40-F

UNITED STATES	OMB APPROVAL
SECURITIES AND EXCHANGE COMMISSION
	OMB Number: 3235-0381
Washington, D.C. 20549	Expires: September 30, 2018
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FORM 40-F	hours per response. . . ...429.93

[Check one]

	¨	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
OR
	þ	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: 001-34406

ADVANTAGE OIL & GAS LTD.

(Exact name of Registrant as specified in its charter)

N/A

(Translation of Registrant’s name into English (if applicable))

ALBERTA

(Province or other jurisdiction of incorporation or organization):

1311

(Primary Standard Industrial Classification Code Number (if applicable))

N/A

(I.R.S. Employer Identification Number (if applicable))

Suite 300, 440 – 2 Avenue SW, Calgary, Alberta T2P 5E9 (403) 718-8000

(Address and telephone number of Registrant’s principal executive offices)

Corporation Service Company

1133 Avenue of Americas, 31st Floor, New York, NY 10036 1-800-927-9800

(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.

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

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

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

SEC2285(01-12) Persons who are to respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number.

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

Annual information form þ         Audited annual financial statements þ

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.

Common Shares: 185,963,186

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 ¨   No þ

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 þ   No ¨

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

Emerging growth company ¨

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by checkmark 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.

¨

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

DOCUMENTS INCLUDED IN THIS FORM

The following documents are included in the Form:

No.	Document
1.	Annual Information Form of the Registrant for the year ended December 31, 2017 (filed herein as Exhibit 99.1)
2.	Consolidated Financial Statements of the Registrant for the fiscal year ended December 31, 2017, prepared under International Financial Reporting Standards as issued by the International Accounting Standards Board (filed herein as Exhibit 99.2)
3.	Consolidated Management’s Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2017 (filed herein as Exhibit 99.3).
4.	Consent of PricewaterhouseCoopers LLP to the inclusion of the Auditors’ Report dated March 5, 2018 on the Registrant’s Audited Consolidated Financial Statements for the fiscal year ended December 31, 2017.
5.	Consent of Sproule Associates Limited to the incorporation by reference herein of its Statement of Reserves Data and other Information in Form 51-101F1, which statement and report is contained in the Registrant’s Annual Information Form for the fiscal year ended December 31, 2017.
6.	CEO Certification pursuant to rule 13a-14(a) of the Exchange Act.
7.	CFO Certification pursuant to rule 13a-14(a) of the Exchange Act.
8.	CEO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
9.	CFO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PRINCIPAL DOCUMENTS

A. Annual Information Form

For the Registrant’s Annual Information Form for the fiscal year ended December 31, 2017, see Exhibit 99.1 of this Annual Report on Form 40-F.

B. Audited Annual Financial Statements

For the Registrant’s Audited Consolidated Financial Statements for the year ended December 31, 2017, including the report of its Independent Auditor with respect thereto, see Exhibit 99.2 of this Annual Report on Form 40-F.

C. Consolidated Management’s Discussion and Analysis

For the Registrant’s Consolidated Management’s Discussion and Analysis of the operating and financial results for the year ended December 31, 2017, see Exhibit 99.3 of this Annual Report on Form 40-F.

CERTIFICATIONS AND DISCLOSURES REGARDING
CONTROLS AND PROCEDURES

A.           CERTIFICATIONS. See Exhibits 31.1 and 31.2 to this Annual Report on Form 40-F.

B.           DISCLOSURE CONTROLS AND PROCEDURES. As of the end of the Registrant’s fiscal year ended December 31, 2017, an evaluation of the effectiveness of the Registrant’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 the Registrant’s management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the Registrant’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the Registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Registrant 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 rules and forms and (ii) accumulated and communicated to the Registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

It should be noted that while the Registrant’s principal executive officer and principal financial officer believe that the Registrant’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Registrant’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. Reference is made in the “Evaluation of Disclosure Controls and Procedures” and “Evaluation of Internal Controls over Financial Reporting” sections of Management’s Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2017, included herein.

C.           MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. The required disclosure is included in “Management’s Report on Internal Control over Financial Reporting” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F.

D.           ATTESTATION REPORT OF THE INDEPENDENT AUDITOR. The required disclosure is included in the “Independent Auditor’s Report” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F.

E.           CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. During the fiscal year ended December 31, 2017, there were no significant changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting. Reference is made in the “Evaluation of Internal Controls over Financial Reporting” section of Management’s Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2017, included herein.

NOTICES PURSUANT TO REGULATION BTR

None.

CODE OF ETHICS FOR CHIEF EXECUTIVE OFFICER
AND SENIOR FINANCIAL OFFICERS

The Registrant has adopted a Code of Ethics for its senior officers, principal financial officer and controller or principal accounting officer, directors and employees. This code applies to the President and Chief Executive Officer, Vice President Finance and Chief Financial Officer, Senior Vice President, Directors and employees. It is available on the Registrant’s web site at www.advantageog.com and in print to any shareholder who requests it. All amendments to the code, and all waivers of the code with respect to any of the officers covered by it, will be posted on the Registrant’s web site and provided in print to any shareholder who requests them.

AUDIT COMMITTEE

Identification of Audit Committee

The following individuals comprise the entire membership of the Advantage Audit Committee: Paul G. Haggis, Stephen E. Balog, and Jill Angevine.

Audit Committee Financial Experts

Paul G. Haggis has been determined by the board of the Registrant to meet the “audit committee financial expert” criteria prescribed by the Securities and Exchange Commission and has been designated as audit committee financial expert for the Audit Committee of the board of the Registrant.

Each of the directors serving on the Audit Committee has also been determined by the board of the Registrant to be independent within the criteria established by the New York Stock Exchange, Inc. for audit committee membership.

PRINCIPAL ACCOUNTING FEES AND
SERVICES – INDEPENDENT AUDITORS

Fees payable to the Registrant’s independent auditors for the years ended December 31, 2017 and December 31, 2016, totaled $321,000 and $364,400, respectively, as detailed in the following tables. All funds are in Canadian dollars.

The following table discloses fees billed to the Registrant by its current auditors, PricewaterhouseCoopers LLP:

	Year ended December 31, 2017		Year ended December 31, 2016
Audit Fees	$	268,000	$	263,000
Audit Related Fees		45,000		45,000
Tax Fees		8,000		16,500
All Other Fees		-		39,900
TOTAL	$	321,000	$	364,400

The nature of the services provided by the Registrant’s independent auditors under each of the categories indicated in the table is described below.

Audit Fees

Audit fees were for professional services rendered by the Registrant’s independent auditors for the audit of the Registrant’s annual financial statements and services provided in connection with statutory and regulatory filings or engagements. These services include audit or review of financials forming part of such prospectus.

Audit-Related Fees

Audit-related fees were for assurance and related services reasonably related to the performance of the audit or review of the annual statements and are not reported under “Audit Fees” above.

Tax Fees

Tax fees were for tax advice and tax planning professional services. These services consisted of general tax planning and advisory services relating to common forms of domestic and international taxation (i.e., income tax, capital tax, goods and services tax, scientific research and experimental development tax credits).

All Other Fees

Work related to Offering.

PREAPPROVAL POLICIES AND PROCEDURES

In 2017, Advantage’s Audit Committee pre-approved all audit, audit-related and tax fees. The Audit Committee will be informed routinely as to the non-audit services actually provided by the auditor pursuant to this pre-approval process. The auditors also present the estimate for the annual audit related services to the Audit Committee for approval prior to undertaking the annual audit of the financial statements.

OFF-BALANCE SHEET ARRANGEMENTS

None.

CONTRACTUAL OBLIGATIONS

	Payments due by period (Cdn$MM)
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Building Leases	$	1.8	$	1.1	$	0.7	$	-	$	-
Pipeline/Transportation	$	384.9	$	46.2	$	100.6	$	89.9	$	148.2
Bank Indebtedness(1) (2)	$	223.9	$	9.4	$	214.5	$	-	$	-
Total Contractual Obligations	$	610.6	$	56.7	$	315.8	$	89.9	$	148.2

(1) As at December 31, 2017, the Corporation’s bank indebtedness was governed by a credit facility agreement with a syndicate of financial institutions. Under the terms of the agreement, the facility is reviewed annually, with the next review scheduled in June 2018. The facility is revolving and extendible at each annual review for a further 364 day period at the option of the syndicate. If not extended, the credit facility is converted at that time into a one-year term facility, with the principal payable at the end of such one-year term. Management fully expects that the facility will be extended at each annual review.

(2) Amounts include estimated amounts of interest.

DISCLOSURES PURSUANT TO REQUIREMENTS OF THE
NEW YORK STOCK EXCHANGE

Presiding Director at Meetings of Non-Management Directors

The Registrant schedules regular executive sessions in which the Registrant’s “non-management directors” (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Ron McIntosh serves as the presiding director (the “Chair of the Board”) at such sessions. Each of the Registrant’s non-management directors is “independent” as such term is used in the rules of the Canadian Securities Commissions and the New York Stock Exchange Corporate Governance Standards.

Communication with Non-Management Directors

Shareholders may send communications to the Registrant’s non-management directors by writing to Investors Relations, Millenium Tower, Suite 300, 440 - 2 Avenue SW, Calgary, Alberta T2P 5E9, or calling the toll free number at 1-866-393-0393. Communications will be referred to the Chair of the Board for appropriate action. The status of all outstanding concerns addressed to the Chair of the Board will be reported to the board of directors as appropriate.

Corporate Governance Guidelines

According to NYSE Rule 303A.09, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics and must disclose any significant ways in which its practices differ from those followed by US domestic companies under the NYSE rules. Such guidelines and disclosures are required to be posted on the listed company’s website. The Registrant has adopted the required guidelines and made the required disclosures, all of which are available on the Registrant’s website at www.advantageog.com and in print to any shareholder who requests them.

Board Committee Charters

Advantage’s Audit Committee Charter, the Terms of Reference of the Human Resources, Compensation and Corporate Governance Committee and the Terms of Reference for the Independent Reserve Evaluation Committee are available for viewing on the Registrant’s website at www.advantageog.com and are available in print to any person who requests them. Requests for copies of these documents should be made by contacting: Investor Relations, Millenium Tower, Suite 300, 440 - 2 Avenue SW, Calgary, Alberta T2P 5E9.

UNDERTAKING

The Registrant 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.

CONSENT TO SERVICE OF PROCESS

The Registrant has previously filed with the Commission a Form F-X in connection with the Common Shares.

Any change to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Securities and Exchange Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

EXHIBITS

The following exhibits are filed as part of this report.

Exhibit Number	Description
23.1	Consent of PricewaterhouseCoopers LLP to the inclusion of the Auditors’ Report dated March 5, 2018 on the Registrant’s Audited Consolidated Financial Statements for the fiscal year ended December 31, 2017.
23.2	Consent of Sproule Associates Limited to the incorporation by reference herein of its Statement of Reserves Data and other Information in Form 51-101F1, which statement and report is contained in the Registrant’s Annual Information Form for the fiscal year ended December 31, 2017.
31.1	CEO Certification pursuant to rule 13a-14(a) of the Exchange Act.
31.2	CFO Certification pursuant to rule 13a-14(a) of the Exchange Act.
32.1	CEO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	CFO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Annual Information Form of the Registrant for the year ended December 31, 2017.
99.2	Consolidated Financial Statements of the Registrant for the fiscal year ended December 31, 2017, prepared under International Financial Reporting Standards as issued by the International Accounting Standards Board.
99.3	Consolidated Management’s Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2017.

SIGNATURE

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 on Form 40-F to be signed on its behalf by the undersigned, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada.

Dated: March 5, 2018

ADVANTAGE OIL & GAS LTD.
By:	/s/ Craig Blackwood
	Name:  Craig Blackwood
	Title:    Vice President Finance and Chief Financial Officer

EX-23.1

Exhibit 23.1

March 5, 2018

Consent of Independent Registered Public Accounting Firm

We hereby consent to the inclusion in this Annual Report on Form 40-F for the year ended December 31, 2017 of Advantage Oil & Gas Ltd. of our report dated March 5, 2018, relating to the consolidated financial statements, and the effectiveness of internal control over financial reporting, which appears in this Annual Report.

We also consent to reference to PricewaterhouseCoopers LLP under the heading “Interests of Experts,” which appears in the Annual Information Form included in this Annual Report on Form 40-F.

/s PricewaterhouseCoopers LLP

Chartered Professional Accountants

PricewaterhouseCoopers LLP, Chartered Professional Accountants

Suncor Energy Centre, 111 5 Avenue SW, Suite 3100, Calgary, Alberta, Canada T2P 5L3

T: +1 403 509 7500, F: +1 403 781 1825, www.pwc.com/ca

“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.

EX-23.2

Exhibit 23.2

March 5, 2018

Consent of Independent Engineers

We refer to our report entitled “Evaluation of the P&NG Reserves of Advantage Oil & Gas Ltd. (As of December 31, 2017)”, dated February 7, 2018 (the “Report”).

We hereby consent to the use of our name and references to excerpts from the Report in the Annual Report on Form 40-F of Advantage Oil & Gas Ltd. for the year ended December 31, 2017.

Sincerely,

SPROULE ASSOCIATES LIMITED

By:	/s/ Attila A. Szabo
	Name:  Attila A. Szabo, P. Eng
	Title:    Vice-President, Strategic Advisory and Director

EX-31.1

Exhibit 31.1

CEO CERTIFICATION

PURSUANT TO RULE 13a-14(a) OF THE SECURITIES EXCHANGE ACT OF 1934

I, Andy J. Mah, certify that:

1. I have reviewed this annual report on Form 40-F of Advantage Oil & Gas 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(s) 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(s) 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 functions):

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 5, 2018	/s/ Andy J. Mah
	Andy J. Mah
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CFO CERTIFICATION

PURSUANT TO RULE 13a-14(a) OF THE SECURITIES EXCHANGE ACT OF 1934

I, Craig Blackwood, certify that:

1. I have reviewed this annual report on Form 40-F of Advantage Oil & Gas 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(s) 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(s) 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 functions):

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 5, 2018	/s/ Craig Blackwood
	Craig Blackwood
	Vice President Finance and Chief Financial Officer

EX-32.1

Exhibit 32.1

CEO CERTIFICATION

PURSUANT TO 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 Advantage Oil & Gas Ltd. (“Advantage”) on Form 40-F for the fiscal year ending December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Andy J. Mah, President and Chief Executive Officer of Advantage, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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 presents, in all material respects, the financial condition and results of operations of Advantage.

Date:  March 5, 2018	/s/ Andy J. Mah
	Andy J. Mah
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CFO CERTIFICATION

PURSUANT TO 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 Advantage Oil & Gas Ltd. (“Advantage”) on Form 40-F for the fiscal year ending December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Craig Blackwood, Vice President Finance and Chief Financial Officer of Advantage, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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 presents, in all material respects, the financial condition and results of operations of Advantage.

Date:  March 5, 2018	/s/ Craig Blackwood
	Craig Blackwood
	Vice President Finance and Chief Financial Officer

EX-99.1

Exhibit 99.1

ANNUAL INFORMATION FORM

YEAR ENDED DECEMBER 31, 2017

March 5, 2018

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS	1
ABBREVIATIONS AND OIL AND GAS ADVISORIES	5
CONVERSION	5
FORWARD-LOOKING STATEMENTS	6
NON-GAAP MEASURES	7
ADVANTAGE OIL & GAS LTD.	8
GENERAL DEVELOPMENT OF THE BUSINESS	8
DESCRIPTION OF OUR BUSINESS AND OPERATIONS	11
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	12
DIRECTORS AND OFFICERS	26
DIVIDEND POLICY	29
DESCRIPTION OF THE CORPORATION'S SECURITIES	30
PRICE RANGE AND TRADING VOLUME OF SECURITIES	30
ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER	31
LEGAL PROCEEDINGS	31
REGULATORY ACTIONS	31
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	32
MATERIAL CONTRACTS	32
INTEREST OF EXPERTS	32
AUDITORS, TRANSFER AGENT AND REGISTRAR	32
AUDIT COMMITTEE INFORMATION	33
AUDIT COMMITTEE CHARTER	33
AUDIT SERVICE FEES	38
INDUSTRY CONDITIONS	38
RISK FACTORS	48
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	67
ADDITIONAL INFORMATION	68

SCHEDULES

"A"	–	REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
"B"	–	REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

GLOSSARY OF TERMS

Selected Defined Terms

"ABCA" means the Business Corporations Act (Alberta), together with any or all regulations promulgated thereunder, as amended from time to time;

"AOG" or "Advantage" or the "Corporation" means Advantage Oil & Gas Ltd., a corporation amalgamated under the ABCA. All references to "AOG" or "Advantage" or the "Corporation", unless the context otherwise requires, are references to Advantage Oil & Gas Ltd. and its predecessors and subsidiaries;

"Board of Directors" or "Board" means the board of directors of Advantage;

"Common Shares" means the common shares of Advantage;

"Credit Facilities" has the meaning ascribed thereto under the heading "General Development of the Business – Three Year History – 2017 – Credit Facilities";

"GAAP" means generally accepted accounting principles for publicly accountable enterprises in Canada which is currently in accordance with IFRS;

"IFRS" means International Financial Report Standards as issued by the International Accounting Standards Board;

"Longview" means Longview Oil Corp., a corporation incorporated under the ABCA;

"NYSE" means the New York Stock Exchange;

"Offering" means the bought-deal public offering pursuant to a short form prospectus of the Corporation dated March 1, 2016 of up to 13,512,500 Common Shares (including 1,762,500 Common Shares issuable on the exercise of an over-allotment option granted to the underwriters) for gross proceeds of up to $100,668,125;

"Shareholders" means the holders from time to time of one or more Common Shares, as shown on the register of such holders maintained by the Corporation or by the transfer agent of the Common Shares, on behalf of the Corporation;

"TSX" means the Toronto Stock Exchange; and

"U.S." means the United States of America.

Selected Defined Oil and Gas Terms

"abandonment and reclamation costs" means all costs associated with the process of restoring a property that has been disturbed by oil and gas activities to a standard imposed by applicable government or regulatory authorities;

"API" means the American Petroleum Institute;

"API gravity" means the American Petroleum Institute gravity expressed in degrees in relation to liquids, which is a measure of how heavy or light a petroleum liquid is compared to water. If a petroleum liquid's API gravity is greater than 10, it is lighter and floats on water; if less than 10, it is heavier than water and sinks. API gravity is thus a measure of the relative density of a petroleum liquid and the density of water, but it is used to compare the relative densities of petroleum liquids;

"COGE Handbook" means the "Canadian Oil and Gas Evaluation Handbook" maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time;

"conventional natural gas" means natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized structural, depositional or erosional geological features;

"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;

"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;

"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;

"development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;

(b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

(c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

(d) provide improved recovery systems;

"exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively referred to as "geological and geophysical costs");

(b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

(c) dry hole contributions and bottom hole contributions;

(d) costs of drilling and equipping exploratory wells; and

(e) costs of drilling exploratory type stratigraphic test wells;

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"forecast prices and costs" means future prices and costs that are:

(a) generally accepted as being a reasonable outlook of the future; or

(b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in subparagraph (a);

"future net revenue" means a forecast of revenue, estimated using forecast prices and costs, arising from the anticipated development and production of resources, net of the associated royalties, operating costs, development costs, and abandonment and reclamation costs;

"gross" means:

(a) in relation to an entity's interest in production and reserves, its "company gross reserves", which are such entity's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interest of such entity;

(b) in relation to wells, the total number of wells in which an entity has an interest; and

(c) in relation to properties, the total area of properties in which an entity has an interest;

"hydrocarbon" means a compound consisting of hydrogen and carbon, which, when naturally occurring, may also contain other elements such as sulphur;

"light crude oil" means crude oil with a relative density greater than 31.1 degrees API gravity;

"medium crude oil" means crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity;

"natural gas" means a naturally occurring mixture of hydrocarbon gases and other gases;

"natural gas liquids" or “NGLs” means those hydrocarbon components that can be recovered from natural gas as a liquid including, but not limited to, ethane, propane, butanes, pentanes plus, and condensates;

"net" means:

(a) in relation to an entity's interest in production and reserves, such entity's working interest (operating or non-operating) share after deduction of royalty obligations, plus the entity's royalty interests in production or reserves;

(b) in relation to an entity's interest in wells, the number of wells obtained by aggregating an entity's working interest in each of its gross wells; and

(c) in relation to an entity's interest in a property, the total area in which an entity has an interest multiplied by the working interest owned by it;

“NGTL” means TransCanada Pipeline’s natural gas gathering and transportation system in Alberta and northeastern British Columbis.

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

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"property" includes: (a) fee ownership or a lease, concession, agreement, permit, licence or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest; (b) royalty interests, production payments payable in oil or gas, and other non-operating interests in properties operated by others; and (c) an agreement with a foreign government or authority under which a reporting issuer participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer). A property does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas;

"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;

"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;

"reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (a) analysis of drilling, geological, geophysical and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates;

"resource play" refers to drilling programs targeted at regionally distributed crude oil or natural gas accumulations; successful exploitation of these reservoirs is dependent upon technologies such as horizontal drilling and multi-stage fracture stimulation to access large rock volumes in order to produce economic quantities of oil or natural gas;

"Sproule" has the meaning ascribed thereto under the heading "Statement of Reserves Data and Other Oil and Gas Information – Disclosure of Reserves Data";

"Sproule Report" has the meaning ascribed thereto under the heading "Statement of Reserves Data and Other Oil and Gas Information – Disclosure of Reserves Data"; and

"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.

Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this annual information form are in Canadian dollars, except where otherwise indicated.

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ABBREVIATIONS AND OIL AND GAS ADVISORIES

Crude Oil and Natural Gas Liquids		Natural Gas
bbls	barrels	Mcf	thousand cubic feet
Mbbls	thousand barrels	MMcf	million cubic feet
MMbbls	million barrels	bcf	billion cubic feet
NGLs	natural gas liquids	bcf/d	billion cubic feet per day
BOE or boe	means barrel of oil equivalent	Mcf/d	thousand cubic feet per day
MMboe	million barrels of oil equivalent	MMcf/d	million cubic feet per day
boe/d	barrels of oil equivalent per day	Mcfe	thousand cubic feet of natural gas equivalent, using the ratio of 6 Mcf of natural gas being equivalent to one bbl of oil
bbls/d	barrels of oil per day	MMcfe	million cubic feet of natural gas equivalent
		MMcfe/d	million cubic feet of natural gasequivalent per day
		MMbtu	million British Thermal Units
		GJ	Gigajoules
		GJ/d	Gigajoules per day

Other
AECO	Alberta Energy Company's natural gas storage facility located at Suffield, Alberta
GJ/d
MM$	means millions of dollars
WTI	means West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade

The term "boe" or barrels of oil equivalent and "Mcfe" or thousand cubic feet equivalent may be misleading, particularly if used in isolation. A boe or Mcfe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil 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.

This annual information form contains certain oil and gas metrics, including reserve life index, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Corporation's performance; however, such measures are not reliable indicators of the future performance of the Corporation and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon.

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.

CONVERSION

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

To Convert From	To	Multiply By
Mcf	cubic metres		28.317
cubic metres	cubic feet		35.315
Bbls	cubic metres		0.159
cubic metres	bbls		6.289
Feet	metres		0.305
Metres	feet		3.281
Miles	kilometres		1.609
kilometres	miles		0.621
Acres	hectares		0.405
hectares	acres		2.471
gigajoules	MMbtu		0.950
MMbtu	gigajoules		1.0526

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FORWARD-LOOKING STATEMENTS

Certain statements contained in this annual information form constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Advantage believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this annual information form should not be unduly relied upon. These statements speak only as of the date of this annual information form.

In particular, this annual information form contains forward-looking statements pertaining to, but not limited to, the following:

· the performance characteristics of our assets;

· crude oil, natural gas and NGL production levels;

· the size of the crude oil, natural gas and NGL reserves;

· projections of market prices and costs and supply and demand for crude oil, natural gas and NGLs;

· expectations with respect to pipeline capacity in northwest Alberta and western Canada generally;

· expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development;

· the Corporation's proposed capital expenditure program for 2018, including the estimated amount of capital expenditures; and the focus of the Corporation's capital expenditures and operations, including the Corporation's drilling, completion and facility expansion plans and its ability to maintain and increase production to the levels disclosed herein;

· drilling and future development plans for the Corporation's assets, including the anticipated timing thereof and estimated production therefrom and capital expenditures related thereto;

· estimated timing of capital expenditures;

· targeted production at Glacier and the anticipated timing of achievement of such targets;

· timing of development of undeveloped reserves;

· future abandonment and reclamation costs;

· the Corporation's hedging activities;

· tax horizons and treatment under governmental regulatory regimes and tax laws;

· terms of the Credit Facilities, including the effect of revisions or changes in reserve estimates and commodity prices on the borrowing base of the Credit Facilities; and

· capital expenditures programs beyond 2018.

Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward looking statements contained in this annual information form are expressly qualified by this cautionary statement.

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The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this annual information form: risks related to changes in general economic, market and business conditions; continued volatility in market prices for crude oil, NGLs and natural gas; the impact of significant declines in market prices for crude oil, NGLs and natural gas; stock market volatility; changes to legislation and regulations, including environmental regulations, and how they are interpreted and enforced; the Corporation's ability to comply with current and future environmental or other laws; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the crude oil and natural gas industry; the effect of acquisitions; Advantage's success at acquisition, exploitation and development of reserves; unexpected drilling results; failure to achieve production targets on timelines anticipated or at all; the potential for management and reserves evaluators estimates and assumptions to be inaccurate; changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, crude oil and natural gas properties; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; changes or fluctuations in production levels; individual well productivity; delays in anticipated timing of drilling and completion of wells; delays in timing of completion of the Corporation's plant expansion at Glacier; the failure to extend the Credit Facilities at each annual review; competition from other producers for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; the lack of availability of qualified personnel or management; the lack of available capacity on pipelines; ability to access sufficient capital from internal and external sources; credit risk; the other factors discussed under "Risk Factors"; and other factors, many of which are beyond the control of the Corporation. Readers are cautioned that the foregoing list of factors is not exhaustive.

Although the forward-looking statements contained in this annual information form are based upon assumptions which Advantage believes to be reasonable, Advantage cannot assure Shareholders that actual results will be consistent with these forward-looking statements. With respect to forward-looking statements contained in this annual information form, Advantage has made assumptions regarding, but not limited to: that the current commodity price and foreign exchange environment will continue or improve; conditions in general economic and financial markets; current and future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; availability of pipeline capacity; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; royalty rates; future operating costs; that the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Corporation’s conduct and results of operations will be consistent with its expectations; that the Corporation will have the ability to develop the Corporation’s crude oil and natural gas properties in the manner currently contemplated; that current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of the Corporation’s reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; and other matters.

Advantage has included the above summary of assumptions and risks related to forward-looking information provided in this annual information form in order to provide Shareholders with a more complete perspective on the Corporation's current and future operations and such information may not be appropriate for other purposes. The Corporation's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Advantage will derive therefrom.

These forward-looking statements are made as of the date of this annual information form and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

NON-GAAP MEASURES

The Corporation discloses several financial measures in this annual information form that do not have any meaning prescribed under GAAP. These financial measures include “funds from operations” and “cash netbacks”, which should not be considered as alternatives to, or more meaningful than “net income”, “comprehensive income” or “cash provided by operating activities” as determined in accordance with GAAP. Management of the Corporation believes that these measures provide an indication of the results generated by the Corporation’s principal business activities and provide useful supplemental information for analysis of the Corporation’s operating performance and liquidity. Advantage’s method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies.

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Funds from operations, as presented, is based on cash provided by operating activities, before expenditures on decommissioning liability and changes in non-cash working capital, reduced for finance expense excluding accretion. Management of the Corporation believes these adjustments to cash provided by operating activities increase comparability between reporting periods. Cash netbacks are dependent on the determination of funds from operations and include the primary cash sales and expenses on a per mcfe basis that comprise funds from operations.

ADVANTAGE OIL & GAS LTD.

General

The Corporation was formed pursuant to the amalgamation of Advantage Oil & Gas Ltd., 1335703 Alberta Ltd., SET Resources Inc. and Sound Exchange Co Ltd. under the ABCA on September 5, 2007. On July 9, 2009 the articles of the Corporation were amended to change the number of issued and outstanding Common Shares to equal the number of trust units of Advantage Energy Income Fund (the "Trust") outstanding immediately prior to the plan of arrangement pursuant to Section 193 of the ABCA, which closed on July 9, 2009 and pursuant to which, among other things, the Trust was dissolved and the Corporation became the resulting entity.

The Corporation is a reporting issuer in each of the provinces of Canada and the Common Shares are listed on the TSX and NYSE under the symbol "AAV".

The head office of Advantage is located at Suite 300, 440 – 2^nd Avenue S.W., Calgary, Alberta T2P 5E9 and its registered office is located at 2400, 525 – 8^th Avenue S.W., Calgary, Alberta T2P 1G1.

Corporate Structure

As at December 31, 2017, the Corporation did not have any material direct or indirect subsidiaries, as the total assets and revenues of the Corporation's subsidiaries, on a combined basis, does not exceed 10% of the consolidated assets and the consolidated revenues, respectively, of the Corporation.

GENERAL DEVELOPMENT OF THE BUSINESS

General

The Corporation is engaged in the business of natural gas exploitation, development, acquisition and production in the Province of Alberta. The Corporation is focused on development and growth of its extensive Montney natural gas play at Glacier, Alberta. See "Description of our Business and Operations" below.

From 2012 to 2014, Advantage executed on a number of significant transactions with the objective of positioning the Corporation to successfully deliver on its new long-term development plan. Advantage’s transformation included the disposition of non-core assets, simplifying the business to focus on its extensive Glacier Montney natural gas asset, strengthening the balance sheet through utilization of net proceeds from dispositions reducing indebtedness, and realigning the Board, management and staff to achieve the Corporation's development plan.

A detailed description of the historical development of the business of the Corporation for the years ended December 31, 2015, 2016 and 2017 is outlined below. Unless the context otherwise requires, references to "we", "us", "our" or similar terms refer to the Corporation.

Three Year History

2015

2015 Development Plan

On February 17, 2015, Advantage announced that the Board had approved a $110 million reduction in the Corporation’s 2015 capital program and a $150 million reduced capital program for the entire 2015 to 2017 development period. The Corporation also announced that despite the $110 million capital reduction, it still expected to achieve 12 months production growth of 36% from 135 MMcfe/d to 183 MMcfe/d in July 2015. As a result of improved capital efficiencies from slick water completed wells with higher initial production rates and lower declines, fewer wells were required to achieve targeted production than were originally scheduled for the 2015 through 2017 period.

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On August 6, 2015, Advantage announced that it reached the next level of production growth to 183 MMcfe/d on July 20, 2015 with the expansion of its Glacier gas plant and a large inventory of Montney wells that continued to outperform expectations.

Appointment of Director

On May 27, 2015, Ms. Jill T. Angevine was appointed as a director of the Corporation.

Credit Facilities

On May 7, 2015, Advantage announced that its lenders completed their annual review and the borrowing base under its Credit Facilities had been increased to $450 million.

2016 Development Plan

On December 16, 2015, Advantage announced that, based on the assumption of an average AECO $2.50/Mcf natural gas price for 2016 and Advantage's current hedge positions, its Board of Directors had approved a 2016 capital budget of $120 million. As at December 31, 2015, Advantage's standing well inventory consisted of 37 total standing wells of which 23 were completed and 14 remained uncompleted, which management believed would provide sufficient productive capacity to attain the Corporation's estimated average annual production target for the year ended December 31, 2016 of 190 to 210 MMcfe/d.

2016

Glacier Gas Plant

The Glacier gas plant expansion completed in 2015 increased processing capacity to 250 MMcf/d and provided 70 MMcf/d of additional capacity to meet future growth in 2016 and 2017. The Glacier gas plant is capable of processing varying amounts of dry and liquids rich gas providing discretion to vary the number of producing dry or liquids-rich gas wells in order to optimize investment returns and cash netbacks. In 2016, Advantage began another significant expansion of the Glacier gas plant to increase processing capacity by 150 MMcf/d to a total of 400 MMcf/d.

The Offering

On March 8, 2016, Advantage completed the Offering, pursuant to which 13,427,075 Common Shares were issued at a price of $7.45 per Common Share for gross proceeds of $100,031,709, which included the issuance of 1,677,075 Common Shares pursuant to the partial exercise of the over-allotment option granted to the underwriters.

Credit Facilities

During the second quarter of 2016, Advantage renewed the borrowing base under its Credit Facilities at $400 million. Advantage requested a reduction from the prior $450 million borrowing base due to its strong balance sheet and estimated capital requirements for future growth.

2017 Capital Budget and Development Plan

On November 28, 2016, Advantage announced that, based on the assumption of an average AECO $2.95/Mcf natural gas price for 2017 and Advantage's current hedge positions, its Board of Directors had approved a 2017 capital budget of $195 to $215 million to increase production to 230 to 240 MMcfe/d. Advantage's average annual production for the year ended December 31, 2016 was 203 MMcfe/d. Advantage also announced the Corporation's 2017 through 2019 development plan, which is targeted to increase annual production to 316 MMcfe/d in 2019, with total capital expenditures over the development plan period estimated at $625 million, including the drilling of 83 Montney wells.

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2017

2018 Capital Budget and Development Plan

On December 11, 2017, Advantage announced that its Board of Directors had approved a 2018 capital budget of $175 million funded through cash flow to increase production to 260 MMcfe/d. The 2018 capital budget contemplates the completion of the Glacier gas plant expansion by the second quarter of 2018, completion and equipping of standing wells drilled during 2017, a 2018 drilling program and $30 million for the advancement of delineation and development in the Valhalla, Wembley and Progress areas, including initial facility installation at Valhalla to transport additional higher liquids production for processing at Glacier.

Glacier Gas Plant

Construction on the Glacier gas plant expansion began in the second half of 2017. On December 11, 2017, Advantage announced planned capital investment at Glacier in 2018 of $145 million, including $35 million to complete the expansion of its Glacier gas plant. Completion of the Glacier gas plant expansion is anticipated by the second quarter of 2018 and will increase raw gas processing capacity from 250 mmcf/d to 400 mmcf/d with propane plus (C3+) liquids handling capacity increased to 6,800 bbls/d.

Credit Facilities

On October 20, 2017, the semi-annual redetermination of Advantage’s credit facilities (the “Credit Facilities”) was completed with no changes to the borrowing base of $400 million, comprised of a $20 million extendible revolving operating loan facility from one financial institution and a $380 million extendible revolving loan facility from a syndicate of financial institutions.

TransCanada Pipelines (“TCPL”)

In 2017, Advantage participated in TCPL’s long term, fixed price service open season whereby industry committed to transporting approximately 1.5 bcf/d from Empress, Alberta to the Dawn market in Southern Ontario. Advantage’s commitment to this firm transportation service was 55,600 GJ/d (52,700 mcf/d) that began November 1, 2017 and represents approximately 20% of our current production.

Doig/Montney Land Acquisitions

In 2017, Advantage acquired 37 additional sections of Doig/Montney rights in the Valhalla, Wembley and Progress areas proximal to our existing land holdings. Subsequent to year end Advantage acquired an additional 11 sections. Advantage now holds a total of 200 net sections (128,000 net acres) of Doig/Montney rights with 110 of those sections being in the Valhalla/Progress/Wembley areas that have potential for liquids-rich and multi-layer development and the remaining 90 sections at Glacier which has multi-layer liquids-rich development in the middle Montney.

Recent Developments

NGTL Transportation

As of February 2018, the Corporation has secured increasing levels of firm natural gas transportation service on TCPL’s NGTL system of up to 363 mmcf/d through 2020 and retains the ability to reduce our total commitments through existing evergreen contracts. This provides Advantage with the option to consider additional physical market diversification, in addition to our Dawn exposure, while managing our cumulative long term transportation exposure. The Corporations’ philosophy is to carry sufficient firm transportation contracts to meet approximately 100% of our budgeted sales gas volumes.

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Anticipated Changes in the Business

As at the date hereof and other than as disclosed herein, the Corporation does not anticipate that any material change in our business will occur during the balance of the 2018 financial year.

Significant Acquisitions

The Corporation did not complete any acquisitions during the year ended December 31, 2017 for which disclosure is required under Part 8 of National Instrument of 51-102 - Continuous Disclosure Obligations.

As part of its ongoing business, the Corporation evaluates potential acquisitions of all types of petroleum and natural gas assets. The Corporation is normally in the process of evaluating various potential acquisitions at any one time which individually or together could be material. As of the date hereof, the Corporation has not reached agreement on the price or terms of any potential material acquisitions. The Corporation cannot predict whether any current or future opportunities will result in one or more acquisitions for the Corporation.

DESCRIPTION OF OUR BUSINESS AND OPERATIONS

General

Advantage is engaged in the business of natural gas exploitation, development, acquisition and production in the Province of Alberta.

Advantage's exploitation and development program is focused at Glacier, Alberta where it is developing a significant natural gas resource play. As current and future practice, Advantage has established a financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivatives. See "Risk Factors". Although Advantage has a significant capital development program, it also actively evaluates growth opportunities through crude oil and natural gas asset acquisitions, as well as through corporate acquisitions. Advantage targets acquisitions that support and augment its Montney development and long term strategy. It is currently intended that Advantage will finance any acquisitions and investments through the Credit Facilities, the issuance of additional Common Shares from treasury, or accessing long term debt instruments to maintain prudent leverage.

Reorganizations

As at the date hereof, except as disclosed herein, there have been no material reorganizations of Advantage and or any of its subsidiaries within the three most recently completed financial years and there are currently no material reorganizations of Advantage proposed for the current financial year. See "General Development of the Business".

Bankruptcy and Similar Procedures

There have been no bankruptcy, receivership or similar proceedings against the Corporation or any of its subsidiaries or related entities, or any voluntary bankruptcy, receivership or similar proceeding by the Corporation or any of its subsidiaries or related entities since the inception of the Corporation or during or proposed for the current financial year.

Specialized Skill and Knowledge

Advantage employs individuals with various professional skills in the course of pursuing its business plan. These professional skills include, but are not limited to, geology, geophysics, engineering, financial and business skills, which are widely available in the industry. Drawing on significant experience in the oil and gas business, Advantage believes its management team has a demonstrated track record of bringing together all of the key components to a successful exploration and production company: strong technical skills; expertise in planning and financial controls; ability to execute on business development opportunities; capital markets expertise; and an entrepreneurial spirit that allows Advantage to effectively identify, evaluate and execute on its business plan.

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Human Resources

As at December 31, 2017, the Corporation employed 29 full-time employees, 27 of which are located in the head office and 2 of which are located in the field. The Corporation also retained 7 consultants in the head office.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Disclosure of Reserves Data

The reserves data set forth below is based upon an evaluation by Sproule Associates Limited ("Sproule") with an effective date of December 31, 2017 contained in a report of Sproule dated February 7, 2018 (the "Sproule Report"). The Sproule Report evaluated, as at December 31, 2017, the crude oil, NGLs and conventional natural gas reserves of Advantage. The reserves data summarizes Advantage's crude oil, NGLs and conventional natural gas reserves and the net present values of future net revenue for these reserves using forecast prices and costs. All of the Corporation's reserves are in Canada and, specifically, in the Province of Alberta. The Sproule Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101 and the COGE Handbook. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which the Corporation believes is important to readers of this annual information form. Sproule was engaged to provide evaluations of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

The report of management and directors on oil and gas disclosure in Form 51-101F3 and the report on reserves data by Sproule in Form 51-101F2 are attached as Schedules "A" and "B" to this annual information form, respectively, which forms are incorporated herein by reference.

There are numerous uncertainties inherent in estimating quantities of crude oil, NGLs and conventional natural gas reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable crude oil, NGLs and conventional natural gas reserves and the future net cash flows therefrom 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, 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 crude oil, NGL and conventional 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 thereof and such variations could be material.

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 our crude oil, NGLs and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGLs and conventional natural gas reserves may be greater than or less than the estimates provided herein.

The information relating to the Corporation's consolidated crude oil, NGLs and conventional natural gas reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costs related thereto, forecast operating costs, anticipated production and abandonment costs. See "Forward-Looking Statements", "Industry Conditions" and "Risk Factors – Reserves Estimates".

12

In certain of the tables set forth below, the columns may not add due to rounding.

Summary of Oil and Gas Reserves as at December 31, 2017 – Forecast Prices and Costs

	RESERVES
	LIGHT CRUDE OIL AND MEDIUM CRUDE OIL				CONVENTIONAL NATURAL GAS
RESERVES CATEGORY	Gross (Mbbl)		Net (Mbbl)		Gross (MMcf)		Net (MMcf)
PROVED
Developed Producing		4.4		4.3		455,806		415,871
Developed Non-Producing		-		-		45,049		41,095
Undeveloped		-		-		1,197,147		1,078,128
TOTAL PROVED		4.4		4.3		1,698,002		1,535,094
PROBABLE		1.2		1.1		594,271		515,050
TOTAL PROVED PLUS PROBABLE		5.6		5.5		2,292,273		2,050,144

	RESERVES
	NATURAL GAS LIQUIDS				TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (Mbbl)		Net (Mbbl)		Gross (Mboe)		Net (Mboe)
PROVED
Developed Producing		4,481.9		3,654.2		80,454.0		72,970.3
Developed Non-Producing		1,017.7		829.7		8,525.9		7,678.9
Undeveloped		17,557.2		14,109.9		217,081.7		193,797.9
TOTAL PROVED		23,056.8		18,593.8		306,061.6		274,447.2
PROBABLE		8,711.1		6,433.5		107,757.3		92,276.3
TOTAL PROVED PLUS PROBABLE		31,767.9		25,027.2		413,818.9		366,723.4

Summary of Net Present Values of Future Net Revenue of Oil and Gas Reserves as at December 31, 2017 – Forecast Prices and Costs^(1)(2)(3)

	Before Income Tax Discounted at (%/year) (2)										After Income Taxes Discounted at (%/year)(2)(5)										Unit Value Before Income Tax Discounted at 10%/ year(4)
RESERVES CATEGORY	0% ($000's)		5% ($000's)		10% ($000's)		15% ($000's)		20% ($000's)		0% ($000's)		5% ($000's)		10% ($000's)		15% ($000's)		20% ($000's)		($/boe)
PROVED
Developed Producing		1,291,370		1,027,278		835,646		705,904		613,906		1,243,902		1,006,858		826,242		701,323		611,568		11.45
Developed Non-Producing		172,031		118,755		91,582		75,218		64,255		126,940		94,427		77,713		66,980		59,201		11.93
Undeveloped		3,110,192		1,563,430		842,153		464,582		248,778		2,261,474		1,113,751		575,117		293,239		132,688		4.35
TOTAL PROVED		4,573,594		2,709,463		1,769,381		1,245,703		926,938		3,632,316		2,215,036		1,479,071		1,061,543		803,458		6.45
PROBABLE		2,297,267		1,237,088		780,609		543,675		403,957		1,679,360		905,167		573,246		401,779		301,063		8.46
TOTAL PROVED PLUS PROBABLE		6,870,860		3,946,551		2,549,991		1,789,379		1,330,895		5,311,676		3,120,203		2,052,317		1,463,322		1,104,521		6.95

13

Notes:

(1) Advantage's light crude oil and medium crude oil, conventional natural gas and NGL reserves were evaluated using Sproule's product price forecast effective December 31, 2017 prior to interests, debt service charges and general and administrative expenses. It should not be assumed that the future net revenue estimated by Sproule represents the fair market value of the reserves.

