordance with industry practice.

Total employee compensation costs included in total production and general administrative expenses in the Statements of Profit (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2017 and 2016 are detailed in the following table:

($000s)	2017		2016
Production	$	7,860	$	8,360
General and administrative (1)	19,274		11,616
Employee compensation	$	27,134	$	19,976

(1) Amount shown is net of capitalization.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

Statement of compliance

a. Statement of compliance

These financial statements (“financial statements”) were authorized by the Board of Directors on March 13, 2018. The Company prepared these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”).

Basis of measurement

b. Basis of measurement

The financial statements are presented in Canadian dollars, the Company’s functional currency, and have been prepared on the historical cost basis except for derivative financial instruments, marketable securities and liabilities for cash-settled share-based payment arrangements measured at fair value. The financial statements have, in management’s opinion, been properly prepared using careful judgment and reasonable limits of materiality, and within the framework of the significant policies summarized in note 3. Significant estimates and judgments used in the preparation of the financial statements are detailed in note 4.

Revenue Recognition

Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title to the products transfers to the purchasers based on volumes delivered and contracted delivery points and prices. Revenue is measured at the fair value of the consideration received or receivable. Revenue from the sale of crude oil, natural gas, condensate and natural gas liquids (“NGLs”) (prior to deduction of transportation costs) is recognized when all of the following conditions have been satisfied:

• Bellatrix has transferred the significant risks and rewards of ownership of the goods to the purchaser;

• Bellatrix retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;

• the amount of revenue can be measured reliably;

• it is probable that the economic benefits associated with the transaction will flow to Bellatrix; and

• the costs incurred or to be incurred in respect of the transaction can be measured reliably.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements and is included with petroleum and natural gas sales.

Capital processing charges to other entities for use of facilities owned by the Company are recognized as revenue as they accrue in accordance with the terms of the service agreements and are presented as other income.

Transportation

Transportation

Costs paid by Bellatrix for the transportation of crude oil, natural gas, condensate and NGLs to the point of title transfer are recognized when the transportation is provided.

Joint Interests

Joint Interests

A portion of the Company’s exploration and development activities are conducted jointly with others. The joint interests are accounted for on a proportionate consolidation basis and as a result, the financial statements reflect only the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows from these activities.

Joint Arrangements

Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint control, the Company considers whether unanimous consent is required to direct the activities that significantly affect the returns of the arrangement, such as the capital and operating activities of the arrangement. Additionally, the Company assesses the rights and obligations arising from the arrangement by considering its governance structure, legal form, and terms agreed upon by the parties sharing control, including the contractual rights of each partner, dispute resolution procedures, termination provisions, and procedures for subsequent transactions in its determination of joint control.

Once joint control has been established, judgment is also required to classify the joint arrangement. The type of joint arrangement is determined through analysis of the rights and obligations arising from the arrangement by considering its legal structure, legal form and terms agreed upon by the parties sharing control. An arrangement that is not structured through a separate vehicle in which the controlling parties have rights to the assets, revenues and substantially all of the economic benefits generated through the arrangement, in addition to obligations for the liabilities and expenses, is classified as a joint operation. An arrangement in which these criteria are not met is classified as a joint venture.

Non-monetary Transactions

V. Non-monetary Transactions

Judgment is required to determine whether non-monetary transactions have commercial substance.

Property, Plant and Equipment and Exploration and Evaluation Assets

I. Pre-exploration expenditures

Expenditures made by the Company before acquiring the legal right to explore in a specific area do not meet the definition of an asset and therefore are expensed by the Company as incurred.

II. Exploration and evaluation expenditures

Once the legal right to explore has been acquired, costs incurred are capitalized as intangible exploration and evaluation assets (“E&E). These costs include, but are not limited to, exploration license expenditures, leasehold property acquisition costs, evaluation costs, including drilling costs directly attributable to an identifiable well and directly attributable general and administrative costs. These costs are accumulated in cost centres by property and are not subject to depletion, until technical feasibility and commercial viability have been determined. 

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, or if facts and circumstances suggest that the carrying amount is unlikely to be recovered.

III. Developing and production costs

Items of property, plant and equipment (“PP&E”), which include oil and gas development and production assets, are measured at cost less accumulated depletion, depreciation and accumulated impairment losses net of recoveries.

Gains and losses on disposal of an item of PP&E, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of PP&E, and are recognized within the Statements of Profit (Loss) and Comprehensive Income (Loss).

IV. Joint arrangements

The Company has entered into certain joint arrangements whereby the joint arrangement partner will earn a working interest on certain properties through the payment of a pre-determined portion of the costs of drilling, completing and equipping. A gain on disposition for each well is recognized to account for the disposal of the pre-payout working interest earned by the partner on the well, as described under "Dispositions" below. Bellatrix has property, plant and equipment assets that are subject to these arrangements.

Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a well, field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

VI. Depletion and depreciation

Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes in relation to total estimated proven and probable reserves as determined annually by independent engineers in accordance with National Instrument 51-101, Standards of Disclosure of Oil and Gas Activities. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Calculations for depletion are based on total capitalized costs plus estimated future development costs of proven and probable undeveloped reserves less the estimated net realizable value of production equipment and facilities after the proved and probable reserves are fully produced.

Depreciation is recognized on significant facilities to expense the cost of significant components of assets less their residual values over their useful lives. Phase 1 of the Alder Flats Plant and associated equipment are depreciated using the straight-line method over estimated useful lives as follows:

• General plant and processing equipment - 40 years

• Other properties and equipment - 10 years

• Turnarounds - 5 years

Costs of facilities under construction related to Phase II of the Alder Flats Plant as at December 31, 2017 were excluded from depreciation calculations.

Depreciation of office furniture and equipment is provided for on a 20% declining balance basis.

Depreciation methods, useful lives and residual values are reviewed at each reporting date and, if necessary, any changes would be accounted for prospectively.

VII. Dispositions

Gains on disposal of an item of PP&E or E&E are determined by comparing the proceeds from disposal with the carrying amount of PP&E or E&E and are recognized separately in the Statements of Profit (Loss) and Comprehensive Income (Loss). Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reasonably measured. Where the exchange is measured at fair value, a gain or loss is recognized in the Statements of Profit (Loss) and Comprehensive Income (Loss).

Description of accounting policy for exploration and evaluation expenditures

I. Pre-exploration expenditures

Expenditures made by the Company before acquiring the legal right to explore in a specific area do not meet the definition of an asset and therefore are expensed by the Company as incurred.

II. Exploration and evaluation expenditures

Once the legal right to explore has been acquired, costs incurred are capitalized as intangible exploration and evaluation assets (“E&E). These costs include, but are not limited to, exploration license expenditures, leasehold property acquisition costs, evaluation costs, including drilling costs directly attributable to an identifiable well and directly attributable general and administrative costs. These costs are accumulated in cost centres by property and are not subject to depletion, until technical feasibility and commercial viability have been determined. 

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, or if facts and circumstances suggest that the carrying amount is unlikely to be recovered.

III. Developing and production costs

Items of property, plant and equipment (“PP&E”), which include oil and gas development and production assets, are measured at cost less accumulated depletion, depreciation and accumulated impairment losses net of recoveries.

Gains and losses on disposal of an item of PP&E, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of PP&E, and are recognized within the Statements of Profit (Loss) and Comprehensive Income (Loss).

IV. Joint arrangements

The Company has entered into certain joint arrangements whereby the joint arrangement partner will earn a working interest on certain properties through the payment of a pre-determined portion of the costs of drilling, completing and equipping. A gain on disposition for each well is recognized to account for the disposal of the pre-payout working interest earned by the partner on the well, as described under "Dispositions" below. Bellatrix has property, plant and equipment assets that are subject to these arrangements.

V. Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a well, field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

VI. Depletion and depreciation

Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes in relation to total estimated proven and probable reserves as determined annually by independent engineers in accordance with National Instrument 51-101, Standards of Disclosure of Oil and Gas Activities. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Calculations for depletion are based on total capitalized costs plus estimated future development costs of proven and probable undeveloped reserves less the estimated net realizable value of production equipment and facilities after the proved and probable reserves are fully produced.

Depreciation is recognized on significant facilities to expense the cost of significant components of assets less their residual values over their useful lives. Phase 1 of the Alder Flats Plant and associated equipment are depreciated using the straight-line method over estimated useful lives as follows:

• General plant and processing equipment - 40 years

• Other properties and equipment - 10 years

• Turnarounds - 5 years

Costs of facilities under construction related to Phase II of the Alder Flats Plant as at December 31, 2017 were excluded from depreciation calculations.

Depreciation of office furniture and equipment is provided for on a 20% declining balance basis.

Depreciation methods, useful lives and residual values are reviewed at each reporting date and, if necessary, any changes would be accounted for prospectively.

VII. Dispositions

Gains on disposal of an item of PP&E or E&E are determined by comparing the proceeds from disposal with the carrying amount of PP&E or E&E and are recognized separately in the Statements of Profit (Loss) and Comprehensive Income (Loss). Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reasonably measured. Where the exchange is measured at fair value, a gain or loss is recognized in the Statements of Profit (Loss) and Comprehensive Income (Loss).

Impairment and Impairment Reversals

Impairment and Impairment Reversal

I. Financial assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. All impairment losses are recognized in profit or loss.

II. Non-financial assets

Developing and producing assets are assessed for impairment if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. The impairment test is performed at the asset or CGU level.

The recoverable amount of an asset or a cash-generating unit ("CGU") is the greater of its value in use (“VIU”) and its fair value less costs to sell (“FVLCS”). FVLCS is determined to be the amount for which the asset could be sold in an arm’s length transaction. FVLCS can be determined by using an observable market metric or by using discounted future net cash flows of proved and probable reserves using forecasted prices and costs. VIU is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in the Company’s Statement of Profit (Loss) and Comprehensive Income (Loss) in the period in which it occurs.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

E&E assets are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to producing assets (oil and natural gas interests in PP&E). E&E assets are grouped together with the Company’s CGU’s when they are assessed for impairment.

Identification of CGUs

Bellatrix’s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, geology, production profile and infrastructure of their assets.

Impairment Indicators and Impairment Reversal 

Judgment is required to assess when impairment indicators exist and impairment testing is required with respect to exploration and evaluation assets and property, plant and equipment.

Recoverability of asset carrying values

The Company assesses its oil and gas properties, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date. 

The assessment of any impairment of property, plant and equipment is dependent upon estimates of recoverable amount that take into account factors such as reserves, future estimated commodity prices, royalties and costs, economic and market conditions, timing of cash flows, the useful lives of assets and their related salvage values. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company’s assets in future periods.

Provisions

Provisions

Provisions are recognized when the Company has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Provisions are determined by discounting the expected cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability, if the risks have not been incorporated into the estimate of cash flows. The increase in the provision due to the passage of time is recognized within finance expense.

I. Decommissioning liabilities

The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. A provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation at the balance sheet date. Changes in the present value of the estimated expenditure are reflected as an adjustment to the liability and the relevant asset. The accretion or unwinding of the discount on the decommissioning provision is recognized as a finance expense. Actual costs incurred upon settlement of the decommissioning liabilities are charged against the provision to the extent the provision was recognized.

II. Environmental liabilities

The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Any amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Share-based Payments

Share-based Payments

I. Equity-settled transactions

Bellatrix accounts for options issued under the Company’s share option plan by reference to the fair value of the equity instruments granted. The fair value of each share option is estimated on the date of the grant using the Black-Scholes options pricing model and charged to earnings over the vesting period with a corresponding increase to contributed surplus. The Company estimates a forfeiture rate on the grant date and the rate is adjusted to reflect the actual number of options that actually vest. The expected life of the options granted is adjusted, based on the Company’s best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.

II. Cash-settled transactions

The Company’s Deferred Share Unit Plan (the “DSU Plan”) is accounted for as a cash settled share based payment plan in which the fair value of the amount payable under the DSU Plan is recognized as an expense with a corresponding increase in liabilities. The liability is remeasured at each reporting date and at settlement date. Any changes in the fair value of the liability are recognized in profit or loss.

Awards under the Award Incentive Plan ("Award Plan") may be settled in cash, in common shares of the Company, or a combination thereof. The Company’s Restricted and Performance Award Plan is accounted for as a cash settled share based payment plan in which the fair value of the amounts payable under the Award Plan are recognized incrementally as an expense over the vesting period, with a corresponding change in liabilities.

Income Taxes

Income Taxes

Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

I. Current tax

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid, to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted, or substantively enacted, by the date of the statement of financial position.

II. Deferred tax 

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted, or substantively enacted, by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Financial Instruments

Financial Instruments

All financial instruments, including all derivatives, are recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in income. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income and reclassified to income when derecognized or impaired. The Company has the following classifications:

Financial Assets and Liabilities	Category	Subsequent Measurement
Accounts receivable	Loans and receivables	Amortized cost
Loans receivable	Loans and receivables	Amortized cost
Marketable securities	Held-for-trading	Fair value through profit or loss; Level 1
Commodity risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Foreign exchange risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Accounts payable and accrued liabilities	Other liabilities	Amortized cost
Deferred share units	Other liabilities	Fair value through profit or loss; Level 1
Restricted awards	Other liabilities	Fair value through profit or loss; Level 1
Performance awards	Other liabilities	Fair value through profit or loss; Level 2
Credit Facilities	Other liabilities	Amortized cost
Senior Notes	Other liabilities	Amortized cost
Convertible Debentures	Other liabilities	Amortized cost
Deferred capital obligation	Other liabilities	Amortized cost
Finance lease obligation	Other liabilities	Amortized cost

Financial instruments measured at fair value on the balance sheet require classification into one of the following levels of the fair value hierarchy:

Level 1 – Valuation based on quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 – Valuation based on inputs other than quoted prices included in level 1, that are observable directly or indirectly.

Level 3 – Valuation based on inputs that are not based on observable market data.

The fair value hierarchy level at which a fair value measurement is categorized is determined on the basis of the lowest level input that is significant to the fair value measurement in its entirety. The Company has categorized its financial instruments that are fair valued on the balance sheet according to the fair value hierarchy.

Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument using the effective interest rate method.

The Company utilizes financial derivatives and commodity sales contracts requiring physical delivery to manage the price risk attributable to anticipated sale of petroleum and natural gas production and foreign exchange exposures. The Company does not enter into derivative financial instruments for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, financial derivatives are classified as fair value through profit or loss and are recorded on the balance sheet at fair value, with fair value changes recorded in profit or loss.

The derivative financial instruments are initiated within the guidelines of the Company’s corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet, to specific firm commitments, or forecasted transactions.

The Company accounts for its commodity sales and purchase contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items, in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, physical sales and purchase contracts are not recorded at fair value on the balance sheet. Settlements on these physical sales and purchase contracts are recognized in petroleum and natural gas sales.

Compound financial Instruments

Compound Financial Instruments

The Company's compound financial instruments are comprised of its Convertible Debentures that can be converted to common shares at the option of the holder. The number of shares to be issued does not vary with changes in fair value. 

The liability component of the Convertible Debentures is recognized initially at the fair value of a similar liability that does not have an equity conversion option. The equity component is recognized initially as the difference between the fair value of the Convertible Debenture and the fair value of the liability component. Any directly attributable transaction costs are allocated to the liability and equity components in proportion to their initial carrying amounts.

Subsequent to initial recognition, the liability component of the Convertible Debentures is measured at amortized cost using the effective interest method. The equity component of the Convertible Debentures is not re-measured subsequent to initial recognition.

Lease Obligations

Lease Obligations

Leases which effectively transfer substantially all of the risks and rewards of ownership to the Company are classified as finance leases and are accounted for as an acquisition of an asset and an assumption of an obligation at the inception of the lease, measured as the present value of minimum lease payments to a maximum of the asset’s fair value. The asset is amortized in accordance with the Company’s depletion and depreciation policy. The obligations recorded under finance lease payments are reduced by the lease payments made.

Assets held under other leases are classified as operating leases and are not recognized in the balance sheet. Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. Lease incentives received from landlords are deferred and recognized as an integral part of the total lease expense, over the term of the lease.

Basic and Diluted per Share Calculations

Basic and Diluted per Share Calculations

Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. The Company uses the treasury share method to determine the dilutive effect of share options. Under the treasury share method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted per share amounts.

Finance Income and Expense

Finance Income and Expenses

Finance income is recognized as it accrues in profit or loss, using the effective interest method. Finance expense comprises interest expense on borrowings, amortization of financing costs and discounts, accretion of the discount on provisions and impairment losses recognized on financial assets.

Borrowing Costs

Borrowing Costs

Borrowing costs incurred for the construction of qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use. All other borrowing costs are recognized in profit or loss using the effective interest method. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Company’s outstanding borrowings during the period.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with original maturities of three months or less.

Business Combinations

Business Combinations

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities and contingent liabilities assumed are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the aggregate consideration transferred, measured at the acquisition date fair value. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in profit or loss. If the cost of the acquisition is more than the fair value of the net assets acquired, the difference is recognized on the balance sheet as goodwill. Acquisition costs incurred are expensed.

Foreign Currency Translation

Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses are translated at the period average rates of exchange. Translation gains and losses are included in earnings in the period in which they arise.

Bellatrix’s functional and presentation currency is Canadian dollars.

Oil and Gas reserves

Oil and Gas Reserves

Reserves and resources are used in the units of production calculation for depletion, depreciation and amortization, and the impairment analysis which affect net profit or loss. There are numerous uncertainties inherent in estimating oil and gas reserves. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net profit as further information becomes available and as the economic environment changes.

Decommissioning obligations

Decommissioning obligations

Provisions for decommissioning obligations associated with the Company’s drilling operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology.

Income taxes

Income taxes 

Deferred tax assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.

Business combinations

Business combinations 

The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or goodwill. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.

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SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

Disclosure of financial instruments

The Company has the following classifications:

Financial Assets and Liabilities	Category	Subsequent Measurement
Accounts receivable	Loans and receivables	Amortized cost
Loans receivable	Loans and receivables	Amortized cost
Marketable securities	Held-for-trading	Fair value through profit or loss; Level 1
Commodity risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Foreign exchange risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Accounts payable and accrued liabilities	Other liabilities	Amortized cost
Deferred share units	Other liabilities	Fair value through profit or loss; Level 1
Restricted awards	Other liabilities	Fair value through profit or loss; Level 1
Performance awards	Other liabilities	Fair value through profit or loss; Level 2
Credit Facilities	Other liabilities	Amortized cost
Senior Notes	Other liabilities	Amortized cost
Convertible Debentures	Other liabilities	Amortized cost
Deferred capital obligation	Other liabilities	Amortized cost
Finance lease obligation	Other liabilities	Amortized cost

Bellatrix had the following United States dollar foreign exchange forward purchase contracts outstanding at December 31, 2017:

Type	Value Date	Notional Amount ($000s USD)		Foreign Exchange Rate		Settlement ($000s CDN)
Fixed	May 14, 2020	$	32,500	$	1.3076	$	42,497
Fixed	May 14, 2020	$	30,000	$	1.3080	$	39,240

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EXPLORATION AND EVALUATION ASSETS (Tables)

12 Months Ended

Dec. 31, 2017

Exploration For And Evaluation Of Mineral Resources [Abstract]

Disclosure of detailed information about exploration and evaluation assets

($000s)
Cost
Balance, December 31, 2015	$	87,919
Additions	2,349
Dispositions	(31,176		)
Transfer to oil and natural gas properties	(29,846		)
Balance, December 31, 2016	29,246
Additions	1,664
Dispositions	(7,843		)
Transfer to oil and natural gas properties	(336		)
Balance, December 31, 2017	$	22,731

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2017

Property, plant and equipment [abstract]

Disclosure of detailed information about property, plant and equipment

($000s)	Oil and Natural  Gas Properties			Operated Facilities			Office Furniture and Equipment		Total
Cost
Balance, December 31, 2015	$	2,565,698		$	105,035		$	26,190	$	2,696,923
Additions	61,002			9,590			230		70,822
Acquisition	29,735			—			—		29,735
Transfer from exploration and evaluation assets	29,846			—			—		29,846
Joint venture wells	6,687			—			—		6,687
Disposals	(658,014		)	(58,565		)	—		(716,579		)
Balance, December 31, 2016	2,034,954			56,060			26,420		2,117,434
Additions	111,485			12,058			1,888		125,431
Transfer from exploration and evaluation assets	336			—			—		336
Disposals	(298,102		)	—			—		(298,102		)
Balance, December 31, 2017	$	1,848,673		$	68,118		$	28,308	$	1,945,099

($000s)	Oil and Natural  Gas Properties			Operated Facilities			Office Furniture and Equipment		Total
Accumulated depletion, depreciation and impairment losses
Balance, December 31, 2015	$	1,211,214		$	1,829		$	9,031	$	1,222,074
Charge for the year	131,468			1,862			3,188		136,518
Disposals	(272,026		)	(1,704		)	—		(273,730		)
Impairment (reversal)	(264,000		)	—			—		(264,000		)
Balance, December 31, 2016	806,656			1,987			12,219		820,862
Charge for the year	116,693			1,122			2,837		120,652
Disposals	(196,955		)	—			—		(196,955		)
Impairment	$	13,150		$	—		$	—	$	13,150
Balance, December 31, 2017	$	739,544		$	3,109		$	15,056	$	757,709
Carrying amounts
Balance, December 31, 2016	$	1,228,298		$	54,073		$	14,201	$	1,296,572
Balance, December 31, 2017	$	1,109,129		$	65,009		$	13,252	$	1,187,390

Disclosure of information for VIU and FVLCS cash-generating units

The VIU of each CGU was based on before-tax discount rates ranging from 15-20% and the following forward commodity price estimates:

Year	EdmontonCrude Ref Oil ($/bbl) (1)	AECO NaturalGas ($/MMBtu) (1)	Butane ($/bbl) (1)	Propane  ($/bbl) (1)	Condensate($/bbl) (1)	CDN$/US$ Exchange Rates(1)
2018	71.36	2.52	51.38	35.68	74.93	1.27
2019	73.44	2.93	52.88	36.72	77.12	1.25
2020	75.47	3.22	54.34	35.85	79.25	1.23
2021	80.49	3.51	57.96	36.22	84.52	1.22
2022	82.38	3.75	59.31	37.07	86.50	1.20
2023	84.22	3.85	60.64	37.90	88.43	1.19
2024	86.01	3.95	61.93	38.70	90.31	1.18
2025	88.85	4.11	63.97	39.98	93.29	1.18
2026	90.62	4.27	65.25	40.78	95.15	1.18
2027	92.43	4.35	66.55	41.60	97.06	1.18
Thereafter	+2% per year	+2% per year	+2% per year	+2% per year	+2% per year	1.18

(1)The InSite price forecasts, effective January 1, 2018.

The VIU determination of estimated recoverable amounts of each CGU was based on before-tax discount rates ranging from 10-20% and the following forward commodity price estimates:

Year	EdmontonCrude Ref Oil ($/bbl) (1)	AECO Gas ($/MMBtu)(1)	Butane ($/bbl)(1)	Propane($/bbl)(1)	Condensate($/bbl) (1)	CDN$/US$ Exchange Rates(1)
2017	68.33	3.47	47.83	23.92	75.17	1.33
2018	72.32	3.42	52.07	25.31	79.55	1.29
2019	76.05	3.59	54.75	26.62	83.65	1.25
2020	79.54	3.93	57.27	27.84	87.50	1.21
2021	82.82	4.01	59.63	28.99	91.11	1.18
2022	88.60	4.17	63.79	31.01	97.46	1.18
2023	90.37	4.27	65.07	31.63	99.41	1.18
2024	92.18	4.43	66.37	32.26	101.39	1.18
2025	94.02	4.52	67.69	32.91	103.42	1.18
2026	95.90	4.61	69.05	33.57	105.49	1.18
Thereafter	+2% per year	+2% per year	+2% per year	+2% per year	+2% per year	1.18

(1)The InSite price forecasts, effective January 1, 2017.

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DEBT (Tables)

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Disclosure of detailed information about borrowings

($000s)	Liability Component			Equity Component
Balance, December 31, 2015	$	—		$	—
Issuance of Convertible Debentures	$	38,540		$	11,460
Issue costs	$	(1,842	)	$	(548	)
Deferred income tax liability	$	—		$	(3,094	)
Effective interest on Convertible Debentures	$	722		$	—
Balance, December 31, 2016	$	37,420		$	7,818
Effective interest on Convertible Debentures	2,006			—
Balance, December 31, 2017	$	39,426		$	7,818

($000s)	Amount
Balance, December 31, 2015	$	332,024
Unrealized foreign exchange gain(1) (2)	(9,879		)
Amortization of discount and debt issue costs	2,601
	324,746
Debt issue costs	(55		)
Balance, December 31, 2016	$	324,691
Unrealized foreign exchange gain (3) (4)	(22,079		)
Amortization of discount and debt issue costs	2,797
Balance, December 31, 2017	$	305,409

(1) Exchange rate (CDN$/US$1.00) at December 31, 2016 was 1.3427.

(2) Amount does not include unrealized loss on foreign exchange contracts of $2.0 million.

(3) Exchange rate (CDN$/US$1.00) at December 31, 2017 was 1.2518.

(4) Amount does not include unrealized loss on foreign exchange contracts of $3.9 million.

($000s)	2017		2016
Credit Facilities - current	$	—	$	19,143
Credit Facilities - non-current	52,066		—
Convertible Debentures (liability component)	39,426		37,420
Senior Notes (due on May 15, 2020)	305,409		324,691
Debt	$	396,901	$	381,254

The Company is in compliance with the covenant at December 31, 2017 as shown below.

	Covenant as at		Position at
	December 31, 2017		December 31, 2017
Credit Facilities – Senior Debt Covenant	Maximum Ratio
Senior Debt (1) to Bank EBITDA (2) for the last four fiscal quarters	3.00	x	1.22	x

(1)“Senior Debt” is defined as Consolidated Total Debt, including outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred financing obligations, deferred capital obligations and net working capital deficiency. Excluded from the calculation is any unsecured or subordinated debt (Senior Notes and Convertible Debentures (liability component)), decommissioning liabilities, deferred gain and deferred tax liability. “Consolidated Total Debt” is defined as determined on a consolidated basis in accordance with GAAP and without duplication, all Debt of the Borrower. The Company’s calculation of Consolidated Total Debt excludes decommissioning liabilities and deferred tax liability. The calculation includes outstanding letters of credit, Credit Facilities, finance lease obligations, deferred lease inducements, deferred capital obligations, deferred financing obligations and net working capital deficiency (excess), calculated as working capital deficiency excluding current risk management contract assets and liabilities and current portion of decommissioning liability. Senior Debt at December 31, 2017 was $104.0 million.

(2)“Bank EBITDA” refers to earnings before interest, taxes, depletion, depreciation, amortization and other non-cash charges. Bank EBITDA is calculated based on terms and definitions set out in the agreement governing the credit facilities which adjusts net income for financing costs, certain specific unrealized and non-cash transactions, and acquisition and disposition activity and is calculated based on a trailing twelve month basis. Bank EBITDA for the trailing twelve months ended December 31, 2017 was $85.1 million.