(2) Assumes that development of Glacier will occur, without regard to the likely availability to the Corporation of funding required for that development.

(3) Future net revenue incorporates management's estimates of required abandonment and reclamation costs, including expected timing such costs will be incurred, associated with all wells (including undrilled wells that have been attributed reserves), facilities and infrastructure. No abandonment and reclamation costs have been excluded.

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

(5) Values are calculated by considering existing tax pools for Advantage in the evaluation of Advantage's oil and gas properties, and take into account current federal tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see Advantage's Consolidated Financial Statements and Management's Discussion and Analysis for the year ended December 31, 2017.

Total Future Net Revenue (Undiscounted) as at December 31, 2017 – Forecast Prices and Costs⁽¹⁾⁽²⁾

RESERVES CATEGORY	REVENUE ($000's)		ROYALTIES ($000's)		OPERATING COSTS ($000's)		DEVELOP- MENT COSTS ($000's)		ABANDONMENT AND RECLAMATION COSTS(3) ($000's)		FUTURE NET REVENUE BEFORE INCOME TAXES ($000's)		FUTURE INCOME TAXES ($000's)		FUTURE NET REVENUE AFTER INCOME TAXES (4) ($000's)
Proved Reserves		9,230,942		1,047,531		1,926,627		1,520,675		162,515		4,573,594		941,278		3,632,316
Proved Plus Probable Reserves		12,852,334		1,611,591		2,539,212		1,657,081		173,590		6,870,860		1,559,185		5,311,676

Notes:

(1) Advantage's light crude oil and medium crude oil, conventional natural gas and NGL reserves were evaluated using Sproule's product price forecast effective December 31, 2017 prior to interests, debt service charges and general and administrative expenses. It should not be assumed that the future net revenue estimated by Sproule represents the fair market value of the reserves.

(2) Assumes that development of Glacier will occur, without regard to the likely availability to the Corporation of funding required for that development.

(3) Future net revenue incorporates management's estimates of required abandonment and reclamation costs, including expected timing such costs will be incurred, associated with all wells (including undrilled wells that have been attributed reserves), facilities and infrastructure. No abandonment and reclamation costs have been excluded.

(4) Values are calculated by considering existing tax pools for Advantage in the evaluation of Advantage's oil and gas properties, and take into account current federal tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see Advantage's Consolidated Financial Statements and Management's Discussion and Analysis for the year ended December 31, 2017.

14

Future Net Revenue by Product Type as at December 31, 2017 – Forecast Prices and Costs

	Net Present Value of Future Net Revenue (before deducting Future Income Tax Expenses and  Discounted at 10%/year) ($000’s)		Unit Value (before deducting Future Income Tax Expenses and  Discounted at 10%/year) ($/Mcf)(3)
Proved reserves
Light Crude Oil and Medium Crude Oil(1)		173		13.91
Natural Gas Liquids		-		-
Conventional Natural Gas(2)		1,769,208		6.45
Total Proved		1,769,381
Proved plus Probable reserves
Light Crude Oil and Medium Crude Oil(1)		214		13.46
Natural Gas Liquids		-		-
Conventional Natural Gas(2)		2,549,777		6.95
Total Proved Plus Probable reserves		2,549,991

Notes:

(1) Including solution gas and other by-products.

(2) Including by-products, but excluding solution gas and by-products from oil wells.

(3) Unit values are based on net reserve volumes.

Pricing Assumptions

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 us by our independent reserves evaluator, Sproule, and were Sproule's then current forecasts at the date of the Sproule Report.

Summary of Pricing and Inflation Rate Assumptions as at December 31, 2017 – Forecast Prices and Costs

Year	Western Canada Select 20.5o API ($Cdn/bbl)		Canadian  Light  Sweet  Crude Oil 40o API ($Cdn/ bbl)		NATURAL GAS AECO-C Spot ($Cdn/ MMBtu)		NATURAL GAS LIQUIDS Edmonton  Pentanes  Plus ($Cdn/bbl)		NATURAL  GAS  LIQUIDS Edmonton Butanes ($Cdn/bbl)		OPERATING COST INFLATION RATE %/Year		CAPITAL COST INFLATION RATE %/Year		EXCHANGE RATE (2) ($US/$Cdn)
2018		51.05		65.44		2.85		67.72		48.73		0.0		0.0		0.790
2019		59.61		74.51		3.11		75.61		55.49		2.0		2.0		0.820
2020		64.94		78.24		3.65		78.82		57.65		2.0		2.0		0.850
2021		68.43		82.45		3.80		82.35		60.12		2.0		2.0		0.850
2022		69.80		84.10		3.95		84.07		61.32		2.0		2.0		0.850
2023		71.20		85.78		4.05		85.82		62.55		2.0		2.0		0.850
2024		72.62		87.49		4.15		87.61		63.80		2.0		2.0		0.850
2025		74.07		89.24		4.25		89.43		65.07		2.0		2.0		0.850
2026		75.55		91.03		4.36		91.29		66.37		2.0		2.0		0.850
2027		77.06		92.85		4.46		93.19		67.70		2.0		2.0		0.850
2028		78.61		94.71		4.57		95.12		69.06		2.0		2.0		0.850
Thereafter										Escalation rate of 2% thereafter

Notes:

(1) This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.

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

Weighted average historical prices, including hedging, realized by the Corporation for the year ended December 31, 2017, were $2.82/Mcf for conventional natural gas, $62.73/bbl for crude oil, and $49.04/bbl for NGLs.

15

Reconciliations of Changes in Reserves

The following table sets forth a reconciliation of the Corporation's total gross proved, total gross probable and total gross proved plus probable reserves as at December 31, 2017 against such reserves as at December 31, 2016 based on forecast prices and cost assumptions.

	Light Crude Oil and Medium Crude Oil									Natural Gas Liquids
FACTORS	Proved (Mbbl)			Probable (Mbbl)			Proved Plus Probable (Mbbl)			Proved (Mbbl)			Probable (Mbbl)			Proved Plus Probable (Mbbl)
December 31, 2016		8.4			2.7			11.1			15,523.7			8,005.1			23,528.8
Extensions		-			-			-			1,274.3			713.2			1,987.5
Improved Recovery		-			-			-			-			-			-
Infill Drilling		-			-			-			5,618.5			1,912.6			7,531.1
Technical Revisions (1)		(7.8	)		(2.7	)		(10.5	)		1,075.9			(1,918.8	)		(842.9	)
Discoveries		-			-			-			-			-			-
Acquisitions		4.5			1.2			5.7			2.0			0.4			2.4
Dispositions		-			-			-			-			-			-
Economic Factors		-			-			-			6.4			(1.4	)		5.0
Production		(0.7	)		-			(0.7	)		(444.0	)		-			(444.0	)
December 31, 2017		4.4			1.2			5.6			23,056.8			8,711.1			31,767.9

	Conventional Natural Gas									Oil Equivalent
FACTORS	Proved (MMcf)			Probable (MMcf)			Proved Plus Probable (MMcf)			Proved (MBoe)			Probable (MBoe)			Proved Plus Probable (MBoe)
December 31, 2016		1,437,149			618,249			2,055,398			255,056.9			111,049.3			366,106.2
Extensions		30,677			20,843			51,520			6,387.1			4,187.0			10,574.2
Improved Recovery		-			-			-			-			-			-
Infill Drilling		165,289			51,220			216,509			33,166.7			10,449.3			43,615.9
Technical Revisions (1)		148,498			(95,886	)		52,612			25,817.8			(17,902.5	)		7,915.3
Discoveries		-			-			-			-			-			-
Acquisitions		43			12			55			13.7			3.6			17.3
Dispositions		-			-			-			-			-			-
Economic Factors		(222	)		(167	)		(389	)		(30.6	)		(29.2	)		(59.8	)
Production		(83,432	)		-			(83,432	)		(14.350.0	)		-			(14,350.0	)
December 31, 2017		1,698,002			594,271			2,292,273			306,061.6			107,757.3			413,818.9

Notes:

(1) Technical revisions accounted for 40% of the total proved reserve additions and 13% of the total proved plus probable reserve additions. Percentage of each category calculated by dividing the technical revisions in the category by the total reserve additions in the same category before production.

16

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped reserves are attributed by Sproule in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Proved and probable undeveloped reserves have been assigned in accordance with engineering and geological practices as defined under NI 51-101.

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

The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by product type, first attributed to us in each of the following financial years.

Proved Undeveloped Reserves

	Light Crude Oil and Medium Crude Oil (Mbbl)				Conventional Natural Gas (MMcf)				NGLs (Mbbl)
Year	First Attributed		Cumulative  at Year End		First Attributed		Cumulative  at Year End		First Attributed		Cumulative  at Year End
2015		-		-		86,336		876,137		2,060.6		8,694.7
2016		-		-		142,211		1,027,433		3,166.1		11,281.4
2017		-		-		195,966		1,197,147		6,892.8		17,557.2

Sproule has assigned 217.1 MMboe of gross proved undeveloped reserves in the Sproule Report under forecast prices and costs, together with $1.5 billion of associated undiscounted future capital expenditures. Proved undeveloped capital spending in the first two forecast years of the Sproule Report accounts for $431.6 million, or 28%, of the total forecast. These figures increase to $1.0 billion or 68%, during the first five years of the Sproule Report.

For proved undeveloped reserves Sproule assigns reserves based on a 90% probability that the estimated reserves will be recovered. Advantage’s expectation is to develop the reserves in a similar timeframe as forecasted by Sproule, which approximates drilling over the next 10 years.

Probable Undeveloped Reserves

	Light Crude Oil and Medium Crude Oil (Mbbl)				Conventional Natural Gas (MMcf)				NGLs (Mbbl)
Year	First Attributed		Cumulative  at Year End		First Attributed		Cumulative  at Year End		First Attributed		Cumulative  at Year End
2015		-		-		60,502		497,612		1,252.5		6,658.5
2016		-		-		32,473		481,140		800.1		6,371.5
2017		-		-		72,063		444,717		2,625.8		6,972.9

17

Sproule has assigned 81.1 MMboe of gross probable undeveloped reserves in the Sproule Report under forecast prices and costs, together with $136.0 million of associated undiscounted future capital expenditures. Probable undeveloped capital spending in the first two forecast years of the Sproule Report accounts for $21.9 million, or 16%, of the total forecast. These figures increase to $99.5 million or 73%, during the first five years of the Sproule Report.

For proved plus probable reserves Sproule assigns reserves based on a 50% probability that at least the sum of the estimated proved reserves plus probable reserves will be recovered. Advantage’s expectation is to develop the reserves in a similar timeframe as forecasted by Sproule, which approximates drilling over the next 10 years.

Significant Factors or Uncertainties

General

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on production forecasts, prices and economic conditions. The Corporation's reserves are evaluated by Sproule.

As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, commodity prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.

Abandonment and Reclamation Costs

Abandonment and reclamation costs are based on management’s estimate of costs to abandon, remediate and reclaim all of its surface leases, wells (including undrilled wells that have been attributed reserves), facilities, and pipelines based on its working interest, the current regulatory standards, actual abandonment cost history, estimated timing of such expenditures and excludes salvage values. These costs relate to wells and facilities in properties that may or may not have reserves attributed to them. Abandonment and reclamation costs include the Corporation’s existing crude oil and natural gas activities and costs associated with future development activities including all development drilling, and dedicated gathering and processing facility expansions or builds, required to enable production of the forecast development in Sproule's report. All existing and future abandonment and reclamation costs are reflected in Sproule's estimate of future net revenue.

The approximate net cost to abandon and reclaim all wells and facilities, discounted at 10%, totals $14.5 million ($173.6 million undiscounted and inflated at 2.0% per annum), all of which are included in the estimate of future net revenue. Management has estimated the net cost to abandon and reclaim all existing wells and facilities totalling $49.9 million undiscounted and uninflated and Sproule has estimated the cost to abandon and reclaim all future facilities and undrilled wells that have been attributed reserves. Undiscounted abandonment and reclamation costs expected to be paid over the next three years aggregate $5.2 million with the majority of these costs expected to be incurred between 2041 to 2077.

18

Future Development Costs

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

	Forecast Prices and Costs
Year	Proved Reserves ($millions)		Proved Plus Probable Reserves ($millions)
2018		177.2		183.2
2019		256.3		272.3
2020		259.4		285.7
2021		183.0		183.0
2022		152.1		203.8
Total: Undiscounted for all years		1,520.7		1,657.1

To fund Advantage's capital program, including future development costs, the Corporation has many financing alternatives available, including partial retention of funds from operations, bank debt financing, issuance of additional Common Shares, and issuance of convertible debentures and other financial instruments. Advantage evaluates the appropriate financing alternatives closely and has made use of all these options dependent on the given investment situation and the capital markets. The Corporation maintains a capital structure that is intended to maximize the investment return to Shareholders as compared to the cost of financing. Advantage expects to continue using all financing alternatives available to continue pursuing its development strategy. The assorted financing instruments have certain inherent costs which are considered in the economic evaluation of pursuing any development opportunity.

There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the Sproule Report. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to reserves.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates set forth above and would reduce the reserves and future net revenue to some degree depending upon the funding sources utilized. The Corporation does not anticipate that interest or other funding costs would make further development of any of the Corporation's assets uneconomic.

Other Oil and Gas Information

Advantage is a natural gas, pure play, growth-oriented Corporation with a significant position in the Montney resource play at Glacier, Alberta. The Corporation operates 100% of its Glacier assets, which allows the Corporation to control the nature and timing of the capital investments necessary to maximize the potential in developing this asset.

Property Descriptions

The following property descriptions are as of December 31, 2017 unless otherwise noted and reserves quoted are as reported in the Sproule Report.

19

Glacier Area, Alberta (Glacier/Valhalla/Wembley/Progress)

The Glacier/Valhalla/Wembley/Progress properties lie along the Alberta side of the border with British Columbia between Grande Prairie, Alberta and Dawson Creek, British Columbia. The primary zones of interest are within the Triassic Montney and Doig formation siltstones. Advantage now holds a total of 200 net sections (128,000 net acres) of Doig/Montney rights with 110 of those sections being in the Valhalla/Progress/Wembley areas that have potential for liquids-rich, multi-layer development and each of these three areas having at least 30 contiguous sections that can support scalable development. At Valhalla, Wembley and Progress ongoing industry drilling and production activity has demonstrated encouraging initial results with attractive liquid yields and gas rates. Industry drilling adjacent to our lands have targeted multiple Montney layers with results demonstrating liquids-rich gas accumulations in all layers to date. The remaining 90 net sections are held at Glacier where the total thickness of the Lower Doig/Montney is up to 300 metres and lends itself to multiple layers of development which contributes to the significant inventory of undrilled wells within this resource play. During 2017, Advantage continued with our program to delineate the Glacier land block vertically by drilling and testing wells in intervals other than the historically drilled Doig and Lower Montney. To date, a total of 28 horizontal wells and 3 vertical recompletions have tested and produced in intervals other than the Lower Doig or Lower Montney, with an additional 11 wells either cased or in various stages of completion and progressing towards being placed on production. This development has resulted in significant delineation and de-risking of the liquid rich Middle Montney resource potential at Glacier.

Based on current reserves assignments as of December 31, 2017, these properties have a combined proved plus probable reserve life index ("RLI") of 28 years at a production rate of 245 MMcfe/d, which was the average production rate achieved at the Glacier Area during the fourth quarter of 2017. RLI is calculated by dividing the total volume of proved plus probable reserves of 2.5 Tcfe as provided in the Sproule Report by the fourth quarter production rate and express in years.

Since the spud of the first horizontal well on July 26, 2008 to the end of December 2017, Advantage has drilled and completed 185 net horizontal wells on our properties in either the Triassic Montney or Doig formation siltstones. In addition, two vertical wells drilled into the underlying Belloy Formation are used for acid gas disposal and two vertical and one horizontal well are used as service wells that support our water disposal system.

As at March 5, 2018, production is approximately 245 MMcfe/d or 40,800 boe/d with our Valhalla property producing approximately 5 MMcfe/d and Glacier producing 240 MMcfe/d. Advantage’s Upper, Middle and Lower Montney wells are continuing to demonstrate strong production performance.

Throughout 2017 Advantage drilled 33.4 net Montney horizontal wells across all our properties which included delineation drilling on our undeveloped land holdings at Valhalla, Wembley and Progress. During the year ended December 31, 2017, Advantage drilled 28.0, 3.4, 1.0 and 1.0 net wells at Glacier, Valhalla, Wembley and Progress respectively. At Glacier, Advantage drilled 28 net wells focusing our drilling on multi-well pads with our smallest pad drilled during the year being 8 wells.

Advantage’s current standing well inventory consists of 31 total wells of which 8 wells are tied-in waiting to be produced, 10 wells are in various stages of completion, and 13 wells are cased waiting to be completed. These wells are estimated to provide sufficient productive capacity to attain our 2018 annual production target.

Advantage owns and operates a 100% working interest gas plant located at 05-02-76-12W6. The plant currently has throughput capacity of 260 MMcf/d of raw gas. A major expansion of the Glacier plant was announced in 2016 to increase the capacity from the current licenced level of 260 MMcf/d to 400 MMcf/d including the expansion of hydrocarbon liquid processing capacity to 6,800 bbls/d. Construction of the expansion has significantly progressed and all major equipment is in place with the majority of the mechanical and electrical work completed. Commissioning of the new equipment along with a shut down for final tie-in of the new equipment will occur in April 2018. Advantage’s strategy of owning and operating our own infrastructure has helped us achieve an industry leading low cost structure.

Gas is sold through Advantage’s sales pipeline system into the TransCanada Pipelines Limited Alberta system. In Q4 of 2018 Advantage will also be connected to the Alliance pipeline system via the installation of a new meter station. The operating cost structure of the Corporation is very favorable with combined field and plant operating costs averaging $0.25/Mcfe in 2017.

20

Oil and Gas Wells

The following table sets forth the number and status of wells as at December 31, 2017 in which the Corporation has a working interest.

Oil Wells

Natural Gas Wells

Producing

Non-Producing

Producing

Non-Producing

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Alberta, Canada

-

-

-

-

182

172

53

49

Notes:

(1) "Gross" wells means the number of wells in which the Corporation has a working interest.

(2) "Net" wells means the aggregate number of wells obtained by multiplying each gross well by the Corporation's percentage working interest therein.

(3) Non-producing includes wellbores shut-in for economic reasons, wellbores not capable of production and wellbores used for disposal of water.

Properties with no Attributed Reserves

The following table sets out our unproved properties as at December 31, 2017.

	Gross Acres		Net Acres
Alberta, Canada		71,040		71,040

We expect that rights to explore, develop and exploit 5 sections (3,200 net acres) of our undeveloped land holdings will expire by December 31, 2018. The land expirations do not consider our 2018 exploitation and development program that may result in extending or eliminating such potential expirations. We closely monitor land expirations as compared to our development program with the strategy of minimizing undeveloped land expirations relating to significant identified opportunities. Development of the Corporation's properties with no attributed reserves are subject to current industry conditions and uncertainties as indicated under "Risk Factors" herein.

Forward Contracts

Our financial results and condition will be dependent on the prices received for natural gas production. Natural gas prices have fluctuated widely and are determined by supply and demand factors, including weather, and general economic conditions in natural gas consuming and producing regions throughout North America. Any upward or downward movement in crude oil, NGL and natural gas prices could have an effect on our financial condition and capital development.

Advantage has an approved hedging policy that utilizes, amongst others, costless collars, options and fixed price swaps to hedge up to 75% of its gross crude oil, NGLs and natural gas production for a period of three years and 50% over the fourth and fifth years. In addition, Advantage is able to enter into basis swap arrangements to any natural gas price point in North America for up to 100,000 MMbtu/day with a maximum term of seven years. Basis swap arrangements do not count against the limitations on hedged production. These hedging activities could expose the Corporation to losses or gains. To the extent that the Corporation engages in risk management activities related to commodity prices, it will be subject to credit risk associated with the parties with which it contracts. This credit risk will be mitigated by entering into contracts with only stable and creditworthy parties and through the frequent review of the Corporation's exposure to these entities. See "Risk Factors".

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Advantage has the following derivatives in place:

Description of Derivative	Term	Volume	Price
Natural gas – AECO
Fixed price swap	April 2017 to March 2018	4,739 mcf/d	Cdn $3.27/mcf
Fixed price swap	April 2017 to March 2018	14,217 mcf/d	Cdn $3.27/mcf
Fixed price swap	November 2017 to March 2018	18,956 mcf/d	Cdn $3.22/mcf
Fixed price swap	July 2017 to March 2018	4,739 mcf/d	Cdn $3.02/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.01/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	July 2017 to June 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	April 2017 to March 2018	23,695 mcf/d	Cdn $3.01/mcf
Call option sold	April 2017 to December 2018	23,695 mcf/d	Cdn $3.17/mcf (1)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.01/mcf (2)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.06/mcf (3)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.11/mcf (4)
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	9,478 mcf/d	Cdn $3.00/mcf

⁽¹⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

⁽²⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.32/mcf.

⁽³⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.38/mcf.

⁽⁴⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2018 to December 2019	25,000 mcf/d	Henry Hub less US $0.95/mcf
Basis swap	January 2019 to December 2019	25,000 mcf/d	Henry Hub less US $0.90/mcf

Natural gas – Dawn

Fixed price swap December 2017 to March 2018   10,000 mcf/d US $3.45/mcf

Subsequent to December 31, 2017, the Corporation entered into the following derivative contracts:

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2021 to December 2024	5,000 mcf/d	Henry Hub less US $1.135/mcf
Basis swap	January 2021 to December 2024	2,500 mcf/d	Henry Hub less US $1.185/mcf
Basis swap	January 2021 to December 2024	17,500 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2020	5,000 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2024	15,000 mcf/d	Henry Hub less US $1.20/mcf

Tax Horizon

In 2017, we did not pay any income related taxes and it is expected, based on current legislation that no cash income taxes are to be paid by Advantage prior to 2021. See "Risk Factors".

Capital Expenditures

The following tables summarize capital expenditures (including capitalized general and administrative expenses) related to our activities for the year ended December 31, 2017:

Capital Expenditures ($ thousands)	2017
Drilling, completions and workovers		143,797
Well equipping and facilities		97,652
Other		118
Expenditures on property, plant and equipment		241,567
Property Acquisition – Proved Properties		-
Property Acquisition – Unproved Properties		7,207
Property dispositions		-
Exploration costs		-
Development costs		-
Total capital expenditures		248,774

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Exploration and Development Activities

The following table sets forth the gross and net wells in which we participated during the year ended December 31, 2017:

	Exploratory				Development				Total
	Gross		Net		Gross		Net		Gross		Net
Oil wells		-		-		-		-		-		-
Gas wells		2.0		2.0		32.0		31.4		34.0		33.4
Service wells		-		-		-		-		-		-
Stratigraphic test wells		-		-		-		-		-		-
Dry holes		-		-		-		-		-		-
Total		2.0		2.0		32.0		31.4		34.0		33.4

Subject to, among other things, the availability of drilling rigs and weather that permits access to drill sites, in the first 6 months of 2018, we plan to drill 2 net wells and complete 11 net wells. See "Other Oil and Gas Information – Property Descriptions" for a description of the Corporation's exploration and development activities.

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2018 reflected in the estimate of future net revenue disclosed in the tables contained under "Disclosure of Reserves Data".

	Light Crude Oil and Medium Crude Oil				Conventional Natural Gas				Natural Gas Liquids				Total
	(bbls/d)				(Mcf/d)				(bbls/d)				(Boe/d)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved Producing		1		1		198,871		187,304		1,896		1,756		35,043		32,974
Proved Developed Non-Producing		-		-		14,323		13,600		414		393		2,801		2,659
Proved Undeveloped		-		-		16,964		16,115		167		159		2,995		2,844
Total Proved		1		1		230,159		217,019		2,478		2,307		40,839		38,478
Total Probable		-		-		20,485		19,449		367		346		3,781		3,588
Total Proved Plus Probable		1		1		250,644		236,468		2,844		2,653		44,619		42,066

The following table indicates our production estimated from our important fields for the year ended December 31, 2018:

Light Crude Oil and Medium Crude Oil

Conventional Natural Gas

Natural Gas Liquids

Total

(bbls/d)

(Mcf/d)

(bbls/d)

(Boe/d)

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Alberta – Glacier Property

-

-

238,059

224,581

2,312

2,151

41,988

39,581

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Production History

The following tables summarize certain information in respect of production, prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:

	Quarter Ended 2017									Year Ended
	Mar. 31		June 30		Sept. 30			Dec. 31		Dec. 31, 2017
Average Daily Production(1)
Light Crude Oil and Medium Crude Oil (bbls/d)		446		507		516			402		468
NGLs (bbls/d)		705		591		879			825		750
Conventional Natural Gas (mcf/d)		230,906		225,844		219,812			237,780		228,583
Combined (mcfe/d)		237,812		232,432		228,182			245,142		235,891
Average Prices Received(3)
Light Crude Oil and Medium Crude Oil ($/bbl)		60.74		65.39		56.60			69.60		62.73
NGLs ($/bbl)		49.30		50.32		41.28			56.03		49.04
Conventional Natural Gas ($/Mcf)		2.99		2.98		1.84			2.15		2.49
Combined ($/Mcfe)		3.17		3.16		2.06			2.38		2.69
Royalties Paid
Light Crude Oil and Medium Crude Oil ($/bbl)		2.67		3.47		(0.55	)		2.14		1.88
NGLs ($/bbl)		4.85		8.53		(0.93	)		2.98		3.35
Conventional Natural Gas ($/Mcf)		0.08		0.13		(0.02	)		0.06		0.06
Combined ($/Mcfe)		0.10		0.15		(0.02	)		0.07		0.07
Production Costs (4) (5)
Light Crude Oil and Medium Crude Oil ($/bbl)		1.37		1.60		1.52			1.60		1.52
NGLs ($/bbl)		1.36		1.60		1.51			1.58		1.52
Conventional Natural Gas ($/Mcf)		0.23		0.27		0.25			0.26		0.25
Combined ($/Mcfe)		0.23		0.27		0.25			0.26		0.25
Transportation Costs
Light Crude Oil and Medium Crude Oil ($/bbl)		6.80		10.84		7.23			9.17		8.43
NGLs ($/bbl)		6.81		10.82		7.21			9.16		8.43
Conventional Natural Gas ($/Mcf)		0.36		0.33		0.31			0.47		0.37
Combined ($/Mcfe)		0.38		0.37		0.35			0.50		0.40
Netback Received(2) (6)
Light Crude Oil and Medium Crude Oil ($/bbl)		49.90		49.48		48.40			56.69		50.90
NGLs ($/bbl)		36.28		29.37		33.49			42.31		35.74
Conventional Natural Gas ($/Mcf)		2.32		2.25		1.30			1.36		1.81
Combined ($/Mcfe)		2.46		2.37		1.48			1.55		1.97

Notes:

(1) Before deduction of royalties.

(2) Netbacks are calculated by subtracting royalties, production costs and transportation costs from revenues.

(3) Before (gain) loss on Risk Management Contracts.

(4) This figure includes all field operating expenses.

(5) The Corporation does not record operating expenses on a commodity basis. Information in respect of operating expenses for crude oil and NGLs ($/bbl) and natural gas ($/Mcf) has been determined by allocating expenses on a relative volume of crude oil, NGLs and natural gas production basis.

(6) Information in respect of netbacks received for crude oil and NGLs ($/bbl) and natural gas ($/Mcf) is calculated using operating expense figures for crude oil and NGLs ($/bbl) and natural gas ($/Mcf), which figures have been estimated. See note (5) above.

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The following table indicates our approximate average daily production from our important fields for the year ended December 31, 2017:

	Light Crude Oil and Medium Crude Oil		Conventional Natural Gas		Natural Gas Liquids		Total
	(bbls/d)		(Mcf/d)		(bbls/d)		(Mcfe/d)
Alberta – Glacier Property		-		224,590		1,132		231,384

Marketing

Our natural gas and NGL production is primarily sold through marketing companies at current market prices. Risk management price hedging is done outside of our marketing contracts. Natural gas marketing contracts are for one year and are cancellable on 30 days notice. None of our natural gas production is sold to aggregators who accumulate production from various producers and market the gas on behalf of the group. NGL contracts are typically renegotiated annually and run for one year and are cancellable on 30 days notice.

Cyclical and Seasonal Impact of Industry

Our operational results and financial condition will be dependent on the prices received for oil, NGL and natural gas production. Oil, NGL and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions. Any decline in oil, NGL and natural gas prices could have an adverse effect on our financial condition. We mitigate such price risk through closely monitoring the various commodity markets and establishing hedging programs, as deemed necessary, to fix netbacks on production volumes. See "Other Oil and Gas Information – Forward Contracts" for our current hedging program.

Environmental Considerations

Advantage is pro-active in its approach to environmental concerns. Procedures are in place to ensure that significant care is taken in the day-to-day management of its oil and gas properties. Government regulations and procedures are followed in strict adherence to the law. We believe in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to us. Our Environmental Management System is continuously updated and meets or exceeds the Canadian Association of Petroleum Producers ("CAPP") Environmental Management Guidelines.

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Health, Safety and Environmental

Advantage is committed to a comprehensive and effective health, safety and environmental program that meets or exceeds regulatory and corporate requirements.

Advantage participates in the Certificate of Recognition ("COR") Safety Program and has received certification for the last seven years, achieving first-quartile results in each year. The COR Health and Safety Auditing and the COR Safety Program require commitment to continuous improvement in environment, health and safety management practices, including sound planning and implementation. The program is externally audited every 3 years and internally audited every other year. The program ensures open communication and measured performance to maintain such program.

Management, employees and all contractors are responsible and accountable for the overall health, safety and environmental program. Advantage operates in compliance with all applicable regulations and ensures all staff and contractors employ sound practices to protect the environment and to ensure employee and public health and safety.

In 2017, the Corporation participated in multiple Enhanced Production Audits, all of which it passed. Advantage's incident ratings in 2017 were significantly below industry averages. In addition, a total of 26 reclamation certificates were received by Advantage in 2017. Advantage's spill volumes in 2017 were zero and in the last five years, only one year had a very minor spill, which was negligible.

The Corporation maintains and will continue to maintain a safe and environmentally responsible work place, and will continue to provide training, equipment and procedures to all individuals in adhering to our policies. The Corporation will also solicit and take into consideration input from our neighbours, communities and other stakeholders in regard to protecting people and the environment.

Competitive Conditions

There is considerable competition in the worldwide oil and natural gas industry, including the Province of Alberta where the Corporation's assets, activities, and employees are located. We are a member of the petroleum industry, which is highly competitive at all levels. We compete with other companies for all of our business inputs, including exploitation and development prospects, access to commodity markets, acquisition opportunities, available capital and staffing. We strive to be competitive by maintaining a strong financial condition and by utilizing current technologies to enhance exploitation, development and operational activities. See "Risk Factors".

DIRECTORS AND OFFICERS

The following table sets forth the name, place of residence, date first elected as a director of Advantage and positions for each of the directors and officers of Advantage as at the date hereof, together with their principal occupations during the last five years.

Name, Province and Country of Residence	Position Held and Period Served as a Director or Officer(4)(5)	Principal Occupations During Past Five Years
Andy J. Mah Alberta, Canada	President since April 21, 2011, Chief Executive Officer since January 27, 2009 and a Director since June 23, 2006	President since April 21, 2011. Chief Executive Officer since January 27, 2009. President and Chief Operating Officer from June 23, 2006 to January 27, 2009. Chief Operating Officer of Longview from December 15, 2010 to November 7, 2013. Prior thereto, President of Ketch Resources Ltd. from October 2005 to June 2006. Chief Operating Officer of Ketch Resources Ltd. from January 2005 to September 2005. Prior thereto, Executive Officer and Vice President, Engineering and Operations of Northrock Resources Ltd. from August 1998 to January 2005.

26

Name, Province and Country of Residence	Position Held and Period Served as a Director or Officer(4)(5)	Principal Occupations During Past Five Years
Ronald A. McIntosh(2)(3) Alberta, Canada	Director since September 25, 1998(6) Chairman since February 4, 2014	Chairman of North American Energy Partners Inc., a publicly traded corporation and a director of Fortaleza Energy Inc., previously known as Alvopetro Inc., formerly named Fortress Energy Inc. Mr. McIntosh has extensive experience in the energy business, with previous roles including President and Chief Executive Officer of Navigo Energy, Chief Operating Officer of Gulf Canada, Vice President Exploration and International of PetroCanada and Chief Operating Officer of Amerada Hess Canada.
Stephen E. Balog(1)(2)(3) Alberta, Canada	Director since August 16, 2007	President, West Butte Management Inc., a private consulting company that provides business and technical advisory services to oil and gas operators.  Formerly Principal of Alconsult International Ltd. and prior thereto, President & Chief Operating Officer and a Director of Tasman Exploration Ltd. from 2001 to June, 2007.  Mr. Balog has extensive oil and gas industry experience in the management and operation of senior and junior production companies.  Mr. Balog was a key contributor to the development and use of the Canadian Oil & Gas Evaluation Handbook as an industry standard for reserves evaluation, and has previously served on the Petroleum Advisory Committee, Alberta Securities Commission.
Grant B. Fagerheim(2)(3) Alberta, Canada	Director since May 26, 2014	Chairman, President and Chief Executive Officer of Whitecap Resources Inc., a public oil and gas company, since June, 2008. Prior thereto, Mr. Fagerheim was the President and Chief Executive Officer and a Director of Cadence Energy Inc. (formerly, Kereco Energy Ltd.), a public oil and gas company, from January 2005 to September 2008. Mr. Fagerheim received his Bachelor's degree in Education (Economics Minor) from the University of Calgary in 1983 and attended the Executive MBA at Queen's University in 1995. Mr. Fagerheim currently sits on the board of directors of PRD Energy Inc., a public oil and gas company.
Paul G. Haggis(1)(2)(3) Alberta, Canada	Director since November 7, 2008	Mr. Haggis was President and Chief Executive Officer of Ontario Municipal Employees Retirement System (OMERS) from September 2003 to March 2007, Interim Chief Executive Officer of the Public Sector Pension Investment Board (PSPIB) during 2003 and Executive Vice-President, Development and Chief Credit Officer of Manulife Financial in 2002. Mr. Haggis has extensive financial markets and public board experience having served on the Board of Directors of Canadian Tire Bank until March 30, 2012. Mr. Haggis was a director and Chair of the Investment Committee of the Insurance Corporation of British Columbia and currently serves as an advisor to the committee. Mr. Haggis was also Chair of the Audit Committee of C.A. Bancorp and Prime Restaurants Royalty Income Fund and the Chair of Canadian Pacific Railway. Mr. Haggis was on the Board of UBC Investment Management Inc. Currently, Mr. Haggis is the Chairman of Alberta Enterprise Corp a Director of Home Capital Group Inc. Mr. Haggis holds a Bachelor of Arts degree from the University of Western Ontario and is certified as a Chartered Director through the Directors College at McMaster University.
Jill T. Angevine(1)(2) Alberta, Canada	Director since May 27, 2015	Vice President and Portfolio Manager at Matco Financial Inc. (an independent, privately held asset management firm) since October 2013. Director of Chinook Energy Inc. since November 2014 and Director of Tourmaline Oil Corp. since November 2015.  Independent businesswoman from September 2011 until October 2013 and prior thereto, Vice President and Director, Institutional Research at FirstEnergy Capital Corp. (a financial advisory and investment services provider in the energy market).
Craig Blackwood Alberta, Canada	Vice President, Finance since January 27, 2009 and Chief Financial Officer since August 1, 2013	Chief Financial Officer of Advantage since August 1, 2013. Vice President, Finance of Advantage since January 27, 2009. Chief Financial Officer of Longview from March 4, 2010 to February 4, 2014. Mr. Blackwood is a Chartered Accountant and was the Director of Finance of Advantage from November 2004 to January 27, 2009.

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Name, Province and Country of Residence	Position Held and Period Served as a Director or Officer(4)(5)	Principal Occupations During Past Five Years
Neil Bokenfohr Alberta, Canada	Senior Vice President, since March 27, 2014	Senior Vice President since March 27, 2014. Vice-President, Exploitation of Advantage from June 23, 2006 to March 27, 2014. Vice-President, Exploitation of Longview from May 13, 2011 to November 7, 2013. Prior thereto, Vice President Exploitation and Operations of Ketch Resources Ltd. from January 2005 to June 2006; Vice President, Engineering of Bear Creek Energy Ltd. (and Crossfield Gas Corp. prior thereto) from March 2002 to January 2005. Prior thereto, Director of Exploitation for Calpine Canada Natural Gas Company from December 2000 to March 2002.
Jay P. Reid Alberta, Canada	Corporate Secretary, Since April, 2001	Mr. Reid is a partner at the Calgary based law firm of Burnet, Duckworth & Palmer LLP and has practiced corporate and securities law since 1990. Mr. Reid has served, and continues to serve, as a director or officer of a number of private and publicly listed issuers.

Notes:

(1) Member of the Audit Committee.

(2) Member of the Human Resources, Compensation and Corporate Governance Committee.

(3) Member of the Independent Reserve Evaluation Committee.

(4) Advantage does not have an executive committee of the Board.

(5) Advantage's directors shall hold office until the next annual general meeting of Shareholders or until each director's successor is appointed or elected pursuant to the ABCA.

(6) The period of time served by Ronald A. McIntosh as a director of Advantage includes the period of time served as a director of Search prior to the Amalgamation, where applicable. Mr. McIntosh was appointed a director of post-Reorganization Search on May 24, 2001.

As at March 5, 2018, the directors and executive officers of Advantage, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 2,495,651 Common Shares, or approximately 1.3% of the issued and outstanding Common Shares.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Other than as disclosed below:

(a) no director or executive officer of Advantage has, within the last ten years prior to the date of this annual information form, been a director, chief executive officer or chief financial officer of any issuer (including Advantage) that, (i) while the person was acting in the capacity as director, chief executive officer or chief financial officer, was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, that was in effect for a period of more than thirty (30) consecutive days; or (ii) 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 of an issuer, in the issuer being the subject of a cease trade or similar order or an order that denied the relevant issuer access to any exemption under securities legislation, for a period of more than thirty (30) consecutive days, which resulted from an event that occurred while that person was acting as a director, chief executive officer or chief financial officer of the issuer;

(b) no director or executive officer of Advantage or security holder holding a sufficient number of securities of Advantage to affect materially the control of Advantage is, as at the date of this annual information form, or has, within the last ten years prior to the date of this annual information form, been a director or executive officer of any company (including Advantage) that, while such 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 for compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;

(c) no director or executive officer of Advantage or securityholder holding a sufficient number of securities of Advantage to affect materially the control of Advantage has, within the last ten years prior to the date of this document, 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, officer or securityholder; and

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(d) no director or executive officer of Advantage or securityholder holding a sufficient number of securities of Advantage to affect materially the control of Advantage 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.

Mr. McIntosh is a director of Fortaleza Energy Inc. ("Fortaleza"). On March 2, 2011, the Court of Queen’s Bench of Alberta granted an order (the "Order") under the Companies’ Creditors Arrangement Act (Canada) ("CCAA") staying all claims and actions against Fortaleza and its assets and allowing Fortaleza to prepare a plan of arrangement for its creditors if necessary. Fortaleza took such step in order to enable Fortaleza to challenge a reassessment issued by the Canada Revenue Agency ("CRA"). As a result of the reassessment, if Fortaleza had not taken any action, it would have been compelled to immediately remit one half of the reassessment to the CRA and Fortaleza did not have the necessary liquid funds to remit, although Fortaleza had assets in excess of its liabilities with sufficient liquid assets to pay all other liabilities and trade payables. Fortaleza believed that the CRA’s position was not sustainable and vigorously disputed the CRA’s claim. Fortaleza filed a Notice of Objection to the reassessment and on October 20, 2011 announced that its Notice of Objection was successful, CRA having confirmed there were no taxes payable. As the CRA claim had been vacated and no taxes or penalties were owing Fortaleza no longer required the protection of the Order under the CCAA and on October 28, 2011 the Order was removed. On March 3, 2011 the TSX suspended trading in the securities of Fortaleza due to Fortaleza having been granted a stay under the CCAA. In addition the securities regulatory authorities in Alberta, Ontario and Quebec issued a cease trade order with respect to Fortaleza for failure to file its annual financial statements for the year ended December 31, 2010 by March 31, 2011. The delay in filing was due to Fortaleza being granted the CCAA order on March 2, 2011 and the resulting additional time required by its auditors to deliver their audit opinion. The required financial statements and other continuous disclosure documents were filed on April 29, 2011 and the cease trade order was subsequently removed. On September 1, 2010 Fortaleza closed the sale of substantially all of its oil and gas assets. As a result of the sale Fortaleza was delisted from the TSX on March 30, 2011 as it no longer met minimum listing requirements.

Mr. Fagerheim was formerly a director of The Resort at Copper Point Ltd. (a private real estate development company) which was placed in voluntary receivership in February 2009.

Conflicts of Interest

The directors and officers of Advantage may, from time to time, be involved in the business and operations of other issuers, in which case a conflict may arise. The ABCA provides that in the event a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interests arise, such conflicts will be resolved in accordance with the provisions of the ABCA.

As at March 5, 2018, other than as disclosed herein, the Corporation was not aware of any existing or potential material conflicts of interest between the Corporation and a director or officer of the Corporation.

DIVIDEND POLICY

The Corporation did not pay any dividends during the years ended December 31, 2017, 2016, and 2015, does not anticipate paying dividends in the immediate future and will instead direct cash flow to capital expenditures and debt reduction. The amount of future cash dividends, if any, is not assured and will be subject to the discretion of the Board of Directors and may vary depending on a variety of factors, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates, contractual restrictions (including under the Credit Facilities), financing agreement covenants, solvency tests imposed by corporate law and other factors that the Board of Directors may deem relevant. See "Risk Factors".

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DESCRIPTION OF THE CORPORATION'S SECURITIES

Share Capital

The Corporation is authorized to issue an unlimited number of Common Shares, non-voting shares, preferred shares and exchangeable shares. As of December 31, 2017, there were 185,963,186 Common Shares issued and outstanding and there were no non-voting shares, preferred shares or exchangeable shares issued and outstanding.