	Covenant as at		Position at
	December 31, 2017		December 31, 2017
Senior Notes – Incurrence Test	Minimum Ratio
Fixed charge coverage (1)	2.25	x	2.12	x

(1)Fixed charge coverage is computed as the ratio of fixed charges (as defined in the Note Indenture, fixed charges generally includes interest expense plus paid or accrued dividends, if any) to trailing twelve month cash flow (as defined in the Note Indenture, cash flow includes the net profit (loss) and adds back provision for taxes, fixed charges, depletion, and various other non-recurring expenses and charges). For the trailing twelve months ended December 31, 2017, fixed charges were $36.6 million and cash flow was $77.8 million.

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DECOMMISSIONING LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2017

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

Disclosure of decommissioning liabilities

($000s)	2017			2016
Balance, beginning of year	$	62,844		$	96,423
Incurred on development activities	1,501			911
Acquired through business combinations	—			552
Revisions on estimates	3,210			(2,292		)
Decommissioning costs incurred	(2,758		)	(2,927		)
Reversed on dispositions	(5,473		)	(31,536		)
Accretion expense	1,287			1,713
Balance, end of year	$	60,611		$	62,844

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OTHER DEFERRED LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

Disclosure of summary of other liabilities

10. OTHER DEFERRED LIABILITIES

($000s)	Finance lease obligation			Deferred lease inducements			Deferred financing obligations(1)			Deferred gain(1)		Deferred Capital Obligation(1)			Total
Balance, December 31, 2016	$	8,429		$	2,387		$	7,525		$	10,706	$	21,890		$	50,937
Deferred lease inducements	—			(366		)	—			—		—			(366		)
Payments on finance lease	(1,538		)	—			—			—		—			(1,538		)
Drawdown deferred financing obligations	—			—			(6,020		)	—		—			(6,020		)
Drawdown deferred capital obligations	—			—			—			—		(14,693		)	(14,693		)
Change in estimate	$	—		$	—		$	—		$	2,314	$	(2,442	)	$	(128	)
Balance, December 31, 2017	$	6,891		$	2,021		$	1,505		$	13,020	$	4,755		$	28,192
Current portion of other deferred liabilities	$	1,170		$	340		$	1,505		$	13,020	$	4,755		$	20,790
Long term portion of other deferred liabilities	$	5,721		$	1,681		$	—		$	—	$	—		$	7,402

(1) Pursuant to the Alder Flats Plant Sale Bellatrix recognized a deferred capital obligation, deferred gain and a deferred financing obligation as part of the

Disclosure of maturity analysis of finance lease payments receivable

The following is a schedule of future minimum lease payments under the finance lease obligations:

Year ending December 31,	($000s)
2018	$	2,138
2019	1,317
2020	1,240
2021	1,164
2022	1,088
Thereafter	6,525
Total lease payments	13,472
Amount representing implicit interest at 15.28%	(6,581		)
Total lease obligation at December 31, 2017	$	6,891

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SHAREHOLDERS' CAPITAL (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of share capital, reserves and other equity interest [Abstract]

Disclosure of classes of share capital

	2017			2016
	Number	Amount ($000s)		Number	Amount ($000s)
Common shares, opening balance	49,317,166	$	1,068,084	38,392,782	$	1,000,100
Shares issued on settlement of share-based compensation	60,860	289		55,953	285
Share issue costs on property acquisition, net of tax effect	—	—		—	(98		)
Issued for cash on equity issue (1)	—	—		6,758,916	40,400
Share issue costs on equity issue, net of tax effect	—	4		—	(1,781		)
Shares issued for property acquisition	—	—		4,109,515	29,178
Balance, end of year	49,378,026	$	1,068,377	49,317,166	$	1,068,084

(1)In August 2016, Bellatrix issued 5,000,000 subscription receipts at a price of $6.00 per subscription receipt for total gross proceeds of $30 million. Proceeds were used to reduce indebtedness under the Company’s credit facilities. Additionally, in October 2016, Bellatrix issued 1,694,915 common shares on a “flow-through” basis in respect of Canadian Development Expenses (“CDE”) at a price of $5.90 per share resulting in gross proceeds of $10 million.

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SHARE-BASED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2017

Share-Based Payment Arrangements [Abstract]

Summary of Share-Based Compensation Expense (Recovery)

The following tables provide a summary of the Company’s share-based compensation expense (recovery) for the years ended December 31, 2017 and December 31, 2016:

($000s)	2017			2016
Share options expense	$	1,074		$	2,565
Deferred share units expense (recovery)	(583		)	834
Restricted awards expense (recovery)	178			241
Performance awards expense (recovery)	(137		)	144
Share-based compensation expense included in general and administrative expense	$	532		$	3,784
Share-based compensation expense included in operating expense	$	167		$	152
Total share-based compensation expense	$	699		$	3,936

The following tables provide a summary of the Company’s share options expense for the years ended December 31, 2017 and December 31, 2016:

($000s)	2017		2016
Share options expense	$	1,074	$	2,565
Share options expense capitalized	600		1,147
Gross share option expense	$	1,674	$	3,712

Summary of Company's Share-Based Compensation Liability Balances

The following table provides a summary of the Company’s share-based compensation liability balances within accounts payable and accrued liabilities:

($000s)	Deferred Share Units		Restricted Awards		Performance Awards		Total
Liability balance, December 31, 2017	$	1,212	$	754	$	457	$	2,423
Liability balance, December 31, 2016	$	2,360	$	1,038	$	751	$	4,149

Disclosure of Share Options Weighted Average Assumptions Used

The weighted average fair market value of share options granted during the years ended December 31, 2017 and 2016, and the weighted average assumptions used in their determination are as noted below:

	2017		2016
Inputs:
Share price	$	4.27	$	5.10
Exercise price	$	4.55	$	5.10
Risk free interest rate (%)	0.9		0.6
Option life (years)	2.8		2.8
Option volatility (%)	71		73
Results:
Weighted average fair value of each share option granted	$	1.87	$	2.35

Disclosure of Share Options Continuity

The following tables summarize information regarding Bellatrix’s Share Option Plan:

Share Options Continuity
	Weighted Average Exercise Price		Number
Balance, December 31, 2015	$	28.45	2,569,273
Granted	$	5.10	581,820
Forfeited	$	30.43	(287,735	)
Expired	$	26.03	(290,334	)
Balance, December 31, 2016	$	23.22	2,573,024
Granted	$	4.55	185,000
Forfeited	$	35.10	(877,956	)
Expired	$	17.12	(257,936	)
Balance, December 31, 2017	$	15.62	1,622,132

DSU Continuity
	Number
Balance, December 31, 2015	202,927
Granted	184,823
Exercised	(10,083	)
Balance, December 31, 2016	377,667
Granted	260,381
Exercised	(120,150	)
Balance, December 31, 2017	517,898

RA Continuity
	Number of RAs
Balance, December 31, 2015	318,762
Granted	284,771
Exercised	(113,457	)
Forfeited	(63,681	)
Balance, December 31, 2016	426,395
Granted	652,740
Exercised	(175,833	)
Forfeited	(79,815	)
Balance, December 31, 2017	823,487

PA Continuity
	Number of PAs
Balance, December 31, 2015	249,240
Granted	145,085
Exercised	(70,430	)
Forfeited	(20,560	)
Balance, December 31, 2016	303,335
Granted	370,000
Exercised	(61,920	)
Forfeited	(38,360	)
Balance, December 31, 2017	573,055

Disclosure of Range of Exercise Prices of Outstanding Share Options

Share Options Outstanding, December 31, 2017

				Outstanding				Exercisable
Exercise Price				At December 31, 2017	Weighted  Average Exercise Price		Weighted Average Remaining Contractual Life	At December 31, 2017	Weighted Average Exercise Price
	$3.85	-	$4.47	125,000		$3.85	4.5	—	—
	$4.48	-	$5.55	494,832		$5.10	3.6	234,944		$5.10
	$5.56	-	$18.70	76,400		$7.78	3.9	10,928		$14.30
	$18.71	-	$19.52	624,000		$18.75	2.4	469,327		$18.75
	$19.53	-	$27.48	118,600		$20.30	1.9	118,600		$20.30
	$27.49	-	$37.95	67,800		$36.66	0.9	67,800		$36.66
	$37.96	-	$45.78	26,700		$39.01	1.0	26,700		$39.01
	$45.79	-	$50.20	88,800		$46.28	1.5	88,800		$46.28
	$3.85	-	$50.20	1,622,132		$15.62	2.8	1,017,099		$19.86

Disclosure of Number and Weighted Average Remaining Contractual Life of Outstanding Share Options

Share Options Outstanding, December 31, 2017

				Outstanding				Exercisable
Exercise Price				At December 31, 2017	Weighted  Average Exercise Price		Weighted Average Remaining Contractual Life	At December 31, 2017	Weighted Average Exercise Price
	$3.85	-	$4.47	125,000		$3.85	4.5	—	—
	$4.48	-	$5.55	494,832		$5.10	3.6	234,944		$5.10
	$5.56	-	$18.70	76,400		$7.78	3.9	10,928		$14.30
	$18.71	-	$19.52	624,000		$18.75	2.4	469,327		$18.75
	$19.53	-	$27.48	118,600		$20.30	1.9	118,600		$20.30
	$27.49	-	$37.95	67,800		$36.66	0.9	67,800		$36.66
	$37.96	-	$45.78	26,700		$39.01	1.0	26,700		$39.01
	$45.79	-	$50.20	88,800		$46.28	1.5	88,800		$46.28
	$3.85	-	$50.20	1,622,132		$15.62	2.8	1,017,099		$19.86

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2017

Income Taxes [Abstract]

Disclosure of provision for income taxes

This difference results from the following items:

($000s)	2017			2016
Expected income tax expense (recovery)	$	(20,506	)	$	(9,052	)
Change in unrecognized deferred tax asset	44,114			—
Unrealized foreign exchange (gain) loss	(4,947		)	(1,938		)
Share based compensation expense	610			856
Flow through share issuance	108			2,700
Other	(3,964		)	576
Deferred tax expense (recovery)	$	15,415		$	(6,858	)

Disclosure of net deferred income tax expense (income)

A continuity of the net deferred income tax asset (liability) for 2017 and 2016 is provided below:

($000s)	Balance, January 1, 2017			Recognized in profit (loss)			Recognized in equity		Balance, December 31, 2017
Property, plant and equipment and exploration and evaluation assets	$	(12,555	)	$	5,710		$	—	$	(6,845	)
Decommissioning liabilities	16,967			(602		)	—		16,365
Risk management contract asset	—			(8,943		)	—		(8,943		)
Risk management contract liability	4,477			(3,271		)	—		1,206
Share issue costs	1,950			(1,110		)	—		840
Non-capital losses	38,895			20			—		38,915
Finance lease obligation	2,276			(416		)	—		1,860
Deferred capital obligation	5,910			(5,910		)	—		—
Deferred financing obligation	2,032			(1,626		)	—		406
Deferred gain on sale	2,890			625			—		3,515
Alberta non-capital losses greater than Federal non-capital losses	1,935			—			—		1,935
Senior Notes	418			338			—		756
Convertible Debentures	(3,028		)	412			—		(2,616		)
Other	1,546			(642		)	—		904
Total	$	63,713		$	(15,415	)	$	—	$	48,298

($000s)	Balance, January 1, 2016			Recognized in profit (loss)			Recognized in equity			Balance, December 31, 2016
Property, plant and equipment and exploration and evaluation assets	$	(12,142	)	$	(413	)	$	—		$	(12,555	)
Decommissioning liabilities	26,034			(9,067		)	—			16,967
Risk management contract asset	(3,600		)	3,600			—			—
Risk management contract liability	105			4,372			—			4,477
Share issue costs	2,520			(1,264		)	694			1,950
Non-capital losses	40,766			(1,871		)	—			38,895
Finance lease obligation	2,717			(441		)	—			2,276
Deferred capital obligation	—			5,910			—			5,910
Deferred financing obligation	—			2,032			—			2,032
Deferred gain on sale	—			2,890			—			2,890
Alberta non-capital losses greater than Federal non-capital losses	1,935			—			—			1,935
Senior Notes	(65		)	483			—			418
Convertible Debentures	—			66			(3,094		)	(3,028		)
Other	985			561			—			1,546
Total	$	59,255		$	6,858		$	(2,400	)	$	63,713

The components of the net deferred tax asset at December 31, 2017 are as follows:

($000s)	2017			2016
Deferred tax liabilities:
Property, plant and equipment and exploration and evaluation assets	$	(6,845	)	$	(12,555	)
Risk management contract asset	(8,943		)	—
Convertible Debentures	(2,616		)	(3,028		)
Deferred tax assets:
Senior Notes	756			418
Finance lease obligation	1,860			2,276
Deferred capital obligation	—			5,910
Deferred financing obligation	406			2,032
Deferred gain on sale	3,515			2,890
Risk management contract liability	1,206			4,477
Decommissioning liabilities	16,365			16,967
Share issue costs	840			1,950
Non-capital losses	40,850			40,830
Other	904			1,546
Deferred tax asset (liability)	$	48,298		$	63,713

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FINANCE INCOME AND EXPENSES (Tables)

12 Months Ended

Dec. 31, 2017

Borrowing costs [abstract]

Disclosure Of Finance Costs

($000s)	2017		2016
Interest on Credit Facilities (1)	$	2,194	$	13,516
Interest on Convertible Debentures (2)	5,381		2,063
Interest on Senior Notes (2)	30,378		30,771
Accretion on decommissioning liabilities (non-cash)	1,287		1,713
Finance expense	$	39,240	$	48,063

(1) Includes interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 1.00% to 3.50%, depending on the type of borrowing and the Company’s Senior Debt to EBITDA ratio. A standby fee is charged between 0.500% and 0.875% on the undrawn portion of the Credit Facilities, depending on the Company’s Senior Debt to EBITDA ratio.

(2) Includes amortized costs related to the issuance of the Senior Notes and Convertible Debentures (detailed in note 8).

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FOREIGN EXCHANGE (Tables)

12 Months Ended

Dec. 31, 2017

Effect Of Changes In Foreign Exchange Rates [Abstract]

Disclosure of effect of changes in foreign exchange rate on profit (loss)

($000s)	2017			2016
Realized gain (loss) on foreign exchange	$	(797	)	$	277
Unrealized gain (loss) on foreign exchange	22,165			9,939
Unrealized gain (loss) on foreign exchange contracts	(3,867		)	(2,021		)
Gain (loss) on foreign exchange	$	17,501		$	8,195

Disclosure of financial instruments

The Company has the following classifications:

Financial Assets and Liabilities	Category	Subsequent Measurement
Accounts receivable	Loans and receivables	Amortized cost
Loans receivable	Loans and receivables	Amortized cost
Marketable securities	Held-for-trading	Fair value through profit or loss; Level 1
Commodity risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Foreign exchange risk management contracts	Held-for-trading	Fair value through profit or loss; Level 2
Accounts payable and accrued liabilities	Other liabilities	Amortized cost
Deferred share units	Other liabilities	Fair value through profit or loss; Level 1
Restricted awards	Other liabilities	Fair value through profit or loss; Level 1
Performance awards	Other liabilities	Fair value through profit or loss; Level 2
Credit Facilities	Other liabilities	Amortized cost
Senior Notes	Other liabilities	Amortized cost
Convertible Debentures	Other liabilities	Amortized cost
Deferred capital obligation	Other liabilities	Amortized cost
Finance lease obligation	Other liabilities	Amortized cost

Bellatrix had the following United States dollar foreign exchange forward purchase contracts outstanding at December 31, 2017:

Type	Value Date	Notional Amount ($000s USD)		Foreign Exchange Rate		Settlement ($000s CDN)
Fixed	May 14, 2020	$	32,500	$	1.3076	$	42,497
Fixed	May 14, 2020	$	30,000	$	1.3080	$	39,240

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PER SHARE AMOUNTS (Tables)

12 Months Ended

Dec. 31, 2017

Earnings per share [abstract]

Earnings per share

The calculation of basic earnings per share for the year ended December 31, 2017 was based on a net loss of $91.4 million (2016: net loss of $26.7 million). 

	2017	2016
Basic common shares outstanding	49,378,026	49,317,165
Fully dilutive effect of:
Share options outstanding	1,622,132	2,573,024
Shares issuable on conversion of Convertible Debentures	6,172,840	6,172,840
Fully diluted common shares outstanding	57,172,998	58,063,029
Weighted average shares outstanding	49,351,848	42,821,013
Dilutive effect of share options (1)	—	—
Diluted weighted average shares outstanding	49,351,848	42,821,013

(1) For the year ended December 31, 2017, a total of 1,622,132 (2016: 2,573,024) share options and 6,172,840 (2016: 6,172,840) shares issuable on conversion of Convertible Debentures were excluded from the calculation as they were anti-dilutive.

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FINANCIAL RISK MANAGEMENT (Tables)

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Disclosure of fair value measurement of assets

The fair value of financial assets and liabilities, excluding working capital and Credit Facilities, is attributable to the following fair value hierarchy levels at December 31, 2017 and December 31, 2016:

($000s)		Fair Value
2017	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	33,123	—	33,123	—
Financial liabilities
Risk management liability	7,890	—	7,890	—
Convertible Debentures (1)	39,426	—	46,000	—
Senior Notes (2)	305,409	—	299,258	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $92.00 per Debenture as at December 31, 2017, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $95.63 per Senior Note as at December 31, 2017.

($000s)		Fair Value
2016	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	445	—	445	—
Financial liabilities
Risk management liability	16,582	—	16,582	—
Convertible Debentures (1)	37,420	—	50,825	—
Senior Notes (2)	324,691	—	332,318	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $101.65per Debenture as at December 31, 2016, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $99.00 per Senior Note as at December 31, 2016.

Disclosure of fair value measurement of liabilities

The fair value of financial assets and liabilities, excluding working capital and Credit Facilities, is attributable to the following fair value hierarchy levels at December 31, 2017 and December 31, 2016:

($000s)		Fair Value
2017	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	33,123	—	33,123	—
Financial liabilities
Risk management liability	7,890	—	7,890	—
Convertible Debentures (1)	39,426	—	46,000	—
Senior Notes (2)	305,409	—	299,258	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $92.00 per Debenture as at December 31, 2017, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $95.63 per Senior Note as at December 31, 2017.

($000s)		Fair Value
2016	Carrying Value	Level 1	Level 2	Level 3
Financial assets
Risk management asset	445	—	445	—
Financial liabilities
Risk management liability	16,582	—	16,582	—
Convertible Debentures (1)	37,420	—	50,825	—
Senior Notes (2)	324,691	—	332,318	—

(1) The fair value of the Convertible Debentures is based on the closing market price on the TSX of $101.65per Debenture as at December 31, 2016, and represents the market value of the entire instrument.

(2) The fair value of the Senior Notes is based on the closing market price of $99.00 per Senior Note as at December 31, 2016.

The following is a summary of the net risk management asset (liability) as at December 31, 2016 and December 31, 2017:

($000s)	2017			2016
Current portion commodity contract asset	$	31,910		$	—
Commodity contract asset (long term)	1,213			—
Foreign exchange contract asset (long term)	—			445
Current portion commodity contract liability	(4,468		)	(13,936		)
Commodity contract liability (long term)	—			(2,646		)
Foreign exchange contract liability (long term)	(3,422		)	—
Net risk management asset (liability)	$	25,233		$	(16,137	)

Disclosure of capital structure

The Company’s capital structure and its calculation of total net debt and the total net debt to adjusted funds flow ratio as defined by the Company is as follows:

Debt to Adjusted Funds Flow Ratio
	Year ended December 31,
($000s, except where noted)	2017		2016
Shareholders’ equity	774,022		863,418
Credit Facilities	52,066		19,143
Loans receivable (long term)	—		(8,775	)
Adjusted working capital deficiency (1)	23,926		23,716
Subtotal	75,992		34,084
Senior Notes (mature May 15, 2020) (2)	305,409		324,691
Net debt (1)	381,401		358,775
Convertible Debentures (liability component)	39,426		37,420
Total net debt (1) at year end	420,827		396,195
Debt to adjusted funds flow ratio (annualized)(3) (4)
Adjusted funds flow (4) (annualized)	62,800		33,748
Net debt (1) to periods adjusted funds flow ratio (annualized) (3)	6.1	x	10.6		x
Total net debt to periods adjusted funds flow ratio (annualized) (3)	6.7	x	11.7		x
Debt to adjusted funds flow ratio (4)
Adjusted funds flow for the year (4)	58,240		40,916
Net debt (1) to adjusted funds flow ratio (4) for the year	6.5	x	8.8		x
Total net debt (1) to adjusted funds flow ratio (4) for the year	7.2	x	9.7		x

(1)Net debt and total net debt as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, deferred capital obligation, long-term risk management contract liabilities, decommissioning liabilities, and the deferred tax liability. Total net debt includes the adjusted working capital deficiency, Convertible Debentures (liability component), current Credit Facilities, long term loan receivable and Senior Notes. The adjusted working capital deficiency as presented does not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. The Company calculated adjusted working capital deficiency as net working capital deficiency excluding current risk management contract assets and liabilities, current portion of other deferred liabilities, current portion of deferred capital obligation, current portion of Credit Facilities and the current portion of decommissioning liability. Net debt excludes the liability component of Convertible Debentures that is included in total net debt.

(2)For the year ended December 31, 2017, Senior Notes includes an unrealized foreign exchange gain of $22.2 million (2016: $9.9 million gain) and does not include an unrealized loss of $3.9 million (2016: $2.0 millionloss) on foreign exchange contracts.

(3)For the years ended December 31, 2017 and 2016, net debt and total net debt to period’s adjusted funds flow ratio (annualized) is calculated based upon fourth quarter adjusted funds flow annualized.

(4)Adjusted funds flow as presented do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Adjusted funds flow is calculated as cash flow from operating activities, excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.

Disclosure of credit risk exposure

As at December 31, 2017, accounts receivable was comprised of the following:

Aging ($000s)	Not past due (less than 90 days)		Past due (90 days or more)			Total
Joint venture and other trade accounts receivable	$	13,627	$	5,186		$	18,813
Revenue and other accruals	27,312		436			27,748
Less: Allowance for doubtful accounts	—		(889		)	(889		)
Total accounts receivable	$	40,939	$	4,733		$	45,672

Disclosure of maturity analysis for non-derivative financial liabilities

The following are the contractual maturities of financial liabilities as at December 31, 2017:

Liabilities ($000s)	Total		< 1 Year		1-3 Years		3-5 Years		More than 5 years
Accounts payable and accrued liabilities	$	73,307	$	73,307	$	—	$	—	$	—
Risk management liability	7,890		4,468		3,422		—		—
Credit Facilities	52,066		—		52,066		—		—
Convertible Debentures (1)	50,000		—		—		50,000		—
Senior Notes (1)	312,950		—		312,950		—		—
Deferred capital obligation	4,755		4,755		—		—		—
Deferred financing obligation	1,505		1,505		—		—		—
Finance lease obligation	6,891		1,170		947		928		3,846
Total	$	509,364	$	85,205	$	369,385	$	50,928	$	3,846

(1) Principal amount of the instruments

Disclosure of commodity price risk management

As at December 31, 2017, the Company has entered into commodity price risk management arrangements as follows:

Natural gas fixed price arrangements

Type		Period	Volume	Price	Index
Natural gas fixed	Financial	January 1, 2018 to December 31, 2018	75,000 GJ/d	2.69	AECO

Natural gas basis differential arrangements

Type		Period	Volume	Price			Index
Natural gas	FInancial	April 1, 2018 to October 31, 2018	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX
Natural gas	Financial	April 1, 2019 to October 31, 2020	10,551 GJ/d	$	(1.17	) US	AECO 7A/NYMEX

Natural gas liquids fixed differential arrangements

Type		Period	Volume	Fixed Differential	Index
Propane	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	47% of NYMEX WTI	OPIS Conway Propane

Crude oil fixed price arrangements

Type		Period	Volume	Price			Index
Oil	Financial	January 1, 2018 to December 31, 2018	1,000 bbl/d	$	70.14	CDN	WTI - NYMEX

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COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

Disclosure of maturity analysis of operating lease payments

The following is a summary of Bellatrix’s commitments as at December 31, 2017:

($000s)	1 Year		2-3 Years		4-5 Years		More than 5 years		Total
Operating leases (1)	$	24,835	$	48,748	$	40,811	$	30,934	$	145,328
Transportation and processing agreements (2)	$	62,207	$	97,788	$	69,481	$	128,873	$	358,349

(1) Operating leases is comprised of the Company’s commitment for office space, net of recoveries and gross operating leases for field equipment. The Company is committed to payments under fixed term operating leases for office space which do not currently provide for early termination.

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RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2017

Related Party [Abstract]

Compensation paid or payable to key management for employee services

The compensation paid or payable to key management for employee services is shown below:

($000s)	2017		2016
Short-term employee benefits (1)	$	4,901	$	3,933
Share-based compensation (2)	452		2,509
Total key management compensation	$	5,353	$	6,442

(1) Includes termination benefits for the year ended December 31, 2017 of $1.3 million (2016: nil)

(2) Share-based compensation includes share options, RAs, PAs, and DSUs.

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SUPPLEMENTAL DISCLOSURES (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Supplemental Disclosures [Abstract]

Disclosure of detailed information about changes in non-cash working capital

Changes in Non-cash Working Capital

($000s)	2017			2016
Changes in non-cash working capital items:
Accounts receivable	$	(6,445	)	$	18,034
Loans receivable	15,000			—
Deposits and prepaid expenses	1,496			2,925
Accounts payable and accrued liabilities	(3,578		)	(32,127		)
	$	6,473		$	(11,168	)
Changes related to:
Operating activities	$	(272	)	$	(443	)
Financing activities	16,353			601
Investing activities	(9,608		)	(11,326		)
	$	6,473		$	(11,168	)

Disclosure of detailed information for employee compensation costs

Total employee compensation costs included in total production and general administrative expenses in the Statements of Profit (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2017 and 2016 are detailed in the following table:

($000s)	2017		2016
Production	$	7,860	$	8,360
General and administrative (1)	19,274		11,616
Employee compensation	$	27,134	$	19,976

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SIGNIFICANT ACCOUNTING POLICIES - Property, Plant and Equipment and Exploration and Evaluation Assets (Details)	12 Months Ended
	Dec. 31, 2017
Disclosure of detailed information about property, plant and equipment [line items]
Declining balance basis	20.00%
General plant and processing equipment
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	40 years
Other properties and equipment
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	10 years
Turnarounds
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	5 years

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EXPLORATION AND EVALUATION ASSETS - Summary of Exploration and Evaluation Assets (Details) - Exploration and evaluation assets - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	$ 29,246	$ 87,919
Additions	1,664	2,349
Dispositions	(7,843)	(31,176)
Transfer to oil and natural gas properties	(336)	(29,846)
Balance at end of period	$ 22,731	$ 29,246