The following is a description of the rights attaching to the Common Shares, non-voting shares and the preferred shares.

Common Shares

Each Common Share entitles its holder to receive notice of and to attend all meetings of the shareholders of Advantage and to one vote at such meetings. The holders of Common Shares are, at the discretion of the Advantage Board of Directors and subject to applicable legal restrictions, entitled to receive any dividends declared by the Board of Directors on the Common Shares. The holders of Common Shares are entitled to share equally in any distribution of the assets of Advantage upon the liquidation, dissolution, bankruptcy or winding-up of Advantage or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any instruments having priority over the Common Shares.

Non-Voting Shares

The non-voting shares have identical rights to the Common Shares except that holders of non-voting shares are not generally entitled to receive notice of or attend at meetings of shareholders of Advantage or to vote their shares at such meetings.

Preferred Shares

The preferred shares may be issued, from time to time, in one or more series, each series consisting of such number of preferred shares as determined by the Board of Directors, who may also fix the designations, rights, privileges, restrictions and conditions attached to the shares of each series of preferred shares. No preferred shares are presently issued and outstanding. The preferred shares of each series shall, with respect to payment of dividends and distributions of assets in the event of liquidation, dissolution or winding-up of Advantage, whether voluntary or involuntary, or any other distribution of the assets of Advantage among its shareholders for the purpose of winding-up its affairs, rank on a parity with the preferred shares of every other series and shall be entitled to preference over the Common Shares and the shares of any other class ranking junior to the preferred shares.

PRICE RANGE AND TRADING VOLUME OF SECURITIES

Common Shares

The Common Shares are listed and trade on the TSX and the NYSE and commenced trading under the symbol "AAV" on July 9, 2009. The following table sets forth the trading history of the Common Shares for the periods indicated.

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Period	High		Low		Volume
	($)		($)
TSX Trading
2017
January		9.31		8.22		12,769,130
February		8.83		7.86		10,056,301
March		8.84		7.65		15,562,000
April		9.29		8.24		11,099,100
May		9.18		8.00		12,532,400
June		8.82		8.02		11,484,400
July		9.24		8.37		9,687,000
August		8.64		7.78		10,560,700
September		8.24		7.48		10,740,900
October		7.81		6.57		11,524,700
November		7.44		5.98		13,266,000
December		6.19		4.84		25,650,800
2018
January		5.73		3.90		38,400,100
February		4.26		3.48		23,628,500
NYSE Trading (U.S.$)
2017
January		6.90		6.20		2,210,186
February		6.70		6.00		1,817,630
March		6.68		5.70		2,907,400
April		6.94		6.03		1,288,700
May		6.80		5.82		2,905,600
June		6.80		5.95		1,824,700
July		7.35		6.48		2,367,600
August		6.90		6.20		1,653,100
September		6.70		6.13		1,302,900
October		6.25		5.05		2,564,300
November		5.90		4.63		2,542,800
December		4.90		3.75		6,501,100
2018
January		4.58		3.15		7,851,400
February		3.45		2.75		6,610,500

Prior Sales

During the year ended December 31, 2017, the Corporation did not grant any stock options pursuant to the Corporation's stock option plan and granted 723,676 performance awards pursuant to the Corporation's restricted and performance award incentive plan.

ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER

There are presently no Advantage securities held in escrow or subject to contractual restrictions on transfer.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings and Advantage and its subsidiaries were not involved in any legal proceedings during the year ended December 31, 2017, which involved claims in excess of 10% of the Corporation's current asset value and to which Advantage or its subsidiaries were a party or in respect of which any of its properties are subject, nor are there any such proceedings known to be contemplated.

REGULATORY ACTIONS

During the year ended December 31, 2017 there were: (i) no penalties or sanctions imposed against Advantage or its subsidiaries by a court relating to securities legislation or by a securities regulatory authority; (ii) no other penalties or sanctions imposed by a court or regulatory body against Advantage or its subsidiaries that would likely be considered important to a reasonable investor in making an investment decision; and (iii) no settlement agreements Advantage or its subsidiaries entered into before a court relating to securities legislation or with a securities regulatory authority.

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INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and executive officers of Advantage or its subsidiaries or nominees for director of Advantage or its subsidiaries, any Shareholder who beneficially owns or directs or controls more than 10% of the Common Shares or any known associate or affiliate of such persons in any transaction during the year ended December 31, 2017 or in any proposed transaction which has materially affected or would materially affect Advantage or its subsidiaries.

MATERIAL CONTRACTS

Except for contracts entered into by us in the ordinary course of business or otherwise disclosed herein, the only agreement which is material to Advantage is the Credit Facility, a copy of which is available at www.sedar.com. See "General Development of the Business – Three Year History".

INTEREST OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 Continuous Disclosure Obligations by us during, or related to, our most recently completed financial year other than Sproule Associates Limited, our independent engineering evaluator and PricewaterhouseCoopers LLP, our current external auditors. As at the date hereof, none of the principals of Sproule Associates Limited had any registered or beneficial interests, direct or indirect, in any securities or other property of Advantage or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. The Corporation’s independent auditors are PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued an independent auditor’s report dated March 5, 2018 in respect of the Corporation’s consolidated financial statements as at December 31, 2017 and December 31, 2016 and for each of the years ended December 31, 2017 and the Corporation’s internal control over financial reporting as at December 31, 2017. PricewaterhouseCoopers LLP has advised that they are independent with respect to the Corporation within the meaning of the Rules of Professional Conduct with Guidance of the Chartered Professional Accountants of Alberta and the rules of the US Securities and Exchange Commission.

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 Advantage or of any associate or affiliate of Advantage.

AUDITORS, TRANSFER AGENT AND REGISTRAR

Our auditors are PricewaterhouseCoopers LLP, Calgary, Alberta.

Computershare Trust Company of Canada at its offices in Calgary, Alberta and Toronto, Ontario acts as the transfer agent and registrar for the Common Shares.

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AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

The Corporation's audit committee (the "Audit Committee") is comprised of Messrs. Paul Haggis and Stephen Balog and Ms. Jill T. Angevine. The following chart sets out the assessment of each Audit Committee member's independence, financial literacy and relevant educational background and experience supporting such financial literacy.

Name, Province and Country of Residence	Independent	Financially Literate	Relevant Education and Experience
Paul G. Haggis Alberta, Canada	Yes	Yes	Mr. Haggis was President and Chief Executive Officer of Ontario Municipal Employees Retirement System (OMERS) from September 2003 to March 2007, Interim Chief Executive Officer of the Public Sector Pension Investment Board (PSPIB) during 2003 and Executive Vice-President, Development and Chief Credit Officer of Manulife Financial in 2002. Mr. Haggis has extensive financial markets and public board experience having served on the Board of Directors of Canadian Tire Bank until March 30, 2012. Mr. Haggis was a director and Chair of the Investment Committee of the Insurance Corporation of British Columbia and currently serves as an advisor to the committee. Mr. Haggis was also Chair of the Audit Committee of C.A. Bancorp and Prime Restaurants Royalty Income Fund and the Chair of Canadian Pacific Railway. Mr. Haggis was on the Board of UBC Investment Management Inc. Currently, Mr. Haggis is the Chairman of Alberta Enterprise Corp a Director of Home Capital Group Inc. Mr. Haggis holds a Bachelor of Arts degree from the University of Western Ontario and is certified as a Chartered Director through the Directors College at McMaster University.
Stephen E. Balog Alberta, Canada	Yes	Yes	President, West Butte Management Inc., a private consulting company that provides business and technical advisory services to oil and gas operators.  Formerly Principal of Alconsult International Ltd. and prior thereto, President & Chief Operating Officer and a Director of Tasman Exploration Ltd. from 2001 to June, 2007.  Mr. Balog has extensive oil and gas industry experience in the management and operation of senior and junior production companies.  Mr. Balog was a key contributor to the development and use of the Canadian Oil & Gas Evaluation Handbook as an industry standard for reserves evaluation, and has previously served on the Petroleum Advisory Committee, Alberta Securities Commission.
Jill T. Angevine Alberta, Canada	Yes	Yes	Vice President and Portfolio Manager at Matco Financial Inc. (an independent, privately held asset management firm) since October 2013. Director of Chinook Energy Inc. since November 2014 and Director of Tourmaline Oil Corp. since November 2015.  Independent businesswoman from September 2011 until October 2013 and prior thereto, Vice President and Director, Institutional Research at FirstEnergy Capital Corp. (a financial advisory and investment services provider in the energy market).

Pre-Approval of Policies and Procedures

We have adopted policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by PricewaterhouseCoopers LLP as set forth in item 22 of the Audit Committee charter, which is reproduced below under the heading "Audit Committee Charter". The Audit Committee has approved the provision of a specified list of audit and permitted non-audit services that the audit committee believes to be typical, reoccurring or otherwise likely to be provided by PricewaterhouseCoopers LLP during the current fiscal year. The list of services is 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 pre-approved services.

AUDIT COMMITTEE CHARTER

The following is a summary of our Audit Committee Charter approved by the Board of Directors.

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Purpose

The primary function of the Audit Committee is to assist the Board of Directors of AOG in fulfilling its responsibilities by reviewing: the financial reports and other financial information provided by AOG to any governmental body or the public; AOG's systems of internal controls regarding finance, accounting, legal compliance and ethics that management and the Board have established; and AOG's auditing, accounting and financial reporting processes generally. Consistent with this function, the Audit Committee should endeavour to encourage continuous improvement of, and should endeavour to foster adherence to, AOG's policies, procedures and practices at all levels. In performing its duties, the external auditor is to report directly to the Audit Committee.

The Audit Committee's primary objectives are:

1. To assist directors meet their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of AOG and related matters;

2. To provide better communication between directors and external auditors;

3. To assist the Board's oversight of the auditor's qualifications and independence;

4. To assist the Board's oversight of the credibility, integrity and objectivity of financial reports;

5. To strengthen the role of the outside directors by facilitating discussions between directors on the Audit Committee, management and external auditors;

6. To assist the Board's oversight of the performance of the Corporation's internal audit function and independent auditors; and

7. To assist the Board's oversight of the Corporation's compliance with legal and regulatory requirements.

Composition

The Audit Committee shall be comprised of three or more directors as determined by the Board of Directors, none of whom are members of management of AOG and all of whom are "independent" (as such term is defined in: (a) National Instrument 52-110 — Audit Committees ("NI 52-110"); and (b) Section 303A.02 of the Corporate Governance Rules of the New York Stock Exchange). All of the members of the Audit Committee shall be "financially literate". The Board of Directors has adopted the definition for "financial literacy" used in NI 52-110. Audit Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by AOG or an outside consultant. In addition, at least one member of the Audit Committee must have accounting or related financial management expertise, as the Corporation's Board of Directors interprets such qualification in its business judgment.

The members of the Audit Committee shall be elected by the Board of Directors and remain as members of the Audit Committee until their successors shall be duly elected and qualified. Unless a Chair is elected by the full Board of Directors, the members of the Audit Committee may designate a Chair by majority vote of the full Audit Committee membership.

In connection with its annual review procedures, the Board will determine whether any member or proposed nominee for the Audit Committee serves on the Audit Committees of more than three public companies. To the extent that any member or proposed nominee of AOG serves on the Audit Committees of more than three public companies, the Board will make a determination as to whether such simultaneous services would impair the ability of such member to effectively serve on AOG's Audit Committee and will disclose such determination in AOG's annual information circular and annual report on Form 40-F filed with the Securities and Exchange Commission.

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Meetings

The Audit Committee shall meet at least four times annually, or more frequently as circumstances dictate. As part of its job to foster open communication, the Audit Committee should meet at least annually with management, internal auditors and the independent auditors in separate executive sessions to discuss any matters that the Audit Committee or each of these groups believe should be discussed privately. In addition, the Audit Committee or at least its Chair should meet with the independent auditors and management quarterly to review AOG's financials consistent with Section 4 below. The Audit Committee should also meet with management and independent auditors on an annual basis to review and discuss annual financial statements and the management's discussion and analysis of financial conditions and results of operations.

A quorum for meetings of the Audit Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Audit Committee shall be the same as those governing the Board.

Responsibilities and Duties

To fulfill its responsibilities and duties, the Audit Committee shall endeavour to:

Documents/Reports Review

1. Review and update this Charter periodically, at least annually, as conditions dictate.

2. Review the organization's annual and interim financial statements, MD&A, earnings press releases and any reports or other financial information submitted to any governmental body or the public, including any certification, report, opinion or review rendered by the independent auditors.

3. Review the reports to management prepared by the independent auditors and management's responses.

4. Review with financial management and the independent auditors the quarterly financial statements prior to their filing or prior to the release of earnings. The Chair of the Audit Committee may represent the entire Audit Committee for purposes of this review.

5. Review significant findings during the year, including the status of previous significant audit recommendations.

6. Periodically assess the adequacy of procedures for the review of corporate disclosure that is derived or extracted from the financial statements.

7. Periodically discuss guidelines and policies to govern the processes by which the Chief Executive Officer and senior management assess and manage the Corporation's exposure to risk.

8. Report regularly to the Board any issues that arise with respect to the quality or integrity of the Corporation's financial statements, compliance with legal or regulatory requirements, performance and independence of the Corporation's auditors, or performance of the internal audit function.

9. To prepare, if required, an Audit Committee report to be included in AOG's annual information circular and proxy statement.

10. Preparing an annual performance evaluation of the Audit Committee.

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

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Independent Auditors

12. Recommend to the Board the external auditors to be nominated for appointment by the Shareholders.

13. Approve the compensation of the external auditors.

14. On an annual basis, the Audit Committee should review and discuss with the auditors all significant relationships the auditors have with AOG to determine the auditors' independence. In addition, the Audit Committee will ensure the rotation of the lead audit partner every five years and, in order to ensure continuing auditor independence, consider the rotation of the audit firm itself.

15. Review and, as appropriate, resolve any material disagreements between management and the independent auditors and review, consider and make a recommendation to the Board regarding any proposed discharge of the auditors when circumstances warrant.

16. 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.

17. Periodically consult with the independent auditors, without the presence of management, about internal controls and the fullness and accuracy of the organization's financial statements.

18. Oversee the establishment of an internal audit function.

19. Periodically assess the Corporation's internal audit function, including the Corporation's risk management processes and system of internal controls.

20. Review the audit scope and plan of the independent auditor.

21. Oversee the work of the external auditors engaged for the purpose of preparing or issuing an auditor's report or performing other audit, review or attest services for AOG.

22. Pre-approve the completion of any non-audit services by the external auditors and determine which non-audit services the external auditor is prohibited from providing. The Audit Committee may delegate to one or more members of the Audit Committee authority to pre-approve non-audit services in satisfaction of this requirement and if such delegation occurs, the pre-approval of non-audit services by the Audit Committee member to whom authority has been delegated must be presented to the Audit Committee at its first scheduled meeting following such pre-approval. The Audit Committee shall be entitled to adopt specific policies and procedures for the engagement of non-audit services if:

(a) the pre-approval policies and procedures are detailed as to the particular service;

(b) the Audit Committee is informed of each non-audit service; and

(c) the procedures do not include delegation of the Audit Committee's responsibilities to management.

The Audit Committee will satisfy the pre-approval requirement set forth in this paragraph 22 if:

(a) the aggregate amount of all non-audit services that were not pre-approved is reasonably expected to constitute no more than 5% of the total amount of fees paid by AOG and its subsidiary entities to the auditors during the fiscal year in which the services are provided;

(b) AOG or the subsidiary entity, as the case may be, did not recognize the services as non-audit services at the time of the engagement;

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(c) the services are promptly brought to the attention of the Audit Committee and approved, prior to completion of the audit, by the Audit Committee or by one or more of its members to whom authority to grant such approvals has been delegated by the Audit Committee; and

23. Review, set and approve hiring policies relating to staff of current and former auditors.

Financial Reporting Processes

24. In consultation with the independent auditors, annually review the integrity of the organization's financial reporting processes, both internal and external.

25. In consultation with the independent auditors, consider annually the quality and appropriateness of the Corporation's accounting principles as applied in its financial reporting.

26. Consider and approve, if appropriate, major changes to AOG's auditing and accounting principles and practices as suggested by the independent auditors or management.

27. Review risk management policies and procedures of AOG (i.e., litigation and insurance).

Process Improvement

28. Request reporting to the Audit Committee by each of management and the independent auditors of any significant judgments made in the management's preparation of the financial statements and the view of each group as to appropriateness of such judgments.

29. Following completion of the annual audit, review separately with each of management and the independent auditors any significant difficulties encountered during the course of the audit, including any restrictions on the scope of work or access to required information.

30. Review any significant disagreements among management and the independent auditors in connection with the preparation of the financial statements.

31. Review with the independent auditors and management the extent to which changes or improvements in financial or accounting practices, as approved by the Audit Committee, have been implemented. (This review should be conducted at an appropriate time subsequent to implementation of changes or improvements, as decided by the Audit Committee.)

32. Conduct and authorize investigations into any matters brought to the Audit Committee's attention and within the Audit Committee's scope of responsibilities. The Audit Committee shall be empowered to retain and to approve compensation for any independent counsel and other professionals to assist in the conduct of any investigation.

33. Review the systems that identify and manage principal business risks.

34. Establish a procedure for:

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

(b) the confidential, anonymous submission by employees of AOG of concerns regarding questionable accounting or auditing matters;

which procedure shall be set forth in a "whistle blower program" to be adopted by the Audit Committee in connection with such matters.

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Ethical and Legal Compliance

35. Establish, review and update periodically a Code of Ethical Conduct and ensure that management has established a system to enforce this code.

36. Review management's monitoring of AOG's compliance with the organization's Ethical Code.

37. In consultation with the auditors, consider the review system established by management regarding the Corporation's financial statements, reports and other financial information disseminated to governmental organizations and the public in the context of the applicable legal requirements.

38. On at least an annual basis, review with AOG's auditors or counsel, as appropriate, any legal matters that could have a significant impact on the organization's financial statements, AOG's compliance with applicable laws and regulations and inquiries received from regulators or government agencies.

39. Review with the organization's counsel legal compliance matters including the trading policies of securities.

Other

40. Perform any other activities consistent with this Charter, AOG's by-laws and governing law, as the Audit Committee or the Board of Directors deems necessary or appropriate.

41. In connection with the performance of its responsibilities as set forth above, the Audit Committee shall have the authority to engage outside advisors and to pay outside auditors and advisors.

AUDIT SERVICE FEES

Auditor Services Fees

The following table discloses fees billed to us by our auditors, PricewaterhouseCoopers LLP.

Type of Service Provided	2017		2016
Audit Fees(1)	$	268,000	$	263,000
Audit-Related Fees(2)		45,000		45,000
Tax Fees(3)		8,000		16,500
Other Fees(4)		-		39,900
Total	$	321,000	$	364,400

Notes:

(1) "Audit Fees" include fees necessary to perform the annual audit of the Corporation's consolidated financial statements.

(2) "Audit-Related Fees" include services that are traditionally performed by the auditor. These audit-related services include quarterly reviews of the Corporation's consolidated financial statements.

(3) "Tax Fees" include fees for all tax services other than those included in "Audit Fees" and "Audit-Related Fees". This category includes fees for tax compliance, tax planning and general tax advice, including the preparation and filing of Scientific Research & Experimental Development Tax Credits.

(4) "Other Fees" represents fees related to the Offering.

INDUSTRY CONDITIONS

Companies carrying on business in the crude oil and natural gas sector in Canada are subject to extensive controls and regulations imposed through legislation of the federal government and the provincial governments where the companies have assets or operations. While these regulations do not affect the Corporation's operations in any manner that is materially different than they affect other similarly-sized industry participants with similar assets and operations, investors should consider such regulations carefully. Although governmental legislation is a matter of public record, the Corporation is unable to predict what additional legislation or amendments governments may enact in the future.

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The Corporation holds interests in crude oil and natural gas properties, along with related assets, primarily in the Canadian province of Alberta. The Corporation's assets and operations are regulated by administrative agencies deriving authority from underlying legislation. Regulated aspects of the Corporation's upstream crude oil and natural gas business include all manner of activities associated with the exploration for and production of crude oil and natural gas, including, among other matters: (i) permits for the drilling of wells; (ii) technical drilling and well requirements; (iii) permitted locations and access of operation sites; (iv) operating standards regarding conservation of produced substances and avoidance of waste, such as restricting flaring and venting; (v) minimizing environmental impacts; (vi) storage, injection and disposal of substances associated with production operations; 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, 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.

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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.

Currently, 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 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.

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

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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.

Alberta has 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, Alberta has 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 province of Alberta. According to Alberta Energy, approximately 19% of mineral rights in the Province of Alberta are owned by private freehold owners and other non-Crown entities. 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 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.

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.

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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.

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 hold the mineral rights. A description of the freehold mineral taxes payable in Alberta is included in the above description of the royalty regimes in Alberta.

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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 Canadian Energy Regulator ("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.

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On May 12, 2017, the federal government introduced the Oil Tanker Moratorium Act in Parliament. This legislation is aimed at providing coastal protection in northern British Columbia by prohibiting crude oil tankers carrying more than 12,500 metric tonnes of crude oil or persistent crude oil products from stopping, loading, or unloading crude oil in that area. Parliament is still considering the bill, which passed second reading on October 4, 2017. If implemented, the legislation may prevent the building of pipelines to, and export terminals located on, the portion of the British Columbia coast subject to the moratorium and, as a result, negatively affect the ability of producers to access global markets.

Alberta

The AER is the single regulator responsible for all 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 public and examines the cumulative impacts of development on the environment and communities by incorporating the management of all resources, including energy, minerals, land, air, water and biodiversity. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including Alberta Environment and Parks, Alberta Energy, the Policy Management Office, the Aboriginal Consultation Office and the Land Use Secretariat.

The Government of Alberta's land-use policy for surface land in Alberta sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans. As a result, several regional plans have been implemented and others are in the process of being implemented. These regional plans may affect further development and operations in such regions.

Liability Management Rating Program

Alberta

The AER administers the Licensee Liability 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.

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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.

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 the Corporation's operations and cash flow.

Federal

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") since 1992. Since its inception, the UNFCCC has instigated numerous policy experiments with respect to climate governance. On April 22, 2016, 197 countries signed the Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. As of February 1, 2018, 174 of the 197 parties to the convention have ratified the Paris Agreement.

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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 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.

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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.

RISK FACTORS

The following is a summary of certain risk factors relating to the business of Advantage. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this annual information form.

Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Corporation'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 the Corporation's business and the oil and natural gas business generally.

Prices, Markets and Marketing

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

Numerous factors beyond the Corporation's control do, and will continue to, affect the marketability and price of oil and natural gas acquired, produced, or discovered by the Corporation. The Corporation's ability to market its oil, natural gas and NGLs 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 Corporation'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 Corporation.

Prices for oil, natural gas and NGLs are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil, natural gas and NGLs, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors include economic and political conditions in the United States, Canada, Europe, China and emerging markets, the actions of the Organization of the Petroleum Exporting Countries ("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, natural gas and NGLs are also subject to the availability of foreign markets and the Corporation's ability to access such markets. A material decline in prices could result in a reduction of the Corporation's net production revenue. The economics of producing from some wells may change because of lower prices, which could result in reduced production of oil or natural gas and associated NGLs and a reduction in the volumes and the value of the Corporation's reserves. The Corporation might also elect not to produce from certain wells at lower prices.

All these factors could result in a material decrease in the Corporation's expected net production revenue and a reduction in its oil and natural gas production, development and exploration activities. Any substantial and extended decline in the price of oil, natural gas and NGLs would have an adverse effect on the Corporation's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

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Oil, natural gas and NGLs 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, natural gas and NGLs 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.

In addition, bank borrowings available to the Corporation may, in part, be determined by the Corporation's borrowing base. A sustained material decline in prices from historical average prices could reduce the Corporation's borrowing base, therefore reducing the bank credit available to the Corporation which could require that a portion, or all, of the Corporation's bank debt be repaid.

See "Risk Factors - Weakness in the Oil and Gas Industry".

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 the Corporation's reserves, restrict its cash flow and its ability to access capital to fund the development of it properties.

Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by 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 additional downward price pressure on oil and gas produced and sold in Western Canada and uncertainty and reduced confidence in the oil and gas industry in Western Canada. Lower commodity prices may also affect the volume and value of the Corporation's reserves, rendering certain reserves uneconomic. In addition, lower commodity prices restrict the Corporation's cash flow resulting in less funds from operations being available to fund the Corporation's capital expenditure budget. Consequently, the Corporation may not be able to replace its production with additional reserves and both the Corporation's production and reserves could be reduced on a year over year basis. Any decrease in value of the Corporation's reserves may reduce the borrowing base under its credit facilities, which, depending on the level of the Corporation's indebtedness, could result in the Corporation having to repay a portion of its indebtedness. In addition to possibly resulting in a decrease in the value of the Corporation's economically recoverable reserves, lower commodity prices may also result in a decrease in the value of the Corporation's infrastructure and facilities, all of which could also have the effect of requiring a write down of the carrying value of the Corporation's oil and gas assets on its balance sheet and the recognition of an impairment charge in its income statement. Given the current market conditions and the lack of confidence in the Canadian oil and gas industry, the Corporation may have difficulty raising additional funds or if it is able to do so, it may be on unfavourable and highly dilutive terms.

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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.

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 the Corporation.

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 the Corporation's ability to market its products internationally, increase costs for goods and services required for the Corporation's operations, reduce access to skilled labour and negatively impact the Corporation's business, operations, financial conditions and the market value of 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.

Exploration, Development and Production Risks

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

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Corporation depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the Corporation's existing reserves, and the production from them, will decline over time as the Corporation produces from such reserves. A future increase in the Corporation's reserves will depend on both the ability of the Corporation to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Corporation will be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of the Corporation may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participation uneconomic. There is also no assurance that the Corporation will discover or acquire further commercial quantities of oil and natural gas.

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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 Corporation 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 the Corporation.

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 Corporation's business, financial condition, results of operations and prospects.

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

Gathering and Processing Facilities and Pipeline Systems

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

The Corporation delivers its products through gathering and processing facilities and pipeline systems. The amount of oil and natural gas that the Corporation can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities and pipeline systems. The lack of availability of capacity in any of the gathering and processing facilities and pipeline systems could result in the Corporation's inability to realize the full economic potential of its production or in a reduction of the price offered for the Corporation's production. The lack of firm pipeline capacity continues to affect the oil and natural gas industry and 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 Corporation'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 Corporation's business and, in turn, the Corporation'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.

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A portion of the Corporation's production may, from time to time, be processed through facilities owned by third parties and over which the Corporation does not have control. From time to time, these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could have a materially adverse effect on the Corporation's ability to process its production and deliver the same 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.

Pipeline Systems

Pipeline interruptions or capacity constraints may have a negative impact on the Corporation's ability to transport and market its products.

The interruption of firm pipeline transportation has and may continue to affect the oil and natural gas industry and limit the ability to fully produce and market oil and natural gas production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems may also 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 may also affect the Corporation's production, operations and financial results. The Corporation's production could be adversely impacted by both firm and interruptible transportation service curtailments on TransCanada's NGTL and Canadian Mainline systems.

Project Risks

The success of the Corporation'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 delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. The Corporation's ability to execute projects and market oil, natural gas and NGLs depends upon numerous factors beyond the Corporation's control, including:

· the availability of processing capacity;

· the availability and proximity of pipeline capacity;

· the availability of storage capacity;

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

· the effects of inclement weather;

· the availability of drilling and related equipment;

· unexpected cost increases;

· accidental events;

· currency fluctuations;

· regulatory changes;

· the availability and productivity of skilled labour; and

· the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

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

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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 the Corporation.

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

· 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, natural gas and NGLs 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, the Corporation's independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil, natural gas and NGLs, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from the Corporation's oil, natural gas and NGLs reserves will vary from the estimates contained in the reserve evaluation, and such variations could be material. The reserve evaluation is based in part on the assumed success of activities the Corporation intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom and contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation. The reserve evaluation is effective as of a specific effective date and, except as may be specifically stated, has not been updated and therefore does not reflect changes in the Corporation's reserves since that date.

Hedging

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

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

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

Credit Facility Arrangements

Failing to comply with covenants under the Corporation's credit facility could result in restricted access to capital or being required to repay all amounts owing thereunder.

The Corporation currently has a credit facility and the amount authorized thereunder is dependent on the borrowing base determined by its lenders. The Corporation is required to comply with covenants under its credit facility which may, in certain cases, include certain financial ratio tests, which from time to time either affect the availability, or price, of additional funding and in the event that the Corporation does not comply with these covenants, the Corporation's access to capital could be restricted or repayment could be required. Events beyond the Corporation's control may contribute to the failure of the Corporation to comply with such covenants. A failure to comply with covenants could result in default under the Corporation's credit facility, which could result in the Corporation being required to repay amounts owing thereunder. The acceleration of the Corporation's indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the Corporation's credit facility may impose operating and financial restrictions on the Corporation that could include restrictions on, the payment of dividends, repurchasing or making other distributions with respect to the Corporation's securities, incurring additional indebtedness, providing guarantees, the assumption of loans, making capital expenditures, entering into amalgamations, mergers, take-over bids or disposing of assets, among others.

The Corporation's lenders use the Corporation's reserves, commodity prices, applicable discount rate and other factors to periodically determine the Corporation's borrowing base. Commodity prices continue to be depressed and have fallen dramatically since 2014, and while prices have recently increased they remain volatile as a result of various factors including actions taken to limit OPEC and non-OPEC production and increasing production by US shale producers. Depressed commodity prices could reduce the Corporation's borrowing base, reducing the funds available to the Corporation under the credit facility. This could result in the requirement to repay a portion, or all, of the Corporation's indebtedness.

If the Corporation's lenders require repayment of all or portion of the amounts outstanding under its credit facilities for any reason, including for a default of a covenant or the reduction of a borrowing base, there is no certainty that the Corporation would be in a position to make such repayment. Even if the Corporation is able to obtain new financing in order to make any required repayment under its credit facilities, it may not be on commercially reasonable terms or terms that are acceptable to the Corporation. If the Corporation is unable to repay amounts owing under credit facilities, the lenders under the credit facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.

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Forward-Looking Information

Forward-Looking Information May Prove Inaccurate.

Shareholders and prospective investors are cautioned not to place undue reliance on the Corporation's forward-looking information, and in particular, the guidance provided under "General Development of the Business". 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 "Forward-Looking Statements".

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, natural gas and NGLs reserves in the future. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, the Corporation's ability to do so is dependent on, among other factors:

· the overall state of the capital markets;

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

· commodity prices;

· interest rates;

· royalty rates;

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

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

Further, if the Corporation's revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. The 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 Corporation. The Corporation may be required to seek additional equity financing on terms that are highly dilutive to existing shareholders. The inability of the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation's business financial condition, results of operations and prospects.

Additional Funding Requirements

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

The Corporation's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times and from time to time, the Corporation may require additional financing in order to carry out its oil and natural gas acquisition, exploration and development activities. Failure to obtain financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. Due to the conditions in the oil and gas industry and/or global economic and political volatility, the Corporation may from time to time have restricted access to capital and increased borrowing costs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing.

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

Royalty Regimes

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

There can be no assurance that the governments in the jurisdictions in which the Corporation has assets will not adopt new royalty regimes or modify the existing royalty regimes which may have an impact on the economics of the Corporation's projects. An increase in royalties would reduce the Corporation's earnings and could make future capital investments, or the Corporation's operations, less economic. On January 29, 2016, the Government of Alberta adopted a new royalty regime which took effect on January 1, 2017. See "Industry Conditions - Royalties and Incentives".

Geo-Political Risks

Global political events may adversely affect commodity prices which in turn affect the Corporation'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 the Corporation. 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 the Corporation'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 the Corporation's properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. The Corporation does not have insurance to protect against the risk from terrorism.

Management of Growth

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

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

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Reliance on Key Personnel

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

The Corporation's success depends in large measure on certain key personnel. The loss of the services of such key personnel may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. The Corporation does not have any key personnel insurance in effect for the Corporation. The contributions of the existing management team to the immediate and near term operations of the Corporation are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract and retain all personnel necessary for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of the Corporation.

Information Technology Systems and Cyber-Security

Breaches of the Corporation's cyber-security and loss of, or access to, electronic data may adversely impact 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, manage our land base, manage financial resources, analyze seismic information, administer our contracts with our operators and lessees and communicate with employees and third-party partners.

Further, the Corporation is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Corporation’s information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to our business activities or our competitive position. In addition, cyber phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card details (and money) by disguising as a trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years. If the Corporation becomes a victim to a cyber phishing attack it could result in a loss or theft of the Corporation's financial resources or critical data and information or could result in a loss of control of the Corporation's technological infrastructure or financial resources. The Corporation applies technical and process controls in line with industry-accepted standards to protect our information assets and systems; however, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on our performance and earnings, as well as on our reputation. 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.

Market Price of Common Shares

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

The trading price of securities of oil and natural gas issuers is subject to substantial volatility often based on factors related and unrelated to the financial performance or prospects of the issuers involved. Factors unrelated to the Corporation's performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices or current perceptions of the oil and gas market, including governmental regulatory actions or adverse changes in general market conditions or economic trends. 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 could be subject to significant fluctuations in response to variations in the Corporation's operating results, financial condition, liquidity and other internal factors, as well as the Corporation's operating results failing to meet the expectations of securities analysts or investors in any quarter, downward revision in securities analysts' estimates, acquisitions, dispositions or other material public announcements by the Corporation or its competitors, along with a variety of additional factors. Accordingly, the price at which the Common Shares will trade cannot be accurately predicted.

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Impact of Future Financings on Market Price

The Corporation's future financings may negatively impact the market price of the Common Shares.

In order to finance future operations or acquisition opportunities, the Corporation may raise funds through the issuance of Common Shares or the issuance of debt instruments or securities convertible into Common Shares. The Corporation cannot predict the size of future issuances of Common Shares or the issuance of debt instruments or other securities convertible into Common Shares or the effect, if any, that future issuances and sales of the Corporation’s securities will have on the market price of the Common Shares.

Dilution

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

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

Competition

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

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

Environmental

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

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge. Although the Corporation believes that it will be in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

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Disposal of Fluids Used in Operations

Regulations regarding the disposal of fluids used in the Corporation's operations may increase its costs of compliance or subject it to regulatory penalties or litigation.

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

Carbon Pricing Risk

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

The majority of countries across the globe have agreed to reduce their carbon emissions in accordance with the Paris Agreement. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation". In Canada, the federal and certain provincial governments have implemented legislation aimed at incentivizing the use of 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 the Corporation's operating expenses, each of which may have a material adverse effect on the Corporation's profitability and financial condition. Further, the imposition of carbon taxes puts the Corporation at a disadvantage with its counterparts who operate in jurisdictions where there are less costly carbon regulations.

Climate Change

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

The Corporation's exploration and production facilities and other operations and activities emit greenhouse gases which may require the Corporation 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 UNFCCC and a signatory to the Paris Agreement, which was ratified in Canada on October 3, 2016, the Government of Canada pledged to cut its GHG emissions by 30 per cent from 2005 levels by 2030. One of the pertinent policies announced to date by the Government of Canada to reduce GHG emission is the planned implementation of a nation-wide price on carbon emissions. 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 the Corporation's business, financial condition, results of operations and prospects. Some of the Corporation's significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the control of GHG and resulting requirements, it is expected that current and future climate change regulations will have the affect of increasing the Corporation's operating expenses and in the long-term reducing the demand for oil and gas production resulting in a decrease in the Corporation's profitability and a reduction in the value of its assets or asset write-offs. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation".

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Regulatory

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

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing 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 the Corporation's costs, either of which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. Recently, the federal government and certain provincial governments have taken steps to initiate protocols and regulations to limit the release of methane from oil and gas operations. Such draft regulations and protocols may require additional expenditures or otherwise negatively impact the Corporation's operations, which may affect the Corporation's profitability. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulations".

In order to conduct oil and natural gas operations, the Corporation will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities at the municipal, provincial and federal level. There can be no assurance that the Corporation will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that it may wish to undertake. In addition, certain federal legislation such as the Competition Act and the Investment Canada Act could negatively affect the Corporation's business, financial condition and the market value of its Common Shares or its assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity.

Hydraulic Fracturing

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

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

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.

Variations in Foreign Exchange Rates and Interest Rates

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

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

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

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

Changing Investor Sentiment

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

A number of factors, including the 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 the Corporation. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in the Corporation or not investing in the Corporation at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, the Corporation, may result in limiting the Corporation's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares.

Insurance

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

The Corporation's involvement in the exploration for and development of oil and natural gas properties may result in the Corporation becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards. Although the Corporation maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Corporation may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to the Corporation. The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

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 oil, natural gas and NGLs production and other parties. In addition, the Corporation may be exposed to third party credit risk from operators of properties in which the Corporation has a working or royalty interest. In the event such entities fail to meet their contractual obligations to the Corporation, such failures may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in the Corporation's ongoing capital program, potentially delaying the program and the results of such program until the Corporation finds a suitable alternative partner. To the extent that any of such third parties go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in the Corporation being unable to collect all or portion of any money owing from such parties. Any of these factors could materially adversely affect the Corporation's financial and operational results.

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Liability Management

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

Alberta has developed liability management programs designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder is unable to satisfy its regulatory obligations. These programs involve an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed its deemed assets, a security deposit is generally required. Changes to the required ratio of the Corporation's deemed assets to deemed liabilities or other changes to the requirements of liability management programs may result in significant increases to the Corporation's compliance obligations. In addition, the liability management regime may prevent or interfere with the Corporation's ability to acquire or dispose of assets, as both the vendor and the purchaser of oil and 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".

Tax Horizon

The Corporation's projections regarding its tax horizons may be inaccurate, resulting in a requirement to pay taxes sooner than expected.

It is expected, based upon current legislation, the projections contained in the Sproule Report and various other assumptions that no cash income taxes are to be paid by the Corporation prior to 2021. A lower level of capital expenditures than those contained in the Sproule Report or should the assumptions used by the Corporation prove to be inaccurate, the Corporation may be required to pay cash income taxes sooner than anticipated, which will reduce cash flow available to the Corporation.

Operational Dependence

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

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

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

Title to Assets

Defects in the title to the Corporation'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 the Corporation in properties may accordingly vary from the Corporation's records. If a title defect does exist, it is possible that the Corporation may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. There may be valid challenges to title or legislative changes, which affect the Corporation's title to the oil and natural gas properties the Corporation controls that could impair the Corporation's activities on them and result in a reduction of the revenue received by the Corporation.

Expiration of Licenses and Leases

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

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

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

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

The Corporation considers acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation. The integration of acquired businesses 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 Corporation can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the Corporation may realize less on disposition than their carrying value on the financial statements of the Corporation.

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In addition, acquisitions of oil and gas properties or companies are based in large part on engineering, environmental and economic assessments made by the acquiror, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of oil and gas, future operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the Corporation. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated. Although select title and environmental reviews are conducted prior to any purchase of resource assets, such reviews cannot guarantee that any unforeseen defects in the chain of title will not arise to defeat the Corporation's title to certain assets or that environmental defects, liabilities or deficiencies do not exist or are greater than anticipated. Such deficiencies or defects could adversely affect the value of the assets acquired and the Corporation's securities.

Reputational Risk Associated with the Corporation's Operations

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

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

Issuance of Debt

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

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

Conflicts of Interest

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

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

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

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy generation devices could reduce the demand for oil, natural gas and 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 the Corporation's business, financial condition, results of operations and cash flows by decreasing the Corporation's profitability, increasing its costs, limiting its access to capital and decreasing the value of its assets.

Litigation

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

In the normal course of the Corporation's operations, it may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, 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 with respect to outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the Corporation, and as a result, could have a material adverse effect on the Corporation's assets, liabilities, business, financial condition and results of operations. Even if the Corporation prevails in any such legal proceedings, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from business operations, which could have an adverse affect on the Corporation's financial condition.

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Breach of Confidentiality

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

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

Internal Controls

Material weaknesses in the Corporation's internal controls may negatively affect the Corporation and the market price of the Common Shares.

Effective internal controls are necessary for the Corporation to provide reliable financial reports and to help prevent fraud. Although the Corporation will undertake a number of procedures in order to help ensure the reliability of its financial reports, including those imposed on it under Canadian securities laws, the Corporation cannot be certain that such measures will ensure that the Corporation will maintain adequate control over financial processes and reporting. Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm the Corporation's results of operations or cause it to fail to meet its reporting obligations. If the Corporation or its independent auditors discover a material weakness, the disclosure of that fact, even if quickly remedied, could reduce the market's confidence in the Corporation's financial statements and harm the trading price of the Common Shares.

Income Taxes

Taxation authorities may reassess the Corporation's tax returns.

The Corporation files all required income tax returns and believes that it is in full compliance with the provisions of the Income Tax Act (Canada) and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of the Corporation, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable.

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

Availability of Drilling Equipment and Access

Restrictions on the availability of and access to drilling equipment may impede the Corporation's exploration and development activities.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) as well as skilled personnel trained to use such equipment in the areas where such activities will be conducted. Demand for such limited equipment and skilled personnel, or access restrictions, may affect the availability of such equipment and skilled personnel to the Corporation and may delay exploration and development activities.

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Seasonality and Extreme Weather Conditions

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

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Roads bans and other restrictions generally result in a reduction of drilling and exploratory activities and may also result in the shut-in of some of the Corporation's production if not otherwise tied-in. Certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. In addition, extreme cold weather, heavy snowfall and heavy rainfall may restrict the Corporation's ability to access its properties, cause operational difficulties including damage to machinery or contribute to personnel injury because of dangerous working conditions.

Aboriginal Claims

Aboriginal claims may affect the Corporation.

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

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. The amount of future cash dividends paid by the Corporation, if any, will be subject to the discretion of the board of directors of the Corporation and will depend 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. See "Dividend Policy".

Expansion into New Activities

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

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

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE

As a foreign private issuer listed on the NYSE, Advantage is not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic Canadian requirements. Advantage is, however, required to comply with the following NYSE Rules: (i) Advantage 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) Advantage must 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) Advantage must annually 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. Advantage 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.

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ADDITIONAL INFORMATION

Additional information relating to the Corporation can be found on SEDAR at www.sedar.com and the Corporation’s website at www.advantageog.com.

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Common Shares and securities authorized for issuance under equity compensation plans, will be contained in the Corporation's Information Circular for the most recent annual meeting of shareholders that involved the election of directors of Advantage. Additional financial information is provided for in the Corporation's Consolidated financial statements and management's discussion and analysis for the year ended December 31, 2017.

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SCHEDULE "A"

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

(Form 51-101F3)

Report of Management and Directors on Reserves Data and Other Information

Management of Advantage Oil & Gas 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 reserves data and other oil and gas information;

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

(c) the content and filing of this report.