XML

PROPERTY, PLANT AND EQUIPMENT - Summary of Property, Plant and Equipment (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	$ 1,296,572
Balance at end of period	1,187,390	$ 1,296,572
Future development costs	832,000	950,000
Salvage costs	46,600	46,000
Construction in progress	39,700
Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	2,117,434	2,696,923
Additions	125,431	70,822
Acquisition		29,735
Transfer from exploration and evaluation assets	336	29,846
Joint venture wells		6,687
Disposals	(298,102)	(716,579)
Balance at end of period	1,945,099	2,117,434
Accumulated depletion, depreciation and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	(820,862)	(1,222,074)
Charge for the year	120,652	136,518
Disposals	(196,955)	(273,730)
Impairment (reversal)	13,150	(264,000)
Balance at end of period	(757,709)	(820,862)
Oil and Natural Gas Properties
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	1,228,298
Balance at end of period	1,109,129	1,228,298
Oil and Natural Gas Properties | Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	2,034,954	2,565,698
Additions	111,485	61,002
Acquisition		29,735
Transfer from exploration and evaluation assets	336	29,846
Joint venture wells		6,687
Disposals	(298,102)	(658,014)
Balance at end of period	1,848,673	2,034,954
Oil and Natural Gas Properties | Accumulated depletion, depreciation and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	(806,656)	(1,211,214)
Charge for the year	116,693	131,468
Disposals	(196,955)	(272,026)
Impairment (reversal)	13,150	(264,000)
Balance at end of period	(739,544)	(806,656)
Operated Facilities
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	54,073
Balance at end of period	65,009	54,073
Operated Facilities | Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	56,060	105,035
Additions	12,058	9,590
Acquisition		0
Transfer from exploration and evaluation assets	0	0
Joint venture wells		0
Disposals	0	(58,565)
Balance at end of period	68,118	56,060
Operated Facilities | Accumulated depletion, depreciation and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	(1,987)	(1,829)
Charge for the year	1,122	1,862
Disposals	0	(1,704)
Impairment (reversal)	0	0
Balance at end of period	(3,109)	(1,987)
Office Furniture and Equipment
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	14,201
Balance at end of period	13,252	14,201
Office Furniture and Equipment | Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	26,420	26,190
Additions	1,888	230
Acquisition		0
Transfer from exploration and evaluation assets	0	0
Joint venture wells		0
Disposals	0	0
Balance at end of period	28,308	26,420
Office Furniture and Equipment | Accumulated depletion, depreciation and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Balance at beginning of period	(12,219)	(9,031)
Charge for the year	2,837	3,188
Disposals	0	0
Impairment (reversal)	0	0
Balance at end of period	$ (15,056)	$ (12,219)

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PROPERTY, PLANT AND EQUIPMENT - Dispositions (Details) $ in Millions	3 Months Ended					12 Months Ended
	Sep. 30, 2017 CAD ($)	Jun. 30, 2017 CAD ($)	Dec. 31, 2016 CAD ($) shares	Sep. 30, 2016 CAD ($) MMcf	Jun. 30, 2016 CAD ($)	Dec. 31, 2016 CAD ($) shares	Dec. 31, 2017 CAD ($)
Disclosure of detailed information about property, plant and equipment [line items]
Rental fee period					8 years
Deferred capital obligation		$ 20.0
Capitalized general and administrative expenses			$ 7.0			$ 7.0	$ 7.6
Capitalized share-based compensation expense			1.4			1.4	0.8
Oil and Gas Properties, West Pembina Area Of Alberta
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposal of oil and gas assets	$ 16.0		42.0
Losses on disposals of property, plant and equipment	$ 18.6
Consideration from disposal of oil and gas assets			$ 47.0			$ 47.0
Shares received from purchaser from disposal of oil and gas assets | shares			2,171,667			2,171,667
Fair value of shares from purchaser from disposal of oil and gas assets			$ 5.0			$ 5.0
Oil And Gas Properties, Strachan Area Of Alberta
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposal of oil and gas assets		34.5
Losses on disposals of property, plant and equipment		37.0	26.2
Oil and Gas Properties, Harmattan
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposal of oil and gas assets			65.0
Losses on disposals of property, plant and equipment			147.7
Consideration from disposal of oil and gas assets			80.0			80.0
Loan receivable from disposal of oil and gas assets			$ 15.0			$ 15.0
Loan receivable from disposal of oil and gas assets, interest percentage			10.00%			10.00%
Oil and Gas Properties, Willesden Green Area Of Alberta
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposal of oil and gas assets		$ 20.0
Production Facilities
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposal of oil and gas assets					$ 75.0
Alder Flats Plant Sale
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposal of oil and gas assets				$ 112.5
Percentage of working interest disposed of				35.00%
Midstream services and governance agreement, purchased capacity access limits | MMcf				80.5
Midstream services and governance agreement, purchased capacity contract term				10 years
Percentage of voting equity interests acquired				25.00%
Option to reacquire working interest percentage				5.00%
Cost to reacquire working interest in oil and gas assets				$ 8.0
Alder Flats Plant Sale, Phase One
Disclosure of detailed information about property, plant and equipment [line items]
Gains on disposals of property, plant and equipment				9.8
Deferred capital obligation							4.8
Alder Flats Plant Sale, Phase Two
Disclosure of detailed information about property, plant and equipment [line items]
Deferred gains on disposals of property plant and equipment				$ 10.7
Deferred financing obligation							$ 1.5
Drilling Oil and Gas Wells
Disclosure of detailed information about property, plant and equipment [line items]
Gains on disposals of property, plant and equipment						$ 6.7

XML

PROPERTY, PLANT AND EQUIPMENT - Business Combinations (Details) - CAD ($) $ in Millions	Jul. 01, 2017	Jun. 30, 2016
Disclosure of detailed information about property, plant and equipment [line items]
Number of shares issued	1
Ferrier
Disclosure of detailed information about property, plant and equipment [line items]
Consideration transferred, acquisition-date fair value		$ 29.2
Number of shares issued		4,109,515
Financial assets recognised as of acquisition date		$ 29.7
Financial liabilities recognised as of acquisition date		$ 0.5

XML

PROPERTY, PLANT AND EQUIPMENT - Impairment Loss (Reversal) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about property, plant and equipment [line items]
Increase to discount rate	1.00%
Decrease in discount rate	1.00%
South Central
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount of asset or cash-generating unit		$ 64.0
Impairment loss		43.0
Cash Generating Unit, North Alberta
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount of asset or cash-generating unit	$ 5.3
Impairment loss	12.2	0.0
Increase to impairment loss	0.3
Central Alberta
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal) – PP&E		307.0
Recoverable amount of asset or cash-generating unit		1,300.0
Cash Generating Unit, South Alberta
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount of asset or cash-generating unit	1.4
Impairment loss	1.0	$ 0.0
Increase to impairment loss	$ 0.1
Bottom of range
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate used in current estimate of value in use	15.00%
Discount rate used in current measurement of fair value less costs of disposal		10.00%
Top of range
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate used in current estimate of value in use	20.00%
Discount rate used in current measurement of fair value less costs of disposal		20.00%

XML

PROPERTY, PLANT AND EQUIPMENT - VIU Cash Generating Units (Details)	Dec. 31, 2017 $ / MMBTU $ / bbl $ / $	Dec. 31, 2016 $ / MMBTU $ / bbl $ / $
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.27	1.33
Later than one year not later than two years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.25	1.29
Later than two years and not later than three years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.23	1.25
Later than three years and not later than four years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.22	1.21
Later than four years and not later than five years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.20	1.18
Later than five years and not later than six years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.19	1.18
Later than six years and not later than seven years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.18	1.18
Later than seven years and not later than eight years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.18	1.18
Later than eight years and not later than nine years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.18	1.18
Later than nine years and not later than ten years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.18	1.18
Thereafter
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / $	1.18	1.18
Crude Oil
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	71.36	68.33
Crude Oil | Later than one year not later than two years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	73.44	72.32
Crude Oil | Later than two years and not later than three years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	75.47	76.05
Crude Oil | Later than three years and not later than four years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	80.49	79.54
Crude Oil | Later than four years and not later than five years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	82.38	82.82
Crude Oil | Later than five years and not later than six years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	84.22	88.60
Crude Oil | Later than six years and not later than seven years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	86.01	90.37
Crude Oil | Later than seven years and not later than eight years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	88.85	92.18
Crude Oil | Later than eight years and not later than nine years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	90.62	94.02
Crude Oil | Later than nine years and not later than ten years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	92.43	95.90
Crude Oil | Thereafter
Disclosure of information for cash-generating units [line items]
Value in use commodity rate increase per year applied to cash flow projections	2.00%	2.00%
AECO Natural Gas
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	2.52	3.47
AECO Natural Gas | Later than one year not later than two years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	2.93	3.42
AECO Natural Gas | Later than two years and not later than three years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	3.22	3.59
AECO Natural Gas | Later than three years and not later than four years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	3.51	3.93
AECO Natural Gas | Later than four years and not later than five years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	3.75	4.01
AECO Natural Gas | Later than five years and not later than six years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	3.85	4.17
AECO Natural Gas | Later than six years and not later than seven years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	3.95	4.27
AECO Natural Gas | Later than seven years and not later than eight years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	4.11	4.43
AECO Natural Gas | Later than eight years and not later than nine years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	4.27	4.52
AECO Natural Gas | Later than nine years and not later than ten years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections | $ / MMBTU	4.35	4.61
AECO Natural Gas | Thereafter
Disclosure of information for cash-generating units [line items]
Value in use commodity rate increase per year applied to cash flow projections	2.00%	2.00%
Butane
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	51.38	47.83
Butane | Later than one year not later than two years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	52.88	52.07
Butane | Later than two years and not later than three years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	54.34	54.75
Butane | Later than three years and not later than four years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	57.96	57.27
Butane | Later than four years and not later than five years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	59.31	59.63
Butane | Later than five years and not later than six years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	60.64	63.79
Butane | Later than six years and not later than seven years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	61.93	65.07
Butane | Later than seven years and not later than eight years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	63.97	66.37
Butane | Later than eight years and not later than nine years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	65.25	67.69
Butane | Later than nine years and not later than ten years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	66.55	69.05
Butane | Thereafter
Disclosure of information for cash-generating units [line items]
Value in use commodity rate increase per year applied to cash flow projections	2.00%	2.00%
Propane
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	35.68	23.92
Propane | Later than one year not later than two years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	36.72	25.31
Propane | Later than two years and not later than three years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	35.85	26.62
Propane | Later than three years and not later than four years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	36.22	27.84
Propane | Later than four years and not later than five years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	37.07	28.99
Propane | Later than five years and not later than six years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	37.90	31.01
Propane | Later than six years and not later than seven years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	38.70	31.63
Propane | Later than seven years and not later than eight years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	39.98	32.26
Propane | Later than eight years and not later than nine years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	40.78	32.91
Propane | Later than nine years and not later than ten years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	41.60	33.57
Propane | Thereafter
Disclosure of information for cash-generating units [line items]
Value in use commodity rate increase per year applied to cash flow projections	2.00%	2.00%
Condensate
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	74.93	75.17
Condensate | Later than one year not later than two years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	77.12	79.55
Condensate | Later than two years and not later than three years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	79.25	83.65
Condensate | Later than three years and not later than four years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	84.52	87.50
Condensate | Later than four years and not later than five years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	86.50	91.11
Condensate | Later than five years and not later than six years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	88.43	97.46
Condensate | Later than six years and not later than seven years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	90.31	99.41
Condensate | Later than seven years and not later than eight years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	93.29	101.39
Condensate | Later than eight years and not later than nine years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	95.15	103.42
Condensate | Later than nine years and not later than ten years
Disclosure of information for cash-generating units [line items]
Value in use commodity rate applied to cash flow projections	97.06	105.49
Condensate | Thereafter
Disclosure of information for cash-generating units [line items]
Value in use commodity rate increase per year applied to cash flow projections	2.00%	2.00%

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DEBT - Schedule of Debt (Details) - CAD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about borrowings [line items]
Debt	$ 396,901	$ 381,254
Current credit facilities
Disclosure of detailed information about borrowings [line items]
Debt	0	19,143
Non-current credit facilities
Disclosure of detailed information about borrowings [line items]
Debt	52,066	0
Convertible Debentures (liability component)
Disclosure of detailed information about borrowings [line items]
Debt	39,426	37,420	$ 0
Senior Notes (due on May 15, 2020)
Disclosure of detailed information about borrowings [line items]
Debt	$ 305,409	$ 324,691	$ 332,024