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

(signed) "Andy Mah"	(signed) "Craig Blackwood"
Andy Mah	Craig Blackwood
President and Chief Executive Officer	Vice President, Finance and Chief Financial Officer
(signed) "Ronald A. McIntosh"	(signed) "Stephen Balog"
Ronald A. McIntosh	Stephen Balog
Director	Director
Dated the 5 day of March, 2018

SCHEDULE "B"

REPORT ON RESERVES DATA

BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

(Form 51-101F2)

Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor

To the board of directors of Advantage Oil & Gas 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 evaluated and reported on to the Company's board of directors:

			Net Present Value of Future Net Revenue (before income taxes, 10% discount rate)
Independent Qualified Reserves  Evaluator or  Auditor	Effective Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited (M$)		Evaluated (M$)		Reviewed (M$)		Total (M$)
Sproule Associates Limited	December 31, 2017	Canada		-	$	2,549,991		-	$	2,549,991
Totals				-	$	2,549,991		-	$	2,549,991

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 reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.

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

EXECUTED as to our report referred to above:

Sproule Associates Limited	Original Signed by Alec Kovaltchouk, P. Geo.
Calgary, Alberta, Canada	Alec Kovaltchouk, P. Geo.
February 7, 2018	Vice-President, Geosciences
	Original Signed by Cameron P. Six, P. Eng.
	Cameron P. Six, P. Eng.
	Chief Operating Officer and Director
	Original Signed by Brent A. Hawkwood, C.E.Ts.
	Brent A. Hawkwood, P. Eng.
	Senior Technologist

2

EX-99.2

Exhibit 99.2

Consolidated Financial Statements

Management’s Responsibility for Financial Statements

The Management of Advantage Oil & Gas Ltd. (the “Corporation”) is responsible for the preparation and presentation of the consolidated financial statements together with all operational and other financial information contained in the consolidated financial statements. The consolidated financial statements have been prepared by Management in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and utilize the best estimates and careful judgments of Management, where appropriate. Operational and other financial information presented is consistent with that provided in the consolidated financial statements.

Management has developed and maintains a system of internal controls designed to provide reasonable assurance that all transactions are accurately and reliably recorded, that the consolidated financial statements accurately report the Corporation’s operating and financial results within acceptable limits of materiality, that all other operational and financial information presented is accurate, and that the Corporation’s assets are properly safeguarded.

The Audit Committee, comprised of non-management directors, acts on behalf of the Board of Directors to ensure that Management fulfills its financial reporting and internal control responsibilities. The Audit Committee is responsible for meeting regularly with Management, the external auditor, and the internal auditor to discuss internal controls over financial reporting processes, auditing matters and various aspects of financial reporting. The Audit Committee reviewed the consolidated financial statements with Management and the external auditor, and recommended approval to the Board of Directors. The Board of Directors has approved these consolidated financial statements.

PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, appointed by the shareholders as the external auditor of the Corporation, has audited the consolidated statement of financial position as at December 31, 2017 and 2016, and the consolidated statements of comprehensive income (loss), changes in shareholders’ equity and cash flows for the years ended December 31, 2017 and 2016. The external auditor conducted their audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) and have unlimited and unrestricted access to the Audit Committee.

Andy J. Mah	Craig Blackwood
President and Chief Executive Officer	Vice President Finance and Chief Financial Officer
March 5, 2018

Advantage Oil & Gas Ltd. - 1

Management’s Report on Internal Control over Financial Reporting

The Management of Advantage Oil & Gas Ltd. is responsible for establishing and maintaining adequate internal control over financial reporting for the Corporation as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision of our Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on our assessment, we have concluded that as of December 31, 2017, our internal control over financial reporting was effective.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation. Further, 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.

PricewaterhouseCoopers LLP, the Corporation’s independent firm of Chartered Professional Accountants, was appointed by the shareholders to audit and provide an independent opinion on both the consolidated financial statements and the Corporation’s internal control over financial reporting as at December 31, 2017, as stated in their Report of Independent Registered Public Accounting Firm. PricewaterhouseCoopers LLP has provided such opinion.

Andy J. Mah	Craig Blackwood
President and Chief Executive Officer	Vice President Finance and Chief Financial Officer
March 5, 2018

Advantage Oil & Gas Ltd. - 2

 

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Advantage Oil and Gas Ltd.

Opinions on the Consolidated Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying Consolidated Statement of Financial Position of Advantage Oil & Gas Ltd. and its subsidiaries, (together, the “Company”) as of December 31, 2017 and December 31, 2016, and the related Consolidated Statements of Comprehensive Income (Loss), Changes in Shareholders’ Equity and Cash Flows for the years then ended, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and December 31, 2016, and their financial performance and their cash flows for the years then ended in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board (IFRS). Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, 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 opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

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

PricewaterhouseCoopers LLP

Suncor Energy Centre, 111 5 Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3

T: +1 403 509 7500, F: +1 403 781 1825, www.pwc.com/ca

Advantage Oil & Gas Ltd. - 3

 

“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.

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 consolidated 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated 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 (iii) 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 consolidated 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.

 

Chartered Professional Accountants

Calgary, Alberta, Canada

March 5, 2018

We have served as the Company’s auditor since 2007.

Advantage Oil & Gas Ltd. - 4

Consolidated Statement of Financial Position
(thousands of Canadian dollars)	Notes	December 31, 2017			December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	5	$	6,916		$	-
Trade and other receivables	6		28,678			26,305
Prepaid expenses and deposits			1,602			1,681
Derivative asset	9		33,093			730
Total current assets			70,289			28,716
Non-current assets
Derivative asset	9		17,777			1,448
Exploration and evaluation assets	7		22,143			16,012
Property, plant and equipment	8		1,580,973			1,450,283
Total non-current assets			1,620,893			1,467,743
Total assets		$	1,691,182		$	1,496,459
LIABILITIES
Current liabilities
Trade and other accrued liabilities		$	51,004		$	34,153
Derivative liability	9		111			13,812
Total current liabilities			51,115			47,965
Non-current liabilities
Derivative liability	9		-			10,912
Bank indebtedness	10		208,978			153,102
Decommissioning liability	11		46,913			40,992
Deferred income tax liability	12		72,500			35,215
Total non-current liabilities			328,391			240,221
Total liabilities			379,506			288,186
SHAREHOLDERS' EQUITY
Share capital	13		2,340,801			2,334,199
Contributed surplus			110,077			108,315
Deficit			(1,139,202	)		(1,234,241	)
Total shareholders' equity			1,311,676			1,208,273
Total liabilities and shareholders' equity		$	1,691,182		$	1,496,459

Commitments (note 21)

See accompanying Notes to the Consolidated Financial Statements

On behalf of the Board of Directors of Advantage Oil & Gas Ltd.:

Paul G. Haggis, Director	Andy J. Mah, Director

Advantage Oil & Gas Ltd. - 5

Consolidated Statement of Comprehensive Income (Loss)              

		Year ended
		December 31
(thousands of Canadian dollars, except for per share amounts)	Notes	2017			2016
Natural gas and liquids sales	16	$	231,764		$	161,933
Royalty expense			(6,387	)		(4,900	)
Natural gas and liquids revenue			225,377			157,033
Operating expense			(21,729	)		(20,358	)
Transportation expense			(34,517	)		(6,982	)
General and administrative expense	17		(7,165	)		(7,469	)
Share based compensation	15		(5,119	)		(3,281	)
Depreciation expense	8		(117,945	)		(116,232	)
Exploration and evaluation expense	7		(168	)		-
Finance expense	18		(7,882	)		(10,250	)
Gains (losses) on derivatives	9		101,152			(13,687	)
Other income			320			878
Income (loss) before taxes			132,324			(20,348	)
Income tax recovery (expense)	12		(37,285	)		4,614
Net income (loss) and comprehensive income (loss)		$	95,039		$	(15,734	)
Net income (loss) per share	14
Basic		$	0.51		$	(0.09	)
Diluted		$	0.50		$	(0.09	)

See accompanying Notes to the Consolidated Financial Statements

Advantage Oil & Gas Ltd. - 6

Consolidated Statement of Changes in Shareholders' Equity

(thousands of Canadian dollars)	Notes	Share capital		Contributed surplus			Deficit			Total shareholders' equity
Balance, December 31, 2016		$	2,334,199	$	108,315		$	(1,234,241	)	$	1,208,273
Net income and comprehensive income			-		-			95,039			95,039
Share based compensation	15		-		8,364			-			8,364
Settlement of Performance Awards	13, 15(b)		5,374		(5,374	)		-			-
Exercise of Stock Options	13, 15(a)		1,228		(1,228	)		-			-
Balance, December 31, 2017		$	2,340,801	$	110,077		$	(1,139,202	)	$	1,311,676

(thousands of Canadian dollars)	Notes	Share capital		Contributed surplus			Deficit			Total shareholders' equity
Balance, December 31, 2015		$	2,236,728	$	103,726		$	(1,218,507	)	$	1,121,947
Net loss and comprehensive loss			-		-			(15,734	)		(15,734	)
Shares issued on financing	13		96,453		-			-			96,453
Share based compensation	15		-		5,607			-			5,607
Exercise of Stock Options	13, 15(a)		1,018		(1,018	)		-			-
Balance, December 31, 2016		$	2,334,199	$	108,315		$	(1,234,241	)	$	1,208,273

See accompanying Notes to the Consolidated Financial Statements

Advantage Oil & Gas Ltd. - 7

Consolidated Statement of Cash Flows
		Year ended
		December 31
(thousands of Canadian dollars)	Notes	2017			2016
Operating Activities
Income (loss) before taxes		$	132,324		$	(20,348	)
Add (deduct) items not requiring cash:
Share based compensation	15		5,119			3,281
Exploration and evaluation expense	7		168			-
Depreciation expense	8		117,945			116,232
Unrealized (gains) losses on derivatives	9		(73,305	)		66,781
Finance expense	18		7,882			10,250
Expenditures on decommissioning liability	11		(1,190	)		(1,857	)
Changes in non-cash working capital	20		(2,542	)		567
Cash provided by operating activities			186,401			174,906
Financing Activities
Increase (decrease) in bank indebtedness	10		56,189			(133,718	)
Net proceeds of equity financing	13		-			95,130
Interest paid			(7,244	)		(9,034	)
Cash provided by (used in) financing activities			48,945			(47,622	)
Investing Activities
Payments on property, plant and equipment	8, 20		(221,223	)		(121,283	)
Payments on exploration and evaluation assets	7		(7,207	)		(6,001	)
Cash used in investing activities			(228,430	)		(127,284	)
Increase in cash and cash equivalents			6,916			-
Cash and cash equivalents, beginning of year			-			-
Cash and cash equivalents, end of year		$	6,916		$	-

See accompanying Notes to the Consolidated Financial Statements

Advantage Oil & Gas Ltd. - 8

Notes to The Consolidated Financial Statements

For the years ended December 31, 2017 and 2016

All tabular amounts are in thousands of Canadian dollars except as otherwise indicated.

1. Business and structure of Advantage Oil & Gas Ltd.

Advantage Oil & Gas Ltd. and its subsidiaries (together “Advantage” or the “Corporation”) is an intermediate natural gas and liquids development and production corporation with a significant position in the Montney resource play located in Western Canada.

Advantage is domiciled and incorporated in Canada under the Business Corporations Act (Alberta). Advantage’s head office address is 300, 440 – 2^nd Avenue SW, Calgary, Alberta, Canada. The Corporation’s primary listing is on the Toronto Stock Exchange and is also traded on the New York Stock Exchange as a Foreign Private Issuer, under the symbol “AAV”.

2. Basis of preparation

(a) Statement of compliance

The Corporation prepares its consolidated financial statements in accordance with Canadian generally accepted accounting principles (“GAAP”) as defined in the Chartered Professional Accountants Canada Handbook (the “CPA Canada Handbook”). The CPA Canada Handbook incorporates International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. Publicly accountable enterprises, such as the Corporation, are required to apply these standards. Accordingly, these consolidated financial statements are prepared and issued under IFRS.

The accounting policies applied in these consolidated financial statements are based on IFRS issued and outstanding as of March 5, 2018, the date the Board of Directors approved the statements.

(b) Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis, except as detailed in the Corporation’s accounting policies in note 3.

The methods used to measure fair values of derivative instruments are discussed in note 9.

(c) Functional and presentation currency

These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s functional currency.

Advantage Oil & Gas Ltd. - 9

3. Significant accounting policies

The accounting policies set out below have been applied consistently to all years presented in these financial statements and notes.

(a) Cash and cash equivalents

Cash consists of balances held with banks, and other short-term highly liquid investments with original maturities of three months or less from inception.

(b) Basis of consolidation

(i) Subsidiaries

Subsidiaries are entities controlled by the Corporation. Control exists when the Corporation is exposed, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

(ii) Joint arrangements

A portion of the Corporation’s natural gas and liquids activities involve joint operations. The consolidated financial statements include the Corporation’s share of these joint operations and a proportionate share of the relevant revenue and costs.

(c) Financial instruments

All financial instruments are initially recognized at fair value on the Consolidated Statement of Financial Position. Measurement of financial instruments subsequent to the initial recognition, as well as resulting gains and losses, is based on how each financial instrument was initially classified. The Corporation has classified each identified financial instrument into the following categories: fair value through profit or loss, loans and receivables, held to maturity investments, available for sale financial assets, and financial assets and liabilities at amortized cost. Fair value through profit or loss financial instruments are measured at fair value with gains and losses recognized in income immediately. Available for sale financial assets are measured at fair value with gains and losses, other than impairment losses, recognized in other comprehensive income and transferred to income when the asset is derecognized. Loans and receivables, held to maturity investments and financial assets and liabilities at amortized cost, are recognized at amortized cost using the effective interest method and impairment losses are recorded in income when incurred.

Derivative instruments executed by the Corporation to manage market risk associated with volatile commodity prices are classified as fair value through profit or loss and recorded on the Consolidated Statement of Financial Position as derivatives assets and liabilities measured at fair value. Gains and losses on these instruments are recorded as gains and losses on derivatives in the Consolidated Statement of Comprehensive Income (Loss) in the period they occur. Gains and losses on derivative instruments are comprised of cash receipts and payments associated with periodic settlement that occurs over the life of the instrument, and non-cash gains and losses associated with changes in the fair values of the instruments, which are remeasured at each reporting date and recorded on the Consolidated Statement of Financial Position.

Advantage Oil & Gas Ltd. - 10

3. Significant accounting policies (continued)

(d) Property, plant and equipment and exploration and evaluation assets

(i) Recognition and measurement

Exploration and evaluation costs

Pre-license costs are recognized in the Consolidated Statement of Comprehensive Income (Loss) as incurred.

All exploratory costs incurred subsequent to acquiring the right to explore for natural gas and liquids before technical feasibility and commercial viability of the area have been established are capitalized. Such costs can typically include costs to acquire land rights, geological and geophysical costs and exploration well costs.

Exploration and evaluation costs are not depreciated and are accumulated in cost centers by well, field or exploration area and carried forward pending determination of technical feasibility and commercial viability.

The technical feasibility and commercial viability of extracting a mineral resource from exploration and evaluation assets is considered to be generally determinable when proved or probable reserves are determined to exist. Upon determination of proved or probable reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to property, plant and equipment, net of any impairment loss.

Management reviews and assesses exploration and evaluation assets to determine if technical feasibility and commercial viability exist. If Management decides not to continue the exploration and evaluation activity, the unrecoverable costs are charged to exploration and evaluation expense in the period in which the determination occurs.

Property, plant and equipment

Items of property, plant and equipment, which include natural gas and liquids properties, are measured at cost less accumulated depreciation and accumulated impairment losses. Costs include lease acquisition, drilling and completion, production facilities, decommissioning costs, geological and geophysical costs and directly attributable general and administrative costs and share based compensation related to development and production activities, net of any government incentive programs.

When significant parts of an item of property, plant and equipment, including natural gas and liquids properties, have different useful lives, they are accounted for as separate items (major components).

(ii) Subsequent costs

Costs incurred subsequent to development and production that are significant are recognized as natural gas and liquids property only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in comprehensive income as incurred. Such capitalized natural gas and liquids costs generally represent costs incurred in developing proved and probable reserves and producing or enhancing production from such reserves, and are accumulated on a field or area basis. The carrying amount of any replaced or sold component is derecognized in accordance with our policies. The costs of the day-to-day servicing of property, plant and equipment are recognized in the Consolidated Statement of Comprehensive Income (Loss) as incurred.

(iii) Depreciation

The net carrying value of natural gas and liquids properties is depreciated using the units-of-production (“UOP”) method by reference to the ratio of production in the period to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.

Advantage Oil & Gas Ltd. - 11

3. Significant accounting policies (continued)

(d) Property, plant and equipment and exploration and evaluation assets (continued)

(iv) Dispositions

Gains and losses on disposal of an item of property, plant and equipment, including natural gas and liquids properties, are determined by comparing the proceeds from disposition with the carrying amount of property, plant and equipment and are recognized net within other income (expenses) in the Consolidated Statement of Comprehensive Income (Loss).

(v) Impairment

The carrying amounts of the Corporation’s property, plant and equipment are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, the asset’s recoverable amount is estimated. For the purpose of impairment testing of property, plant and equipment, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the “cash-generating unit” or “CGU”).

Exploration and evaluation assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, and facts and circumstances suggest that the carrying amount exceeds the recoverable amount. Exploration and evaluation assets are allocated to CGU’s or groups of CGU’s for the purposes of assessing such assets for impairment.

The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs of disposition. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Fair value less costs of disposition is assessed utilizing market valuation based on an arm’s length transaction between active participants. In the absence of any such transactions, fair value less costs of disposition is estimated by discounting the expected after-tax cash flows of the cash generating unit at an after-tax discount rate that reflects the risk of the properties in the cash generating unit. The discounted cash flow calculation is then increased by a tax-shield calculation, which is an estimate of the amount that a prospective buyer of the cash generating unit would be entitled. The carrying value of the cash generating unit is reduced by the deferred tax liability associated with its property, plant and equipment.

Impairment losses on property, plant and equipment are recognized in the Consolidated Statement of Comprehensive Income (Loss) as impairment of natural gas and liquids properties and are separately disclosed. An impairment of exploration and evaluation assets is recognized as exploration and evaluation expense in the Consolidated Statement of Comprehensive Income (Loss).

(e) Decommissioning liability

A decommissioning liability is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Decommissioning liabilities are determined by discounting the expected future cash flows at a risk-free rate.

Advantage Oil & Gas Ltd. - 12

3. Significant accounting policies (continued)

(f) Share based compensation

Advantage accounts for share based compensation expense based on the fair value of rights granted under its share based compensation plans.

Advantage’s Stock Option Plan (“Stock Option Plan”) authorizes the Board of Directors to grant Stock Options to service providers, including directors, officers, employees and consultants of Advantage. Compensation costs related to the Stock Options are recognized as share based compensation expense over the vesting period at fair value.

Advantage’s Restricted and Performance Award Incentive Plan provides share based compensation for service providers. Awards granted under this plan may be settled in cash or in shares. As the Corporation generally intends to settle the Awards in shares, the plan is considered and accounted for as “equity-settled”.

As compensation expense is recognized, contributed surplus is recorded until the Performance Awards vest or Stock Options are exercised, at which time the appropriate common shares are then issued to the service providers and the contributed surplus is transferred to share capital.

(g) Revenue

Revenue from the sale of natural gas and liquids is recorded when the significant risks and rewards of ownership of the product is substantially transferred to the buyer.

(h) Finance expense

Finance expense comprises interest expense on bank indebtedness and accretion of the discount on the decommissioning liability.

(i) Income tax

Income tax expense or recovery comprises current and deferred income tax. Income tax expense or recovery is recognized in income or loss except to the extent that it relates to items recognized directly in shareholders’ equity.

Current income tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to income tax payable in respect of previous years.

Deferred income tax is recognized using the liability 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 income tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination, and at the time of the transaction, affects neither accounting income nor taxable income. Deferred income 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.

A deferred income 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 income 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. Deferred income tax assets and liabilities are only offset when they are within the same legal entity and same tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

(j) Net income (loss) per share

Basic net income (loss) per share is calculated by dividing the net income (loss) attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share is determined by adjusting the net income (loss) attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as Performance Awards and Stock Options granted to service providers using the treasury stock method.

(k) Investment tax credits

Investment tax credits relating to Scientific Research and Experimental Development claims are considered an income tax credit and are offset against our income tax expense when they become probable of realization.

Advantage Oil & Gas Ltd. - 13

3. Significant accounting policies (continued)

(l) Accounting Pronouncement not yet Adopted

IFRS 9 Financial Instruments introduces a new classification and measurement requirements, impairment model and hedge accounting model. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Advantage does not anticipate any material changes or effects to our current accounting.

IFRS 15 Revenue from Contracts with Customers requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. The standard is to be adopted for annual periods beginning on or after January 1, 2018, either retrospectively or using a modified retrospective approach. Advantage has individually assessed each current and possible future revenue stream using the principles established by IFRS 15. Based on these assessments, Advantage has determined that accounting for each of its revenue streams will be substantially the same under IFRS 15 as under current IFRS standards. Advantage does not anticipate any material impacts to its current accounting from the adoption of IFRS 15.

IFRS 16 Leases requires the recognition of assets and liabilities for most leases. The standard applies to annual periods beginning on or after January 1, 2019. Under IFRS 16, lease assets and liabilities will be required to be recognized on the balance sheet for most leases, where the entity is acting as a lessee. Certain leases of low-value assets and leases with short-terms (less than 12 months) will be exempt from the balance sheet recognition requirements, and may continue to be treated as operating leases. Advantage is currently reviewing the impact of IFRS 16 on its financial statements.

4. Significant accounting judgments, estimates and assumptions

The preparation of consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates, and differences could be material. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected. Significant estimates and judgments made in the preparation of the consolidated financial statements are outlined below.

(a) Reserves base

The natural gas and liquids properties are depreciated on a UOP basis at a rate calculated by reference to proved and probable reserves determined in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” and incorporating the estimated future cost of developing and extracting those reserves. Proved plus probable reserves are determined using estimates of natural gas and liquids in place, recovery factors and future natural gas and liquids prices. Future development costs are estimated using assumptions as to the number of wells required to produce the reserves, the cost of such wells and associated production facilities and other capital costs.

(b) Determination of cash generating unit

Management has determined there to be a single CGU (the “Glacier Area”) on the basis of its ability to generate independent cash flows, similar reserve characteristics, geographical location, and shared infrastructure, namely a single processing plant owned by Advantage. For purposes of assessment of impairment, management has allocated all exploration and evaluation assets to the Glacier Area CGU, on the basis of their geographic proximity.

(c) Impairment indicators and calculation of impairment

At each reporting date, Advantage assesses whether or not there are circumstances that indicate a possibility that the carrying values of exploration and evaluation assets and property, plant and equipment are not recoverable, or impaired. Such circumstances include, but are not limited to, incidents of physical damage, deterioration of commodity prices, changes in the regulatory environment, a reduction in estimates of proved and probable reserves, or significant increases to expected costs to produce and transport reserves.

When management judges that circumstances indicate potential impairment, property, plant and equipment are tested for impairment by comparing the carrying values to their recoverable amounts. The recoverable amounts of cash generating units are determined based on the higher of value-in-use calculations and fair values less costs of disposition. These calculations require the use of estimates and assumptions, that are subject to change as new information becomes available including information on future commodity prices, expected production volumes, quantities of reserves, discount rates, future development costs and operating costs.

Advantage Oil & Gas Ltd. - 14

4. Significant accounting judgements, estimates and assumptions (continued)

(d) Derivative assets and liabilities

Derivative assets and liabilities are recorded at their fair values at the reporting date, with gains and losses recognized directly into comprehensive income in the same period. The fair value of derivatives outstanding is an estimate based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are non-cash items and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions.

(e) Decommissioning liability

Decommissioning costs will be incurred by the Corporation at the end of the operating life of the Corporation’s facilities and properties. The ultimate decommissioning liability is uncertain and can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques, experience at other production sites, or changes in the risk-free discount rate. The expected timing and amount of expenditure can also change in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results.

(f) Income taxes

Income tax laws and regulations are subject to change. Deferred tax liabilities that arise from temporary differences between recorded amounts on the statement of financial position and their respective tax bases will be payable in future periods. The amount of a deferred tax liability is subject to management’s best estimate of when a temporary difference will reverse and expected changes in income tax rates. These estimates by nature involve significant measurement uncertainty.

Advantage Oil & Gas Ltd. - 15

5. Cash and cash equivalents

	December 31, 2017		December 31, 2016
Cash at financial institutions	$	6,916	$	-

Cash at financial institutions earns interest at floating rates based on daily deposit rates. As at December 31, 2017, cash at financial institutions included US$0.1 million (December 31, 2016: nil). The Corporation only deposits cash with major financial institutions of high quality credit ratings.

6. Trade and other receivables

	December 31, 2017		December 31, 2016
Trade receivables	$	25,384	$	25,087
Receivables from joint venture partners		1,425		581
Other		1,869		637
	$	28,678	$	26,305

7. Exploration and evaluation assets

Balance at December 31, 2015	$	10,071
Additions		6,001
Transferred to property, plant and equipment (note 8)		(60	)
Balance at December 31, 2016	$	16,012
Additions		7,207
Lease expiries		(168	)
Transferred to property, plant and equipment (note 8)		(908	)
Balance at December 31, 2017	$	22,143

Advantage Oil & Gas Ltd. - 16

8. Property, plant and equipment

Cost	Natural gas and  liquids properties			Furniture  and  equipment		Total
Balance at December 31, 2015	$	1,874,418		$	5,482	$	1,879,900
Additions		121,847			166		122,013
Change in decommissioning liability (note 11)		(2,641	)		-		(2,641	)
Transferred from exploration and evaluation assets (note 7)		60			-		60
Balance at December 31, 2016	$	1,993,684		$	5,648	$	1,999,332
Additions		241,449			118		241,567
Change in decommissioning liability (note 11)		6,160			-		6,160
Transferred from exploration and evaluation assets (note 7)		908			-		908
Balance at December 31, 2017	$	2,242,201		$	5,766	$	2,247,967

Accumulated depreciation	Natural gas and  liquids properties		Furniture  and  equipment		Total
Balance at December 31, 2015	$	428,905	$	3,912	$	432,817
Depreciation		115,885		347		116,232
Balance at December 31, 2016	$	544,790	$	4,259	$	549,049
Depreciation		117,643		302		117,945
Balance at December 31, 2017	$	662,433	$	4,561	$	666,994

Net book value	Natural gas and  liquids properties		Furniture  and  equipment		Total
At December 31, 2016	$	1,448,894	$	1,389	$	1,450,283
At December 31, 2017	$	1,579,768	$	1,205	$	1,580,973

During the year ended December 31, 2017, Advantage capitalized general and administrative expenditures directly related to development activities of $4.1 million (December 31, 2016 - $3.8 million). During the year ended December 31, 2017, Advantage capitalized share based compensation directly related to development activities of $3.2 million (December 31, 2016 - $2.3 million).

Advantage included future development costs of $1.7 billion (December 31, 2016 – $1.6 billion) in property, plant and equipment costs subject to depreciation.

Advantage Oil & Gas Ltd. - 17

9. Financial risk management

Financial instruments of the Corporation include trade and other receivables, deposits, trade and other accrued liabilities, bank indebtedness, and derivative assets and liabilities.

Trade and other receivables and deposits are classified as loans and receivables and measured at amortized cost. Trade and other accrued liabilities and bank indebtedness are all classified as financial liabilities at amortized cost. As at December 31, 2017, there were no significant differences between the carrying amounts reported on the Consolidated Statement of Financial Position and the estimated fair values of these financial instruments due to the short terms to maturity and the floating interest rate on the bank indebtedness.

Fair value is determined following a three level hierarchy:

Level 1: Quoted prices in active markets for identical assets and liabilities. The Corporation does not have any financial assets or liabilities that require level 1 inputs.

Level 2: Inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly. Such inputs can be corroborated with other observable inputs for substantially the complete term of the contract. Derivative assets and liabilities are measured at fair value on a recurring basis. For derivative assets and liabilities, pricing inputs include quoted forward prices for commodities, foreign exchange rates, volatility and risk-free rate discounting, all of which can be observed or corroborated in the marketplace. The actual gains and losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions.

Level 3: Fair value is determined using inputs that are not observable. Advantage has no assets or liabilities that use level 3 inputs.

Advantage Oil & Gas Ltd. - 18

9. Financial risk management (continued)

The Corporation’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:

· credit risk;

· liquidity risk;

· price risk; and

· interest rate risk.

(a) Credit risk

Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Corporation’s receivables from natural gas and liquids marketers and companies with whom we enter into derivative contracts. The maximum exposure to credit risk is as follows:

	December 31, 2017		December 31, 2016
Trade and other receivables	$	28,678	$	26,305
Deposits		938		665
Derivative asset		50,870		2,178
	$	80,486	$	29,148

Trade and other receivables, deposits, and derivative assets are subject to credit risk exposure and the carrying values reflect Management’s assessment of the associated maximum exposure to such credit risk. Advantage mitigates such credit risk by closely monitoring significant counterparties and dealing with a broad selection of counterparties that diversify risk within the sector. The Corporation’s deposits are due from the Alberta Provincial government and are viewed by Management as having minimal associated credit risk. To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities. In addition, the Corporation only enters into derivative contracts with major banks and international energy firms to further mitigate associated credit risk.

Substantially all of the Corporation’s trade and other receivables are due from customers concentrated in the Canadian oil and gas industry. As such, trade and other receivables are subject to normal industry credit risks. As at December 31, 2017, $0.2 million or 0.8% of trade and other receivables are outstanding for 90 days or more (December 31, 2016 - $0.4 million or 1.4% of trade and other receivables). The Corporation believes the entire balance is collectible, and in some instances has the ability to mitigate risk through withholding production or offsetting payables with the same parties. Management has not provided an allowance for doubtful accounts at December 31, 2017 or 2016.

The Corporation’s most significant customer, a Canadian oil and natural gas marketer, accounts for $19.2 million of the trade and other receivables at December 31, 2017 (December 31, 2016 - $22.2 million).

Advantage Oil & Gas Ltd. - 19

9. Financial risk management (continued)

(b) Liquidity risk

The Corporation is subject to liquidity risk attributed from trade and other accrued liabilities and bank indebtedness. Trade and other accrued liabilities are primarily due within one year of the Consolidated Statement of Financial Position date and Advantage does not anticipate any problems in satisfying the obligations from cash provided by operating activities and the existing credit facilities. The Corporation’s bank indebtedness is subject to $400 million credit facility agreements. Although the credit facilities are a source of liquidity risk, the facilities also mitigate liquidity risk by enabling Advantage to manage interim cash flow fluctuations. The terms of the credit facilities are such that they provide Advantage adequate flexibility to evaluate and assess liquidity issues if and when they arise. Additionally, the Corporation regularly monitors liquidity related to obligations by evaluating forecasted cash flows, optimal debt levels, capital spending activity, working capital requirements, and other potential cash expenditures. This continual financial assessment process further enables the Corporation to mitigate liquidity risk.

To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to liquidity risk as derivative liabilities become due. While the Corporation has elected not to follow hedge accounting, derivative instruments are not entered for speculative purposes and Management closely monitors existing commodity risk exposures. As such, liquidity risk is mitigated since any losses actually realized are offset by increased cash flows realized from the higher commodity price environment.

The timing of cash outflows relating to financial liabilities as at December 31, 2017 and 2016 are as follows:

December 31, 2017		Less than one year		One to  three years		Total
Trade and other accrued liabilities		$	51,004	$	-	$	51,004
Bank indebtedness	- principal		-		210,001		210,001
	- interest (1)		9,404		4,483		13,887
		$	60,408	$	214,484	$	274,892

December 31, 2016		Less than one year		One to  three years		Total
Trade and other accrued liabilities		$	34,153	$	-	$	34,153
Bank indebtedness	- principal		-		153,811		153,811
	- interest (1)		6,890		3,284		10,174
		$	41,043	$	157,095	$	198,138

⁽¹⁾ Interest on bank indebtedness was calculated assuming conversion of the revolving credit facility to a one-year term facility.

The Corporation’s bank indebtedness does not have specific maturity dates. It is governed by credit facility agreements with a syndicate of financial institutions (note 10). Under the terms of the agreements, the facilities are reviewed annually, with the next review scheduled in June 2018. The facilities are revolving and are extendible at each annual review for a further 364 day period at the option of the syndicate. If not extended, the credit facilities are converted at that time into one year term facilities, with the principal payable at the end of such one year terms. Management fully expects that the facilities will be extended at each annual review.

Advantage Oil & Gas Ltd. - 20

9. Financial risk management (continued)

(c) Price risk

Advantage’s derivative assets and liabilities are subject to price risk as their fair values are based on assumptions regarding forward commodity prices. The Corporation enters into non-financial derivatives to manage commodity price risk exposure relative to actual commodity production and does not utilize derivative instruments for speculative purposes. Changes in the price assumptions can have a significant effect on the fair value of the derivative assets and liabilities and thereby impact earnings. It is estimated that a 10% change in the forward AECO natural gas price used to calculate the fair value of the fixed price swap and sold call option natural gas derivatives at December 31, 2017 would result in a $4.7 million change in net income (loss) for the year ended December 31, 2017. It is estimated that a 10% change in the forward basis differential between Henry Hub and AECO natural gas prices would result in a $2.1 million change in net income (loss) for the year ended December 31, 2017. It is estimated that a 10% change in the forward Dawn natural gas price used to calculate the fair value of the fixed price swap natural gas derivatives at December 31, 2017 would result in a $3.3 million change in net income (loss) for the year ended December 31, 2017.

The Corporation’s derivative contracts are classified as Level 2 within the fair value hierarchy. As at December 31, 2017, the Corporation had the following derivative contracts in place:

Description of Derivative	Term	Volume	Price
Natural gas – AECO
Fixed price swap	April 2017 to March 2018	4,739 mcf/d	Cdn $3.27/mcf
Fixed price swap	April 2017 to March 2018	14,217 mcf/d	Cdn $3.27/mcf
Fixed price swap	November 2017 to March 2018	18,956 mcf/d	Cdn $3.22/mcf
Fixed price swap	July 2017 to March 2018	4,739 mcf/d	Cdn $3.02/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.01/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	July 2017 to June 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	April 2017 to March 2018	23,695 mcf/d	Cdn $3.01/mcf
Call option sold	April 2017 to December 2018	23,695 mcf/d	Cdn $3.17/mcf (1)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.01/mcf (2)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.06/mcf (3)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.11/mcf (4)
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	9,478 mcf/d	Cdn $3.00/mcf

⁽¹⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

⁽²⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.32/mcf.

⁽³⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.38/mcf.

⁽⁴⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2018 to September 2018	25,000 mcf/d	Henry Hub less US $0.95/mcf
Basis swap	January 2019 to December 2019	25,000 mcf/d	Henry Hub less US $0.90/mcf

Natural gas – Dawn

Fixed price swap December 2017 to March 2018  10,000 mcf/d US $3.45/mcf

Advantage Oil & Gas Ltd. - 21

9. Financial risk management (continued)

(c) Price risk (continued)

Subsequent to December 31, 2017, the Corporation entered into the following derivative contracts:

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2021 to December 2024	5,000 mcf/d	Henry Hub less US $1.135/mcf
Basis swap	January 2021 to December 2024	2,500 mcf/d	Henry Hub less US $1.185/mcf
Basis swap	January 2021 to December 2024	17,500 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2020	5,000 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2024	15,000 mcf/d	Henry Hub less US $1.20/mcf

As at December 31, 2017, the fair value of the derivatives outstanding resulted in an asset of $50.9 million (December 31, 2016 – $2.2 million) and a liability of $0.1 million (December 31, 2016 – $24.7 million). The fair value of the commodity risk management derivatives have been allocated to current assets and liabilities on the basis of expected timing of cash settlement.

For the year ended December 31, 2017, $101.2 million was recognized in net income (loss) as a derivative gain (December 31, 2016 - $13.7 million loss). The table below summarizes the realized and unrealized gains (losses) on derivatives recognized in net income (loss).

	Year ended		Year ended
	December 31, 2017		December 31, 2016
Realized gains on derivatives	$	27,847	$	53,094
Unrealized gains (losses) on derivatives		73,305		(66,781	)
Gains (losses) on derivatives	$	101,152	$	(13,687	)

(d) Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on the outstanding bank indebtedness fluctuates with the interest rates posted by the lenders. The Corporation is exposed to interest rate risk and has not entered into any mitigating interest rate hedges or swaps. Had the borrowing rate been different by 100 basis points throughout the year ended December 31, 2017, net income (loss) and comprehensive income (loss) would have changed by $1.2 million (December 31, 2016 - $1.5 million) based on the average debt balance outstanding during the year.

Advantage Oil & Gas Ltd. - 22

9. Financial risk management (continued)

(e) Capital management

The Corporation manages its capital with the following objectives:

· To ensure sufficient financial flexibility to achieve the ongoing business objectives including replacement of production, funding of future growth opportunities, and pursuit of accretive acquisitions; and

· To maximize shareholder return through enhancing the share value.

Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Corporation is composed of working capital (excluding derivative assets and liabilities), bank indebtedness, and share capital. Advantage may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing either through bank indebtedness or convertible debenture issuances, refinancing current debt, issuing other financial or equity-based instruments, declaring a dividend, adjusting capital spending, or disposing of assets. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis.

Advantage’s capital structure as at December 31, 2017 and 2016 is as follows:

	December 31, 2017		December 31, 2016
Bank indebtedness (non-current) (note 10)	$	208,978	$	153,102
Working capital deficit		13,808		6,167
Total debt (1)	$	222,786	$	159,269
Shares outstanding (note 13)		185,963,186		184,654,333
Share closing market price ($/share)	$	5.40	$	9.12
Market capitalization		1,004,201		1,684,048
Total capitalization	$	1,226,987	$	1,843,317

(1) Total debt is a non-GAAP measure that includes bank indebtedness and working capital deficit.

Advantage Oil & Gas Ltd. - 23

10. Bank indebtedness

	December 31, 2017			December 31, 2016
Revolving credit facility	$	210,001		$	153,811
Discount on Bankers Acceptances and other fees		(1,023	)		(709	)
Balance, end of year	$	208,978		$	153,102

As at December 31, 2017, the Corporation had reserve-based credit facilities (the "Credit Facilities") with a borrowing base of $400 million. The Credit Facilities are comprised of a $20 million extendible revolving operating loan facility from one financial institution and a $380 million extendible revolving credit facility from a syndicate of financial institutions. The revolving period for the Credit Facilities will end in June 2018 unless extended at the option of the syndicate for a further 364 day period. If not extended, the credit facility will be converted at that time into a one-year term facility, with the principal payable at the end of such one-year term. The Credit Facilities are subject to re-determination of the borrowing base semi-annually in October and June of each year, with the next annual review scheduled to occur in June 2018. There can be no assurance that the Credit Facilities will be renewed at the current borrowing base level at that time. The borrowing base is determined based on, among other things, a thorough evaluation of Advantage's reserve estimates based upon the lenders commodity price assumptions. Revisions or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing base. In the event that the lenders reduce the borrowing base below the amount drawn at the time of redetermination, the Corporation has 60 days to eliminate any shortfall by repaying amounts in excess of the new re-determined borrowing base. Amounts borrowed under the Credit Facilities bear interest at rates ranging from LIBOR plus 2% to 3.25% per annum, and Canadian prime or US base rate plus 1% to 2.25% per annum, in each case, depending on the type of borrowing and the Corporation’s debt to Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”) ratio. Undrawn amounts under the Credit Facilities bear a standby fee ranging from 0.5% to 0.8125% per annum, dependent on the Corporation’s debt to EBITDA ratio. Repayments of principal are not required prior to maturity provided that the borrowings under the Credit Facilities do not exceed the authorized borrowing base and the Corporation is in compliance with all covenants, representations and warranties. The Credit Facilities prohibit the Corporation from entering into any fixed price derivative contract, excluding basis swaps, where the term of such contract exceeds five years. Further, the aggregate of such contracts cannot hedge greater than 75% of total estimated natural gas and liquids production over the first three years and 50% over the fourth and fifth years. In addition, the Credit Facilities allow us to enter into basis swap arrangements to any natural gas price point in North America for up to 100,000 MMbtu/day with a maximum term of seven years. Basis swap arrangements do not count against the limitations on hedged production. The Credit Facilities contain standard commercial covenants for credit facilities of this nature. The Corporation did not have any financial covenants at December 31, 2017 and December 31, 2016. All applicable non-financial covenants were met at December 31, 2017 and 2016. Breach of any covenant will result in an event of default in which case the Corporation has 30 days to remedy such default. If the default is not remedied or waived, and if required by the lenders, the administrative agent of the lenders has the option to declare all obligations under the credit facilities to be immediately due and payable without further demand, presentation, protest, days of grace, or notice of any kind. The Credit Facilities are collateralized by a $1 billion floating charge demand debenture covering all assets. For the year ended December 31, 2017, the average effective interest rate on the outstanding amounts under the facilities was approximately 4.5% (December 31, 2016 – 3.5%). Advantage had no letters of credit issued and outstanding at December 31, 2017 (December 31, 2016 - none).

Advantage Oil & Gas Ltd. - 24

11. Decommissioning liability

The Corporation’s decommissioning liability results from net ownership interests in natural gas and liquids assets including well sites, gathering systems and processing facilities, all of which will require future costs of decommissioning under environmental legislation. These costs are expected to be incurred between 2018 and 2077. A risk-free rate of 2.20% (December 31, 2016 – 2.34%) and an inflation factor of 2.0% (December 31, 2016 – 2.0%) were used to calculate the fair value of the decommissioning liability at December 31, 2017. A reconciliation of the decommissioning liability is provided below:

	Year ended			Year ended
	December 31, 2017			December 31, 2016
Balance, beginning of year	$	40,992		$	44,575
Accretion expense		951			915
Property acquisitions		751			-
Liabilities incurred		2,175			2,193
Change in estimates		(2,665	)		(1,165	)
Effect of change in risk-free rate and inflation rate factor		5,899			(3,669	)
Liabilities settled		(1,190	)		(1,857	)
Balance, end of year	$	46,913		$	40,992

Advantage Oil & Gas Ltd. - 25

12. Income taxes

The provision for income taxes is as follows:

	Year ended		Year ended
	December 31, 2017		December 31, 2016
Current income tax expense	$	-	$	-
Deferred income tax expense (recovery)		37,285		(4,614	)
Income tax expense (recovery)	$	37,285	$	(4,614	)

The provision for income taxes varies from the amount that would be computed by applying the combined federal and provincial income tax rates for the following reasons:

	Year ended			Year ended
	December 31, 2017			December 31, 2016
Income (loss) before taxes	$	132,324		$	(20,348	)
Combined federal and provincial income tax rates		27.00	%		27.00	%
Expected income tax expense (recovery)		35,727			(5,494	)
Increase (decrease) in income taxes resulting from:
Non-deductible share based compensation		2,261			1,515
Difference between current and expected tax rates		(703	)		(635	)
	$	37,285		$	(4,614	)
Effective tax rate		28.18	%		22.68	%

The movement in deferred income tax liabilities and assets without taking into consideration the offsetting of balances within the same tax jurisdiction is as follows:

Deferred income tax liability	Property, plant and equipment		Derivative  asset/liability			Total
Balance at December 31, 2015	$	262,997	$	11,943		$	274,940
Charged (credited) to income		5,192		(18,031	)		(12,839	)
Balance at December 31, 2016	$	268,189	$	(6,088	)	$	262,101
Charged to income		13,522		19,793			33,315
Balance at December 31, 2017	$	281,711	$	13,705		$	295,416

Deferred income tax asset	Decommissioning liability			Non-capital losses			Other			Total
Balance at December 31, 2015	$	(12,064	)	$	(198,649	)	$	(23,075	)	$	(233,788	)
Charged to income		991			7,200			34			8,225
Credited to equity		-			(264	)		(1,059	)		(1,323	)
Balance at December 31, 2016	$	(11,073	)	$	(191,713	)	$	(24,100	)	$	(226,886	)
Charged (credited) to income		(1,593	)		5,268			295			3,970
Balance at December 31, 2017	$	(12,666	)	$	(186,445	)	$	(23,805	)	$	(222,916	)

Net deferred income tax liability (asset)
Balance at December 31, 2015	$	41,152
Credited to income		(4,614	)
Credited to equity		(1,323	)
Balance at December 31, 2016	$	35,215
Charged to income		37,285
Balance at December 31, 2017	$	72,500

Advantage Oil & Gas Ltd. - 26

12. Income taxes (continued)

The estimated tax pools available at December 31, 2017 are as follows:

Canadian development expenses	$	210,758
Canadian exploration expenses		65,994
Canadian oil and gas property expenses		14,631
Non-capital losses		690,538
Undepreciated capital cost		251,203
Capital losses		157,869
Scientific research and experimental development expenditures		32,506
Other		10,900
	$	1,434,399

The non-capital loss carry forward balances above expire no earlier than 2023.

No deferred tax asset has been recognized for capital losses of $158 million (December 31, 2016 – $158 million). Recognition is dependent on the realization of future taxable capital gains.

13. Share capital

(a) Authorized

The Corporation is authorized to issue an unlimited number of shares without nominal or par value.

(b) Issued

	Common Shares		Amount
Balance at December 31, 2015		170,827,158	$	2,236,728
Shares issued on financing, net of issue costs and deferred taxes		13,427,075		96,453
Shares issued on exercise of stock options (note 15(a))		400,100		-
Contributed surplus transferred on exercise of stock options (note 15(a))		-		1,018
Balance at December 31, 2016		184,654,333	$	2,334,199
Shares issued on Performance Award settlement (note 15(b))		825,359		-
Contributed surplus transferred on Performance Award settlement (note 15(b))		-		5,374
Shares issued on exercise of stock options (note 15(a))		483,494		-
Contributed surplus transferred on exercise of stock options (note 15(a))		-		1,228
Balance at December 31, 2017		185,963,186	$	2,340,801

On March 8, 2016, the Corporation closed an equity financing whereby 13,427,075 common shares were issued at $7.45 per share, for gross proceeds of $100 million, less $3.6 million related to $4.9 million of issuance costs net of $1.3 million of deferred taxes.

Advantage Oil & Gas Ltd. - 27

14. Net income (loss) per share

The calculations of basic and diluted net income (loss) per share are derived from both net income (loss) and weighted average shares outstanding, calculated as follows:

	Year ended
	December 31
	2017		2016
Net income (loss)
Basic and diluted	$	95,039	$	(15,734	)
Weighted average shares outstanding
Basic		185,641,050		182,056,120
Stock Options		389,977		-
Performance Awards		3,545,861		-
Diluted		189,576,888		182,056,120

The calculation of diluted net income (loss) per share for the year ended December 31, 2016 excludes the effects of Stock Options and Performance Awards, as their impacts would be anti-dilutive. Total weighted average shares of 866,241 and 648,037 in respect of Stock Options and Performance Awards, respectively, were excluded from the diluted net income (loss) per share calculation.

Advantage Oil & Gas Ltd. - 28

15. Share based compensation

(a) Stock Option Plan

Under the Stock Option Plan, service providers are granted Stock Options with exercise prices that approximate the market price of common shares at the date of grant. Share based compensation costs of the Stock Option Plan are determined using a Black-Scholes valuation model, using weighted average assumptions as follows:

Volatility	41	%
Expected forfeiture rate	0.98	%
Dividend rate	0	%
Risk-free rate	1.05	%

Volatility is based on historical stock prices at the close-of-trade-day over a historical time period.

The following tables summarize information about changes in Stock Options outstanding at December 31, 2017:

	Stock Options			Weighted-Average Exercise Price
Balance at December 31, 2015		4,031,302		$	5.49
Exercised		(921,387	)		4.64
Balance at December 31, 2016		3,109,915		$	5.75
Exercised		(1,085,681	)	$	4.72
Forfeited		(18,377	)		6.82
Balance at December 31, 2017		2,005,857		$	6.30

	Stock Options Outstanding						Stock Options Exercisable
Range of Exercise Price	Number of Stock Options Outstanding		Weighted Average Remaining Contractual Life - Years		Weighted Average Exercise Price		Number of Stock Options Exercisable		Weighted Average Exercise Price
$5.87 - $6.81		1,110,009		1.29	$	5.87		1,110,009	$	5.87
$6.82		895,848		2.26		6.82		584,927		6.82
$5.87 - $6.82		2,005,857		1.72	$	6.30		1,694,936	$	6.20

During the year ended December 31, 2017, 1,085,681 Stock Options were exercised with no cash consideration, resulting in the issuance of 483,494 common shares.

Advantage Oil & Gas Ltd. - 29

15. Share based compensation (continued)

(b) Performance Incentive Plan

Under the Performance Incentive Plan, service providers can be granted two types of Incentive Awards: Restricted Awards and Performance Awards. A Restricted Award is a grant denominated in a fixed number of common shares which generally vests 1/3 on the first anniversary of the grant date, 1/3 on the second anniversary, and 1/3 on the third anniversary. A Performance Award is a grant denominated in a fixed number of common shares which vests on the third anniversary of the grant date. Performance Award grants are multiplied by a Payout Multiplier, that is determined based on Corporate Performance Measures, as approved by the Board of Directors.

As at December 31, 2017, no Restricted Awards have been granted.

The following table is a continuity of Performance Awards:

	Performance Awards
Balance at December 31, 2015		666,092
Granted		661,571
Balance at December 31, 2016		1,327,663
Granted		723,676
Settlements		(402,582	)
Forfeited/cancelled		(68,458	)
Balance at December 31, 2017		1,580,299

During April 2017, 402,582 Performance Awards matured and were settled with no cash consideration, resulting in the issuance of 825,359 common shares, after applying the Payout Multiplier.

Share based compensation recognized by plan for the years ended December 31, 2017 and 2016 are as follows:

	Year ended
	December 31
	2017			2016
Stock Options	$	355		$	784
Performance Awards		8,009			4,823
Total share based compensation		8,364			5,607
Capitalized (note 8)		(3,245	)		(2,326	)
Net share based compensation expense	$	5,119		$	3,281

Advantage Oil & Gas Ltd. - 30

16. Natural gas and liquids sales

	Year ended
	December 31
	2017		2016
Natural gas sales	$	207,623	$	145,878
Natural gas liquids sales		24,141		16,055
Total natural gas and liquids sales	$	231,764	$	161,933

17. General and administrative expense (“G&A”)

	Year ended
	December 31
	2017			2016
Salaries and benefits	$	8,741		$	7,332
Office rent		1,069			989
Other		1,432			2,952
Total G&A		11,242			11,273
Capitalized (note 8)		(4,077	)		(3,804	)
General and administrative expense	$	7,165		$	7,469

18. Finance expense

	Year ended
	December 31
	2017		2016
Interest on bank indebtedness (note 10)	$	6,931	$	9,335
Accretion of decomissioning liability (note 11)		951		915
Total finance expense	$	7,882	$	10,250

19. Related party transactions

Key management compensation

The compensation paid or payable to officers and directors is as follows:

	Year ended  December 31, 2017		Year ended December 31, 2016
Salaries, director fees and short-term benefits	$	2,495	$	2,111
Share based compensation (1)		4,300		2,676
	$	6,795	$	4,787

⁽¹⁾ Represents the grant date fair value of Performance Awards and Stock Options granted.

As at December 31, 2017, there is a commitment of $2.9 million (December 31, 2016 - $2.2 million) related to change of control or termination of employment of officers.

Advantage Oil & Gas Ltd. - 31

20. Supplementary cash flow information

Changes in non-cash working capital is comprised of:

	Year ended
	December 31
	2017			2016
Source (use) of cash:
Trade and other receivables	$	(2,373	)	$	(12,417	)
Prepaid expenses and deposits		79			285
Trade and other accrued liabilities		16,850			11,103
	$	14,556		$	(1,029	)
Related to operating activities	$	(2,542	)	$	567
Related to financing activities		-			-
Related to investing activities		17,098			(1,596	)
	$	14,556		$	(1,029	)

21. Commitments

Advantage has lease commitments relating to office buildings of $1.8 million (December 31, 2016 - $3.0 million) and transportation commitments of $384.9 million (December 31, 2016 - $180.2 million). The estimated remaining annual minimum payments are as follows:

	December 31
	2017		2016
2017	$	-	$	26,067
2018		47,327		27,338
2019		51,316		28,519
2020		49,941		21,850
2021		45,997		17,892
2022		43,885		17,566
2023 and thereafter		148,239		43,980
Total commitments	$	386,705	$	183,212

Advantage Oil & Gas Ltd. - 32

Directors   Jill T. Angevine ⁽¹⁾⁽³⁾ Stephen E. Balog ^(1)(2)(3) Grant B. Fagerheim ⁽²⁾⁽³⁾ Paul G. Haggis ^(1)(2)(3) Andy J. Mah Ronald A. McIntosh ^{(2)(3)   (1)} Member of Audit Committee ⁽²⁾ Member of Reserve Evaluation Committee ⁽³⁾ Member of Human Resources, Compensation & Corporate Governance Committee   Officers   Andy J. Mah, President and CEO Craig Blackwood, Vice President, Finance and CFO Neil Bokenfohr, Senior Vice President   Corporate Secretary   Jay P. Reid, Partner Burnet, Duckworth and Palmer LLP   Auditors   PricewaterhouseCoopers LLP   Bankers   The Bank of Nova Scotia National Bank of Canada Royal Bank of Canada Canadian Imperial Bank of Commerce The Bank of Tokyo-Mitsubishi UFJ, Ltd., Canada Branch Alberta Treasury Branches Wells Fargo Bank N.A., /Canada Branch   Independent Reserve Evaluators   Sproule Associates Limited Legal Counsel   Burnet, Duckworth and Palmer LLP   Transfer Agent   Computershare Trust Company of Canada   Abbreviations   bbls            - barrels bbls/d        - barrels per day boe             - barrels of oil equivalent (6 mcf = 1 bbl) boe/d         - barrels of oil equivalent per day mcf             - thousand cubic feet mcf/d         - thousand cubic feet per day mmcf          - million cubic feet mmcf/d      - million cubic feet per day mcfe           - thousand cubic feet equivalent (1 bbl = 6 mcf) mcfe/d       - thousand cubic feet equivalent per day bcf              - billion cubic feet gj                - gigajoules NGLs         - natural gas liquids WTI           - West Texas Intermediate   Corporate Office   300, 440 – 2nd Avenue SW Calgary, Alberta T2P 5E9 (403) 718-8000   Contact Us   Toll free: 1-866-393-0393 Email: ir@advantageog.com Visit our website at www.advantageog.com   Stock Exchange Trading Symbol   (Toronto Stock Exchange and New York Stock Exchange)   Shares: AAV

Advantage Oil & Gas Ltd. - 33

EX-99.3

Exhibit 99.3

CONSOLIDATED MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis (“MD&A”), dated as of March 5, 2018, provides a detailed explanation of the consolidated financial and operating results of Advantage Oil & Gas Ltd. (“Advantage”, the “Corporation”, “us”, “we” or “our”) for the three months and year ended December 31, 2017 and should be read in conjunction with the December 31, 2017 audited consolidated financial statements. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”), representing generally accepted accounting principles (“GAAP”) for publicly accountable enterprises in Canada. All references in the MD&A and consolidated financial statements are to Canadian dollars unless otherwise indicated.

This MD&A contains non-GAAP measures and forward-looking information. Readers are advised to read this MD&A in conjunction with both the “Non-GAAP Measures” and “Forward-looking Information and Other Advisories” found at the end of this MD&A.

	Three months ended						Year ended
Financial and Operating Highlights	December 31						December 31
	2017			2016			2017			2016
Financial ($000, except as otherwise indicated)
Sales including realized hedging	$	65,779		$	71,090		$	259,611		$	215,027
Net income	$	21,425		$	(8,845	)	$	95,039		$	(15,734	)
per share	$	0.12		$	(0.05	)	$	0.51		$	(0.09	)
Funds from operations (1)	$	43,883		$	54,610		$	183,202		$	166,861
per share (2)	$	0.24		$	0.30		$	0.99		$	0.92
Total capital expenditures	$	73,723		$	30,043		$	248,774		$	128,014
Working capital deficit	$	13,808		$	6,167		$	13,808		$	6,167
Bank indebtedness	$	208,978		$	153,102		$	208,978		$	153,102
Basic weighted average shares (000)		185,963			184,641			185,641			182,056
Operating
Daily Production
Natural gas (mcf/d)		237,780			215,369			228,583			197,852
Liquids (bbls/d)		1,227			949			1,218			915
Total mcfe/d		245,142			221,063			235,891			203,342
Total boe/d		40,857			36,844			39,315			33,890
Average prices (including hedging)
Natural gas ($/mcf)	$	2.69		$	3.35		$	2.82		$	2.75
Liquids ($/bbl)	$	60.48		$	53.01		$	54.28		$	47.97
Cash netbacks ($/mcfe) (1)
Natural gas and liquids sales	$	2.38		$	3.17		$	2.69		$	2.18
Realized gains on derivatives		0.53			0.32			0.32			0.71
Royalty expense		(0.07	)		(0.18	)		(0.07	)		(0.07	)
Operating expense		(0.26	)		(0.22	)		(0.25	)		(0.27	)
Transportation expense (3)		(0.50	)		(0.26	)		(0.40	)		(0.09	)
Operating netback (1)		2.08			2.83			2.29			2.46
General and administrative		(0.05	)		(0.08	)		(0.08	)		(0.10	)
Finance expense		(0.09	)		(0.09	)		(0.08	)		(0.13	)
Other income		-			0.02			-			0.01
Cash netbacks (1)	$	1.94		$	2.68		$	2.13		$	2.24

⁽¹⁾ Non-GAAP Measure which may not be comparable to similar non-GAAP measures used by other entities. Please see "Non-GAAP Measures".

⁽²⁾ Based on basic weighted average shares outstanding.

⁽³⁾ Commencing on November 1, 2016, Advantage requested that its natural gas marketing contract be modified to reflect natural gas transportation as a cost. Prior to November 1, 2016, Advantage's realized natural gas prices were reduced for natural gas transportation from the sales points to AECO. This change has no effect on cash flow, cash netbacks, or net income; however, Advantage believes this is more instructive for our investors to compare cost structures going forward.

Advantage Oil & Gas Ltd. - 1

Natural Gas and Liquids Sales

	Three months ended							Year ended
	December 31							December 31
($000)	2017		2016		% change			2017		2016		% change
Natural gas sales	$	46,950	$	59,925		(22	)%	$	207,623	$	145,878		42	%
Realized gains on derivatives		12,002		6,534		84	%		27,847		53,094		(48	)%
Natural gas sales including derivatives		58,952		66,459		(11	)%		235,470		198,972		18	%
Liquids sales		6,827		4,631		47	%		24,141		16,055		50	%
Total (1)	$	65,779	$	71,090		(7	)%	$	259,611	$	215,027		21	%

(1) Total excludes unrealized derivative gains and losses.

For the three months ended December 31, 2017, total sales including realized derivative gains was $65.8 million, a decrease of $5.3 million or 7% as compared to the same period of 2016. The decrease to total sales was primarily attributable to a 29% decrease in realized natural gas prices, partially offset by a 14% increase in realized liquids prices, an 11% increase in total production and an 84% increase in realized gains on derivatives. For the year ended December 31, 2017, total sales including realized derivative gains was $259.6 million, an increase of $44.6 million or 21% that was primarily attributable to a 16% increase in total production and a 24% increase in realized natural gas prices, partially offset by lower realized gains on derivatives due to differences in natural gas prices and contracts outstanding during the periods (see “Commodity Price Risk Management and Market Diversification”).

Natural gas sales were positively impacted by Advantage’s ongoing commodity price risk management and market diversification initiatives. Commencing November 1, 2017, approximately 20% of our natural gas production volumes were sold at the Dawn market in Southern Ontario, which realized higher average prices than AECO (see “Commodity Prices and Marketing”). Advantage has also continued to proactively manage commodity price risk through entering into derivative transactions which resulted in realized prices that exceeded benchmark prices with gains of $12.0 million and $27.8 million for the three months and year ended December 31, 2017, respectively.

Liquids sales increased significantly due to higher realized liquids prices and additional Middle Montney wells coming on production, for which liquids are extracted at our Glacier gas plant refrigeration facilities. Liquids production was comprised of approximately 71% condensate during 2017.

Production

	Three months ended									Year ended
	December 31									December 31
	2017			2016			% change			2017			2016			% change
Natural gas (mcf/d)		237,780			215,369			10	%		228,583			197,852			16	%
Liquids (bbls/d)		1,227			949			29	%		1,218			915			33	%
Total - mcfe/d		245,142			221,063			11	%		235,891			203,342			16	%
- boe/d		40,857			36,844			11	%		39,315			33,890			16	%
Natural gas (%)		97	%		97	%					97	%		97	%
Liquids (%)		3	%		3	%					3	%		3	%

For the three months and year ended December 31, 2017, total production increased 11% to a record 245 mmcfe/d and 16% to 236 mmcfe/d, respectively, as compared to 2016. Total production has continued to increase due to the success of our Montney development program. Annual average production for 2018 is expected to be between 255 and 265 mmcfe/d, with a 56% increase to annual average liquids production to 1,900 bbls/d, consisting of 73% condensate. Production in the first and second quarters of 2018 is anticipated to be consistent with the fourth quarter of 2017. A planned shut-down of our Glacier gas plant necessary to tie-in new equipment and complete the expansion of the Glacier Gas Plant to 400 mmcf/d processing capacity has been incorporated into our 2018 production guidance.

Advantage Oil & Gas Ltd. - 2

Commodity Prices and Marketing

	Three months ended							Year ended
	December 31							December 31
	2017		2016		% change			2017		2016		% change
Average Realized Prices
Natural gas, excluding hedging ($/mcf)	$	2.15	$	3.02		(29	)%	$	2.49	$	2.01		24	%
Natural gas, including hedging ($/mcf)	$	2.69	$	3.35		(20	)%	$	2.82	$	2.75		3	%
Liquids, excluding and including hedging ($/bbl)	$	60.48	$	53.01		14	%	$	54.28	$	47.97		13	%
Benchmark Prices
AECO daily ($/mcf)	$	1.69	$	3.09		(45	)%	$	2.15	$	2.16		-	%
AECO monthly ($/mcf)	$	1.95	$	2.81		(31	)%	$	2.43	$	2.09		16	%
Dawn daily ($US/mmbtu)	$	3.77	$	4.29		(12	)%	$	3.96	$	3.42		16	%
Henry Hub ($US/mmbtu)	$	2.94	$	2.95		-	%	$	3.11	$	2.43		28	%
Edmonton Light ($/bbl)	$	66.89	$	60.76		10	%	$	62.26	$	52.27		19	%
Exchange rate (US$/CDN$1.00)		0.7865		0.7497		5	%		0.7712		0.7550		2	%

As part of our ongoing market diversification, commencing November 2017 we began delivering approximately 20% of our natural gas production to the Dawn market in Southern Ontario. Realized natural gas prices, excluding hedging, for the three months ended December 31, 2017 were lower than the fourth quarter of 2016 due to significantly weaker AECO prices, while realized natural gas prices for the year ended December 31, 2017 were higher than 2016 due primarily to stronger average AECO monthly prices and natural gas transportation expense which was previously deducted from our gas sales price. Alberta natural gas prices, in particular AECO, were very volatile during the third quarter of 2017 and continuing into October due to pipeline maintenance and expansion activities conducted by TransCanada Pipeline (“TCPL”) on the Alberta system. This resulted in various receipt and delivery curtailments that placed pressure on prices beginning in July and were more pronounced in September and October 2017. We believe that significant downward pressure on AECO prices has resulted primarily from restrictions in delivery interruptible service that has limited periodic inventory injections causing an extremely tight market with little flexibility for the growing natural gas supply to clear the system. With the reduction in maintenance and restrictions as we progress through the winter season, we would expect the market to be better balanced with less price volatility, albeit at Alberta natural gas prices lower than is typical of winter.

Advantage participated in TCPL’s long term, fixed price service open season whereby industry committed to transporting approximately 1.5 bcf/d from Empress, Alberta to the Dawn market. Advantage’s commitment to this firm transportation service was 55,600 GJ/d (52,700 mcf/d) that began November 1, 2017. The Dawn market provides Advantage with additional physical market diversification from AECO with a corresponding increase in transportation expense to access this market. During the three months and year ended December 31, 2017, Advantage realized $5.4 million of incremental revenue from the Dawn market (the excess of Dawn realized prices over AECO daily prices for volumes sold at Dawn).

Prior to November 1, 2016, the natural gas prices we realized were reduced for transportation from the sales points to AECO. Commencing on November 1, 2016, gas transportation is no longer deducted from realized natural gas prices, but rather presented as Transportation Expense (see “Transportation Expense”).

Advantage Oil & Gas Ltd. - 3

Commodity Price Risk Management and Market Diversification

The Corporation’s financial results and condition will be dependent on the prices received for natural gas production. Natural gas prices have fluctuated widely and are determined by supply and demand factors, including weather, and general economic conditions in natural gas consuming and producing regions throughout North America. Management has been proactive in entering into derivative contracts for the purposes of reducing cash flow volatility and diversifying price realizations to multiple markets in support of our Montney development plans. Advantage’s Credit Facilities allow us to enter fixed price derivative contracts up to 75% of total estimated natural gas and liquids production over the first three years and up to 50% over the fourth and fifth years. In addition, the Credit Facilities allow us to enter into basis swap arrangements to any natural gas price point in North America for up to 100,000 MMbtu/day with a maximum term of seven years. Basis swap arrangements do not count against the limitations on hedged production.

Our natural gas production and corresponding derivative contracts are expected to result in the realization of the following fixed and variable market prices for 2018:

	January 1 to December 31, 2018
				% of
	Volumes Contracted			Estimated Production
	(mmcf/d)		Average Minimum Price	(net of royalties)
Fixed Price
AECO fixed price swaps		61.1	$2.99/mcf		25	%
Dawn fixed price swaps		30.0	US$2.86/mcf		12	%
		91.1			37	%
Variable Price
AECO		108.5	AECO		45	%
Dawn		22.7	Dawn		10	%
AECO / Henry Hub basis swaps		18.8	Henry Hub less US$0.95/mcf		8	%
		150.0			63	%
Total Natural Gas (2)		241.1			100	%

(1)	All volumes contracted converted to mcf on the basis of 1 mcf = 1.055056 GJ and 1 mcf = 1 mmbtu
(2)	Represents the midpoint of our Guidance for 2018 Budget gas volumes (see News Release dated December 11, 2017)

A summary of realized and unrealized derivative gains and losses for the three months and years ended December 31, 2017 and 2016 are as follows:

	Three months ended								Year ended
	December 31								December 31
($000)	2017		2016			% change			2017		2016			% change
Realized gains on derivatives	$	12,002	$	6,534			84	%	$	27,847	$	53,094			(48	)%
Unrealized gains (losses) on derivatives		17,200		(36,587	)		(147	)%		73,305		(66,781	)		(210	)%
Gains (losses) on derivatives	$	29,202	$	(30,053	)		(197	)%	$	101,152	$	(13,687	)		(839	)%

For the three months and year ended December 31, 2017 and 2016, Advantage realized derivative gains as a result of natural gas prices decreasing to levels below our average derivative contract prices. For the three months and year ended December 31, 2017, Advantage recognized unrealized derivative gains of $17.2 million and $73.3 million, resulting from an increase in the fair value of our derivative contracts to a net asset of $50.8 million at December 31, 2017 as compared to a net asset of $33.6 million at September 30, 2017 and a net liability of $22.5 million at December 31, 2016. The fair value of the net derivative asset or liability is the estimated value to settle the outstanding contracts as at a point in time. As such, unrealized derivative gains and losses do not impact funds from operations and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. The increases in the fair value of our outstanding derivative contracts over the three months and year ended December 31, 2017 were primarily due to decreases in natural gas prices. Remaining derivative contracts will settle between January 1, 2018 and December 31, 2024.

Advantage Oil & Gas Ltd. - 4

Royalty Expense

	Three months ended									Year ended
	December 31									December 31
	2017			2016			% change			2017			2016			% change
Royalty expense ($000)	$	1,575		$	3,637			(57	)%	$	6,387		$	4,900			30	%
per mcfe	$	0.07		$	0.18			(61	)%	$	0.07		$	0.07			-	%
Royalty Rate (percentage of natural gas and liquids sales)		2.9	%		5.6	%		(2.7	)%		2.8	%		3.0	%		(0.2	)%

Advantage pays royalties to the owners of mineral rights from which we have leases. The Corporation has mineral leases with provincial governments, individuals and other companies. Our current average royalty rates are determined by various royalty regimes that incorporate factors including well depths, well production rates, and commodity prices. Royalties also include the impact of gas cost allowance (“GCA”) which is a reduction of royalties payable to the Alberta Provincial Government (the “Crown”) to recognize capital and operating expenditures incurred by Advantage in the gathering and processing of the Crown’s share of our natural gas production. Royalty expense for the year ended December 31, 2017 was higher than 2016, primarily due to increased corporate production and higher realized commodity prices in 2017 and a $2.1 million GCA recovery in the second quarter of 2016. Due to lower realized prices during the fourth quarter of 2017, royalty expense was lower than the comparative period of 2016. Advantage can experience significantly reduced royalty rates during periods of low commodity prices. We anticipate a 2018 average royalty rate of between 3.0% and 5.0%.

Operating Expense

	Three months ended							Year ended
	December 31							December 31
	2017		2016		% change			2017		2016		% change
Operating expense ($000)	$	5,967	$	4,490		33	%	$	21,729	$	20,358		7	%
per mcfe	$	0.26	$	0.22		18	%	$	0.25	$	0.27		(7	)%

Operating expense per mcfe for the year ended December 31, 2017 decreased by 7% to $0.25/mcfe as compared to 2016. Lower operating expense per mcfe was due to reduced water disposal and handling costs attributable to an additional 100% owned water disposal well which was placed in-service in 2016, continued efficiency improvement with equipment maintenance procedures and higher plant throughput. Operating expense was lower during the three months ended December 31, 2016 at $0.22/mcfe due to a short period of third party processing volumes that was accepted into our Glacier gas plant during that quarter.

Advantage Oil & Gas Ltd. - 5

Transportation Expense

	Three months ended							Year ended
	December 31							December 31
	2017		2016		% change			2017		2016		% change
Transportation expense
Natural gas ($000)	$	10,316	$	4,217		145	%	$	30,770	$	4,217		630	%
per mcf	$	0.29	$	0.21		38	%	$	0.37	$	0.06		517	%
Liquids ($000)	$	1,034	$	1,006		3	%	$	3,747	$	2,765		36	%
per bbl	$	5.92	$	6.66		(11	)%	$	8.43	$	8.27		2	%
Total transportation expense ($000)	$	11,350	$	5,223		117	%	$	34,517	$	6,982		394	%
per mcfe	$	0.50	$	0.26		92	%	$	0.40	$	0.09		344	%

Transportation expense represents the cost of transporting our natural gas and liquids to the sales points, including associated fuel costs. Higher liquids recoveries and production at our Glacier gas plant resulted in increased liquids transportation expense for the year ended December 31, 2017 as compared to 2016 (see “Production”). Natural gas transportation expense for the three months and year ended December 31, 2017 increased significantly from the same periods of 2016 due to the change in contract assignment discussed below, as well as Advantage’s participation in TCPL’s long term, fixed price service open season from Empress, Alberta to the Dawn market, which commenced November 1, 2017. Advantage’s commitment to this firm transportation service is 55,600 GJ/d (52,700 mcf/d), representing approximately 20% of our current production. Dawn provides Advantage with additional physical market diversification from AECO with a corresponding increase in transportation expense to access this market. Transportation under our firm commitment from AECO to Dawn is approximately $1.10/mcf. During the three months and year ended December 31, 2017, Advantage incurred incremental transportation expense of $3.6 million to the Dawn market.

Prior to November 1, 2016, natural gas transportation was presented as a reduction against realized natural gas prices (see “Commodity Prices and Marketing”) as our transportation contracts were permanently assigned to a third party marketer. With the increase in transportation commitments corresponding to our continued growth, commencing November 1, 2016 Advantage chose to have these contracts permanently assigned back to Advantage and natural gas transportation expense is presented separately. This change has no effect on funds from operations, cash netbacks, or net income.

General and Administrative Expense

	Three months ended							Year ended
	December 31							December 31
	2017		2016		% change			2017		2016		% change
General and administrative expense	$	1,052	$	1,680		(37	)%	$	7,165	$	7,469		(4	)%
per mcfe	$	0.05	$	0.08		(38	)%	$	0.08	$	0.10		(20	)%
Employees at December 31									29		27		7	%

General and administrative (“G&A”) expense for the year ended December 31, 2017 was mainly consistent with 2016 and decreased 20% on a per mcfe basis to $0.08/mcfe due to the higher production during 2017. G&A expense for 2017 was modestly lower than 2016 due to additional legal fees incurred during 2016 associated with an equity financing and lower director compensation costs in 2017 related to the revaluation of deferred share units at the current lower share price.

Advantage Oil & Gas Ltd. - 6

Finance Expense

	Three months ended							Year ended
	December 31							December 31
	2017		2016		% change			2017		2016		% change
Finance expense
Cash expense ($000)	$	1,968	$	1,913		3	%	$	6,931	$	9,335		(26	)%
per mcfe	$	0.09	$	0.09		-	%	$	0.08	$	0.13		(38	)%
Accretion expense ($000)	$	223	$	291		(23	)%	$	951	$	915		4	%
per mcfe	$	0.01	$	0.01		-	%	$	0.01	$	0.01		-	%
Total finance expense ($000)	$	2,191	$	2,204		(1	)%	$	7,882	$	10,250		(23	)%
per mcfe	$	0.10	$	0.10		-	%	$	0.09	$	0.14		(36	)%

Advantage’s average outstanding bank indebtedness was lower during the year ended December 31, 2017 compared to 2016 due to proceeds from the equity financing that closed on March 8, 2016, partly offset by the use of bank debt to partially support the 2017 capital program. The lower average bank indebtedness contributed to a decrease in cash finance expense for 2017 as compared to 2016. Interest rates are primarily based on short term bankers’ acceptance rates plus a stamping fee and determined by total debt to the trailing four quarters Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”) ratio as calculated pursuant to our Credit Facilities. In 2018, we expect higher cash finance expense resulting from the higher average bank indebtedness and interest rates as determined by our total debt to EBITDA ratio.

Funds from Operations and Cash Netbacks

	Three months ended												Year ended
	December 31												December 31
	2017						2016						2017						2016
	$000			per mcfe			$000			per mcfe			$000			per mcfe			$000			per mcfe
Natural gas and liquids sales (1)	$	53,777		$	2.38		$	64,556		$	3.17		$	231,764		$	2.69		$	161,933		$	2.18
Realized gains on derivatives		12,002			0.53			6,534			0.32			27,847			0.32			53,094			0.71
Royalty expense		(1,575	)		(0.07	)		(3,637	)		(0.18	)		(6,387	)		(0.07	)		(4,900	)		(0.07	)
Operating expense		(5,967	)		(0.26	)		(4,490	)		(0.22	)		(21,729	)		(0.25	)		(20,358	)		(0.27	)
Transportation expense (1)		(11,350	)		(0.50	)		(5,223	)		(0.26	)		(34,517	)		(0.40	)		(6,982	)		(0.09	)
Operating  income and operating netbacks (2)		46,887			2.08			57,740			2.83			196,978			2.29			182,787			2.46
General and administrative expense		(1,052	)		(0.05	)		(1,680	)		(0.08	)		(7,165	)		(0.08	)		(7,469	)		(0.10	)
Finance expense (3)		(1,968	)		(0.09	)		(1,913	)		(0.09	)		(6,931	)		(0.08	)		(9,335	)		(0.13	)
Other income (4)		16			-			463			0.02			320			-			878			0.01
Funds from operations and cash netbacks (2)	$	43,883		$	1.94		$	54,610		$	2.68		$	183,202		$	2.13		$	166,861		$	2.24
Per basic weighted average share (2)	$	0.24					$	0.30					$	0.99					$	0.92

⁽¹⁾ Prior to November 1, 2016, the natural gas prices we realized were reduced for transportation from the sales points to AECO. Commencing on November 1, 2016, gas transportation is no longer deducted from realized natural gas prices, but rather presented as Transportation Expense (see "Transportation Expense"). In the first three quarters of 2016, transportation expense represented only costs related to our liquids production. Natural gas transportation was $0.32/mcf and $0.30/mcf for three months and year ended December 31, 2016, respectively.

⁽²⁾ Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Please see "Non-GAAP Measures".

⁽³⁾ Finance expense excludes non-cash accretion expense.

⁽⁴⁾ Other income excludes non-cash other income.

Advantage realized funds from operations of $43.9 million and $183.2 million with cash netbacks of $1.94/mcfe and $2.13/mcfe for the three months and year ended December 31, 2017, respectively. Funds from operations on a per share basis was $0.24 and $0.99 for the three months and year ended December 31, 2017, respectively. Funds from operations decreased by $10.7 million or 20% for the fourth quarter of 2017 as compared to the same period in 2016, primarily due to a 45% decrease in AECO daily natural gas prices, partially offset by additional realized gains on derivatives and an 11% increase in total production. Higher transportation expense during the fourth quarter of 2017 was primarily due to Advantage’s participation in TCPL’s long term, fixed price service open season from Empress, Alberta to the Dawn market in Southern Ontario, which commenced November 1, 2017 (see “Transportation Expense”).

Advantage Oil & Gas Ltd. - 7

For the year ended December 31, 2017, funds from operations increased by $16.3 million or 10% compared to 2016. Funds from operations increased due to a 16% increase in total production, a Montney leading low cash cost structure (calculated as total of royalty expense, operating expense, transportation expense, G&A expense and finance expense excluding non-cash accretion) of $0.88/mcfe, a 24% increase in average realized natural gas prices (excluding hedging) and realized derivative gains of $27.8 million from our commodity risk management program (see “Commodity Price Risk Management and Market Diversification”). Advantage’s strong funds from operations and balance sheet supported our capital program during the year and resulted in a total debt to trailing twelve-month funds from operations ratio of 1.2 as at December 31, 2017. Excluding realized gains on derivatives, Advantage’s cash netback was $1.41/mcfe and $1.81/mcfe for the three months and year ended December 31, 2017 resulting in margins representing 59% and 67% of our realized natural gas and liquids sales, respectively.

Share Based Compensation

	Three months ended							Year ended
	December 31							December 31
	2017		2016		% change			2017		2016		% change
Share based compensation ($000)
Stock Options	$	33	$	119		(72	)%	$	217	$	459		(53	)%
Performance Awards		1,216		797		53	%		4,902		2,822		74	%
Total Share based compensation	$	1,249	$	916		36	%	$	5,119	$	3,281		56	%
per mcfe	$	0.06	$	0.05		20	%	$	0.06	$	0.04		50	%

Share based compensation represents expense associated with Advantage’s stock option plan and restricted and performance award plan that are designed to provide for long-term compensation to employees and contractors and to align the interests of these individuals with those of shareholders. For the year ended December 31, 2017, share based compensation increased by $1.8 million compared to 2016, primarily due to an increase in the value of Performance Awards granted in 2014 that vested in the second quarter of 2017 and revaluations of Payout Multipliers associated with outstanding Performance Awards that can result in expense variability. As at December 31, 2017, a total of 2.0 million Stock Options and 1.6 million Performance Awards are unexercised which represents 1.9% of Advantage’s total outstanding common shares.

Depreciation Expense

	Three months ended							Year ended
	December 31							December 31
	2017		2016		% change			2017		2016		% change
Depreciation expense ($000)	$	29,394	$	28,382		4	%	$	117,945	$	116,232		1	%
per mcfe	$	1.30	$	1.40		(7	)%	$	1.37	$	1.56		(12	)%

Depreciation of natural gas and liquids properties is provided on the units-of–production method based on total proved and probable reserves, including future development costs, on a component basis. The rate of depreciation expense per mcfe has decreased during 2017 due to the continued efficiency of our reserve additions. Continued production increases have resulted in modestly higher depreciation expense for the three months and year ended December 31, 2017 as compared to the same periods of 2016 (see “Production”).

Advantage Oil & Gas Ltd. - 8

Taxes

Deferred income taxes arise from differences between the accounting and tax bases of our assets and liabilities. For the year ended December 31, 2017, the Corporation recognized a deferred income tax expense of $37.3 million as a result of $132.3 million income before taxes. As at December 31, 2017, the Corporation had a deferred income tax liability of $72.5 million.

Estimated tax pools at December 31, 2017, are as follows:

	($ millions)
Canadian Development Expenses	$	211
Canadian Exploration Expenses		66
Canadian Oil and Gas Property Expenses		14
Non-capital losses		690
Undepreciated Capital Cost		251
Capital losses		158
Scientific Research and Experimental Development Expenditures		33
Other		11
	$	1,434

Net Income (Loss) and Comprehensive Income (Loss)

	Three months ended								Year ended
	December 31								December 31
	2017		2016			% change			2017		2016			% change
Net income (loss) and comprehensive income (loss) ($000)	$	21,425	$	(8,845	)		(342	)%	$	95,039	$	(15,734	)		(704	)%
per share - basic	$	0.12	$	(0.05	)		(340	)%	$	0.51	$	(0.09	)		(667	)%
per share - diluted	$	0.11	$	(0.05	)		(320	)%	$	0.50	$	(0.09	)		(656	)%

Advantage recognized net income of $21.4 million and $95.0 million for the three months and year ended December 31, 2017, respectively. Net income for 2017 was positively impacted by higher revenue due to increased production and commodity prices and lower finance expense resulting from reduced average bank indebtedness. Net income for the three months ended December 31, 2017 was positively impacted by the increased production and higher realized gains on derivatives from the weaker commodity price environment that resulted in lower revenue. Operating and transportation expense increased during 2017 due to the higher production and participation in TCPL’s long term, fixed price service open season whereby we began transporting natural gas to the Dawn premium market in Southern Ontario. Unrealized gains on derivatives of $17.2 million and $73.3 million for the three months and year ended December 31, 2017, respectively, contributed significantly to net income. Unrealized gains and losses on derivatives are non-cash and can fluctuate greatly between periods from changes to the estimated value to settle outstanding contracts (see “Commodity Price Risk Management and Market Diversification”).

Contractual Obligations and Commitments

The Corporation has contractual obligations in the normal course of operations including purchases of assets and services, operating agreements, transportation commitments, sales contracts and bank indebtedness. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner. The following table is a summary of the Corporation’s remaining contractual obligations and commitments. Advantage has no guarantees or off-balance sheet arrangements other than as disclosed.

		Payments due by period
($ millions)		Total		2018		2019		2020		2021		2022		After 2022
Building leases		$	1.8	$	1.1	$	0.7	$	-	$	-	$	-	$	-
Transportation			384.9		46.2		50.7		49.9		46.0		43.9		148.2
Bank indebtedness (1)	- principal		210.0		-		210.0		-		-		-		-
	- interest		13.9		9.4		4.5		-		-		-		-
Total contractual obligations		$	610.6	$	56.7	$	265.9	$	49.9	$	46.0	$	43.9	$	148.2

(1) As at December 31, 2017, the Corporation’s bank indebtedness was governed by a credit facility agreement with a syndicate of financial institutions. Under the terms of the agreement, the facility is reviewed annually, with the next review scheduled in June 2018. The facility is revolving and extendible at each annual review for a further 364 day period at the option of the syndicate. If not extended, the credit facility is converted at that time into a one-year term facility, with the principal payable at the end of such one-year term. Management fully expects that the facility will be extended at each annual review.

Advantage Oil & Gas Ltd. - 9

Liquidity and Capital Resources

The following table is a summary of the Corporation’s capitalization structure:

($000, except as otherwise indicated)	December 31, 2017
Bank indebtedness (non-current)	$	208,978
Working capital deficit		13,808
Total debt (1)	$	222,786
Shares outstanding		185,963,186
Shares closing market price ($/share)	$	5.40
Market capitalization	$	1,004,201
Total capitalization	$	1,226,987
Total debt to funds from operations (2)		1.2

⁽¹⁾ Total debt is a non-GAAP measure that includes bank indebtedness and working capital deficit.

⁽²⁾ Total debt to funds from operations is calculated by dividing total debt by funds from operations for the previous four quarters.

Advantage has a $400 million credit facility of which $191 million or 48% was available at December 31, 2017 (see “Bank Indebtedness, Credit Facilities and Other Obligations”). The Corporation’s twelve-month trailing funds from operations of $183 million was partially supplemented by working capital and bank indebtedness to fund our net capital expenditure program of $249 million. Through continuous careful management of our bank indebtedness and timing of capital expenditures, total debt to twelve-month trailing funds from operations remained low at 1.2 times as at December 31, 2017. Advantage has a strong balance sheet, a disciplined commodity risk management program, an industry leading low cost structure, and substantial available liquidity such that it is well positioned to continue successfully executing our multi-year development plan.

Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Corporation is composed of working capital, bank indebtedness, and share capital. Advantage may manage its capital structure by issuing new common shares, repurchasing outstanding common shares, obtaining additional financing through bank indebtedness, refinancing current debt, issuing other financial or equity-based instruments, declaring a dividend, or adjusting capital spending. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis. Management of the Corporation’s capital structure is facilitated through its financial and operational forecasting processes. Selected forecast information is frequently provided to the Board of Directors. This continual financial assessment process further enables the Corporation to mitigate risks. The Corporation continues to satisfy all liabilities and commitments as they come due.