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DEBT - Narrative (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017 CAD ($) day shares	Dec. 31, 2017 USD ($)	Dec. 31, 2017 CAD ($) $ / shares	Mar. 31, 2017	Dec. 31, 2016 CAD ($)	Dec. 31, 2015 CAD ($)
Disclosure of detailed information about borrowings [line items]
Debt			$ 396,901,000		$ 381,254,000
EBITDA	$ 85,100,000
Shares available for sale under prospectus			470,800,000
Shares authorised under prospectus			500,000,000
Credit Facilities
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity of credit facility			120,000,000
Debenture securing debt			$ 1,000,000,000
Senior debt covenant, maximum		3.00	3.00	3.5
Fixed charge coverage ratio	2.25
Additional indebtedness, maximum amount	$ 675,000,000
Percentage of adjusted net tangible assets	35.00%
Borrowing amount above ACNTA	$ 150,000,000
Current maximum borrowing amount	$ 675,000,000
Credit Facilities | Top of range
Disclosure of detailed information about borrowings [line items]
Standby fee rate		0.875%	0.875%
Credit Facilities | Bottom of range
Disclosure of detailed information about borrowings [line items]
Standby fee rate		0.50%	0.50%
Credit Facilities | Floating interest rate | Weighted average
Disclosure of detailed information about borrowings [line items]
Interest rate		4.45%	4.45%
Bank debt, operating facility
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity of credit facility			$ 25,000,000
Bank debt, syndicated facility
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity of credit facility			95,000,000
Convertible debentures
Disclosure of detailed information about borrowings [line items]
Debt			39,426,000		37,420,000	$ 0
Nominal amount			$ 50,000,000
Shares converted per $1,000 of debt | shares	123.4568
Conversion price (in dollars per share) | $ / shares			$ 8.10
Convertible debentures | Stated interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate		6.75%	6.75%
Convertible debentures | Borrowings, Redemption, Period One
Disclosure of detailed information about borrowings [line items]
Threshold consecutive trading days | day	20
Convertible debentures | Borrowings, Redemption, Period One | Top of range
Disclosure of detailed information about borrowings [line items]
Notice period for conversion	60 days
Convertible debentures | Borrowings, Redemption, Period One | Bottom of range
Disclosure of detailed information about borrowings [line items]
Notice period for conversion	30 days
Threshold percentage of stock price trigger	125.00%
Convertible debentures | Borrowings, Redemption, Period Two
Disclosure of detailed information about borrowings [line items]
Threshold trading days | day	60
Convertible debentures | Borrowings, Redemption, Period Three | Top of range
Disclosure of detailed information about borrowings [line items]
Notice period for conversion	60 days
Convertible debentures | Borrowings, Redemption, Period Three | Bottom of range
Disclosure of detailed information about borrowings [line items]
Notice period for conversion	40 days
Conversion price as a percentage of share price	95.00%
Non-current credit facilities
Disclosure of detailed information about borrowings [line items]
Debt			$ 52,066,000		0
Current credit facilities
Disclosure of detailed information about borrowings [line items]
Debt			0		19,143,000
Nominal amount			120,000,000
Senior Notes
Disclosure of detailed information about borrowings [line items]
Debt			$ 305,409,000		324,691,000	$ 332,024,000
Nominal amount		$ 250
Senior Notes | Stated interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate		8.50%	8.50%
Senior Notes | Effective interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate		9.60%	9.60%
Senior Notes | Borrowings, Redemption, Period One
Disclosure of detailed information about borrowings [line items]
Redemption price percentage	104.25%
Senior Notes | Borrowings, Redemption, Period Two
Disclosure of detailed information about borrowings [line items]
Redemption price percentage	102.125%
Senior Notes | Borrowings, Redemption, Period Three
Disclosure of detailed information about borrowings [line items]
Redemption price percentage	100.00%
Letters of credit
Disclosure of detailed information about borrowings [line items]
Debt			$ 13,000,000
Debt issue costs | Senior Notes
Disclosure of detailed information about borrowings [line items]
Debt			$ 7,700,000		$ (55,000)

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DEBT - Rollforward of Convertible Debentures (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Liability Component
Beginning balance	$ 381,254
Ending balance	396,901	$ 381,254
Equity Component
Beginning balance	7,818
Deferred income tax liability	0	(2,400)
Ending balance	7,818	7,818
Convertible debentures
Liability Component
Beginning balance	37,420	0
Issuance of Convertible Debentures		38,540
Issue costs		(1,842)
Effective interest on Convertible Debentures	2,006	722
Ending balance	39,426	37,420
Equity Component
Beginning balance	7,818	0
Issuance of Convertible Debentures		11,460
Issue costs		(548)
Deferred income tax liability		(3,094)
Ending balance	$ 7,818	$ 7,818

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DEBT - Rollforward of Senior Notes (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 CAD ($) $ / $	Dec. 31, 2016 CAD ($) $ / $
Disclosure of detailed information about borrowings [line items]
Beginning balance	$ 381,254
Unrealized gain (loss) on foreign exchange	22,165	$ 9,939
Ending balance	396,901	381,254
Unrealized gain (loss) on foreign exchange contracts	3,867	2,021
Senior Notes
Disclosure of detailed information about borrowings [line items]
Beginning balance	324,691	332,024
Unrealized gain (loss) on foreign exchange	(22,079)	(9,879)
Amortization of discount and debt issue costs	2,797	2,601
Ending balance	$ 305,409	$ 324,691
Foreign Exchange Rate | $ / $	1.2518	1.3427
Unrealized gain (loss) on foreign exchange contracts		$ 2,000
Cost | Senior Notes
Disclosure of detailed information about borrowings [line items]
Beginning balance	$ 324,746
Ending balance		$ 324,746

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DEBT - Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 CAD ($)	Mar. 31, 2017
Disclosure of detailed information about borrowings [line items]
Consolidated total debt	$ 104.0
EBITDA	85.1
Fixed charges	36.6
Consolidated cash flows	$ 77.8
Credit Facilities
Disclosure of detailed information about borrowings [line items]
Senior Debt Covenant, Maximum	3.00	3.5
Senior Debt Covenant, Position	1.22
Senior Notes
Disclosure of detailed information about borrowings [line items]
Incurrence Covenant, Maximum	2.25
Incurrence Covenant, Position	2.12

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DECOMMISSIONING LIABILITIES - Narrative (Details) - Provision for decommissioning liabilities - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of other provisions [line items]
Undiscounted liabilities	$ 94,600	$ 97,900
Inflation rate	2.00%	2.00%
Revisions on estimates	$ 3,210	$ (2,292)
Bottom of range
Disclosure of other provisions [line items]
Risk-free interest rate	1.66%	0.83%
Top of range
Disclosure of other provisions [line items]
Risk-free interest rate	2.20%	2.34%

XML

DECOMMISSIONING LIABILITIES - Rollforward of Decommissioning Liabilities (Details) - Provision for decommissioning liabilities - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of other provisions [line items]
Balance, beginning of year	$ 62,844	$ 96,423
Incurred on development activities	1,501	911
Acquired through business combinations	0	552
Revisions on estimates	3,210	(2,292)
Decommissioning costs incurred	(2,758)	(2,927)
Reversed on dispositions	(5,473)	(31,536)
Accretion expense	1,287	1,713
Balance, end of year	$ 60,611	$ 62,844

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OTHER DEFERRED LIABILITIES - Summary of Other Liabilities (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of financial liabilities [line items]
Other liabilities, beginning of period	$ 50,937
Deferred lease inducements (note 10)	(366)	$ (340)
Payments on finance lease	(1,538)
Drawdown deferred financing obligations	(6,020)
Drawdown deferred capital obligations	(14,693)	(3,291)
Change in estimate	(128)
Other liabilities, end of period	28,192	50,937
Current portion of other deferred liabilities (note 10)	20,790	26,064
Other deferred liabilities (note 10)	7,402	24,873
Finance lease obligation
Disclosure of financial liabilities [line items]
Other liabilities, beginning of period	8,429
Deferred lease inducements (note 10)	0
Payments on finance lease	(1,538)
Drawdown deferred financing obligations	0
Drawdown deferred capital obligations	0
Change in estimate	0
Other liabilities, end of period	6,891	8,429
Current portion of other deferred liabilities (note 10)	1,170
Other deferred liabilities (note 10)	5,721
Deferred lease inducements
Disclosure of financial liabilities [line items]
Other liabilities, beginning of period	2,387
Deferred lease inducements (note 10)	(366)
Payments on finance lease	0
Drawdown deferred financing obligations	0
Drawdown deferred capital obligations	0
Change in estimate	0
Other liabilities, end of period	2,021	2,387
Current portion of other deferred liabilities (note 10)	340
Other deferred liabilities (note 10)	1,681
Deferred financing obligations
Disclosure of financial liabilities [line items]
Other liabilities, beginning of period	7,525
Deferred lease inducements (note 10)	0
Payments on finance lease	0
Drawdown deferred financing obligations	(6,020)
Drawdown deferred capital obligations	0
Change in estimate	0
Other liabilities, end of period	1,505	7,525
Current portion of other deferred liabilities (note 10)	1,505
Other deferred liabilities (note 10)	0
Deferred gain
Disclosure of financial liabilities [line items]
Other liabilities, beginning of period	10,706
Deferred lease inducements (note 10)	0
Payments on finance lease	0
Drawdown deferred financing obligations	0
Drawdown deferred capital obligations	0
Change in estimate	2,314
Other liabilities, end of period	13,020	10,706
Current portion of other deferred liabilities (note 10)	13,020
Other deferred liabilities (note 10)	0
Deferred Capital Obligation
Disclosure of financial liabilities [line items]
Other liabilities, beginning of period	21,890
Deferred lease inducements (note 10)	0
Payments on finance lease	0
Drawdown deferred financing obligations	0
Drawdown deferred capital obligations	(14,693)
Change in estimate	(2,442)
Other liabilities, end of period	4,755	$ 21,890
Current portion of other deferred liabilities (note 10)	4,755
Other deferred liabilities (note 10)	$ 0

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OTHER DEFERRED LIABILITIES - Narrative (Details) - Operated Facilities - CAD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Cost
Disclosure of recognised finance lease as assets by lessee [line items]
Recognised finance lease as assets	$ 15.3	$ 15.3
Accumulated depreciation
Disclosure of recognised finance lease as assets by lessee [line items]
Recognised finance lease as assets	$ 4.4	$ 3.7

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OTHER DEFERRED LIABILITIES - Schedule of Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2017 CAD ($)
Disclosure of finance lease and operating lease by lessee [line items]
Total lease payments	$ 13,472
Amount representing implicit interest at 15.28%	(6,581)
Total lease obligation at December 31, 2017	6,891
2018
Disclosure of finance lease and operating lease by lessee [line items]
Total lease payments	2,138
2019
Disclosure of finance lease and operating lease by lessee [line items]
Total lease payments	1,317
2020
Disclosure of finance lease and operating lease by lessee [line items]
Total lease payments	1,240
2021
Disclosure of finance lease and operating lease by lessee [line items]
Total lease payments	1,164
2022
Disclosure of finance lease and operating lease by lessee [line items]
Total lease payments	1,088
Thereafter
Disclosure of finance lease and operating lease by lessee [line items]
Total lease payments	$ 6,525

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SHAREHOLDERS' CAPITAL - Summary of Shareholders' Capital (Details) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	Oct. 31, 2016 CAD ($) $ / shares shares	Aug. 31, 2016 CAD ($) $ / shares shares	Dec. 31, 2017 CAD ($) shares	Dec. 31, 2016 CAD ($) shares	Jul. 01, 2017 shares
Disclosure of classes of share capital [line items]
Number of shares issued					1
Number of shares outstanding, beginning of period (in shares)			49,317,165
Equity attributable to owners of parent, beginning of period | $			$ 863,418
Number of shares outstanding, end of period (in shares)			49,378,026	49,317,165
Preference shares
Disclosure of classes of share capital [line items]
Number of shares authorised			95,978,621
Issued capital
Disclosure of classes of share capital [line items]
Number of shares outstanding, beginning of period (in shares)			49,317,166.000	38,392,782.000
Equity attributable to owners of parent, beginning of period | $			$ 1,068,084	$ 1,000,100
Shares issued on settlement of share-based compensation (in shares)			60,860	55,953
Share-based compensation awards | $			$ 289	$ 285
Share issue costs on property acquisition, net of tax effect | $				$ (98)
Issued for cash on equity issue (in shares)	1,694,915	5,000,000		6,758,916
Issued for cash on equity issue | $	$ 10,000	$ 30,000	0	$ 40,400
Share issue costs on equity issue, net of tax effect | $			$ 4	$ (1,781)
Shares issued for property acquisition (in shares)				4,109,515
Shares issued for property acquisition | $				$ 29,178
Number of shares outstanding, end of period (in shares)			49,378,026	49,317,166.000
Par value per share | $ / shares	$ 5.90	$ 6.00

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SHARE-BASED COMPENSATION PLANS - Summary of Share-based Compensation Expense (Recovery) (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation expense included in general and administrative expense	$ 532	$ 3,784
Share-based compensation expense included in operating expense	167	152
Total share-based compensation expense	699	3,936
Share Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation expense included in general and administrative expense	1,074	2,565
Deferred Share Units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation expense included in general and administrative expense	(583)	834
Restricted Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation expense included in general and administrative expense	178	241
Performance Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation expense included in general and administrative expense	$ (137)	$ 144

XML

SHARE-BASED COMPENSATION PLANS - Summary of Share Option Expense (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation expense included in general and administrative expense	$ 532	$ 3,784
Share Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation expense included in general and administrative expense	1,074	2,565
Share options expense capitalized	600	1,147
Gross share option expense	$ 1,674	$ 3,712

XML

SHARE-BASED COMPENSATION PLANS - Summary of Company's Share-Based Compensation Liability Balance (Details) - CAD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of terms and conditions of share-based payment arrangement [line items]
Liabilities balance	$ 2,423	$ 4,149
Deferred Share Units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Liabilities balance	1,212	2,360
Restricted Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Liabilities balance	754	1,038
Performance Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Liabilities balance	$ 457	$ 751

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SHARE-BASED COMPENSATION PLANS - Options Fair Value Measurements (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($) year day	Dec. 31, 2016 CAD ($) year
Disclosure of terms and conditions of share-based payment arrangement [line items]
Maximum term of options granted	5 years
Share price (in CAD per share)	$ 4.27	$ 5.10
Exercise price (in CAD per share)	$ 4.55	$ 5.10
Risk free interest rate (%)	0.90%	0.60%
Option life (years) | year	2.8	2.8
Option volatility (%)	100.00%	100.00%
Weighted average fair value of each share option granted (in CAD per share)	$ 1.87	$ 2.35
Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Forfeiture rate	3.00%	3.00%
Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Forfeiture rate	10.00%	10.00%
Share Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of trading days to determine weighted average trading price for options granted | day	5
Share Options | Tranche One
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting percentage	33.33%
Share Options | Tranche Two
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting percentage	33.33%
Share Options | Tranche Three
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting percentage	33.33%