Shareholders’ Equity

As at December 31, 2017, Advantage had 186.0 million common shares outstanding. During the year ended December 31, 2017, Advantage issued 1.3 million common shares to employees and contractors in exchange for the exercise of 1.1 million stock options and the settlement of 0.4 million performance shares. As at December 31, 2017, a total of 2.0 million stock options and 1.6 million performance awards were outstanding, which represents 1.9% of Advantage’s total outstanding common shares. On March 8, 2016, Advantage closed the equity financing of 13,427,075 common shares issued for net proceeds of $95.1 million which was used initially to reduce bank indebtedness. As at March 5, 2018, Advantage had 186.0 million common shares outstanding.

Advantage Oil & Gas Ltd. - 10

Bank Indebtedness, Credit Facilities and Other Obligations

At December 31, 2017, Advantage had bank indebtedness outstanding of $209.0 million, an increase of $55.9 million since December 31, 2016. The change in bank indebtedness was consistent with the timing and execution of Advantage’s planned capital expenditure program. Advantage’s credit facilities have a borrowing base of $400 million that is collateralized by a $1 billion floating charge demand debenture covering all assets of the Corporation and has no financial covenants (the “Credit Facilities”). The borrowing base for the Credit Facilities is determined by the banking syndicate through an evaluation of our reserve estimates based upon their own commodity price assumptions. Revisions or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing base. In October 2017, the semi-annual redetermination of the Credit Facilities borrowing base was completed, with no changes to the borrowing base of $400 million, comprised of a $20 million extendible revolving operating loan facility from one financial institution and a $380 million extendible revolving loan facility from a syndicate of financial institutions. The next annual review is scheduled to occur in June 2018. There can be no assurance that the Credit Facilities will be renewed at the current borrowing base level at that time.

Advantage’s working capital deficit of $13.8 million as at December 31, 2017 increased from $6.2 million at December 31, 2016 due to an increase in capital expenditures activity. Our working capital includes items expected for normal operations such as cash and cash equivalents, trade receivables, prepaid expenses, deposits, and trade payables and accruals. Working capital varies primarily due to the timing of such items, the current level of business activity including our capital expenditure program, commodity price volatility, and seasonal fluctuations. Our working capital is normally in a deficit position due to our capital development activities. We do not anticipate any problems in meeting future obligations as they become due as they can be satisfied with funds from operations and our available Credit Facilities.

Capital Expenditures

	Three months ended					Year ended
	December 31					December 31
($000)	2017			2016		2017		2016
Drilling, completions and workovers	$	44,781		$	21,188	$	143,797	$	56,189
Well equipping and facilities		29,272			8,537		97,652		65,657
Other		(5	)		167		118		167
Expenditures on property, plant and equipment		74,048			29,892		241,567		122,013
Expenditures on exploration and evaluation assets		(325	)		151		7,207		6,001
Net capital expenditures (1)	$	73,723		$	30,043	$	248,774	$	128,014

⁽¹⁾ Net capital expenditures excludes change in decommissioning liability.

Advantage invested $248.8 million on property, plant, equipment and land purchases during the year ended December 31, 2017 with $74 million invested in the fourth quarter.

During the fourth quarter of 2017, construction of the announced expansion of our 100% owned Glacier gas plant to 400 mmcf/d raw gas capability (including 6,800 bbls/d of liquids) continued with an anticipated completion date of early second quarter 2018. All major equipment is in place with the majority of the mechanical and electrical work completed. A planned shutdown of our plant to tie-in the new equipment, along with commissioning and testing, will occur in April. This work and related production impacts have been incorporated into our 2018 production guidance range, which includes slightly lower second quarter 2018 volumes compared to the first quarter. In 2017, a total of $86 million (35% of our total capital expenditure) was invested in infrastructure projects at Glacier, including $78 million for the gas plant expansion. Advantage’s strategy of owning and operating our own infrastructure has helped us achieve an industry leading low cost structure.

Advantage drilled 33.4 net Montney horizontal wells in 2017 across all our properties, which included delineation drilling on our undeveloped land holdings at Valhalla, Wembley and Progress. Advantage drilled 28.0, 3.4, 1.0 and 1.0 net wells at Glacier, Valhalla, Wembley and Progress, respectively. At Glacier, our drilling focused on multi-well pads with our smallest pad drilled during the year being 8 wells. Advantage’s Upper, Middle and Lower Montney wells at Glacier are continuing to demonstrate strong production performance. Middle Montney results at Glacier in 2017 extended our liquids-rich fairway into previously undrilled areas and confirmed well performance improvements from frac design technology changes which has been applied to high liquids-rich areas and reservoir layers within our Montney lands.

Advantage Oil & Gas Ltd. - 11

At Valhalla, a new 2017 four well pad (3.4 net wells) demonstrated a combined initial production flow rate of 6,410 boe/d comprised of 32 mmcf/d gas and 1,075 bbls/d of liquids (based on Glacier gas plant shallow cut extraction process) with certain liquid yields comprised of 90% free condensate/oil in excess of 100 bbls/mmcf. At Valhalla, Wembley and Progress, ongoing industry drilling and production have demonstrated encouraging initial results with attractive liquid yields and gas rates. Industry drilling adjacent to our lands have targeted up to four Montney layers with results demonstrating liquids-rich gas accumulations in all layers to date. Advantage has a total of 110 net sections of Doig/Montney rights within these three areas with at least 30 contiguous sections in each of these land blocks that are capable of supporting scalable development.

Advantage’s current standing well inventory consists of 31 total wells of which 8 wells are tied-in waiting to be produced, 10 wells are in various stages of completion, and 13 wells are cased waiting to be completed. These wells are estimated to provide sufficient productive capacity to attain our 2018 annual production target.

In 2017, Advantage invested $7.2 million to acquire 37 additional sections of Doig/Montney rights in the Valhalla, Wembley and Progress areas proximal to our existing land holdings. Subsequent to year end, Advantage acquired an additional 11 sections and now holds a total of 200 net sections (128,000 net acres) of Doig/Montney rights, with 110 of these sections in the Valhalla/Progress/Wembley areas that have potential for liquids-rich, multi-layer development.

Sources and Uses of Funds

The following table summarizes the various funding requirements during the years ended December 31, 2017 and 2016 and the sources of funding to meet those requirements:

	Year ended
	December 31
($000)	2017		2016
Sources of funds
Funds from operations	$	183,202	$	166,861
Net proceeds of equity financing		-		95,130
Increase in bank indebtedness		56,189		-
Change in non-cash working capital and other		10,573		1,598
	$	249,964	$	263,589
Uses of funds
Decrease in bank indebtedness	$	-	$	133,718
Net capital expenditures		248,774		128,014
Expenditures on decommissioning liability		1,190		1,857
	$	249,964	$	263,589

Bank indebtedness increased during the year ended December 31, 2017 as a result of planned net capital expenditures exceeding funds from operations and changes in non-cash working capital. Advantage continuously monitors the debt levels to ensure an optimal mix of financing and cost of capital.

Annual Financial Information

The following is a summary of selected financial information of the Corporation for the years indicated.

	Year ended		Year ended			Year ended
	Dec. 31, 2017		Dec. 31, 2016			Dec. 31, 2015
Total sales (before royalties) ($000)	$	231,764	$	161,933		$	132,311
Net income (loss) ($000)	$	95,039	$	(15,734	)	$	21,378
per share - basic	$	0.51	$	(0.09	)	$	0.13
per share - diluted	$	0.50	$	(0.09	)	$	0.12
Total assets	$	1,691,182	$	1,496,459		$	1,517,443
Long term financial liabilities ($000) (1)	$	208,978	$	153,102		$	286,519

⁽¹⁾ Long term financial liabilities exclude derivative liability, decommissioning liability and deferred income tax liability.

Advantage Oil & Gas Ltd. - 12

Quarterly Performance

($000, except as otherwise	2017								2016
indicated)	Q4		Q3		Q2		Q1		Q4			Q3		Q2			Q1
Daily production
Natural gas (mcf/d)		237,780		219,812		225,844		230,906		215,369			207,332		203,791			164,618
Liquids (bbls/d)		1,227		1,395		1,098		1,151		949			1,205		1,083			418
Total (mcfe/d)		245,142		228,182		232,432		237,812		221,063			214,562		210,289			167,126
Average prices
Natural gas ($/mcf)
Excluding hedging	$	2.15	$	1.84	$	2.98	$	2.99	$	3.02		$	2.08	$	1.10		$	1.72
Including hedging	$	2.69	$	2.26	$	3.09	$	3.24	$	3.35		$	2.71	$	2.18		$	2.70
AECO daily	$	1.69	$	1.46	$	2.79	$	2.70	$	3.09		$	2.32	$	1.40		$	1.84
AECO monthly	$	1.95	$	2.04	$	2.77	$	2.95	$	2.81		$	2.20	$	1.25		$	2.11
Liquids ($/bbl)
Excluding and including hedging	$	60.48	$	46.95	$	57.27	$	53.73	$	53.01		$	45.58	$	52.67		$	31.21
Edmonton Light ($/bbl)	$	66.89	$	57.11	$	60.38	$	64.72	$	60.76		$	54.34	$	55.02		$	38.85
Total sales including realized hedging	$	65,779	$	51,706	$	69,169	$	72,957	$	71,090		$	56,697	$	45,615		$	41,625
Net income (loss)	$	21,425	$	13,026	$	18,339	$	42,249	$	(8,845	)	$	8,185	$	(29,765	)	$	14,691
per share - basic	$	0.12	$	0.07	$	0.10	$	0.23	$	(0.05	)	$	0.04	$	(0.16	)	$	0.08
per share - diluted	$	0.11	$	0.07	$	0.10	$	0.22	$	(0.05	)	$	0.04	$	(0.16	)	$	0.08
Funds from operations	$	43,883	$	36,722	$	48,625	$	53,972	$	54,610		$	45,132	$	36,883		$	30,236

The table above highlights the Corporation’s performance for the fourth quarter of 2017 and also for the preceding seven quarters. The Corporation’s production for the first quarter of 2016 was negatively impacted by TCPL unplanned firm and interruptible service restrictions in addition to Advantage’s planned outages required to install new equipment for the subsequent Glacier gas plant expansion to 250 mmcfe/d. In the second half of 2016, we attained production levels in excess of 220 mmcfe/d and continued to increase production thereby substantially filling the Glacier gas plant processing capacity in the first and second quarters of 2017, consistent with our multi-year development plan. Production for the third quarter of 2017 was slightly impacted by TCPL capacity restrictions and planned production decreases due to the ongoing expansion of the Glacier gas plant. Production increased during the fourth quarter of 2017, filling the Glacier gas plant capacity and achieving record production for Advantage.

Sales and funds from operations increased through 2016 and early 2017 in conjunction with continued production growth, lower cash costs and gains realized from our commodity risk management program. Sales and funds from operations were weaker in the second half of 2017 as operational achievements were offset by a decline in natural gas prices. Although Advantage has generally reported net income, the net losses reported in the second and fourth quarters of 2016 were primarily due to the recognition of unrealized derivative losses. Net income generated through 2017 has been attributable to increased production with strong funds from operations as well as the recognition of unrealized derivative gains resulting from an increase in the fair value of our outstanding derivative contracts (see “Commodity Price Risk Management and Market Diversification”). Advantage’s production growth, industry leading low cost structure, strong capital efficiencies and commodity risk management program have achieved long-term profitability despite the natural gas price volatility.

Advantage Oil & Gas Ltd. - 13

Critical Accounting Estimates

The preparation of financial statements in accordance with IFRS requires Management to make certain judgments and estimates. Changes in these judgments and estimates could have a material impact on the Corporation’s financial results and financial condition.

Management relies on the estimate of reserves as prepared by the Corporation’s independent qualified reserves evaluator. The process of estimating reserves is critical to several accounting estimates. The process of estimating reserves is complex and requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development and production activities becomes available and as economic conditions impact natural gas and liquids prices, operating expense, royalty burden changes, and future development costs. Reserve estimates impact net income and comprehensive income through depreciation and impairment of natural gas and liquids properties. The reserve estimates are also used to assess the borrowing base for the Corporation’s Credit Facilities. Revision or changes in the reserve estimates can have either a positive or a negative impact on asset values, net income, comprehensive income and the borrowing base of the Corporation.

Management has determined there to be a single cash-generating unit (“CGU”), the Glacier Area, on the basis of its ability to generate independent cash flows, similar reserve characteristics, geographical location, and shared infrastructure, namely a single processing plant owned by Advantage. For purposes of assessment of impairment, Management has allocated all exploration and evaluation assets to the Glacier Area CGU, on the basis of their geographic proximity.

Management’s process of determining the provision for deferred income taxes and the provision for decommissioning liability costs and related accretion expense are based on estimates. Estimates used in the determination of deferred income taxes provisions are significant and can include expected future tax rates, expectations regarding the realization or settlement of the carrying amount of assets and liabilities and other relevant assumptions. Estimates used in the determination of decommissioning liability cost provisions and accretion expense are significant and can include proved and probable reserves, future production rates, future commodity prices, future costs, future interest rates and other relevant assumptions. Revisions or changes in any of these estimates can have either a positive or a negative impact on asset and liability values, net income and comprehensive income.

In accordance with IFRS, derivative assets and liabilities are recorded at their fair values at the reporting date, with gains and losses recognized directly into comprehensive income in the same period. The fair value of derivatives outstanding is an estimate based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are non-cash items and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions.

Changes in Accounting Policies

There have been no changes in accounting policies during the year ended December 31, 2017.

Accounting Pronouncements not yet Adopted

IFRS 9 Financial Instruments introduces a new classification and measurement requirements, impairment model and hedge accounting model. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Advantage does not anticipate any material changes or effects to our current accounting.

IFRS 15 Revenue from Contracts with Customers requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. The standard is to be adopted for annual periods beginning on or after January 1, 2018, either retrospectively or using a modified retrospective approach. Advantage has individually assessed each current and possible future revenue stream using the principles established by IFRS 15. Based on our assessments, Advantage has determined that accounting for each of our revenue streams will be substantially the same under IFRS 15 as under current IFRS standards. Advantage does not anticipate any material impacts to our current accounting from the adoption of IFRS 15.

IFRS 16 Leases requires the recognition of assets and liabilities for most leases. The standard applies to annual periods beginning on or after January 1, 2019. Under IFRS 16, lease assets and liabilities will be required to be recognized on the balance sheet for most leases, where the entity is acting as a lessee. Certain leases of low-value assets and leases with short-terms (less than 12 months) will be exempt from the balance sheet recognition requirements, and may continue to be treated as operating leases. Advantage is currently reviewing the impact of IFRS 16 on our financial statements.

Evaluation of Disclosure Controls and Procedures

Advantage’s Chief Executive Officer and Chief Financial Officer have designed disclosure controls and procedures (“DC&P”), or caused it to be designed under their supervision, to provide reasonable assurance that material information relating to the Corporation is made known to them by others, particularly during the period in which the annual filings are being prepared, and information required to be disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation.

Advantage Oil & Gas Ltd. - 14

Management of Advantage, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Corporation’s DC&P as at December 31, 2017. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the DC&P are effective as of the end of the year, in all material respects.

Evaluation of Internal Controls over Financial Reporting

Advantage’s Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining internal control over financial reporting (“ICFR”). They have as at the financial year end December 31, 2017, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework Advantage’s officers used to design the Corporation’s ICFR is the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations.

Management of Advantage, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Corporation’s ICFR as at December 31, 2017. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the ICFR are effective as of the end of the year, in all material respects.

Advantage’s Chief Executive Officer and Chief Financial Officer are required to disclose any change in the ICFR that occurred during our most recent interim period that has materially affected, or is reasonably likely to materially affect, the Corporation’s ICFR. No material changes in the ICFR were identified during the interim period ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our ICFR.

It should be noted that while the Chief Executive Officer and Chief Financial Officer believe that the Corporation’s design of DC&P and ICFR provide a reasonable level of assurance that they are effective, they do not expect that the control system will prevent all errors and fraud. A control system, no matter how well conceived or operated, does not provide absolute, but rather is designed to provide reasonable assurance that the objective of the control system is met. The Corporation’s ICFR may not prevent or detect all misstatements because of inherent limitations. Additionally, 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 deterioration in the degree of compliance with the Corporation’s policies and procedures.

Corporate Governance

The Corporation’s corporate governance practices can be found in the Management Information Circular.

As a foreign private issuer listed on the New York Stock Exchange (the "NYSE"), Advantage is not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic Canadian requirements. Advantage is, however, required to comply with the following NYSE Rules: (i) Advantage 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) Advantage must 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) Advantage must annually 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. Advantage has reviewed the NYSE listing standards followed by U.S. domestic issuers listed on the NYSE and confirms that its corporate governance practices do not differ significantly from such standards.

Advantage Oil & Gas Ltd. - 15

Non-GAAP Measures

The Corporation discloses several financial and performance measures in the MD&A that do not have any standardized meaning prescribed under GAAP. These financial and performance measures include “funds from operations”, “cash netbacks” and “net capital expenditures”, which should not be considered as alternatives to, or more meaningful than “net income”, “comprehensive income”, “cash provided by operating activities”, or “cash used in investing activities” as determined in accordance with GAAP. Management believes that these measures provide an indication of the results generated by the Corporation’s principal business activities and provide useful supplemental information for analysis of the Corporation’s operating performance and liquidity. Advantage’s method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies.

Funds from operations, as presented, is based on cash provided by operating activities, before expenditures on decommissioning liability and changes in non-cash working capital, reduced for finance expense excluding accretion. Management believes these adjustments to cash provided by operating activities increase comparability between reporting periods. Cash netbacks are dependent on the determination of funds from operations and include the primary cash sales and expenses on a per mcfe basis that comprise funds from operations. Funds from operations reconciled to cash provided by operating activities is as follows:

	Three months ended									Year ended
	December 31									December 31
($000)	2017			2016			% change			2017			2016			% change
Cash provided by operating activities	$	29,848		$	57,099			(48	)%	$	186,401		$	174,906			7	%
Expenditures on decommissioning liability		370			491			(25	)%		1,190			1,857			(36	)%
Changes in non-cash working capital		15,633			(1,067	)		(1565	)%		2,542			(567	)		(548	)%
Finance expense (1)		(1,968	)		(1,913	)		3	%		(6,931	)		(9,335	)		(26	)%
Funds from operations	$	43,883		$	54,610			(20	)%	$	183,202		$	166,861			10	%

⁽¹⁾ Finance expense excludes non-cash accretion expense.

Net capital expenditures include total capital expenditures related to property, plant and equipment and exploration and evaluation assets incurred during the period. Management considers this measure reflective of actual capital activity for the period as it excludes changes in working capital related to other periods.

Conversion Ratio

The term “boe” or barrels of oil equivalent and “mcfe” or thousand cubic feet equivalent may be misleading, particularly if used in isolation. A boe or mcfe conversion ratio of six thousand cubic feet of natural gas equivalent to one barrel of oil (6 mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil 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.

Forward-Looking Information and Other Advisories

This MD&A contains certain forward-looking statements and forward-looking information (collectively, "forward-looking statements"), which are based on our current internal expectations, estimates, projections, assumptions and beliefs. These forward-looking statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar or related expressions. These statements are not guarantees of future performance.

Advantage Oil & Gas Ltd. - 16

In particular, forward-looking statements included in this MD&A include, but are not limited to, Advantage's beliefs as to the benefit to investors of modifying its natural gas marketing contract; the Corporation’s ability to meet its production targets; anticipated annual production for 2018, including the expected amount of liquids production and condensate; the Corporation's expectation that second quarter 2018 production will be consistent with the first quarter of 2018 and the fourth quarter of 2017 and that production will ramp up in the third and fourth quarters of 2018 to achieve the Corporation's anticipated annual production guidance; the Corporation’s expectations with respect to the market for natural gas and volatility in natural gas prices; the anticipated advantages from the Corporation’s participation in the Dawn market; effect of commodity prices on the Corporation’s financial results, condition and performance; industry conditions, including the effect of changes in commodity prices, weather and general economic conditions on the natural gas industry and demand for natural gas; the Corporation's hedging activities; terms of the Corporation's derivative contracts, including the timing of settlement of such contracts; effect of fluctuations in commodity prices as compared to valuation assumptions on actual gains or losses realized on cash settlement of derivatives; average royalty rates and the impact of well depths, well production rates, commodity prices and gas cost allowance on average corporate royalty rates; future royalty rates, including the anticipated 2018 average royalty rate; the Corporation's expectation that it will realize higher cash finance expense in 2018; the Corporation's expectation that bank indebtedness will remain consistent through 2018 and that budgeted capital expenditures will be primarily funded from cash provided by operating activities; estimated tax pools at December 31, 2017; future commitments and contractual obligations; terms of the Corporation's credit facilities, including timing of the next review of the credit facilities, effect of revisions or changes in reserve estimates and commodity prices on the borrowing base, and limitations on the utilization of hedging contracts; the Corporation's expectations regarding extension of Advantage's credit facilities at each annual review; the Corporation’s belief that it is well positioned to successfully execute its multi-year development plan; the Corporation's strategy for managing its capital structure, including the use of equity financing arrangements, share repurchases, obtaining additional financing through bank indebtedness, refinancing current debt, issuing other financial or equity-based instruments, declaring a dividend or adjusting capital spending; the timing of reviews of capital structure and forecast information by Management and the Board of Directors; effect of the Corporation's continual financial assessment processes on the Corporation's ability to mitigate risks; the Corporation's ability to satisfy all liabilities and commitments and meet future obligations as they become due; terms of the Corporation's equity compensation plans; the Corporation's drilling and completion plans, including the anticipated timing thereof; the Corporation’s focus and expectations regarding its capital expenditures and operations; the Corporation's intentions to monitor debt levels to ensure an optimal mix of financing and cost of capital; the timing and impact of IFRS 9, IFRS 15 and IFRS 16 accounting pronouncements; and the statements under "critical accounting estimates" in this MD&A.

These forward-looking statements involve substantial known and unknown risks and uncertainties, many of which are beyond our control, including, but not limited to, risks related to changes in general economic, market and business conditions; continued volatility in market prices for oil and natural gas; the impact of significant declines in market prices for oil and natural gas; stock market volatility; changes to legislation and regulations and how they are interpreted and enforced; our ability to comply with current and future environmental or other laws; actions by governmental or regulatory authorities including increasing taxes, regulatory approvals, changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; our success at acquisition, exploitation and development of reserves; unexpected drilling results; failure to achieve production targets on timelines anticipated or at all; changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; individual well productivity; delays in anticipated timing of drilling and completion of wells; lack of available capacity on pipelines; delays in timing of completion of the expansion of the Corporation's Glacier gas plant; the failure to extend our credit facilities at each annual review; competition from other producers; the lack of availability of qualified personnel or management; ability to access sufficient capital from internal and external sources; credit risk; and the risks and uncertainties described in the Corporation’s Annual Information Form which is available at www.sedar.com and www.advantageog.com. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities.

With respect to forward-looking statements contained in this MD&A, in addition to other assumptions identified herein, Advantage has made assumptions regarding, but not limited to: current and future prices of oil and natural gas; that the current commodity price and foreign exchange environment will continue or improve; conditions in general economic and financial markets; effects of regulation by governmental agencies; receipt of required regulatory approvals; royalty regimes; future exchange rates; royalty rates; future operating costs; availability of skilled labour; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; that the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Corporation’s conduct and results of operations will be consistent with its expectations; that the Corporation will have the ability to develop the Corporation’s crude oil and natural gas properties in the manner currently contemplated; availability of pipeline capacity; that current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; and that the estimates of the Corporation’s production, reserves and resources volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects.

Advantage Oil & Gas Ltd. - 17

Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this MD&A and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

Additional Information

Additional information relating to Advantage can be found on SEDAR at www.sedar.com and the Corporation’s website at www.advantageog.com. Such other information includes the annual information form, the management information circular, press releases, material change reports, material contracts and agreements, and other financial reports. The annual information form will be of particular interest for current and potential shareholders as it discusses a variety of subject matter including the nature of the business, description of our operations, general and recent business developments, risk factors, reserves data and other oil and gas information.

March 5, 2018

Advantage Oil & Gas Ltd. - 18

XML

Document And Entity Information	12 Months Ended
	Dec. 31, 2017 shares
Document Information [Line Items]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Entity Registrant Name	ADVANTAGE OIL & GAS LTD.
Entity Central Index Key	0001468079
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding	0
Entity Current Reporting Status	Yes

XML

Consolidated Statement of Financial Position - CAD CAD in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	CAD 6,916	CAD 0
Trade and other receivables	28,678	26,305
Prepaid expenses and deposits	1,602	1,681
Derivative asset	33,093	730
Total current assets	70,289	28,716
Non-current assets
Derivative asset	17,777	1,448
Exploration and evaluation assets	22,143	16,012
Property, plant and equipment	1,580,973	1,450,283
Total non-current assets	1,620,893	1,467,743
Total assets	1,691,182	1,496,459
Current liabilities
Trade and other accrued liabilities	51,004	34,153
Derivative liability	111	13,812
Total current liabilities	51,115	47,965
Non-current liabilities
Derivative liability	0	10,912
Bank indebtedness	208,978	153,102
Decommissioning liability	46,913	40,992
Deferred income tax liability	72,500	35,215
Total non-current liabilities	328,391	240,221
Total liabilities	379,506	288,186
SHAREHOLDERS' EQUITY
Share capital	2,340,801	2,334,199
Contributed surplus	110,077	108,315
Deficit	(1,139,202)	(1,234,241)
Total shareholders' equity	1,311,676	1,208,273
Total liabilities and shareholders' equity	CAD 1,691,182	CAD 1,496,459

XML

Consolidated Statement of Comprehensive Income (Loss) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Natural gas and liquids sales	CAD 231,764	CAD 161,933
Royalty expense	(6,387)	(4,900)
Natural gas and liquids revenue	225,377	157,033
Operating expense	(21,729)	(20,358)
Transportation expense	(34,517)	(6,982)
General and administrative expense	(7,165)	(7,469)
Share based compensation	(5,119)	(3,281)
Depreciation expense	(117,945)	(116,232)
Exploration and evaluation expense	(168)	0
Finance expense	(7,882)	(10,250)
Gains (losses) on derivatives	101,152	(13,687)
Other income	320	878
Income (loss) before taxes	132,324	(20,348)
Income tax recovery (expense)	(37,285)	4,614
Net income (loss) and comprehensive income (loss)	CAD 95,039	CAD (15,734)
Net income (loss) per share
Basic	CAD 0.51	CAD (0.09)
Diluted	CAD 0.5	CAD (0.09)

XML

Consolidated Statement of Changes in Shareholders' Equity CAD in Thousands, $ in Thousands	CAD	Share capital [member] CAD	Share capital [member] USD ($)	Contributed surplus [member] CAD	Deficit [Member] CAD
Balance at Start at Dec. 31, 2015	CAD 1,121,947	CAD 2,236,728		CAD 103,726	CAD (1,218,507)
Net income and comprehensive income	(15,734)	0		0	(15,734)
Shares issued on financing	96,453	96,453		0	0
Share based compensation	5,607	0		5,607	0
Exercise of Stock Options	0	1,018	$ 1,018	(1,018)	0
Balance at End at Dec. 31, 2016	1,208,273	2,334,199		108,315	(1,234,241)
Net income and comprehensive income	95,039	0		0	95,039
Share based compensation	8,364	0		8,364	0
Settlement of Performance Awards	0	5,374		(5,374)	0
Exercise of Stock Options	0	1,228		(1,228)	0
Balance at End at Dec. 31, 2017	CAD 1,311,676	CAD 2,340,801		CAD 110,077	CAD (1,139,202)

XML

Consolidated Statement of Cash Flows - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Operating Activities
Income (loss) before taxes	CAD 132,324	CAD (20,348)
Add (deduct) items not requiring cash:
Share based compensation	5,119	3,281
Exploration and evaluation expense	168	0
Depreciation expense	117,945	116,232
Unrealized (gains) losses on derivatives	(73,305)	66,781
Finance expense	7,882	10,250
Expenditures on decommissioning liability	(1,190)	(1,857)
Changes in non-cash working capital	(2,542)	567
Cash provided by operating activities	186,401	174,906
Financing Activities
Increase (decrease) in bank indebtedness	56,189	(133,718)
Net proceeds of equity financing	0	95,130
Interest paid	(7,244)	(9,034)
Cash provided by (used in) financing activities	48,945	(47,622)
Investing Activities
Payments on property, plant and equipment	(221,223)	(121,283)
Payments on exploration and evaluation assets	(7,207)	(6,001)
Cash used in investing activities	(228,430)	(127,284)
Increase in cash and cash equivalents	6,916	0
Cash and cash equivalents, beginning of year	0	0
Cash and cash equivalents, end of year	CAD 6,916	CAD 0

XML

Business and structure of Advantage Oil & Gas Ltd.

12 Months Ended

Dec. 31, 2017

Disclosure of business and structure of entity [Abstract]

Disclosure of general information about financial statements [text block]

1. Business and structure of Advantage Oil & Gas Ltd.

Advantage Oil & Gas Ltd. and its subsidiaries (together “Advantage” or the “Corporation”) is an intermediate natural gas and liquids development and production corporation with a significant position in the Montney resource play located in Western Canada.

Advantage is domiciled and incorporated in Canada under the Business Corporations Act (Alberta). Advantage’s head office address is 300, 440 – 2^nd Avenue SW, Calgary, Alberta, Canada. The Corporation’s primary listing is on the Toronto Stock Exchange and is also traded on the New York Stock Exchange as a Foreign Private Issuer, under the symbol “AAV”.

XML

Basis of preparation

12 Months Ended

Dec. 31, 2017

Disclosure Of Basis Of Preparation Of Financial Statements Explanatory [Abstract]

Disclosure of basis of preparation of financial statements [text block]

2. Basis of preparation

(a) Statement of compliance

The Corporation prepares its consolidated financial statements in accordance with Canadian generally accepted accounting principles (“GAAP”) as defined in the Chartered Professional Accountants Canada Handbook (the “CPA Canada Handbook”). The CPA Canada Handbook incorporates International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. Publicly accountable enterprises, such as the Corporation, are required to apply these standards. Accordingly, these consolidated financial statements are prepared and issued under IFRS.

The accounting policies applied in these consolidated financial statements are based on IFRS issued and outstanding as of March 5, 2018, the date the Board of Directors approved the statements.

(b) Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis, except as detailed in the Corporation’s accounting policies in note 3.

The methods used to measure fair values of derivative instruments are discussed in note 9.

(c) Functional and presentation currency

These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s functional currency.

XML

Significant accounting policies

12 Months Ended

Dec. 31, 2017

Disclosure Of Summary Of Significant Accounting Policies Explanatory [Abstract]

Disclosure of significant accounting policies [text block]

3. Significant accounting policies

The accounting policies set out below have been applied consistently to all years presented in these financial statements and notes.

(a) Cash and cash equivalents

Cash consists of balances held with banks, and other short-term highly liquid investments with original maturities of three months or less from inception.

(b) Basis of consolidation

(i) Subsidiaries

Subsidiaries are entities controlled by the Corporation. Control exists when the Corporation is exposed, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

(ii) Joint arrangements

A portion of the Corporation’s natural gas and liquids activities involve joint operations. The consolidated financial statements include the Corporation’s share of these joint operations and a proportionate share of the relevant revenue and costs.

(c) Financial instruments

All financial instruments are initially recognized at fair value on the Consolidated Statement of Financial Position. Measurement of financial instruments subsequent to the initial recognition, as well as resulting gains and losses, is based on how each financial instrument was initially classified. The Corporation has classified each identified financial instrument into the following categories: fair value through profit or loss, loans and receivables, held to maturity investments, available for sale financial assets, and financial assets and liabilities at amortized cost. Fair value through profit or loss financial instruments are measured at fair value with gains and losses recognized in income immediately. Available for sale financial assets are measured at fair value with gains and losses, other than impairment losses, recognized in other comprehensive income and transferred to income when the asset is derecognized. Loans and receivables, held to maturity investments and financial assets and liabilities at amortized cost, are recognized at amortized cost using the effective interest method and impairment losses are recorded in income when incurred.

Derivative instruments executed by the Corporation to manage market risk associated with volatile commodity prices are classified as fair value through profit or loss and recorded on the Consolidated Statement of Financial Position as derivatives assets and liabilities measured at fair value. Gains and losses on these instruments are recorded as gains and losses on derivatives in the Consolidated Statement of Comprehensive Income (Loss) in the period they occur. Gains and losses on derivative instruments are comprised of cash receipts and payments associated with periodic settlement that occurs over the life of the instrument, and non-cash gains and losses associated with changes in the fair values of the instruments, which are remeasured at each reporting date and recorded on the Consolidated Statement of Financial Position.

(d) Property, plant and equipment and exploration and evaluation assets

(i) Recognition and measurement

Exploration and evaluation costs

Pre-license costs are recognized in the Consolidated Statement of Comprehensive Income (Loss) as incurred.

All exploratory costs incurred subsequent to acquiring the right to explore for natural gas and liquids before technical feasibility and commercial viability of the area have been established are capitalized. Such costs can typically include costs to acquire land rights, geological and geophysical costs and exploration well costs.

Exploration and evaluation costs are not depreciated and are accumulated in cost centers by well, field or exploration area and carried forward pending determination of technical feasibility and commercial viability.

The technical feasibility and commercial viability of extracting a mineral resource from exploration and evaluation assets is considered to be generally determinable when proved or probable reserves are determined to exist. Upon determination of proved or probable reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to property, plant and equipment, net of any impairment loss.

Management reviews and assesses exploration and evaluation assets to determine if technical feasibility and commercial viability exist. If Management decides not to continue the exploration and evaluation activity, the unrecoverable costs are charged to exploration and evaluation expense in the period in which the determination occurs.

Property, plant and equipment

Items of property, plant and equipment, which include natural gas and liquids properties, are measured at cost less accumulated depreciation and accumulated impairment losses. Costs include lease acquisition, drilling and completion, production facilities, decommissioning costs, geological and geophysical costs and directly attributable general and administrative costs and share based compensation related to development and production activities, net of any government incentive programs.

When significant parts of an item of property, plant and equipment, including natural gas and liquids properties, have different useful lives, they are accounted for as separate items (major components).

(ii) Subsequent costs

Costs incurred subsequent to development and production that are significant are recognized as natural gas and liquids property only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in comprehensive income as incurred. Such capitalized natural gas and liquids costs generally represent costs incurred in developing proved and probable reserves and producing or enhancing production from such reserves, and are accumulated on a field or area basis. The carrying amount of any replaced or sold component is derecognized in accordance with our policies. The costs of the day-to-day servicing of property, plant and equipment are recognized in the Consolidated Statement of Comprehensive Income (Loss) as incurred.

(iii) Depreciation

The net carrying value of natural gas and liquids properties is depreciated using the units-of-production (“UOP”) method by reference to the ratio of production in the period to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.

(iv) Dispositions

Gains and losses on disposal of an item of property, plant and equipment, including natural gas and liquids properties, are determined by comparing the proceeds from disposition with the carrying amount of property, plant and equipment and are recognized net within other income (expenses) in the Consolidated Statement of Comprehensive Income (Loss).

(v) Impairment

The carrying amounts of the Corporation’s property, plant and equipment are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, the asset’s recoverable amount is estimated. For the purpose of impairment testing of property, plant and equipment, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the “cash-generating unit” or “CGU”).

Exploration and evaluation assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, and facts and circumstances suggest that the carrying amount exceeds the recoverable amount. Exploration and evaluation assets are allocated to CGU’s or groups of CGU’s for the purposes of assessing such assets for impairment.

The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs of disposition. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Fair value less costs of disposition is assessed utilizing market valuation based on an arm’s length transaction between active participants. In the absence of any such transactions, fair value less costs of disposition is estimated by discounting the expected after-tax cash flows of the cash generating unit at an after-tax discount rate that reflects the risk of the properties in the cash generating unit. The discounted cash flow calculation is then increased by a tax-shield calculation, which is an estimate of the amount that a prospective buyer of the cash generating unit would be entitled. The carrying value of the cash generating unit is reduced by the deferred tax liability associated with its property, plant and equipment.

Impairment losses on property, plant and equipment are recognized in the Consolidated Statement of Comprehensive Income (Loss) as impairment of natural gas and liquids properties and are separately disclosed. An impairment of exploration and evaluation assets is recognized as exploration and evaluation expense in the Consolidated Statement of Comprehensive Income (Loss).

(e) Decommissioning liability

A decommissioning liability is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Decommissioning liabilities are determined by discounting the expected future cash flows at a risk-free rate.

(f) Share based compensation

Advantage accounts for share based compensation expense based on the fair value of rights granted under its share based compensation plans.

Advantage’s Stock Option Plan (“Stock Option Plan”) authorizes the Board of Directors to grant Stock Options to service providers, including directors, officers, employees and consultants of Advantage. Compensation costs related to the Stock Options are recognized as share based compensation expense over the vesting period at fair value.

Advantage’s Restricted and Performance Award Incentive Plan provides share based compensation for service providers. Awards granted under this plan may be settled in cash or in shares. As the Corporation generally intends to settle the Awards in shares, the plan is considered and accounted for as “equity-settled”.

As compensation expense is recognized, contributed surplus is recorded until the Performance Awards vest or Stock Options are exercised, at which time the appropriate common shares are then issued to the service providers and the contributed surplus is transferred to share capital.

(g) Revenue

Revenue from the sale of natural gas and liquids is recorded when the significant risks and rewards of ownership of the product is substantially transferred to the buyer.

(h) Finance expense

Finance expense comprises interest expense on bank indebtedness and accretion of the discount on the decommissioning liability.

(i) Income tax

Income tax expense or recovery comprises current and deferred income tax. Income tax expense or recovery is recognized in income or loss except to the extent that it relates to items recognized directly in shareholders’ equity.

Current income tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to income tax payable in respect of previous years.

Deferred income tax is recognized using the liability 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 income tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination, and at the time of the transaction, affects neither accounting income nor taxable income. Deferred income 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.

A deferred income 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 income 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. Deferred income tax assets and liabilities are only offset when they are within the same legal entity and same tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

(j) Net income (loss) per share

Basic net income (loss) per share is calculated by dividing the net income (loss) attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share is determined by adjusting the net income (loss) attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as Performance Awards and Stock Options granted to service providers using the treasury stock method.

(k) Investment tax credits

Investment tax credits relating to Scientific Research and Experimental Development claims are considered an income tax credit and are offset against our income tax expense when they become probable of realization.

(l) Accounting Pronouncement not yet Adopted

IFRS 9 Financial Instruments introduces a new classification and measurement requirements, impairment model and hedge accounting model. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Advantage does not anticipate any material changes or effects to our current accounting.

IFRS 15 Revenue from Contracts with Customers requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. The standard is to be adopted for annual periods beginning on or after January 1, 2018, either retrospectively or using a modified retrospective approach. Advantage has individually assessed each current and possible future revenue stream using the principles established by IFRS 15. Based on these assessments, Advantage has determined that accounting for each of its revenue streams will be substantially the same under IFRS 15 as under current IFRS standards. Advantage does not anticipate any material impacts to its current accounting from the adoption of IFRS 15.

IFRS 16 Leases requires the recognition of assets and liabilities for most leases. The standard applies to annual periods beginning on or after January 1, 2019. Under IFRS 16, lease assets and liabilities will be required to be recognized on the balance sheet for most leases, where the entity is acting as a lessee. Certain leases of low-value assets and leases with short-terms (less than 12 months) will be exempt from the balance sheet recognition requirements, and may continue to be treated as operating leases. Advantage is currently reviewing the impact of IFRS 16 on its financial statements.

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Significant accounting judgments, estimates and assumptions

12 Months Ended

Dec. 31, 2017

Disclosure Of Accounting Judgements And Estimates Explanatory [Abstract]

Disclosure of accounting judgements and estimates [text block]

4. Significant accounting judgments, estimates and assumptions

The preparation of consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates, and differences could be material. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected. Significant estimates and judgments made in the preparation of the consolidated financial statements are outlined below.

(a) Reserves base

The natural gas and liquids properties are depreciated on a UOP basis at a rate calculated by reference to proved and probable reserves determined in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” and incorporating the estimated future cost of developing and extracting those reserves. Proved plus probable reserves are determined using estimates of natural gas and liquids in place, recovery factors and future natural gas and liquids prices. Future development costs are estimated using assumptions as to the number of wells required to produce the reserves, the cost of such wells and associated production facilities and other capital costs.

(b) Determination of cash generating unit

Management has determined there to be a single CGU (the “Glacier Area”) on the basis of its ability to generate independent cash flows, similar reserve characteristics, geographical location, and shared infrastructure, namely a single processing plant owned by Advantage. For purposes of assessment of impairment, management has allocated all exploration and evaluation assets to the Glacier Area CGU, on the basis of their geographic proximity.

(c) Impairment indicators and calculation of impairment

At each reporting date, Advantage assesses whether or not there are circumstances that indicate a possibility that the carrying values of exploration and evaluation assets and property, plant and equipment are not recoverable, or impaired. Such circumstances include, but are not limited to, incidents of physical damage, deterioration of commodity prices, changes in the regulatory environment, a reduction in estimates of proved and probable reserves, or significant increases to expected costs to produce and transport reserves.

When management judges that circumstances indicate potential impairment, property, plant and equipment are tested for impairment by comparing the carrying values to their recoverable amounts. The recoverable amounts of cash generating units are determined based on the higher of value-in-use calculations and fair values less costs of disposition. These calculations require the use of estimates and assumptions, that are subject to change as new information becomes available including information on future commodity prices, expected production volumes, quantities of reserves, discount rates, future development costs and operating costs.

(d) Derivative assets and liabilities

Derivative assets and liabilities are recorded at their fair values at the reporting date, with gains and losses recognized directly into comprehensive income in the same period. The fair value of derivatives outstanding is an estimate based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are non-cash items and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions.

(e) Decommissioning liability

Decommissioning costs will be incurred by the Corporation at the end of the operating life of the Corporation’s facilities and properties. The ultimate decommissioning liability is uncertain and can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques, experience at other production sites, or changes in the risk-free discount rate. The expected timing and amount of expenditure can also change in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results.

(f) Income taxes

Income tax laws and regulations are subject to change. Deferred tax liabilities that arise from temporary differences between recorded amounts on the statement of financial position and their respective tax bases will be payable in future periods. The amount of a deferred tax liability is subject to management’s best estimate of when a temporary difference will reverse and expected changes in income tax rates. These estimates by nature involve significant measurement uncertainty.

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Cash and cash equivalents

12 Months Ended

Dec. 31, 2017

Cash And Cash Equivalent [Abstract]

Disclosure of cash and cash equivalents [text block]

5. Cash and cash equivalents

	December 31, 2017		December 31, 2016
Cash at financial institutions	$	6,916	$	-

Cash at financial institutions earns interest at floating rates based on daily deposit rates. As at December 31, 2017, cash at financial institutions included US$0.1 million (December 31, 2016: nil). The Corporation only deposits cash with major financial institutions of high quality credit ratings.