XML

SHARE-BASED COMPENSATION PLANS - Options Roll Forward (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($) shares	Dec. 31, 2016 CAD ($) shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of share options outstanding, beginning of period (in CAD per share) | $	$ 23.22	$ 28.45
Weighted average exercise price of share options granted (in CAD per share) | $	4.55	5.10
Weighted average exercise price of share options forfeited (in CAD per share) | $	35.10	30.43
Weighted average exercise price of share options expired (in CAD per share) | $	17.12	26.03
Weighted average exercise price of share options outstanding, end of period (in CAD per share) | $	$ 15.62	$ 23.22
Number of share options outstanding, beginning of period (in shares)	2,573,024	2,569,273
Number of share options granted (in shares)	185,000	581,820
Number of share options forfeited (in shares)	(877,956)	(287,735)
Number of share options expired (in shares)	(257,936)	(290,334)
Number of share options outstanding, end of period (in shares)	1,622,132	2,573,024
Share Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of common shares reserved for issuance (in shares)	4,937,803
Number of shares available for future grants (in shares)	3,315,671

XML

SHARE-BASED COMPENSATION PLANS - Options Range of Exercise Price (Details)	Dec. 31, 2017 CAD ($) shares year	Dec. 31, 2016 CAD ($) shares	Dec. 31, 2015 CAD ($) shares
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	1,622,132	2,573,024	2,569,273
Weighted average exercise price of share options outstanding (in CAD per share)	$ 15.62	$ 23.22	$ 28.45
Share options outstanding, weighted average remaining contractual life | year	2.8
Number of share options exercisable (in shares) | shares	1,017,099
Weighted average exercise price of share options exercisable (in CAD per share)	$ 19.86
Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	3.85
Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 50.20
Exercise Price Range One
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	125,000
Weighted average exercise price of share options outstanding (in CAD per share)	$ 3.85
Share options outstanding, weighted average remaining contractual life | year	4.5
Number of share options exercisable (in shares) | shares	0
Weighted average exercise price of share options exercisable (in CAD per share)	$ 0
Exercise Price Range One | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	3.85
Exercise Price Range One | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 4.47
Exercise Price Range Two
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	494,832
Weighted average exercise price of share options outstanding (in CAD per share)	$ 5.10
Share options outstanding, weighted average remaining contractual life | year	3.6
Number of share options exercisable (in shares) | shares	234,944
Weighted average exercise price of share options exercisable (in CAD per share)	$ 5.10
Exercise Price Range Two | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	4.48
Exercise Price Range Two | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 5.55
Exercise Price Range Three
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	76,400
Weighted average exercise price of share options outstanding (in CAD per share)	$ 7.78
Share options outstanding, weighted average remaining contractual life | year	3.9
Number of share options exercisable (in shares) | shares	10,928
Weighted average exercise price of share options exercisable (in CAD per share)	$ 14.30
Exercise Price Range Three | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	5.56
Exercise Price Range Three | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 18.70
Exercise Price Range Four
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	624,000
Weighted average exercise price of share options outstanding (in CAD per share)	$ 18.75
Share options outstanding, weighted average remaining contractual life | year	2.4
Number of share options exercisable (in shares) | shares	469,327
Weighted average exercise price of share options exercisable (in CAD per share)	$ 18.75
Exercise Price Range Four | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	18.71
Exercise Price Range Four | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 19.52
Exercise Price Range Five
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	118,600
Weighted average exercise price of share options outstanding (in CAD per share)	$ 20.30
Share options outstanding, weighted average remaining contractual life | year	1.9
Number of share options exercisable (in shares) | shares	118,600
Weighted average exercise price of share options exercisable (in CAD per share)	$ 20.30
Exercise Price Range Five | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	19.53
Exercise Price Range Five | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 27.48
Exercise Price Range Six
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	67,800
Weighted average exercise price of share options outstanding (in CAD per share)	$ 36.66
Share options outstanding, weighted average remaining contractual life | year	0.9
Number of share options exercisable (in shares) | shares	67,800
Weighted average exercise price of share options exercisable (in CAD per share)	$ 36.66
Exercise Price Range Six | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	27.49
Exercise Price Range Six | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 37.95
Exercise Price Range Seven
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	26,700
Weighted average exercise price of share options outstanding (in CAD per share)	$ 39.01
Share options outstanding, weighted average remaining contractual life | year	1.0
Number of share options exercisable (in shares) | shares	26,700
Weighted average exercise price of share options exercisable (in CAD per share)	$ 39.01
Exercise Price Range Seven | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	37.96
Exercise Price Range Seven | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 45.78
Exercise Price Range Eight
Disclosure of range of exercise prices of outstanding share options [line items]
Number of share options outstanding (in shares) | shares	88,800
Weighted average exercise price of share options outstanding (in CAD per share)	$ 46.28
Share options outstanding, weighted average remaining contractual life | year	1.5
Number of share options exercisable (in shares) | shares	88,800
Weighted average exercise price of share options exercisable (in CAD per share)	$ 46.28
Exercise Price Range Eight | Bottom of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	45.79
Exercise Price Range Eight | Top of range
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in CAD per share))	$ 50.20

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SHARE-BASED COMPENSATION PLANS - Deferred Share Unit Plan (Details) - Deferred Share Units - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of instruments outstanding, beginning of period (in shares)	377,667	202,927
Number of instruments granted (in shares)	260,381	184,823
Number of instruments exercised (in shares)	(120,150)	(10,083)
Number of instruments outstanding, end of period (in shares)	517,898	377,667

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SHARE-BASED COMPENSATION PLANS - Award Plan (Details)	12 Months Ended
	Dec. 31, 2017 shares day	Dec. 31, 2016 shares
Restricted Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Number of trading days to determine weighted average trading price for instruments granted | day	5
Number of instruments outstanding, beginning of period (in shares)	426,395	318,762
Number of instruments granted (in shares)	652,740	284,771
Number of instruments exercised (in shares)	(175,833)	(113,457)
Number instruments forfeited (in shares)	(79,815)	(63,681)
Number of instruments outstanding, end of period (in shares)	823,487	426,395
Performance Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of trading days to determine weighted average trading price for instruments granted | day	5
Forfeiture rate	5.00%
Number of instruments outstanding, beginning of period (in shares)	303,335	249,240
Number of instruments granted (in shares)	370,000	145,085
Number of instruments exercised (in shares)	(61,920)	(70,430)
Number instruments forfeited (in shares)	(38,360)	(20,560)
Number of instruments outstanding, end of period (in shares)	573,055	303,335
Bottom of range | Restricted Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Forfeiture rate	3.00%
Bottom of range | Performance Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Payout multiplier	0.00%
Top of range | Restricted Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Forfeiture rate	10.00%
Top of range | Performance Awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Payout multiplier	200.00%

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INCOME TAXES - Narrative (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Tax pools available for deduction	$ 1,350,000,000
Federal and provincial corporate income tax rate	27.00%	27.00%
Tax effect of deferred tax assets associated with resource pools	$ 163,400,000	$ 0
Deductible temporary differences for which no tax asset is recognized	5,200,000	$ 14,600,000
Non-capital loss carryforwards
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Tax pools available for deduction against future income	$ 144,100,000

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INCOME TAXES - Reconciliation of Expected and Actual Income Tax Expense (Recovery) (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Abstract]
Expected income tax expense (recovery)	$ (20,506)	$ (9,052)
Change in unrecognized deferred tax asset	44,114	0
Non-Deductible Foreign Exchange Gains (Losses)	(4,947)	(1,938)
Unrealized foreign exchange (gain) loss	18,298	7,918
Share based compensation expense	610	856
Flow through share issuance	108	2,700
Other	(3,964)	576
Deferred tax expense (recovery)	$ 15,415	$ (6,858)

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INCOME TAXES - Deferred Tax Liabilities and Assets (Details) - CAD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	$ 48,298	$ 63,713
Deferred tax asset (liability)	(48,298)	(63,713)	$ (59,255)
Property, plant and equipment and exploration and evaluation assets
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(6,845)	(12,555)
Deferred tax asset (liability)	6,845	12,555	12,142
Risk management contract asset
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(8,943)	0
Deferred tax asset (liability)	8,943	0	3,600
Convertible Debentures
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(2,616)	(3,028)
Deferred tax asset (liability)	2,616	3,028	0
Senior Notes
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	756	418
Deferred tax asset (liability)	(756)	(418)	65
Finance lease obligation
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	1,860	2,276
Deferred tax asset (liability)	(1,860)	(2,276)	(2,717)
Deferred capital obligation
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	0	5,910
Deferred tax asset (liability)	0	(5,910)	0
Deferred financing obligation
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	406	2,032
Deferred tax asset (liability)	(406)	(2,032)	0
Deferred gain on sale
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	3,515	2,890
Deferred tax asset (liability)	(3,515)	(2,890)	0
Risk management contract liability
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	1,206	4,477
Decommissioning liabilities
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	16,365	16,967
Deferred tax asset (liability)	(16,365)	(16,967)	(26,034)
Share issue costs
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	840	1,950
Deferred tax asset (liability)	(840)	(1,950)	(2,520)
Non-capital losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	40,850	40,830
Deferred tax asset (liability)	(38,915)	(38,895)	(40,766)
Other
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred taxes (note 13)	904	1,546
Deferred tax asset (liability)	$ (904)	$ (1,546)	$ (985)

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INCOME TAXES - Continuity of Deferred Tax Asset (Liability) (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	$ 63,713	$ 59,255
Recognized in profit (loss)	(15,415)	6,858
Recognized in equity	0	(2,400)
Ending balance	48,298	63,713
Property, plant and equipment and exploration and evaluation assets
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	(12,555)	(12,142)
Recognized in profit (loss)	5,710	(413)
Recognized in equity	0	0
Ending balance	(6,845)	(12,555)
Decommissioning liabilities
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	16,967	26,034
Recognized in profit (loss)	(602)	(9,067)
Recognized in equity	0	0
Ending balance	16,365	16,967
Risk management contract asset
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	0	(3,600)
Recognized in profit (loss)	(8,943)	3,600
Recognized in equity	0	0
Ending balance	(8,943)	0
Risk management contract liability
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	4,477	105
Recognized in profit (loss)	(3,271)	4,372
Recognized in equity	0	0
Ending balance	1,206	4,477
Share issue costs
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	1,950	2,520
Recognized in profit (loss)	(1,110)	(1,264)
Recognized in equity	0	694
Ending balance	840	1,950
Non-capital losses
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	38,895	40,766
Recognized in profit (loss)	20	(1,871)
Recognized in equity	0	0
Ending balance	38,915	38,895
Finance lease obligation
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	2,276	2,717
Recognized in profit (loss)	(416)	(441)
Recognized in equity	0	0
Ending balance	1,860	2,276
Deferred capital obligation
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	5,910	0
Recognized in profit (loss)	(5,910)	5,910
Recognized in equity	0	0
Ending balance	0	5,910
Deferred financing obligation
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	2,032	0
Recognized in profit (loss)	(1,626)	2,032
Recognized in equity	0	0
Ending balance	406	2,032
Deferred gain on sale
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	2,890	0
Recognized in profit (loss)	625	2,890
Recognized in equity	0	0
Ending balance	3,515	2,890
Alberta non-capital losses greater than Federal non-capital losses
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	1,935	1,935
Recognized in profit (loss)	0	0
Recognized in equity	0	0
Ending balance	1,935	1,935
Senior Notes
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	418	(65)
Recognized in profit (loss)	338	483
Recognized in equity	0	0
Ending balance	756	418
Convertible Debentures
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	(3,028)	0
Recognized in profit (loss)	412	66
Recognized in equity	0	(3,094)
Ending balance	(2,616)	(3,028)
Other
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	1,546	985
Recognized in profit (loss)	(642)	561
Recognized in equity	0	0
Ending balance	$ 904	$ 1,546

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FINANCE INCOME AND EXPENSES (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Accretion on decommissioning liabilities (non-cash)	$ 1,287	$ 1,713
Finance expense	39,240	48,063
Credit Facilities
Disclosure of detailed information about borrowings [line items]
Interest	2,194	13,516
Convertible debentures
Disclosure of detailed information about borrowings [line items]
Interest	5,381	2,063
Senior Notes
Disclosure of detailed information about borrowings [line items]
Interest	$ 30,378	$ 30,771
Bottom of range | Credit Facilities
Disclosure of detailed information about borrowings [line items]
Standby fee rate	0.50%
Top of range | Credit Facilities
Disclosure of detailed information about borrowings [line items]
Standby fee rate	0.875%
Canadian Prime Rate, U.S. Base Rate, CDOR RATE, or Libor | Bottom of range | Credit Facilities
Disclosure of detailed information about borrowings [line items]
Adjustment to floating interest rate	1.00%
Canadian Prime Rate, U.S. Base Rate, CDOR RATE, or Libor | Top of range | Credit Facilities
Disclosure of detailed information about borrowings [line items]
Adjustment to floating interest rate	3.50%

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FOREIGN EXCHANGE - Detail of Gain (Loss) on Foreign Exchange (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Effect Of Changes In Foreign Exchange Rates [Abstract]
Realized gain (loss) on foreign exchange	$ (797)	$ 277
Unrealized gain (loss) on foreign exchange	22,165	9,939
Unrealized gain (loss) on foreign exchange contracts	(3,867)	(2,021)
Gain (loss) on foreign exchange	$ 17,501	$ 8,195

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FOREIGN EXCHANGE - Foreign Exchange Forward Contracts (Details) $ in Thousands	Dec. 31, 2017 USD ($) $ / $	Dec. 31, 2017 CAD ($) $ / $
Currency Swap Contract At Exchange Rate Of $1.3076 CDN To $1.00 USD
Disclosure of detailed information about financial instruments [line items]
Notional Amount ($000s USD)	$ 32,500,000	$ 42,497
Foreign Exchange Rate	1.3076	1.3076
Foreign exchange contracts
Disclosure of detailed information about financial instruments [line items]
Notional Amount ($000s USD)	$ 30,000,000	$ 39,240
Foreign Exchange Rate	1.3080	1.3080

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PER SHARE AMOUNTS - Narrative (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Earnings per share [abstract]
Net profit (loss)	$ (91,363)	$ (26,668)