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Trade and other receivables

12 Months Ended

Dec. 31, 2017

Disclosure Of Trade And Other Receivables Explanatory [Abstract]

Disclosure of trade and other receivables [text block]

6. Trade and other receivables

	December 31, 2017		December 31, 2016
Trade receivables	$	25,384	$	25,087
Receivables from joint venture partners		1,425		581
Other		1,869		637
	$	28,678	$	26,305

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Exploration and evaluation assets

12 Months Ended

Dec. 31, 2017

Disclosure Of Exploration And Evaluation Assets Explanatory [Abstract]

Disclosure of exploration and evaluation assets [text block]

7. Exploration and evaluation assets

Balance at December 31, 2015	$	10,071
Additions		6,001
Transferred to property, plant and equipment (note 8)		(60	)
Balance at December 31, 2016	$	16,012
Additions		7,207
Lease expiries		(168	)
Transferred to property, plant and equipment (note 8)		(908	)
Balance at December 31, 2017	$	22,143

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Property, plant and equipment

12 Months Ended

Dec. 31, 2017

Disclosure Of Property Plant And Equipment Explanatory [Abstract]

Disclosure of property, plant and equipment [text block]

8. Property, plant and equipment

Cost	Natural gas and  liquids properties			Furniture  and  equipment		Total
Balance at December 31, 2015	$	1,874,418		$	5,482	$	1,879,900
Additions		121,847			166		122,013
Change in decommissioning liability (note 11)		(2,641	)		-		(2,641	)
Transferred from exploration and evaluation assets (note 7)		60			-		60
Balance at December 31, 2016	$	1,993,684		$	5,648	$	1,999,332
Additions		241,449			118		241,567
Change in decommissioning liability (note 11)		6,160			-		6,160
Transferred from exploration and evaluation assets (note 7)		908			-		908
Balance at December 31, 2017	$	2,242,201		$	5,766	$	2,247,967

Accumulated depreciation	Natural gas and  liquids properties		Furniture  and  equipment		Total
Balance at December 31, 2015	$	428,905	$	3,912	$	432,817
Depreciation		115,885		347		116,232
Balance at December 31, 2016	$	544,790	$	4,259	$	549,049
Depreciation		117,643		302		117,945
Balance at December 31, 2017	$	662,433	$	4,561	$	666,994

Net book value	Natural gas and  liquids properties		Furniture  and  equipment		Total
At December 31, 2016	$	1,448,894	$	1,389	$	1,450,283
At December 31, 2017	$	1,579,768	$	1,205	$	1,580,973

During the year ended December 31, 2017, Advantage capitalized general and administrative expenditures directly related to development activities of $4.1 million (December 31, 2016 - $3.8 million). During the year ended December 31, 2017, Advantage capitalized share based compensation directly related to development activities of $3.2 million (December 31, 2016 - $2.3 million).

Advantage included future development costs of $1.7 billion (December 31, 2016 – $1.6 billion) in property, plant and equipment costs subject to depreciation.

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Financial risk management

12 Months Ended

Dec. 31, 2017

Disclosure Of Financial Risk Management Explanatory [Abstract]

Disclosure of financial risk management [text block]

9. Financial risk management

Financial instruments of the Corporation include trade and other receivables, deposits, trade and other accrued liabilities, bank indebtedness, and derivative assets and liabilities.

Trade and other receivables and deposits are classified as loans and receivables and measured at amortized cost. Trade and other accrued liabilities and bank indebtedness are all classified as financial liabilities at amortized cost. As at December 31, 2017, there were no significant differences between the carrying amounts reported on the Consolidated Statement of Financial Position and the estimated fair values of these financial instruments due to the short terms to maturity and the floating interest rate on the bank indebtedness.

Fair value is determined following a three level hierarchy:

Level 1: Quoted prices in active markets for identical assets and liabilities. The Corporation does not have any financial assets or liabilities that require level 1 inputs.

Level 2: Inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly. Such inputs can be corroborated with other observable inputs for substantially the complete term of the contract. Derivative assets and liabilities are measured at fair value on a recurring basis. For derivative assets and liabilities, pricing inputs include quoted forward prices for commodities, foreign exchange rates, volatility and risk-free rate discounting, all of which can be observed or corroborated in the marketplace. The actual gains and losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions.

Level 3: Fair value is determined using inputs that are not observable. Advantage has no assets or liabilities that use level 3 inputs. 

The Corporation’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:

· credit risk;

· liquidity risk;

· price risk; and

· interest rate risk.

(a) Credit risk

Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Corporation’s receivables from natural gas and liquids marketers and companies with whom we enter into derivative contracts. The maximum exposure to credit risk is as follows:

	December 31, 2017		December 31, 2016
Trade and other receivables	$	28,678	$	26,305
Deposits		938		665
Derivative asset		50,870		2,178
	$	80,486	$	29,148

Trade and other receivables, deposits, and derivative assets are subject to credit risk exposure and the carrying values reflect Management’s assessment of the associated maximum exposure to such credit risk. Advantage mitigates such credit risk by closely monitoring significant counterparties and dealing with a broad selection of counterparties that diversify risk within the sector. The Corporation’s deposits are due from the Alberta Provincial government and are viewed by Management as having minimal associated credit risk. To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities. In addition, the Corporation only enters into derivative contracts with major banks and international energy firms to further mitigate associated credit risk.

Substantially all of the Corporation’s trade and other receivables are due from customers concentrated in the Canadian oil and gas industry. As such, trade and other receivables are subject to normal industry credit risks. As at December 31, 2017, $0.2 million or 0.8% of trade and other receivables are outstanding for 90 days or more (December 31, 2016 - $0.4 million or 1.4% of trade and other receivables). The Corporation believes the entire balance is collectible, and in some instances has the ability to mitigate risk through withholding production or offsetting payables with the same parties. Management has not provided an allowance for doubtful accounts at December 31, 2017 or 2016.

The Corporation’s most significant customer, a Canadian oil and natural gas marketer, accounts for $19.2 million of the trade and other receivables at December 31, 2017 (December 31, 2016 - $22.2 million).

(b) Liquidity risk

The Corporation is subject to liquidity risk attributed from trade and other accrued liabilities and bank indebtedness. Trade and other accrued liabilities are primarily due within one year of the Consolidated Statement of Financial Position date and Advantage does not anticipate any problems in satisfying the obligations from cash provided by operating activities and the existing credit facilities. The Corporation’s bank indebtedness is subject to $400 million credit facility agreements. Although the credit facilities are a source of liquidity risk, the facilities also mitigate liquidity risk by enabling Advantage to manage interim cash flow fluctuations. The terms of the credit facilities are such that they provide Advantage adequate flexibility to evaluate and assess liquidity issues if and when they arise. Additionally, the Corporation regularly monitors liquidity related to obligations by evaluating forecasted cash flows, optimal debt levels, capital spending activity, working capital requirements, and other potential cash expenditures. This continual financial assessment process further enables the Corporation to mitigate liquidity risk.

To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to liquidity risk as derivative liabilities become due. While the Corporation has elected not to follow hedge accounting, derivative instruments are not entered for speculative purposes and Management closely monitors existing commodity risk exposures. As such, liquidity risk is mitigated since any losses actually realized are offset by increased cash flows realized from the higher commodity price environment.

The timing of cash outflows relating to financial liabilities as at December 31, 2017 and 2016 are as follows:

December 31, 2017		Less than one year		One to  three years		Total
Trade and other accrued liabilities		$	51,004	$	-	$	51,004
Bank indebtedness	- principal		-		210,001		210,001
	- interest (1)		9,404		4,483		13,887
		$	60,408	$	214,484	$	274,892

December 31, 2016		Less than one year		One to  three years		Total
Trade and other accrued liabilities		$	34,153	$	-	$	34,153
Bank indebtedness	- principal		-		153,811		153,811
	- interest (1)		6,890		3,284		10,174
		$	41,043	$	157,095	$	198,138

⁽¹⁾ Interest on bank indebtedness was calculated assuming conversion of the revolving credit facility to a one-year term facility.

The Corporation’s bank indebtedness does not have specific maturity dates. It is governed by credit facility agreements with a syndicate of financial institutions (note 10). Under the terms of the agreements, the facilities are reviewed annually, with the next review scheduled in June 2018. The facilities are revolving and are extendible at each annual review for a further 364 day period at the option of the syndicate. If not extended, the credit facilities are converted at that time into one year term facilities, with the principal payable at the end of such one year terms. Management fully expects that the facilities will be extended at each annual review.

(c) Price risk

Advantage’s derivative assets and liabilities are subject to price risk as their fair values are based on assumptions regarding forward commodity prices. The Corporation enters into non-financial derivatives to manage commodity price risk exposure relative to actual commodity production and does not utilize derivative instruments for speculative purposes. Changes in the price assumptions can have a significant effect on the fair value of the derivative assets and liabilities and thereby impact earnings. It is estimated that a 10% change in the forward AECO natural gas price used to calculate the fair value of the fixed price swap and sold call option natural gas derivatives at December 31, 2017 would result in a $4.7 million change in net income (loss) for the year ended December 31, 2017. It is estimated that a 10% change in the forward basis differential between Henry Hub and AECO natural gas prices would result in a $2.1 million change in net income (loss) for the year ended December 31, 2017. It is estimated that a 10% change in the forward Dawn natural gas price used to calculate the fair value of the fixed price swap natural gas derivatives at December 31, 2017 would result in a $3.3 million change in net income (loss) for the year ended December 31, 2017.

The Corporation’s derivative contracts are classified as Level 2 within the fair value hierarchy. As at December 31, 2017, the Corporation had the following derivative contracts in place:

Description of Derivative	Term	Volume	Price
Natural gas – AECO
Fixed price swap	April 2017 to March 2018	4,739 mcf/d	Cdn $3.27/mcf
Fixed price swap	April 2017 to March 2018	14,217 mcf/d	Cdn $3.27/mcf
Fixed price swap	November 2017 to March 2018	18,956 mcf/d	Cdn $3.22/mcf
Fixed price swap	July 2017 to March 2018	4,739 mcf/d	Cdn $3.02/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.01/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	July 2017 to June 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	April 2017 to March 2018	23,695 mcf/d	Cdn $3.01/mcf
Call option sold	April 2017 to December 2018	23,695 mcf/d	Cdn $3.17/mcf (1)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.01/mcf (2)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.06/mcf (3)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.11/mcf (4)
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	9,478 mcf/d	Cdn $3.00/mcf

⁽¹⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

⁽²⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.32/mcf.

⁽³⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.38/mcf.

⁽⁴⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2018 to September 2018	25,000 mcf/d	Henry Hub less US $0.95/mcf
Basis swap	January 2019 to December 2019	25,000 mcf/d	Henry Hub less US $0.90/mcf

Natural gas – Dawn

Fixed price swap December 2017 to March 2018  10,000 mcf/d US $3.45/mcf

Subsequent to December 31, 2017, the Corporation entered into the following derivative contracts:

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2021 to December 2024	5,000 mcf/d	Henry Hub less US $1.135/mcf
Basis swap	January 2021 to December 2024	2,500 mcf/d	Henry Hub less US $1.185/mcf
Basis swap	January 2021 to December 2024	17,500 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2020	5,000 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2024	15,000 mcf/d	Henry Hub less US $1.20/mcf

As at December 31, 2017, the fair value of the derivatives outstanding resulted in an asset of $50.9 million (December 31, 2016 – $2.2 million) and a liability of $0.1 million (December 31, 2016 – $24.7 million). The fair value of the commodity risk management derivatives have been allocated to current assets and liabilities on the basis of expected timing of cash settlement.

For the year ended December 31, 2017, $101.2 million was recognized in net income (loss) as a derivative gain (December 31, 2016 - $13.7 million loss). The table below summarizes the realized and unrealized gains (losses) on derivatives recognized in net income (loss).

	Year ended		Year ended
	December 31, 2017		December 31, 2016
Realized gains on derivatives	$	27,847	$	53,094
Unrealized gains (losses) on derivatives		73,305		(66,781	)
Gains (losses) on derivatives	$	101,152	$	(13,687	)

(d) Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on the outstanding bank indebtedness fluctuates with the interest rates posted by the lenders. The Corporation is exposed to interest rate risk and has not entered into any mitigating interest rate hedges or swaps. Had the borrowing rate been different by 100 basis points throughout the year ended December 31, 2017, net income (loss) and comprehensive income (loss) would have changed by $1.2 million (December 31, 2016 - $1.5 million) based on the average debt balance outstanding during the year.

(e) Capital management

The Corporation manages its capital with the following objectives:

· To ensure sufficient financial flexibility to achieve the ongoing business objectives including replacement of production, funding of future growth opportunities, and pursuit of accretive acquisitions; and

· To maximize shareholder return through enhancing the share value.

Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Corporation is composed of working capital (excluding derivative assets and liabilities), bank indebtedness, and share capital. Advantage may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing either through bank indebtedness or convertible debenture issuances, refinancing current debt, issuing other financial or equity-based instruments, declaring a dividend, adjusting capital spending, or disposing of assets. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis.

Advantage’s capital structure as at December 31, 2017 and 2016 is as follows:

	December 31, 2017		December 31, 2016
Bank indebtedness (non-current) (note 10)	$	208,978	$	153,102
Working capital deficit		13,808		6,167
Total debt (1)	$	222,786	$	159,269
Shares outstanding (note 13)		185,963,186		184,654,333
Share closing market price ($/share)	$	5.40	$	9.12
Market capitalization		1,004,201		1,684,048
Total capitalization	$	1,226,987	$	1,843,317

(1) Total debt is a non-GAAP measure that includes bank indebtedness and working capital deficit.

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Bank indebtedness

12 Months Ended

Dec. 31, 2017

Disclosure Of Borrowings Explanatory [Abstract]

Disclosure of borrowings [text block]

10. Bank indebtedness

	December 31, 2017			December 31, 2016
Revolving credit facility	$	210,001		$	153,811
Discount on Bankers Acceptances and other fees		(1,023	)		(709	)
Balance, end of year	$	208,978		$	153,102

As at December 31, 2017, the Corporation had reserve-based credit facilities (the "Credit Facilities") with a borrowing base of $400 million. The Credit Facilities are comprised of a $20 million extendible revolving operating loan facility from one financial institution and a $380 million extendible revolving credit facility from a syndicate of financial institutions. The revolving period for the Credit Facilities will end in June 2018 unless extended at the option of the syndicate for a further 364 day period. If not extended, the credit facility will be converted at that time into a one-year term facility, with the principal payable at the end of such one-year term. The Credit Facilities are subject to re-determination of the borrowing base semi-annually in October and June of each year, with the next annual review scheduled to occur in June 2018. There can be no assurance that the Credit Facilities will be renewed at the current borrowing base level at that time. The borrowing base is determined based on, among other things, a thorough evaluation of Advantage's reserve estimates based upon the lenders commodity price assumptions. Revisions or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing base. In the event that the lenders reduce the borrowing base below the amount drawn at the time of redetermination, the Corporation has 60 days to eliminate any shortfall by repaying amounts in excess of the new re-determined borrowing base. Amounts borrowed under the Credit Facilities bear interest at rates ranging from LIBOR plus 2% to 3.25% per annum, and Canadian prime or US base rate plus 1% to 2.25% per annum, in each case, depending on the type of borrowing and the Corporation’s debt to Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”) ratio. Undrawn amounts under the Credit Facilities bear a standby fee ranging from 0.5% to 0.8125% per annum, dependent on the Corporation’s debt to EBITDA ratio. Repayments of principal are not required prior to maturity provided that the borrowings under the Credit Facilities do not exceed the authorized borrowing base and the Corporation is in compliance with all covenants, representations and warranties. The Credit Facilities prohibit the Corporation from entering into any fixed price derivative contract, excluding basis swaps, where the term of such contract exceeds five years. Further, the aggregate of such contracts cannot hedge greater than 75% of total estimated natural gas and liquids production over the first three years and 50% over the fourth and fifth years. In addition, the Credit Facilities allow us to enter into basis swap arrangements to any natural gas price point in North America for up to 100,000 MMbtu/day with a maximum term of seven years. Basis swap arrangements do not count against the limitations on hedged production. The Credit Facilities contain standard commercial covenants for credit facilities of this nature. The Corporation did not have any financial covenants at December 31, 2017 and December 31, 2016. All applicable non-financial covenants were met at December 31, 2017 and 2016. Breach of any covenant will result in an event of default in which case the Corporation has 30 days to remedy such default. If the default is not remedied or waived, and if required by the lenders, the administrative agent of the lenders has the option to declare all obligations under the credit facilities to be immediately due and payable without further demand, presentation, protest, days of grace, or notice of any kind. The Credit Facilities are collateralized by a $1 billion floating charge demand debenture covering all assets. For the year ended December 31, 2017, the average effective interest rate on the outstanding amounts under the facilities was approximately 4.5% (December 31, 2016 – 3.5%). Advantage had no letters of credit issued and outstanding at December 31, 2017 (December 31, 2016 - none).

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Decommissioning liability

12 Months Ended

Dec. 31, 2017

Disclosure of the decommissioning liability [Abstract]

Disclosure of the decommissioning liability [text block]

11. Decommissioning liability

The Corporation’s decommissioning liability results from net ownership interests in natural gas and liquids assets including well sites, gathering systems and processing facilities, all of which will require future costs of decommissioning under environmental legislation. These costs are expected to be incurred between 2018 and 2077. A risk-free rate of 2.20% (December 31, 2016 – 2.34%) and an inflation factor of 2.0% (December 31, 2016 – 2.0%) were used to calculate the fair value of the decommissioning liability at December 31, 2017. A reconciliation of the decommissioning liability is provided below:

	Year ended			Year ended
	December 31, 2017			December 31, 2016
Balance, beginning of year	$	40,992		$	44,575
Accretion expense		951			915
Property acquisitions		751			-
Liabilities incurred		2,175			2,193
Change in estimates		(2,665	)		(1,165	)
Effect of change in risk-free rate and inflation rate factor		5,899			(3,669	)
Liabilities settled		(1,190	)		(1,857	)
Balance, end of year	$	46,913		$	40,992

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Income taxes

12 Months Ended

Dec. 31, 2017

Disclosure Of Income Tax [Abstract]

Disclosure of income tax [text block]

12. Income taxes

The provision for income taxes is as follows:

	Year ended		Year ended
	December 31, 2017		December 31, 2016
Current income tax expense	$	-	$	-
Deferred income tax expense (recovery)		37,285		(4,614	)
Income tax expense (recovery)	$	37,285	$	(4,614	)

The provision for income taxes varies from the amount that would be computed by applying the combined federal and provincial income tax rates for the following reasons:

	Year ended			Year ended
	December 31, 2017			December 31, 2016
Income (loss) before taxes	$	132,324		$	(20,348	)
Combined federal and provincial income tax rates		27.00	%		27.00	%
Expected income tax expense (recovery)		35,727			(5,494	)
Increase (decrease) in income taxes resulting from:
Non-deductible share based compensation		2,261			1,515
Difference between current and expected tax rates		(703	)		(635	)
	$	37,285		$	(4,614	)
Effective tax rate		28.18	%		22.68	%

The movement in deferred income tax liabilities and assets without taking into consideration the offsetting of balances within the same tax jurisdiction is as follows:

Deferred income tax liability	Property, plant and equipment		Derivative  asset/liability			Total
Balance at December 31, 2015	$	262,997	$	11,943		$	274,940
Charged (credited) to income		5,192		(18,031	)		(12,839	)
Balance at December 31, 2016	$	268,189	$	(6,088	)	$	262,101
Charged to income		13,522		19,793			33,315
Balance at December 31, 2017	$	281,711	$	13,705		$	295,416

Deferred income tax asset	Decommissioning liability			Non-capital losses			Other			Total
Balance at December 31, 2015	$	(12,064	)	$	(198,649	)	$	(23,075	)	$	(233,788	)
Charged to income		991			7,200			34			8,225
Credited to equity		-			(264	)		(1,059	)		(1,323	)
Balance at December 31, 2016	$	(11,073	)	$	(191,713	)	$	(24,100	)	$	(226,886	)
Charged (credited) to income		(1,593	)		5,268			295			3,970
Balance at December 31, 2017	$	(12,666	)	$	(186,445	)	$	(23,805	)	$	(222,916	)

Net deferred income tax liability (asset)
Balance at December 31, 2015	$	41,152
Credited to income		(4,614	)
Credited to equity		(1,323	)
Balance at December 31, 2016	$	35,215
Charged to income		37,285
Balance at December 31, 2017	$	72,500

The estimated tax pools available at December 31, 2017 are as follows:

Canadian development expenses	$	210,758
Canadian exploration expenses		65,994
Canadian oil and gas property expenses		14,631
Non-capital losses		690,538
Undepreciated capital cost		251,203
Capital losses		157,869
Scientific research and experimental development expenditures		32,506
Other		10,900
	$	1,434,399

The non-capital loss carry forward balances above expire no earlier than 2023.

No deferred tax asset has been recognized for capital losses of $158 million (December 31, 2016 – $158 million). Recognition is dependent on the realization of future taxable capital gains.

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Share capital

12 Months Ended

Dec. 31, 2017

Disclosure Of Share Capital Reserves And Other Equity Interest Explanatory [Abstract]

Disclosure of share capital, reserves and other equity interest [text block]

13. Share capital

(a) Authorized

The Corporation is authorized to issue an unlimited number of shares without nominal or par value.

(b) Issued

	Common Shares		Amount
Balance at December 31, 2015		170,827,158	$	2,236,728
Shares issued on financing, net of issue costs and deferred taxes		13,427,075		96,453
Shares issued on exercise of stock options (note 15(a))		400,100		-
Contributed surplus transferred on exercise of stock options (note 15(a))		-		1,018
Balance at December 31, 2016		184,654,333	$	2,334,199
Shares issued on Performance Award settlement (note 15(b))		825,359		-
Contributed surplus transferred on Performance Award settlement (note 15(b))		-		5,374
Shares issued on exercise of stock options (note 15(a))		483,494		-
Contributed surplus transferred on exercise of stock options (note 15(a))		-		1,228
Balance at December 31, 2017		185,963,186	$	2,340,801

On March 8, 2016, the Corporation closed an equity financing whereby 13,427,075 common shares were issued at $7.45 per share, for gross proceeds of $100 million, less $3.6 million related to $4.9 million of issuance costs net of $1.3 million of deferred taxes.

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Net income (loss) per share

12 Months Ended

Dec. 31, 2017

Earnings Per Share Explanatory [Abstract]

Earnings per share [text block]

14. Net income (loss) per share

The calculations of basic and diluted net income (loss) per share are derived from both net income (loss) and weighted average shares outstanding, calculated as follows:

	Year ended
	December 31
	2017		2016
Net income (loss)
Basic and diluted	$	95,039	$	(15,734	)
Weighted average shares outstanding
Basic		185,641,050		182,056,120
Stock Options		389,977		-
Performance Awards		3,545,861		-
Diluted		189,576,888		182,056,120

The calculation of diluted net income (loss) per share for the year ended December 31, 2016 excludes the effects of Stock Options and Performance Awards, as their impacts would be anti-dilutive. Total weighted average shares of 866,241 and 648,037 in respect of Stock Options and Performance Awards, respectively, were excluded from the diluted net income (loss) per share calculation.

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Share based compensation

12 Months Ended

Dec. 31, 2017

Disclosure of Share based compensation [Abstract]

Disclosure of share-based payment arrangements [text block]

15. Share based compensation

(a) Stock Option Plan

Under the Stock Option Plan, service providers are granted Stock Options with exercise prices that approximate the market price of common shares at the date of grant. Share based compensation costs of the Stock Option Plan are determined using a Black-Scholes valuation model, using weighted average assumptions as follows:

Volatility	41	%
Expected forfeiture rate	0.98	%
Dividend rate	0	%
Risk-free rate	1.05	%

Volatility is based on historical stock prices at the close-of-trade-day over a historical time period.

The following tables summarize information about changes in Stock Options outstanding at December 31, 2017:

	Stock Options			Weighted-Average Exercise Price
Balance at December 31, 2015		4,031,302		$	5.49
Exercised		(921,387	)		4.64
Balance at December 31, 2016		3,109,915		$	5.75
Exercised		(1,085,681	)	$	4.72
Forfeited		(18,377	)		6.82
Balance at December 31, 2017		2,005,857		$	6.30

	Stock Options Outstanding						Stock Options Exercisable
Range of Exercise Price	Number of Stock Options Outstanding		Weighted Average Remaining Contractual Life - Years		Weighted Average Exercise Price		Number of Stock Options Exercisable		Weighted Average Exercise Price
$5.87 - $6.81		1,110,009		1.29	$	5.87		1,110,009	$	5.87
$6.82		895,848		2.26		6.82		584,927		6.82
$5.87 - $6.82		2,005,857		1.72	$	6.30		1,694,936	$	6.20

During the year ended December 31, 2017, 1,085,681 Stock Options were exercised with no cash consideration, resulting in the issuance of 483,494 common shares.

(b) Performance Incentive Plan

Under the Performance Incentive Plan, service providers can be granted two types of Incentive Awards: Restricted Awards and Performance Awards. A Restricted Award is a grant denominated in a fixed number of common shares which generally vests 1/3 on the first anniversary of the grant date, 1/3 on the second anniversary, and 1/3 on the third anniversary. A Performance Award is a grant denominated in a fixed number of common shares which vests on the third anniversary of the grant date. Performance Award grants are multiplied by a Payout Multiplier, that is determined based on Corporate Performance Measures, as approved by the Board of Directors.

As at December 31, 2017, no Restricted Awards have been granted.

The following table is a continuity of Performance Awards:

	Performance Awards
Balance at December 31, 2015		666,092
Granted		661,571
Balance at December 31, 2016		1,327,663
Granted		723,676
Settlements		(402,582	)
Forfeited/cancelled		(68,458	)
Balance at December 31, 2017		1,580,299

During April 2017, 402,582 Performance Awards matured and were settled with no cash consideration, resulting in the issuance of 825,359 common shares, after applying the Payout Multiplier.

Share based compensation recognized by plan for the years ended December 31, 2017 and 2016 are as follows:

	Year ended
	December 31
	2017			2016
Stock Options	$	355		$	784
Performance Awards		8,009			4,823
Total share based compensation		8,364			5,607
Capitalized (note 8)		(3,245	)		(2,326	)
Net share based compensation expense	$	5,119		$	3,281

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Natural gas and liquids sales

12 Months Ended

Dec. 31, 2017

Disclosure of natural gas and liquids sales [Abstract]

Disclosure of natural gas and liquids sales [text block]

16. Natural gas and liquids sales

	Year ended
	December 31
	2017		2016
Natural gas sales	$	207,623	$	145,878
Natural gas liquids sales		24,141		16,055
Total natural gas and liquids sales	$	231,764	$	161,933

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General and administrative expense (“G&A”)

12 Months Ended

Dec. 31, 2017

Disclosure Of General And Administrative Expense [Abstract]

Disclosure of general and administrative expense [text block]

17. General and administrative expense (“G&;A”)

	Year ended
	December 31
	2017			2016
Salaries and benefits	$	8,741		$	7,332
Office rent		1,069			989
Other		1,432			2,952
Total G&;A		11,242			11,273
Capitalized (note 8)		(4,077	)		(3,804	)
General and administrative expense	$	7,165		$	7,469

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Finance expense

12 Months Ended

Dec. 31, 2017

Disclosure Of Finance Cost [Abstract]

Disclosure of finance cost [text block]

18. Finance expense

	Year ended
	December 31
	2017		2016
Interest on bank indebtedness (note 10)	$	6,931	$	9,335
Accretion of decomissioning liability (note 11)		951		915
Total finance expense	$	7,882	$	10,250

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Related party transactions

12 Months Ended

Dec. 31, 2017

Disclosure Of Related Party Explanatory [Abstract]

Disclosure of related party [text block]

19. Related party transactions

Key management compensation

The compensation paid or payable to officers and directors is as follows:

	Year ended  December 31, 2017		Year ended December 31, 2016
Salaries, director fees and short-term benefits	$	2,495	$	2,111
Share based compensation (1)		4,300		2,676
	$	6,795	$	4,787

⁽¹⁾ Represents the grant date fair value of Performance Awards and Stock Options granted.

As at December 31, 2017, there is a commitment of $2.9 million (December 31, 2016 - $2.2 million) related to change of control or termination of employment of officers.

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Supplementary cash flow information

12 Months Ended

Dec. 31, 2017

Disclosure Of Supplementary cash flow information [Abstract]

Disclosure of cash flow statement [text block]

20. Supplementary cash flow information

Changes in non-cash working capital is comprised of:

	Year ended
	December 31
	2017			2016
Source (use) of cash:
Trade and other receivables	$	(2,373	)	$	(12,417	)
Prepaid expenses and deposits		79			285
Trade and other accrued liabilities		16,850			11,103
	$	14,556		$	(1,029	)
Related to operating activities	$	(2,542	)	$	567
Related to financing activities		-			-
Related to investing activities		17,098			(1,596	)
	$	14,556		$	(1,029	)

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Commitments

12 Months Ended

Dec. 31, 2017

Disclosure Of Commitments [Abstract]

Disclosure of commitments [text block]

21. Commitments

Advantage has lease commitments relating to office buildings of $1.8 million (December 31, 2016 - $3.0 million) and transportation commitments of $384.9 million (December 31, 2016 - $180.2 million). The estimated remaining annual minimum payments are as follows:

	December 31
	2017		2016
2017	$	-	$	26,067
2018		47,327		27,338
2019		51,316		28,519
2020		49,941		21,850
2021		45,997		17,892
2022		43,885		17,566
2023 and thereafter		148,239		43,980
Total commitments	$	386,705	$	183,212

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Significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2017

Disclosure Of Summary Of Significant Accounting Policies Explanatory [Abstract]

Cash and cash equivalents

(a) Cash and cash equivalents

Cash consists of balances held with banks, and other short-term highly liquid investments with original maturities of three months or less from inception.

Basis of consolidation

(b) Basis of consolidation

(i) Subsidiaries

Subsidiaries are entities controlled by the Corporation. Control exists when the Corporation is exposed, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

(ii) Joint arrangements

A portion of the Corporation’s natural gas and liquids activities involve joint operations. The consolidated financial statements include the Corporation’s share of these joint operations and a proportionate share of the relevant revenue and costs.

Financial instruments

(c) Financial instruments

All financial instruments are initially recognized at fair value on the Consolidated Statement of Financial Position. Measurement of financial instruments subsequent to the initial recognition, as well as resulting gains and losses, is based on how each financial instrument was initially classified. The Corporation has classified each identified financial instrument into the following categories: fair value through profit or loss, loans and receivables, held to maturity investments, available for sale financial assets, and financial assets and liabilities at amortized cost. Fair value through profit or loss financial instruments are measured at fair value with gains and losses recognized in income immediately. Available for sale financial assets are measured at fair value with gains and losses, other than impairment losses, recognized in other comprehensive income and transferred to income when the asset is derecognized. Loans and receivables, held to maturity investments and financial assets and liabilities at amortized cost, are recognized at amortized cost using the effective interest method and impairment losses are recorded in income when incurred.

Derivative instruments executed by the Corporation to manage market risk associated with volatile commodity prices are classified as fair value through profit or loss and recorded on the Consolidated Statement of Financial Position as derivatives assets and liabilities measured at fair value. Gains and losses on these instruments are recorded as gains and losses on derivatives in the Consolidated Statement of Comprehensive Income (Loss) in the period they occur. Gains and losses on derivative instruments are comprised of cash receipts and payments associated with periodic settlement that occurs over the life of the instrument, and non-cash gains and losses associated with changes in the fair values of the instruments, which are remeasured at each reporting date and recorded on the Consolidated Statement of Financial Position.

Property, plant and equipment and exploration and evaluation assets

(d) Property, plant and equipment and exploration and evaluation assets

(i) Recognition and measurement

Exploration and evaluation costs

Pre-license costs are recognized in the Consolidated Statement of Comprehensive Income (Loss) as incurred.

All exploratory costs incurred subsequent to acquiring the right to explore for natural gas and liquids before technical feasibility and commercial viability of the area have been established are capitalized. Such costs can typically include costs to acquire land rights, geological and geophysical costs and exploration well costs.

Exploration and evaluation costs are not depreciated and are accumulated in cost centers by well, field or exploration area and carried forward pending determination of technical feasibility and commercial viability.

The technical feasibility and commercial viability of extracting a mineral resource from exploration and evaluation assets is considered to be generally determinable when proved or probable reserves are determined to exist. Upon determination of proved or probable reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to property, plant and equipment, net of any impairment loss.

Management reviews and assesses exploration and evaluation assets to determine if technical feasibility and commercial viability exist. If Management decides not to continue the exploration and evaluation activity, the unrecoverable costs are charged to exploration and evaluation expense in the period in which the determination occurs.

Property, plant and equipment

Items of property, plant and equipment, which include natural gas and liquids properties, are measured at cost less accumulated depreciation and accumulated impairment losses. Costs include lease acquisition, drilling and completion, production facilities, decommissioning costs, geological and geophysical costs and directly attributable general and administrative costs and share based compensation related to development and production activities, net of any government incentive programs.

When significant parts of an item of property, plant and equipment, including natural gas and liquids properties, have different useful lives, they are accounted for as separate items (major components).

(ii) Subsequent costs

Costs incurred subsequent to development and production that are significant are recognized as natural gas and liquids property only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in comprehensive income as incurred. Such capitalized natural gas and liquids costs generally represent costs incurred in developing proved and probable reserves and producing or enhancing production from such reserves, and are accumulated on a field or area basis. The carrying amount of any replaced or sold component is derecognized in accordance with our policies. The costs of the day-to-day servicing of property, plant and equipment are recognized in the Consolidated Statement of Comprehensive Income (Loss) as incurred.

(iii) Depreciation

The net carrying value of natural gas and liquids properties is depreciated using the units-of-production (“UOP”) method by reference to the ratio of production in the period to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.

(iv) Dispositions

Gains and losses on disposal of an item of property, plant and equipment, including natural gas and liquids properties, are determined by comparing the proceeds from disposition with the carrying amount of property, plant and equipment and are recognized net within other income (expenses) in the Consolidated Statement of Comprehensive Income (Loss).

(v) Impairment

The carrying amounts of the Corporation’s property, plant and equipment are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, the asset’s recoverable amount is estimated. For the purpose of impairment testing of property, plant and equipment, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the “cash-generating unit” or “CGU”).

Exploration and evaluation assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, and facts and circumstances suggest that the carrying amount exceeds the recoverable amount. Exploration and evaluation assets are allocated to CGU’s or groups of CGU’s for the purposes of assessing such assets for impairment.

The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs of disposition. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Fair value less costs of disposition is assessed utilizing market valuation based on an arm’s length transaction between active participants. In the absence of any such transactions, fair value less costs of disposition is estimated by discounting the expected after-tax cash flows of the cash generating unit at an after-tax discount rate that reflects the risk of the properties in the cash generating unit. The discounted cash flow calculation is then increased by a tax-shield calculation, which is an estimate of the amount that a prospective buyer of the cash generating unit would be entitled. The carrying value of the cash generating unit is reduced by the deferred tax liability associated with its property, plant and equipment.

Impairment losses on property, plant and equipment are recognized in the Consolidated Statement of Comprehensive Income (Loss) as impairment of natural gas and liquids properties and are separately disclosed. An impairment of exploration and evaluation assets is recognized as exploration and evaluation expense in the Consolidated Statement of Comprehensive Income (Loss).

Decommissioning liability

(e) Decommissioning liability

A decommissioning liability is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Decommissioning liabilities are determined by discounting the expected future cash flows at a risk-free rate.

Share based compensation

(f) Share based compensation

Advantage accounts for share based compensation expense based on the fair value of rights granted under its share based compensation plans.

Advantage’s Stock Option Plan (“Stock Option Plan”) authorizes the Board of Directors to grant Stock Options to service providers, including directors, officers, employees and consultants of Advantage. Compensation costs related to the Stock Options are recognized as share based compensation expense over the vesting period at fair value.

Advantage’s Restricted and Performance Award Incentive Plan provides share based compensation for service providers. Awards granted under this plan may be settled in cash or in shares. As the Corporation generally intends to settle the Awards in shares, the plan is considered and accounted for as “equity-settled”.

As compensation expense is recognized, contributed surplus is recorded until the Performance Awards vest or Stock Options are exercised, at which time the appropriate common shares are then issued to the service providers and the contributed surplus is transferred to share capital.

Revenue

(g) Revenue

Revenue from the sale of natural gas and liquids is recorded when the significant risks and rewards of ownership of the product is substantially transferred to the buyer.

Finance expense

(h) Finance expense

Finance expense comprises interest expense on bank indebtedness and accretion of the discount on the decommissioning liability.

Income tax

(i) Income tax

Income tax expense or recovery comprises current and deferred income tax. Income tax expense or recovery is recognized in income or loss except to the extent that it relates to items recognized directly in shareholders’ equity.

Current income tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to income tax payable in respect of previous years.

Deferred income tax is recognized using the liability 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 income tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination, and at the time of the transaction, affects neither accounting income nor taxable income. Deferred income 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.

A deferred income 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 income 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. Deferred income tax assets and liabilities are only offset when they are within the same legal entity and same tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

Net income (loss) per share

(j) Net income (loss) per share

Basic net income (loss) per share is calculated by dividing the net income (loss) attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share is determined by adjusting the net income (loss) attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as Performance Awards and Stock Options granted to service providers using the treasury stock method.

Investment tax credits

(k) Investment tax credits

Investment tax credits relating to Scientific Research and Experimental Development claims are considered an income tax credit and are offset against our income tax expense when they become probable of realization.

Accounting Pronouncement no yet Adopted

(l) Accounting Pronouncement not yet Adopted

IFRS 9 Financial Instruments introduces a new classification and measurement requirements, impairment model and hedge accounting model. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Advantage does not anticipate any material changes or effects to our current accounting.

IFRS 15 Revenue from Contracts with Customers requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. The standard is to be adopted for annual periods beginning on or after January 1, 2018, either retrospectively or using a modified retrospective approach. Advantage has individually assessed each current and possible future revenue stream using the principles established by IFRS 15. Based on these assessments, Advantage has determined that accounting for each of its revenue streams will be substantially the same under IFRS 15 as under current IFRS standards. Advantage does not anticipate any material impacts to its current accounting from the adoption of IFRS 15.

IFRS 16 Leases requires the recognition of assets and liabilities for most leases. The standard applies to annual periods beginning on or after January 1, 2019. Under IFRS 16, lease assets and liabilities will be required to be recognized on the balance sheet for most leases, where the entity is acting as a lessee. Certain leases of low-value assets and leases with short-terms (less than 12 months) will be exempt from the balance sheet recognition requirements, and may continue to be treated as operating leases. Advantage is currently reviewing the impact of IFRS 16 on its financial statements.

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Cash and cash equivalents (Tables)

12 Months Ended

Dec. 31, 2017

Cash And Cash Equivalent [Abstract]

Disclosure Of Detailed Information About Cash And Cash Equivalents [Text Block]

Cash and cash equivalents

	December 31, 2017		December 31, 2016
Cash at financial institutions	$	6,916	$	-

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Trade and other receivables (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about trade and other receivables [Abstract]

Disclosure of detailed information about trade and other receivables [text block]

	December 31, 2017		December 31, 2016
Trade receivables	$	25,384	$	25,087
Receivables from joint venture partners		1,425		581
Other		1,869		637
	$	28,678	$	26,305

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Exploration and evaluation assets (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about exploration and evaluation assets [Abstract]

Disclosure of detailed information about exploration and evaluation assets [text block]

Balance at December 31, 2015	$	10,071
Additions		6,001
Transferred to property, plant and equipment (note 8)		(60	)
Balance at December 31, 2016	$	16,012
Additions		7,207
Lease expiries		(168	)
Transferred to property, plant and equipment (note 8)		(908	)
Balance at December 31, 2017	$	22,143

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Property, plant and equipment (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Detailed Information About Property Plant And Equipment Explanatory [Abstract]

Disclosure of detailed information about property, plant and equipment [text block]

Cost	Natural gas and  liquids properties			Furniture  and  equipment		Total
Balance at December 31, 2015	$	1,874,418		$	5,482	$	1,879,900
Additions		121,847			166		122,013
Change in decommissioning liability (note 11)		(2,641	)		-		(2,641	)
Transferred from exploration and evaluation assets (note 7)		60			-		60
Balance at December 31, 2016	$	1,993,684		$	5,648	$	1,999,332
Additions		241,449			118		241,567
Change in decommissioning liability (note 11)		6,160			-		6,160
Transferred from exploration and evaluation assets (note 7)		908			-		908
Balance at December 31, 2017	$	2,242,201		$	5,766	$	2,247,967

Accumulated depreciation	Natural gas and  liquids properties		Furniture  and  equipment		Total
Balance at December 31, 2015	$	428,905	$	3,912	$	432,817
Depreciation		115,885		347		116,232
Balance at December 31, 2016	$	544,790	$	4,259	$	549,049
Depreciation		117,643		302		117,945
Balance at December 31, 2017	$	662,433	$	4,561	$	666,994

Net book value	Natural gas and  liquids properties		Furniture  and  equipment		Total
At December 31, 2016	$	1,448,894	$	1,389	$	1,450,283
At December 31, 2017	$	1,579,768	$	1,205	$	1,580,973

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Financial risk management (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Credit Risk Exposure Explanatory [Abstract]

Disclosure of credit risk exposure [text block]

The maximum exposure to credit risk is as follows:

	December 31, 2017		December 31, 2016
Trade and other receivables	$	28,678	$	26,305
Deposits		938		665
Derivative asset		50,870		2,178
	$	80,486	$	29,148

Disclosure of maturity analysis for non-derivative financial liabilities [text block]

The timing of cash outflows relating to financial liabilities as at December 31, 2017 and 2016 are as follows:

December 31, 2017		Less than one year		One to  three years		Total
Trade and other accrued liabilities		$	51,004	$	-	$	51,004
Bank indebtedness	- principal		-		210,001		210,001
	- interest (1)		9,404		4,483		13,887
		$	60,408	$	214,484	$	274,892

December 31, 2016		Less than one year		One to  three years		Total
Trade and other accrued liabilities		$	34,153	$	-	$	34,153
Bank indebtedness	- principal		-		153,811		153,811
	- interest (1)		6,890		3,284		10,174
		$	41,043	$	157,095	$	198,138

⁽¹⁾ Interest on bank indebtedness was calculated assuming conversion of the revolving credit facility to a one-year term facility.

Disclosure of derivative financial instruments [text block]

As at December 31, 2017, the Corporation had the following derivative contracts in place:

Description of Derivative	Term	Volume	Price
Natural gas – AECO
Fixed price swap	April 2017 to March 2018	4,739 mcf/d	Cdn $3.27/mcf
Fixed price swap	April 2017 to March 2018	14,217 mcf/d	Cdn $3.27/mcf
Fixed price swap	November 2017 to March 2018	18,956 mcf/d	Cdn $3.22/mcf
Fixed price swap	July 2017 to March 2018	4,739 mcf/d	Cdn $3.02/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.01/mcf
Fixed price swap	July 2017 to March 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	July 2017 to June 2018	14,217 mcf/d	Cdn $3.00/mcf
Fixed price swap	April 2017 to March 2018	23,695 mcf/d	Cdn $3.01/mcf
Call option sold	April 2017 to December 2018	23,695 mcf/d	Cdn $3.17/mcf (1)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.01/mcf (2)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.06/mcf (3)
Fixed price swap	October 2017 to September 2018	4,739 mcf/d	Cdn $3.01/mcf
Call option sold	October 2017 to December 2018	4,739 mcf/d	Cdn $3.11/mcf (4)
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	18,956 mcf/d	Cdn $3.00/mcf
Fixed price swap	October 2018 to March 2019	9,478 mcf/d	Cdn $3.00/mcf

⁽¹⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

⁽²⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.32/mcf.

⁽³⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.38/mcf.

⁽⁴⁾ Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2018 to September 2018	25,000 mcf/d	Henry Hub less US $0.95/mcf
Basis swap	January 2019 to December 2019	25,000 mcf/d	Henry Hub less US $0.90/mcf

Natural gas – Dawn

Fixed price swap December 2017 to March 2018  10,000 mcf/d US $3.45/mcf

Disclosure of events after reporting period [text block]

Subsequent to December 31, 2017, the Corporation entered into the following derivative contracts:

Natural gas – AECO/Henry Hub Basis Differential

Basis swap	January 2021 to December 2024	5,000 mcf/d	Henry Hub less US $1.135/mcf
Basis swap	January 2021 to December 2024	2,500 mcf/d	Henry Hub less US $1.185/mcf
Basis swap	January 2021 to December 2024	17,500 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2020	5,000 mcf/d	Henry Hub less US $1.20/mcf
Basis swap	January 2020 to December 2024	15,000 mcf/d	Henry Hub less US $1.20/mcf

Disclosure of gain loss on derivatives [text block]

The table below summarizes the realized and unrealized gains (losses) on derivatives recognized in net income (loss).

	Year ended		Year ended
	December 31, 2017		December 31, 2016
Realized gains on derivatives	$	27,847	$	53,094
Unrealized gains (losses) on derivatives		73,305		(66,781	)
Gains (losses) on derivatives	$	101,152	$	(13,687	)

Disclosure of detailed information about capital structure of entity [text block]

Advantage’s capital structure as at December 31, 2017 and 2016 is as follows:

	December 31, 2017		December 31, 2016
Bank indebtedness (non-current) (note 10)	$	208,978	$	153,102
Working capital deficit		13,808		6,167
Total debt (1)	$	222,786	$	159,269
Shares outstanding (note 13)		185,963,186		184,654,333
Share closing market price ($/share)	$	5.40	$	9.12
Market capitalization		1,004,201		1,684,048
Total capitalization	$	1,226,987	$	1,843,317

(1) Total debt is a non-GAAP measure that includes bank indebtedness and working capital deficit.

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Bank indebtedness (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Detailed Information About Borrowings Explanatory [Abstract]

Disclosure of detailed information about borrowings [text block]

	December 31, 2017			December 31, 2016
Revolving credit facility	$	210,001		$	153,811
Discount on Bankers Acceptances and other fees		(1,023	)		(709	)
Balance, end of year	$	208,978		$	153,102

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Decommissioning liability (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of the decommissioning liability [Abstract]

Disclosure of detailed information about reconciliation of the decommissioning liability [text block]

A reconciliation of the decommissioning liability is provided below:

	Year ended			Year ended
	December 31, 2017			December 31, 2016
Balance, beginning of year	$	40,992		$	44,575
Accretion expense		951			915
Property acquisitions		751			-
Liabilities incurred		2,175			2,193
Change in estimates		(2,665	)		(1,165	)
Effect of change in risk-free rate and inflation rate factor		5,899			(3,669	)
Liabilities settled		(1,190	)		(1,857	)
Balance, end of year	$	46,913		$	40,992

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Income taxes (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Income Tax [Abstract]

Disclosure of provision for income tax [text block]

The provision for income taxes is as follows:

	Year ended		Year ended
	December 31, 2017		December 31, 2016
Current income tax expense	$	-	$	-
Deferred income tax expense (recovery)		37,285		(4,614	)
Income tax expense (recovery)	$	37,285	$	(4,614	)

Disclosure of detailed information about provision for income taxes [text block]

The provision for income taxes varies from the amount that would be computed by applying the combined federal and provincial income tax rates for the following reasons:

	Year ended			Year ended
	December 31, 2017			December 31, 2016
Income (loss) before taxes	$	132,324		$	(20,348	)
Combined federal and provincial income tax rates		27.00	%		27.00	%
Expected income tax expense (recovery)		35,727			(5,494	)
Increase (decrease) in income taxes resulting from:
Non-deductible share based compensation		2,261			1,515
Difference between current and expected tax rates		(703	)		(635	)
	$	37,285		$	(4,614	)
Effective tax rate		28.18	%		22.68	%

Disclosure of temporary difference, unused tax losses and unused tax credits [text block]

The movement in deferred income tax liabilities and assets without taking into consideration the offsetting of balances within the same tax jurisdiction is as follows:

Deferred income tax liability	Property, plant and equipment		Derivative  asset/liability			Total
Balance at December 31, 2015	$	262,997	$	11,943		$	274,940
Charged (credited) to income		5,192		(18,031	)		(12,839	)
Balance at December 31, 2016	$	268,189	$	(6,088	)	$	262,101
Charged to income		13,522		19,793			33,315
Balance at December 31, 2017	$	281,711	$	13,705		$	295,416

Deferred income tax asset	Decommissioning liability			Non-capital losses			Other			Total
Balance at December 31, 2015	$	(12,064	)	$	(198,649	)	$	(23,075	)	$	(233,788	)
Charged to income		991			7,200			34			8,225
Credited to equity		-			(264	)		(1,059	)		(1,323	)
Balance at December 31, 2016	$	(11,073	)	$	(191,713	)	$	(24,100	)	$	(226,886	)
Charged (credited) to income		(1,593	)		5,268			295			3,970
Balance at December 31, 2017	$	(12,666	)	$	(186,445	)	$	(23,805	)	$	(222,916	)

Net deferred income tax liability (asset)
Balance at December 31, 2015	$	41,152
Credited to income		(4,614	)
Credited to equity		(1,323	)
Balance at December 31, 2016	$	35,215
Charged to income		37,285
Balance at December 31, 2017	$	72,500

Disclosure of detailed information about estimated tax pools [text block]

The estimated tax pools available at December 31, 2017 are as follows:

Canadian development expenses	$	210,758
Canadian exploration expenses		65,994
Canadian oil and gas property expenses		14,631
Non-capital losses		690,538
Undepreciated capital cost		251,203
Capital losses		157,869
Scientific research and experimental development expenditures		32,506
Other		10,900
	$	1,434,399

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Share capital (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Classes Of Share Capital Explanatory [Abstract]

Disclosure of classes of share capital [text block]

	Common Shares		Amount
Balance at December 31, 2015		170,827,158	$	2,236,728
Shares issued on financing, net of issue costs and deferred taxes		13,427,075		96,453
Shares issued on exercise of stock options (note 15(a))		400,100		-
Contributed surplus transferred on exercise of stock options (note 15(a))		-		1,018
Balance at December 31, 2016		184,654,333	$	2,334,199
Shares issued on Performance Award settlement (note 15(b))		825,359		-
Contributed surplus transferred on Performance Award settlement (note 15(b))		-		5,374
Shares issued on exercise of stock options (note 15(a))		483,494		-
Contributed surplus transferred on exercise of stock options (note 15(a))		-		1,228
Balance at December 31, 2017		185,963,186	$	2,340,801

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Net income (loss) per share (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about basic and diluted net incomeloss per share [Abstract]

Disclosure of detailed information about basic and diluted net income loss per share [text block]

The calculations of basic and diluted net income (loss) per share are derived from both net income (loss) and weighted average shares outstanding, calculated as follows:

	Year ended
	December 31
	2017		2016
Net income (loss)
Basic and diluted	$	95,039	$	(15,734	)
Weighted average shares outstanding
Basic		185,641,050		182,056,120
Stock Options		389,977		-
Performance Awards		3,545,861		-
Diluted		189,576,888		182,056,120

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Share based compensation (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of Share based compensation [Abstract]

Disclosure of indirect measurement of fair value of goods or services received, share options granted during period [text block]

Under the Stock Option Plan, service providers are granted Stock Options with exercise prices that approximate the market price of common shares at the date of grant. Share based compensation costs of the Stock Option Plan are determined using a Black-Scholes valuation model, using weighted average assumptions as follows:

Volatility	41	%
Expected forfeiture rate	0.98	%
Dividend rate	0	%
Risk-free rate	1.05	%

Disclosure of number and weighted average exercise prices of share options [text block]

The following tables summarize information about changes in Stock Options outstanding at December 31, 2017:

	Stock Options			Weighted-Average Exercise Price
Balance at December 31, 2015		4,031,302		$	5.49
Exercised		(921,387	)		4.64
Balance at December 31, 2016		3,109,915		$	5.75
Exercised		(1,085,681	)	$	4.72
Forfeited		(18,377	)		6.82
Balance at December 31, 2017		2,005,857		$	6.30

Disclosure of range of exercise prices of outstanding share options [text block]

	Stock Options Outstanding						Stock Options Exercisable
Range of Exercise Price	Number of Stock Options Outstanding		Weighted Average Remaining Contractual Life - Years		Weighted Average Exercise Price		Number of Stock Options Exercisable		Weighted Average Exercise Price
$5.87 - $6.81		1,110,009		1.29	$	5.87		1,110,009	$	5.87
$6.82		895,848		2.26		6.82		584,927		6.82
$5.87 - $6.82		2,005,857		1.72	$	6.30		1,694,936	$	6.20

Disclosure of number and weighted average exercise prices of other equity instruments [text block]

The following table is a continuity of Performance Awards:

	Performance Awards
Balance at December 31, 2015		666,092
Granted		661,571
Balance at December 31, 2016		1,327,663
Granted		723,676
Settlements		(402,582	)
Forfeited/cancelled		(68,458	)
Balance at December 31, 2017		1,580,299

Disclosure of detailed information about share based compensation recognized by plan [text block]

Share based compensation recognized by plan for the years ended December 31, 2017 and 2016 are as follows:

	Year ended
	December 31
	2017			2016
Stock Options	$	355		$	784
Performance Awards		8,009			4,823
Total share based compensation		8,364			5,607
Capitalized (note 8)		(3,245	)		(2,326	)
Net share based compensation expense	$	5,119		$	3,281

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Natural gas and liquids sales (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of natural gas and liquids sales [Abstract]

Disclosure of detailed information about natural gas and liquids sales [text Block]

	Year ended
	December 31
	2017		2016
Natural gas sales	$	207,623	$	145,878
Natural gas liquids sales		24,141		16,055
Total natural gas and liquids sales	$	231,764	$	161,933

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General and administrative expense (“G&A”) (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of General And Administrative Expense [Abstract]

Disclosure of detailed information about general and administrative expense [text block]

	Year ended
	December 31
	2017			2016
Salaries and benefits	$	8,741		$	7,332
Office rent		1,069			989
Other		1,432			2,952
Total G&;A		11,242			11,273
Capitalized (note 8)		(4,077	)		(3,804	)
General and administrative expense	$	7,165		$	7,469

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Finance expense (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Finance Cost [Abstract]

Disclosure of detailed information about finance expense [text block]

	Year ended
	December 31
	2017		2016
Interest on bank indebtedness (note 10)	$	6,931	$	9,335
Accretion of decomissioning liability (note 11)		951		915
Total finance expense	$	7,882	$	10,250

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Related party transactions (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Information About Key Management Personnel Explanatory [Abstract]

Disclosure of information about key management personnel [text block]

The compensation paid or payable to officers and directors is as follows:

	Year ended  December 31, 2017		Year ended December 31, 2016
Salaries, director fees and short-term benefits	$	2,495	$	2,111
Share based compensation (1)		4,300		2,676
	$	6,795	$	4,787

⁽¹⁾ Represents the grant date fair value of Performance Awards and Stock Options granted.

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Supplementary cash flow information (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Cash Flow Statement Explanatory [Abstract]

Disclosure of detailed information about changes in non cash working capital [text block]

Changes in non-cash working capital is comprised of:

	Year ended
	December 31
	2017			2016
Source (use) of cash:
Trade and other receivables	$	(2,373	)	$	(12,417	)
Prepaid expenses and deposits		79			285
Trade and other accrued liabilities		16,850			11,103
	$	14,556		$	(1,029	)
Related to operating activities	$	(2,542	)	$	567
Related to financing activities		-			-
Related to investing activities		17,098			(1,596	)
	$	14,556		$	(1,029	)

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Commitments (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Commitments [Abstract]

Disclosure of finance lease and operating lease by lessee [text block]

Advantage has lease commitments relating to office buildings of $1.8 million (December 31, 2016 - $3.0 million) and transportation commitments of $384.9 million (December 31, 2016 - $180.2 million). The estimated remaining annual minimum payments are as follows:

	December 31
	2017		2016
2017	$	-	$	26,067
2018		47,327		27,338
2019		51,316		28,519
2020		49,941		21,850
2021		45,997		17,892
2022		43,885		17,566
2023 and thereafter		148,239		43,980
Total commitments	$	386,705	$	183,212

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Cash and cash equivalents (Details) - CAD CAD in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash at financial institutions	CAD 6,916	CAD 0	CAD 0

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Cash and cash equivalents (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Interest income on cash and cash equivalents	$ 0.1	$ 0

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Trade and other receivables (Details) - CAD CAD in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Trade And Other Receivables Explanatory [Abstract]
Trade receivables	CAD 25,384	CAD 25,087
Receivables from joint venture partners	1,425	581
Other	1,869	637
Trade and other current receivables	CAD 28,678	CAD 26,305

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Exploration and evaluation assets (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Balance	CAD 1,450,283
Balance	1,580,973	CAD 1,450,283
Exploration and evaluation assets [member]
Balance	16,012	10,071
Additions	7,207	6,001
Lease expiries	(168)
Transferred to property, plant and equipment (note 8)	(908)	(60)
Balance	CAD 22,143	CAD 16,012

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Property, plant and equipment (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Balance	CAD 1,450,283
Depreciation	117,945	CAD 116,232
Balance	1,580,973	1,450,283
Gross carrying amount [member]
Balance	1,999,332	1,879,900
Additions	241,567	122,013
Change in decommissioning liability (note 11)	6,160	(2,641)
Transferred from exploration and evaluation assets (note 7)	908	60
Balance	2,247,967	1,999,332
Accumulated depreciation [member]
Balance	549,049	432,817
Depreciation	117,945	116,232
Balance	666,994	549,049
Furniture and equipment [Member]
Balance	1,389
Balance	1,205	1,389
Furniture and equipment [Member] | Gross carrying amount [member]
Balance	5,648	5,482
Additions	118	166
Change in decommissioning liability (note 11)	0	0
Transferred from exploration and evaluation assets (note 7)	0	0
Balance	5,766	5,648
Furniture and equipment [Member] | Accumulated depreciation [member]
Balance	4,259	3,912
Depreciation	302	347
Balance	4,561	4,259
Natural gas and liquids properties [member] | Gross carrying amount [member]
Balance	1,993,684	1,874,418
Additions	241,449	121,847
Change in decommissioning liability (note 11)	6,160	(2,641)
Transferred from exploration and evaluation assets (note 7)	908	60
Balance	2,242,201	1,993,684
Natural gas and liquids properties [member] | Accumulated depreciation [member]
Balance	544,790	428,905
Depreciation	117,643	115,885
Balance	CAD 662,433	CAD 544,790

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Property, plant and equipment (Details Textual) CAD in Thousands, $ in Millions	Dec. 31, 2017 CAD	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CAD	Dec. 31, 2016 USD ($)	Dec. 31, 2015 CAD
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment | CAD	CAD 1,580,973		CAD 1,450,283
Capitalised development expenditure [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		$ 1,700.0		$ 1,600.0
Capitalized Share Based Compensation [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, expenditures recognised in course of its construction		3.2		2.3
Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, expenditures recognised in course of its construction		$ 4.1		$ 3.8
Property, plant and equipment | CAD	CAD 22,143		CAD 16,012		CAD 10,071

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Financial risk management (Details) - CAD CAD in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Financial Risk Management Explanatory [Line Items]
Maximum exposure to credit risk	CAD 80,486	CAD 29,148
Trade receivables [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Maximum exposure to credit risk	28,678	26,305
Deposits [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Maximum exposure to credit risk	938	665
Derivatives asset [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Maximum exposure to credit risk	CAD 50,870	CAD 2,178

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Financial risk management (Details 1) - CAD CAD in Thousands		Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Financial Risk Management Explanatory [Line Items]
Trade and other accrued liabilities		CAD 51,004	CAD 34,153
Non-derivative financial liabilities, undiscounted cash flows		274,892	198,138
Not later than one year [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Trade and other accrued liabilities		51,004	34,153
Non-derivative financial liabilities, undiscounted cash flows		60,408	41,043
Later than one year and not later than three years [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Trade and other accrued liabilities		0	0
Non-derivative financial liabilities, undiscounted cash flows		214,484	157,095
Bank indebtedness - principal [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Bank indebtedness - principal and - interest		210,001	153,811
Bank indebtedness - principal [member] | Not later than one year [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Bank indebtedness - principal and - interest		0	0
Bank indebtedness - principal [member] | Later than one year and not later than three years [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Bank indebtedness - principal and - interest		210,001	153,811
Bank indebtedness - interest [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Bank indebtedness - principal and - interest	[1]	13,887	10,174
Bank indebtedness - interest [member] | Not later than one year [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Bank indebtedness - principal and - interest	[1]	9,404	6,890
Bank indebtedness - interest [member] | Later than one year and not later than three years [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Bank indebtedness - principal and - interest	[1]	CAD 4,483	CAD 3,284

[1] Interest on bank indebtedness was calculated assuming conversion of the revolving credit facility to a one-year term facility.

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Financial risk management (Details 2)		2 Months Ended	12 Months Ended
		Feb. 20, 2018	Dec. 31, 2017
Derivative One [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			April 2017 to March 2018
Hedging Instruments Volume Description			4,739 mcf/d
Average price of hedging instrument			3.27
Derivative One [Member] | Henry Hub Natural Gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Basis swap
Description Of Term Of Hedging Instrument			January 2018 to September 2018
Hedging Instruments Volume Description			25,000 mcf/d
Average price of hedging instrument			0.85
Derivative One [Member] | Dawn Natural Gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			December 2017 to March 2018
Hedging Instruments Volume Description			10,000 mcf/d
Average price of hedging instrument			3.45
Derivative Two [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			April 2017 to March 2018
Hedging Instruments Volume Description			14,217 mcf/d
Average price of hedging instrument			3.27
Derivative Two [Member] | Henry Hub Natural Gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Basis swap
Description Of Term Of Hedging Instrument			January 2019 to December 2019
Hedging Instruments Volume Description			25,000 mcf/d
Average price of hedging instrument			0.90
Derivative Three [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			November 2017 to March 2018
Hedging Instruments Volume Description			18,956 mcf/d
Average price of hedging instrument			3.22
Derivative Three [Member] | Henry Hub Natural Gas [Member] | Subsequent events [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments		Basis swap
Description Of Term Of Hedging Instrument		January 2021 to December 2024
Hedging Instruments Volume Description		5,000 mcf/d
Average price of hedging instrument		1.135
Derivative Four [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			July 2017 to March 2018
Hedging Instruments Volume Description			4,739 mcf/d
Average price of hedging instrument			3.02
Derivative Four [Member] | Henry Hub Natural Gas [Member] | Subsequent events [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments		Basis swap
Description Of Term Of Hedging Instrument		January 2021 to December 2024
Hedging Instruments Volume Description		2,500 mcf/d
Average price of hedging instrument		1.185
Derivative Five [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			July 2017 to March 2018
Hedging Instruments Volume Description			14,217 mcf/d
Average price of hedging instrument			3.01
Derivative Five [Member] | Henry Hub Natural Gas [Member] | Subsequent events [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments		Basis swap
Description Of Term Of Hedging Instrument		January 2021 to December 2024
Hedging Instruments Volume Description		17,500 mcf/d
Derivative Six [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			July 2017 to March 2018
Hedging Instruments Volume Description			14,217 mcf/d
Average price of hedging instrument			3.00
Derivative Six [Member] | Henry Hub Natural Gas [Member] | Subsequent events [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments		Basis swap
Description Of Term Of Hedging Instrument		January 2020 to December 2020
Hedging Instruments Volume Description		5,000 mcf/d
Derivative Seven [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			July 2017 to June 2018
Hedging Instruments Volume Description			14,217 mcf/d
Average price of hedging instrument			3.00
Derivative Seven [Member] | Henry Hub Natural Gas [Member] | Subsequent events [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments		Basis swap
Description Of Term Of Hedging Instrument		January 2020 to December 2024
Hedging Instruments Volume Description		15,000 mcf/d
Derivative Eight [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			April 2017 to March 2018
Hedging Instruments Volume Description			23,695 mcf/d
Average price of hedging instrument			3.01
Derivative Nine [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments	[1]		Call option sold
Description Of Term Of Hedging Instrument	[1]		April 2017 to December 2018
Hedging Instruments Volume Description	[1]		23,695 mcf/d
Average price of hedging instrument	[1]		3.17
Derivative Ten [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			October 2017 to September 2018
Hedging Instruments Volume Description			4,739 mcf/d
Average price of hedging instrument			3.01
Derivative Eleven [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments	[2]		Call option sold
Description Of Term Of Hedging Instrument	[2]		October 2017 to December 2018
Hedging Instruments Volume Description	[2]		4,739 mcf/d
Average price of hedging instrument	[2]		3.01
Derivative Twelve [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			October 2017 to September 2018
Hedging Instruments Volume Description			4,739 mcf/d
Average price of hedging instrument			3.01
Derivative Thirteen [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments	[3]		Call option sold
Description Of Term Of Hedging Instrument	[3]		October 2017 to December 2018
Hedging Instruments Volume Description	[3]		4,739 mcf/d
Average price of hedging instrument	[3]		3.06
Derivative Fourteen [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			October 2017 to September 2018
Hedging Instruments Volume Description			4,739 mcf/d
Average price of hedging instrument			3.01
Derivative Fifteen [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments	[1]		Call option sold
Description Of Term Of Hedging Instrument	[1]		October 2017 to December 2018
Hedging Instruments Volume Description	[1]		4,739 mcf/d
Average price of hedging instrument	[1]		3.11
Derivative Sixteen [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			October 2018 to March 2019
Hedging Instruments Volume Description			18,956 mcf/d
Average price of hedging instrument			3.00
Derivative Seventeen [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			October 2018 to March 2019
Hedging Instruments Volume Description			18,956 mcf/d
Average price of hedging instrument			3.00
Derivative Eighteen [Member] | AECO Natural gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Description of financial instruments designated as hedging instruments			Fixed price swap
Description Of Term Of Hedging Instrument			October 2018 to March 2019
Hedging Instruments Volume Description			9,478 mcf/d
Average price of hedging instrument			3.00

[1] Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.43/mcf.

[2] Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.32/mcf.

[3] Call option sold is only exercisable by the counterparty if AECO exceeds Cdn $3.38/mcf.

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Financial risk management (Details 3) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Financial Risk Management Explanatory [Abstract]
Realized gains on derivatives	CAD 27,847	CAD 53,094
Unrealized gains (losses) on derivatives	73,305	(66,781)
Gains (losses) on derivatives	CAD 101,152	CAD (13,687)

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Financial risk management (Details 4) - CAD		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Financial Risk Management Explanatory [Abstract]
Bank indebtedness (non-current) (note 10)		CAD 208,978,000	CAD 153,102,000
Working capital deficit		13,808,000	6,167,000
Total debt	[1]	CAD 222,786,000	CAD 159,269,000
Shares outstanding (note 13)		185,963,186	184,654,333
Share closing market price ($/share)		CAD 5.4	CAD 9.12
Market capitalization		1,004,201,000	1,684,048,000
Total capitalization		CAD 1,226,987,000	CAD 1,843,317,000

[1] Total debt is a non-GAAP measure that includes bank indebtedness and working capital deficit.

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Financial risk management (Details Textual) - CAD CAD in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Financial Risk Management Explanatory [Line Items]
Trade and other current receivables		CAD 28,678	CAD 26,305
Borrowings	[1]	222,786	159,269
Derivative financial assets		50,900	2,200
Derivative financial liabilities		100	24,700
Gains (losses) on change in fair value of derivatives		CAD 101,152	(13,687)
Rate of change in the forward price		10.00%
Later than three months [member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Trade and other current receivables		CAD 200	CAD 400
Expected credit loss rate		0.80%	1.40%
Major Customer One [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Trade and other current receivables		CAD 19,200	CAD 22,200
Reserve-based credit facilities [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Borrowings		400,000
Commodity price risk [member] | Dawn Natural Gas [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Gains (losses) on change in value of forward elements of forward contracts, net of tax		3,300
Commodity price risk [member] | 10% Change [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Gains (losses) on change in value of forward elements of forward contracts, net of tax		4,700	2,100
Interest rate risk [member] | 100 basis points change [Member]
Disclosure Of Financial Risk Management Explanatory [Line Items]
Gains (losses) on change in value of forward elements of forward contracts, net of tax		CAD 1,200	CAD 1,500

[1] Total debt is a non-GAAP measure that includes bank indebtedness and working capital deficit.

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Bank indebtedness (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of the Bank indebtedness [Abstract]
Revolving credit facility	CAD 210,001	CAD 153,811
Discount on Bankers Acceptances and other fees	(1,023)	(709)
Balance, end of year	CAD 208,978	CAD 153,102

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Bank indebtedness (Details Textuals) - CAD CAD in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Bank indebtedness [Line Items]
Borrowings	[1]	CAD 222,786	CAD 159,269
Borrowings, interest rate basis		ranging from LIBOR plus 2% to 3.25% per annum, and Canadian prime or US base rate plus 1% to 2.25% per annum
Description of hedging instruments used to hedge risk exposures and how they are used		The Credit Facilities prohibit the Corporation from entering into any fixed price derivative contract, excluding basis swaps, where the term of such contract exceeds five years. Further, the aggregate of such contracts cannot hedge greater than 75% of total estimated natural gas and liquids production over the first three years and 50% over the fourth and fifth years. In addition, the Credit Facilities allow us to enter into basis swap arrangements to any natural gas price point in North America for up to 100,000 MMbtu/day with a maximum term of seven years. Basis swap arrangements do not count against the limitations on hedged production.
Financial assets pledged as collateral for liabilities or contingent liabilities		CAD 1,000,000
Borrowings, interest rate		4.50%	3.50%
Bottom of range [member]
Bank indebtedness [Line Items]
Undrawn Facility Standby Fee Percentage		0.50%
Top of range [member]
Bank indebtedness [Line Items]
Undrawn Facility Standby Fee Percentage		0.8125%
Reserve-based credit facilities [Member]
Bank indebtedness [Line Items]
Borrowings		CAD 400,000
Revolving operating loan facility [Member]
Bank indebtedness [Line Items]
Borrowings		20,000
Revolving Credit Facility [Member]
Bank indebtedness [Line Items]
Borrowings		380,000
Letters of credit [Member]
Bank indebtedness [Line Items]
Borrowings		CAD 0	CAD 0

[1] Total debt is a non-GAAP measure that includes bank indebtedness and working capital deficit.

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Decommissioning liability (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of the decommissioning liability [Abstract]
Balance, beginning of year	CAD 40,992	CAD 44,575
Accretion expense	951	915
Property acquisitions	751	0
Liabilities incurred	2,175	2,193
Change in estimates	(2,665)	(1,165)
Effect of change in risk-free rate and inflation rate factor	5,899	(3,669)
Liabilities settled	1,190	1,857
Balance, end of year	CAD 46,913	CAD 40,992

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Decommissioning liability (Details Textual)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of the decommissioning liability [Abstract]
Risk free interest rate, fair value measurement	2.20%	2.34%
Inflation factor, fair value measurement	2.00%	2.00%

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Income taxes (Details) - CAD CAD in Thousands		12 Months Ended
	Mar. 08, 2016	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Income Tax [Abstract]
Current income tax expense		CAD 0	CAD 0
Deferred income tax expense (recovery)	CAD 1,300	37,285	(4,614)
Income tax expense (recovery)		CAD 37,285	CAD (4,614)

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Income taxes (Details 1) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Income Tax [Abstract]
Income (loss) before taxes	CAD 132,324	CAD (20,348)
Combined federal and provincial income tax rates	27.00%	27.00%
Expected income tax expense (recovery)	CAD 35,727	CAD (5,494)
Increase (decrease) in income taxes resulting from:
Non-deductible share based compensation	2,261	1,515
Difference between current and expected tax rates	(703)	(635)
Total	CAD 37,285	CAD (4,614)
Effective tax rate	28.18%	22.68%

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Income taxes (Details 2) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income tax [Line Items]
Deferred income tax liability beginning balance	CAD 35,215
Charged (credited) to income	37,285	CAD (4,614)
Credited to equity		(1,323)
Deferred income tax liability ending balance	72,500	35,215
Net deferred income tax liability (asset) beginning balance	35,215	41,152
Net deferred income tax liability (asset) ending balance	72,500	35,215
Deferred income tax liability [Member]
Income tax [Line Items]
Deferred income tax liability beginning balance	262,101	274,940
Charged (credited) to income	33,315	(12,839)
Deferred income tax liability ending balance	295,416	262,101
Deferred income tax liability [Member] | Property, plant and equipment [member]
Income tax [Line Items]
Deferred income tax liability beginning balance	268,189	262,997
Charged (credited) to income	13,522	5,192
Deferred income tax liability ending balance	281,711	268,189
Deferred income tax liability [Member] | Derivative Asset/liability [Member]
Income tax [Line Items]
Deferred income tax liability beginning balance	(6,088)	11,943
Charged (credited) to income	19,793	(18,031)
Deferred income tax liability ending balance	13,705	(6,088)
Deferred income tax asset [Member]
Income tax [Line Items]
Charged (credited) to income	3,970	8,225
Credited to equity		(1,323)
Deferred income tax asset beginning balance	(226,886)	(233,788)
Deferred income tax asset ending balance	(222,916)	(226,886)
Deferred income tax asset [Member] | Decommissioning liability [Member]
Income tax [Line Items]
Charged (credited) to income	(1,593)	991
Credited to equity		0
Deferred income tax asset beginning balance	(11,073)	(12,064)
Deferred income tax asset ending balance	(12,666)	(11,073)
Deferred income tax asset [Member] | Non-capital losses [member]
Income tax [Line Items]
Charged (credited) to income	5,268	7,200
Credited to equity		(264)
Deferred income tax asset beginning balance	(191,713)	(198,649)
Deferred income tax asset ending balance	(186,445)	(191,713)
Deferred income tax asset [Member] | Other [Member]
Income tax [Line Items]
Charged (credited) to income	295	34
Credited to equity		(1,059)
Deferred income tax asset beginning balance	(24,100)	(23,075)
Deferred income tax asset ending balance	CAD (23,805)	CAD (24,100)

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Income taxes (Details 3) - CAD CAD in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	CAD 1,434,399
Canadian development expenses
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	210,758
Canadian exploration expenses
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	65,994
Canadian oil and gas property expenses
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	14,631
Non-capital losses
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	690,538
Undepreciated capital cost
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	251,203
Capital losses
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	157,869	CAD (158,000)
Scientific research and experimental development expenditures
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	32,506
Other
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	CAD 10,900

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Income taxes (Detail Textual) - CAD CAD in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	CAD 1,434,399
Capital loss [Member]
Income tax [Line Items]
Unused tax losses for which no deferred tax asset recognised	CAD 157,869	CAD (158,000)

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Share capital (Details) CAD in Thousands, $ in Thousands	1 Months Ended	12 Months Ended
	Apr. 30, 2017 shares	Dec. 31, 2017 CAD shares	Dec. 31, 2016 CAD shares	Dec. 31, 2016 USD ($) shares
Balance at Start		CAD 1,208,273	CAD 1,121,947
Shares issued on financing, net of issue costs and deferred taxes			96,453
Shares issued on Performance Award settlement (note 15(b)) (in shares) | shares	825,359
Contributed surplus transferred on Performance Award settlement (note 15(b))		CAD 0
Shares issued on exercise of stock options (note 15(a)) (in shares) | shares		483,494
Contributed surplus transferred on exercise of stock options (note 15(a))		CAD 0	0
Balance at End		1,311,676	1,208,273
Issued capital [member]
Balance at Start		CAD 2,334,199	CAD 2,236,728
Balance at Start (in shares) | shares		184,654,333	170,827,158	170,827,158
Shares issued on financing, net of issue costs and deferred taxes			CAD 96,453
Shares issued on financing, net of issue costs and deferred taxes (in shares) | shares			13,427,075	13,427,075
Shares issued on Performance Award settlement (note 15(b))		CAD 0
Shares issued on Performance Award settlement (note 15(b)) (in shares) | shares		825,359
Contributed surplus transferred on Performance Award settlement (note 15(b))		CAD 5,374
Shares issued on exercise of stock options (note 15(a))		CAD 0		$ 0
Shares issued on exercise of stock options (note 15(a)) (in shares) | shares		483,494	400,100	400,100
Contributed surplus transferred on exercise of stock options (note 15(a))		CAD 1,228	CAD 1,018	$ 1,018
Balance at End		CAD 2,340,801	CAD 2,334,199
Balance at End (in shares) | shares		185,963,186	184,654,333	184,654,333

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Share capital (Details Textual) - CAD CAD / shares in Units, CAD in Thousands		12 Months Ended
	Mar. 08, 2016	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Share Capital [Abstract]
Increase (decrease) in number of ordinary shares issued	13,427,075
Par value per share	CAD 7.45
Proceeds from issuing shares	CAD 100,000	CAD 0	CAD 95,130
Share issue related cost	3,600
Share issue related cost before deferred taxes	4,900
Deferred tax expense (income)	CAD 1,300	CAD 37,285	CAD (4,614)

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Net income (loss) per share (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Net income (loss)
Basic and diluted	CAD 95,039	CAD (15,734)
Weighted average ordinary shares and adjusted weighted average ordinary shares [abstract]
Weighted average shares outstanding, Basic	185,641,050	182,056,120
Weighted average shares outstanding, Diluted	189,576,888	182,056,120
Stock Options [Member]
Weighted average ordinary shares and adjusted weighted average ordinary shares [abstract]
Weighted average shares outstanding, Basic	389,977	0
Performance Awards [Member]
Weighted average ordinary shares and adjusted weighted average ordinary shares [abstract]
Weighted average shares outstanding, Basic	3,545,861	0

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Net income (loss) per share (Details Textual)	12 Months Ended
	Dec. 31, 2016 shares
Stock Option Plan [Member]
Earnings per share [line items]
Dilutive effect of share options on number of ordinary shares	866,241
Performance Incentive Plan [Member]
Earnings per share [line items]
Dilutive effect of share options on number of ordinary shares	648,037

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Share based compensation (Details)	12 Months Ended
	Dec. 31, 2017
Disclosure of Share based compensation [Abstract]
Volatility	41.00%
Expected forfeiture rate	0.98%
Dividend rate	0.00%
Risk-free rate	1.05%

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Share based compensation (Details 1)	12 Months Ended
	Dec. 31, 2017 CAD	Dec. 31, 2017 Numberofunits	Dec. 31, 2017	Dec. 31, 2016 CAD Numberofunits
Disclosure of Share based compensation [Abstract]
Balance Beginning | Numberofunits		3,109,915		4,031,302
Exercised		(1,085,681)	1,085,681	(921,387)
Forfeited | Numberofunits		(18,377)
Balance Ending | Numberofunits		2,005,857		3,109,915
Balance Beginning	CAD 5.75			CAD 5.49
Exercised	4.72			4.64
Forfeited	6.82
Balance Ending	CAD 6.30			CAD 5.75

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Share based compensation (Details 2)	Dec. 31, 2017 CAD Numberofunits Numberofunitsyear	Dec. 31, 2017 USD ($) Numberofunits Numberofunitsyear	Dec. 31, 2016 CAD Numberofunits	Dec. 31, 2015 CAD Numberofunits
Disclosure of Share based compensation [Line Items]
Number of Stock Options Outstanding	2,005,857	2,005,857	3,109,915	4,031,302
Weighted average remaining contractual life of outstanding stock options | Numberofunitsyear	1.72	1.72
Weighted average exercise price of stock options outstanding in share-based payment arrangement | CAD	CAD 6.30		CAD 5.75	CAD 5.49
Number of stock options exercisable in share-based payment arrangement	1,694,936	1,694,936
Weighted average exercise price of stock options exercisable in share-based payment arrangement | CAD	CAD 6.20
Bottom of range [member]
Disclosure of Share based compensation [Line Items]
Weighted average exercise price of stock options outstanding in share-based payment arrangement | $		$ 5.87
Top of range [member]
Disclosure of Share based compensation [Line Items]
Weighted average exercise price of stock options outstanding in share-based payment arrangement | $		$ 6.82
Ranges of exercise prices for outstanding share options one [Member]
Disclosure of Share based compensation [Line Items]
Number of Stock Options Outstanding	1,110,009	1,110,009
Weighted average remaining contractual life of outstanding stock options | Numberofunitsyear	1.29	1.29
Weighted average exercise price of stock options outstanding in share-based payment arrangement | CAD	CAD 5.87
Number of stock options exercisable in share-based payment arrangement	1,110,009	1,110,009
Weighted average exercise price of stock options exercisable in share-based payment arrangement | CAD	CAD 5.87
Ranges of exercise prices for outstanding share options one [Member] | Bottom of range [member]
Disclosure of Share based compensation [Line Items]
Weighted average exercise price of stock options outstanding in share-based payment arrangement | $		$ 5.87
Ranges of exercise prices for outstanding share options one [Member] | Top of range [member]
Disclosure of Share based compensation [Line Items]
Weighted average exercise price of stock options outstanding in share-based payment arrangement | $		$ 6.81
Ranges of exercise prices for outstanding share options two [Member]
Disclosure of Share based compensation [Line Items]
Number of Stock Options Outstanding	895,848	895,848
Weighted average remaining contractual life of outstanding stock options | Numberofunitsyear	2.26	2.26
Weighted average exercise price of stock options outstanding in share-based payment arrangement	CAD 6.82	$ 6.82
Number of stock options exercisable in share-based payment arrangement	584,927	584,927
Weighted average exercise price of stock options exercisable in share-based payment arrangement | CAD	CAD 6.82

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Share based compensation (Details 3)	1 Months Ended	12 Months Ended
	Apr. 30, 2017	Dec. 31, 2017 Numberofunits	Dec. 31, 2016 Numberofunits
Disclosure of Share based compensation [Abstract]
Balance at Beginning		1,327,663	666,092
Granted		723,676	661,571
Settlements	402,582	(402,582)
Forfeited/cancelled		18,377
Balance at Ending		1,580,299	1,327,663

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Share based compensation (Details 4) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Share based compensation [Line Items]
Total share based compensation	CAD 5,119	CAD 3,281
Capitalized (note 8)	(3,245)	(2,326)
Net share based compensation expense	5,119	3,281
Stock Options [Member]
Disclosure of Share based compensation [Line Items]
Total share based compensation	355	784
Performance Awards [Member]
Disclosure of Share based compensation [Line Items]
Total share based compensation	CAD 8,009	CAD 4,823

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Share based compensation (Details Textual)	1 Months Ended	12 Months Ended
	Apr. 30, 2017 shares	Dec. 31, 2017 shares	Dec. 31, 2017 Numberofunits	Dec. 31, 2017	Dec. 31, 2016 Numberofunits
Disclosure of Share based compensation [Abstract]
Number of share options exercised in share-based payment arrangement			(1,085,681)	1,085,681	(921,387)
Increase decrease in shares on exercise of stock options		483,494
Number of other equity instruments exercised or vested in share-based payment arrangement	402,582		(402,582)
Increase decrease in shares through issue of shares on performance awards settlements	825,359

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Natural gas and liquids sales (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of natural gas and liquids sales [Abstract]
Natural gas sales	CAD 207,623	CAD 145,878
Natural gas liquids sales	24,141	16,055
Total natural gas and liquids sales	CAD 231,764	CAD 161,933

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General and administrative expense ("G&A") (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of General And Administrative Expense [Abstract]
Salaries and benefits	CAD 8,741	CAD 7,332
Office rent	1,069	989
Other	1,432	2,952
Total G&A	11,242	11,273
Capitalized (note 8)	(4,077)	(3,804)
General and administrative expense	CAD 7,165	CAD 7,469

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Finance expense (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Finance Cost [Abstract]
Interest on bank indebtedness (note 10)	CAD 6,931	CAD 9,335
Accretion of decomissioning liability (note 11)	951	915
Total finance expense	CAD 7,882	CAD 10,250

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Related party transactions (Details) - CAD CAD in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Salaries, director fees and short-term benefits		CAD 2,495	CAD 2,111
Share based compensation	[1]	4,300	2,676
Key management personnel compensation		CAD 6,795	CAD 4,787

[1] Represents the grant date fair value of Performance Awards and Stock Options granted.

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Supplementary cash flow information (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Source (use) of cash:
Trade and other receivables	CAD (2,373)	CAD (12,417)
Prepaid expenses and deposits	79	285
Trade and other accrued liabilities	16,850	11,103
Adjustments For Changes in non-cash working capital	14,556	(1,029)
Related to operating activities	(2,542)	567
Related to financing activities	0	0
Related to investing activities	17,098	(1,596)
Adjustments For Changes in non-cash working capital	CAD 14,556	CAD (1,029)

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Commitments (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	CAD 386,705	CAD 183,212
Not later than one year [member]
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	0	26,067
Later than one year and not later than two years [member]
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	47,327	27,338
Later than two years and not later than three years [member]
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	51,316	28,519
Later than three years and not later than four years [member]
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	49,941	21,850
Later than four years and not later than five years [member]
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	45,997	17,892
Later than five years and not later than six years [Member]
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	43,885	17,566
Later than six years [Member]
Disclosure of Commitments [Line Items]
Minimum operating lease payments recognised as expense	CAD 148,239	CAD 43,980

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Commitments (Details Textual) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
office buildings lease commitments [Member]
Disclosure of Commitments [Line Items]
Minimum finance lease payments payable	CAD 1.8	CAD 3.0
transportation commitments [Member]
Disclosure of Commitments [Line Items]
Minimum finance lease payments payable	CAD 384.9	CAD 180.2