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PER SHARE AMOUNTS - Disclosure of Per Share Amounts (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Jul. 01, 2017
Earnings per share [abstract]
Basic common shares outstanding (in shares)	49,378,026	49,317,165	5
Fully dilutive effect of:
Share options outstanding (in shares)	1,622,132	2,573,024
Shares issuable on conversion of Convertible Debentures (in shares)	6,172,840	6,172,840
Fully diluted common shares outstanding (in shares)	57,172,998	58,063,029
Weighted average shares outstanding (in shares)	49,351,848	42,821,013
Dilutive effect of share options (in shares)	0	0
Diluted weighted average shares outstanding (in shares)	49,351,848	42,821,013

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FINANCIAL RISK MANAGEMENT - Capital Management (Details) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Shareholders’ equity	$ 774,022	$ 863,418	$ 774,022	$ 863,418
Credit facilities	52,066	19,143	52,066	19,143
Loans receivable (long term)	0	(8,775)	0	(8,775)
Adjusted working capital deficiency	23,926	23,716	23,926	23,716
Subtotal	75,992	34,084	75,992	34,084
Non-current portion of senior notes	305,409	324,691	305,409	324,691
Net debt	381,401	358,775	381,401	358,775
Convertible Debentures (liability component)	39,426	37,420	39,426	37,420
Total net debt at year end	420,827	396,195	420,827	396,195
Unrealized gain (loss) on foreign exchange			22,165	9,939
Unrealized gain (loss) on foreign exchange contracts			(3,867)	(2,021)
Capital Risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Adjusted funds flow (annualized)	$ 62,800	$ 33,748
Net debt to periods adjusted funds flow ratio (annualized)	6.1	10.6
Total net debt to periods adjusted funds flow ratio (annualized)	6.7	11.7
Adjusted funds flow for the year			$ 58,240	$ 40,916
Net debt to adjusted funds flow ratio for the year			6.5	8.8
Total net debt to adjusted funds flow ratio for the year			7.2	9.7
Bottom of range
Disclosure of nature and extent of risks arising from financial instruments [line items]
Net capital budget			$ 65,000
Top of range
Disclosure of nature and extent of risks arising from financial instruments [line items]
Net capital budget			$ 80,000

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FINANCIAL RISK MANAGEMENT - Credit Risk (Details) - Credit risk $ in Thousands	Dec. 31, 2017 CAD ($) customer
Disclosure of credit risk exposure [line items]
Number of primary purchasers | customer	10
Joint venture and other trade accounts receivable | Gross
Disclosure of credit risk exposure [line items]
Accounts receivable	$ 18,813
Revenue and other accruals | Gross
Disclosure of credit risk exposure [line items]
Accounts receivable	27,748
Trade receivables
Disclosure of credit risk exposure [line items]
Accounts receivable	45,672
Trade receivables | Less: Allowance for doubtful accounts
Disclosure of credit risk exposure [line items]
Accounts receivable	(889)
60 days | Trade receivables
Disclosure of credit risk exposure [line items]
Accounts receivable	11,200
Not past due (less than 90 days) | Joint venture and other trade accounts receivable | Gross
Disclosure of credit risk exposure [line items]
Accounts receivable	13,627
Not past due (less than 90 days) | Revenue and other accruals | Gross
Disclosure of credit risk exposure [line items]
Accounts receivable	27,312
Not past due (less than 90 days) | Trade receivables
Disclosure of credit risk exposure [line items]
Accounts receivable	40,939
Not past due (less than 90 days) | Trade receivables | Less: Allowance for doubtful accounts
Disclosure of credit risk exposure [line items]
Accounts receivable	0
Past due (90 days or more) | Joint venture and other trade accounts receivable | Gross
Disclosure of credit risk exposure [line items]
Accounts receivable	5,186
Past due (90 days or more) | Revenue and other accruals | Gross
Disclosure of credit risk exposure [line items]
Accounts receivable	436
Past due (90 days or more) | Trade receivables
Disclosure of credit risk exposure [line items]
Accounts receivable	4,733
Past due (90 days or more) | Trade receivables | Less: Allowance for doubtful accounts
Disclosure of credit risk exposure [line items]
Accounts receivable	$ (889)

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FINANCIAL RISK MANAGEMENT - Liquidity Risk, Narrative (Details)	Dec. 31, 2017 CAD ($)
Disclosure of detailed information about borrowings [line items]
Shares available for sale under prospectus	$ 470,800,000
Shares authorised under prospectus	500,000,000
Credit Facilities
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity of credit facility	120,000,000
Remaining borrowing capacity of credit facility	$ 55,000,000

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FINANCIAL RISK MANAGEMENT - Liquidity Risk (Details) $ in Thousands, $ in Thousands	Dec. 31, 2017 USD ($)	Dec. 31, 2017 CAD ($)	Jun. 30, 2017 CAD ($)	Dec. 31, 2016 CAD ($)
Disclosure of detailed information about borrowings [line items]
Credit Facilities		$ 52,066		$ 19,143
Deferred capital obligation			$ 20,000
Liquidity risk
Disclosure of detailed information about borrowings [line items]
Accounts payable and accrued liabilities		73,307
Accounts payable and accrued liabilities		7,890
Credit Facilities		52,066
Convertible Debentures		50,000
Senior Notes		312,950
Deferred capital obligation		4,755
Deferred financing obligation		1,505
Finance lease obligation		6,891
Total	$ 509,364
1 Year | Liquidity risk
Disclosure of detailed information about borrowings [line items]
Accounts payable and accrued liabilities		73,307
Accounts payable and accrued liabilities		4,468
Credit Facilities		0
Convertible Debentures		0
Senior Notes		0
Deferred capital obligation		4,755
Deferred financing obligation		1,505
Finance lease obligation		1,170
Total	85,205
2-3 Years | Liquidity risk
Disclosure of detailed information about borrowings [line items]
Accounts payable and accrued liabilities		0
Accounts payable and accrued liabilities		3,422
Credit Facilities		52,066
Convertible Debentures		0
Senior Notes		312,950
Deferred capital obligation		0
Deferred financing obligation		0
Finance lease obligation		947
Total	369,385
4-5 Years | Liquidity risk
Disclosure of detailed information about borrowings [line items]
Accounts payable and accrued liabilities		0
Accounts payable and accrued liabilities		0
Credit Facilities		0
Convertible Debentures		50,000
Senior Notes		0
Deferred capital obligation		0
Deferred financing obligation		0
Finance lease obligation		928
Total	50,928
More than 5 years | Liquidity risk
Disclosure of detailed information about borrowings [line items]
Accounts payable and accrued liabilities		0
Accounts payable and accrued liabilities		0
Credit Facilities		0
Convertible Debentures		0
Senior Notes		0
Deferred capital obligation		0
Deferred financing obligation		0
Finance lease obligation		$ 3,846
Total	$ 3,846

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FINANCIAL RISK MANAGEMENT - Foreign Exchange Risk (Details) $ in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Change in foreign exchange rate	0.01	0.01
Foreign exchange gain (loss)		$ 17,501	$ 8,195
Foreign Exchange Risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Percentage of anticipated commodity transaction exposures that are hedged	60.00%	60.00%
Foreign exchange gain (loss)	$ 0.8

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FINANCIAL RISK MANAGEMENT - Commodity Price Risk (Details) - Commodity price risk	12 Months Ended
	Dec. 31, 2017 CAD ($) gigajoule barrel_thermal_unit
Natural Gas Fixed Price | 1 Year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Underlying derivative volume | gigajoule	75,000
Natural Gas Fixed Price | 1 Year | Top of range
Disclosure of nature and extent of risks arising from financial instruments [line items]
Underlying derivative conversion rate	2.69
AECO Natural Gas
Disclosure of nature and extent of risks arising from financial instruments [line items]
Reasonably possible change in risk variable amount	$ 0.10
Reasonably possible change in risk variable impact on operating profit	$ 6,000,000
AECO Natural Gas | 1 Year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Underlying derivative volume | gigajoule	10,551
Underlying derivative conversion rate	1.17
AECO Natural Gas | Later than one year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Underlying derivative volume | gigajoule	10,551
Underlying derivative conversion rate	1.17
Crude Oil
Disclosure of nature and extent of risks arising from financial instruments [line items]
Reasonably possible change in risk variable amount	$ 1.00
Reasonably possible change in risk variable impact on operating profit	$ 3,700,000
Crude Oil | 1 Year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Underlying derivative volume | barrel_thermal_unit	1,000
Crude Oil | Later than one year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Underlying derivative conversion rate	70.140
Propane | 1 Year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Underlying derivative volume | barrel_thermal_unit	1,000
Underlying derivative conversion rate	0.47

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FINANCIAL RISK MANAGEMENT - Interest Rate Risk (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017 CAD ($)	Dec. 31, 2017 CAD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Reasonably possible increase in risk variable, impact to net income/loss		$ 0.2
Floating interest rate | Interest Rate Risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Reasonably possible decrease in risk variable, percent	1.00%	1.00%
Reasonably possible decrease in risk variable, impact to net income/loss	$ 0.5
Reasonably possible increase in risk variable, percent	1.00%	1.00%

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FINANCIAL RISK MANAGEMENT - Fair Value Hierachy Levels (Details) - CAD ($)	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	$ 1,340,923,000	$ 1,453,730,000
Financial liabilities	566,901,000	590,312,000
Risk management asset
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	7,890,000	16,582,000
Risk management asset | Level 1
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	0	0
Risk management asset | Level 2
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	7,890,000	16,582,000
Risk management asset | Level 3
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	0	0
Convertible debentures
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	39,426,000	37,420,000
Closing market price per liability	92.00	101.65
Convertible debentures | Level 1
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	0	0
Convertible debentures | Level 2
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	46,000,000	50,825,000
Convertible debentures | Level 3
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	0	0
Senior Notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	305,409,000	324,691,000
Closing market price per liability	95.63	99.00
Senior Notes | Level 1
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	0	0
Senior Notes | Level 2
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	299,258,000	332,318,000
Senior Notes | Level 3
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	0	0
Risk management asset
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	33,123,000	445,000
Risk management asset | Level 1
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	0	0
Risk management asset | Level 2
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	33,123,000	445,000
Risk management asset | Level 3
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	$ 0	$ 0

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FINANCIAL RISK MANAGEMENT - Fair Value (Details) - CAD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Assets	$ 1,340,923	$ 1,453,730
Liabilities	566,901	590,312
Risk management asset	1,213	445
Current portion commodity contract liability	(4,468)	(13,936)
Commodity contract liability (long term)	(3,422)	(2,646)
Net risk management asset (liability)	25,233	(16,137)
Commodity contract
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Current portion commodity contract asset	31,910	0
Risk management asset	1,213	0
Current portion commodity contract liability	(4,468)	(13,936)
Commodity contract liability (long term)	0	(2,646)
Foreign exchange contract
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management asset	0	445
Commodity contract liability (long term)	3,422	0
Risk management asset
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Assets	33,123	445
Level 1 | Risk management asset
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Assets	0	0
Level 2 | Risk management asset
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Assets	33,123	445
Level 3 | Risk management asset
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Assets	0	0
Risk management asset
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	7,890	16,582
Risk management asset | Level 1
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	0	0
Risk management asset | Level 2
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	7,890	16,582
Risk management asset | Level 3
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	0	0
Convertible debentures
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	39,426	37,420
Convertible debentures | Level 1
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	0	0
Convertible debentures | Level 2
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	46,000	50,825
Convertible debentures | Level 3
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	0	0
Senior Notes (due on May 15, 2020)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	305,409	324,691
Senior Notes (due on May 15, 2020) | Level 1
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	0	0
Senior Notes (due on May 15, 2020) | Level 2
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	299,258	332,318
Senior Notes (due on May 15, 2020) | Level 3
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Liabilities	$ 0	$ 0

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COMMITMENTS - Summary of Operating Lease Maturities (Details) $ in Thousands	Dec. 31, 2017 CAD ($)
Disclosure of maturity analysis of operating lease payments [line items]
Operating leases	$ 145,328
Transportation and processing agreements	358,349
1 Year
Disclosure of maturity analysis of operating lease payments [line items]
Operating leases	24,835
Transportation and processing agreements	62,207
2-3 Years
Disclosure of maturity analysis of operating lease payments [line items]
Operating leases	48,748
Transportation and processing agreements	97,788
4-5 Years
Disclosure of maturity analysis of operating lease payments [line items]
Operating leases	40,811
Transportation and processing agreements	69,481
More than 5 years
Disclosure of maturity analysis of operating lease payments [line items]
Operating leases	30,934
Transportation and processing agreements	$ 128,873

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RELATED PARTY TRANSACTIONS (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party [Abstract]
Key management personnel compensation, termination benefits	$ 1,300	$ 0
Short-term employee benefits	4,901	3,933
Share-based compensation	452	2,509
Key management compensation	$ 5,353	$ 6,442

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SUPPLEMENTAL DISCLOSURES - Changes in Non-cash Working Capital (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Supplemental Disclosures [Abstract]
Accounts receivable	$ (6,445)	$ 18,034
Loans receivable	15,000	0
Deposits and prepaid expenses	1,496	2,925
Accounts payable and accrued liabilities	(3,578)	(32,127)
Operating activities	(272)	(443)
Financing activities	16,353	601
Investing activities	(9,608)	(11,326)
Increase (decrease) in working capital	$ 6,473	$ (11,168)

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SUPPLEMENTAL DISCLOSURES - Consolidated Statement of Comprehensive Income (Loss) Presentation (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of defined benefit plans [line items]
Employee compensation	$ 27,134	$ 19,976
Production
Disclosure of defined benefit plans [line items]
Employee compensation	7,860	8,360
General and administrative
Disclosure of defined benefit plans [line items]
Employee compensation	$ 19,274	$ 11,616