40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☒ 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 0-20115

METHANEX CORPORATION

(Exact name of Registrant as specified in its charter)

not applicable

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

CANADA

(Province or other jurisdiction of incorporation or organization)

2860

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

not applicable

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

1800 Waterfront Centre, 200 Burrard Street, Vancouver, British Columbia, Canada V6C 3M1

Telephone: (604) 661-2600

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

CT Corporation System, 111 Eighth Avenue, New York, New York 10011

Telephone: 212-894-8940

(Name, address (including zip code) and telephone number

(including area code) of agent for service in the United States)

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

Title of each class	Name of each exchange on which registered
Common Shares	NASDAQ Global Select Market

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.

3.25% Senior Notes due December 15, 2019

5.25% Senior Notes due March 1, 2022

4.25% Senior Notes due December 1, 2024

5.65% Senior Notes due December 1, 2044

(Title of Class)

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

☒  Annual Information Form ☒  Audited Annual Financial Statements

Indicate 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.

83,770,254 Common Shares were outstanding as of December 31, 2017

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  ☒            No  ☐

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  ☒            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 check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

ANNUAL INFORMATION FORM, AUDITED FINANCIAL STATEMENTS, AND

MANAGEMENT’S DISCUSSION AND ANALYSIS

Methanex Corporation (the “Registrant” or the “Company”) is a Canadian public company whose common shares are listed on the Toronto Stock Exchange in Canada (trading symbol: MX) and on the NASDAQ Global Select Market in the United States (trading symbol: MEOH). The Registrant is a “foreign private issuer” as defined in Rule 3b-4 under Securities Exchange Act of 1934, as amended (the “Exchange Act”), and is eligible to file this annual report on Form 40-F pursuant to the multi-jurisdictional disclosure system.

The following documents of the Company are filed as exhibits to, and incorporated by reference into, this Annual Report:

Document	Exhibit No.
Annual Information Form of the Company for the year ended December 31, 2017	99.1
Management’s Discussion and Analysis of the Company for the year ended December 31, 2017	99.2
Audited financial statements of the Company for the years ended December 31, 2017 and 2016, including the reports of auditor with respect thereto	99.3

Pursuant to Rule 3a12-3 under the Exchange Act, the Company’s equity securities are exempt from sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act.

FORWARD-LOOKING STATEMENTS

This annual report includes or incorporates by reference certain statements that constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. These statements appear in a number of places in this annual report and documents incorporated by reference herein and include statements regarding the Registrant’s intent, belief or current expectations and those of the Registrant’s management. These forward-looking statements involve known and unknown risks and uncertainties that may cause the Registrant’s actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. When used in this annual report or in documents incorporated by reference in this annual report, words such as “believes,” “expects,” “may,” “will,” “should,” “potential,” “estimates,” “anticipates,” “aims,” “goal,” or the negative version of those words or other comparable terminology and similar statements of a future or forward-looking nature are intended to identify these forward-looking statements. These forward-looking statements are based on various factors and were derived utilizing numerous assumptions that could cause the Registrant’s actual results to differ materially from those in the forward-looking statements. Accordingly, readers are cautioned not to put undue reliance on these forward-looking statements. For additional information, please refer to the disclosure contained under the heading, “Caution Regarding Forward-Looking Statements” in the Registrant’s Annual Information Form filed as Exhibit 99.1 to this report.

NOTE TO UNITED STATES READERS REGARDING DIFFERENCES

BETWEEN UNITED STATES AND CANADIAN REPORTING PRACTICES

The Registrant is permitted to prepare this annual report in accordance with Canadian disclosure requirements, which are different from those of the United States. The Registrant prepares its consolidated financial statements in accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board, which principles differ in certain respects from generally accepted accounting principles applicable in the United States (“U.S. GAAP”) and from practices prescribed by the SEC. Therefore, the Company’s financial statements incorporated by reference in this annual report may not be comparable to financial statements prepared in accordance with U.S. GAAP.

CURRENCY

Unless otherwise indicated, all dollar amounts in this Annual Report are in United States dollars. The exchange rate of United States dollars into Canadian dollars on December 29, 2017, the last trading day of the year, based upon the daily exchange rate published by the Bank of Canada, was U.S.$1.00=CDN $1.2545. The exchange rate of United States

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dollars into Canadian dollars, on March 5, 2018, based upon the daily exchange rate as published by the Bank of Canada, was U.S.$1.00=CDN$1.2977.

CONTROLS AND PROCEDURES

Disclosure controls and procedures are defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act to mean controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

At the end of the period covered by this annual report on Form 40-F, being the fiscal year ended December 31, 2017, an evaluation was carried out under the supervision and with the participation of the Registrant’s management, including the principal executive and principal financial officers (its Chief Executive Officer and Chief Financial Officer). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Registrant’s disclosure controls and procedures are effective as of December 31, 2017.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Internal Control Over Financial Reporting

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act as a process designed by, or under the supervision of, the Registrant’s Chief Executive Officer and Chief Financial Officer, and effected by the Registrant’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and preparation of the Registrant’s consolidated financial statements for external purposes in accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board. Internal control over financial reporting includes policies and procedures that:

◾ pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Registrant;

◾ provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and directors of the Registrant; and

◾ provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Registrant’s assets that could have a material effect on the financial statements.

There have been no changes during the year ended December 31, 2017 to internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.

The Company’s internal control system is designed to provide reasonable assurance to management and the board of directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness of internal control over financial reporting to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s Assessment and Auditor’s Attestation Report

Management’s Annual Report on Internal Control over Financial Reporting is provided on page 42 of the Registrants’ Management’s Discussion and Analysis, filed as Exhibit 99.2 to this report. KPMG LLP, an independent registered public accounting firm that audited and reported on our consolidated financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2017. The attestation report is included on the third page of our consolidated financial statements filed as Exhibit 99.3 to this report.

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AUDIT COMMITTEE

The Registrant’s Board of Directors has established a separately-designated Audit, Finance and Risk Committee (the “Audit Committee”) in accordance with Section 3(a)(58)(A) of the Exchange Act and NASDAQ Listing Rule 5605(c). As at the date of this annual report, the Registrant’s Audit Committee is comprised of the following directors, each of whom is independent as determined under each of Rule 10A-3 under the Exchange Act and NASDAQ Listing Rule 5605(a):

A. Terence Poole, Chair

Howard Balloch

Janice Rennie

Benita Warmbold

All members of the Audit Committee are financially literate, meaning they are able to read and understand the Company’s financial statements and to understand the breadth and level of complexity of the issues that can reasonably be expected to be raised by the Company’s financial statements. The Audit Committee meets the composition requirements set forth by NASDAQ Listing Rule 5605(c)(2).

A description of the mandate of the Audit Committee (the “Audit Committee Charter”), together with the relevant education and experience of its members and other Committee information, may be found in the “Audit Committee Information” section of the Registrant’s Annual Information Form for the year ended December 31, 2017, filed as Exhibit 99.1 to this annual report. The full text of the Audit Committee Charter is attached as Appendix “A” to the Annual Information Form.

AUDIT COMMITTEE FINANCIAL EXPERT

The Registrant’s Board of Directors has determined that Mr. A. Terence Poole is an audit committee financial expert (as that term is defined in paragraph (8)(b) of General Instruction B to Form 40-F under the Exchange Act). The Commission has indicated that the designation of Mr. Poole as an audit committee financial expert does not make Mr. Poole an “expert” for any other purpose, impose any duties, obligations or liability on Mr. Poole that are greater than those imposed on members of the Audit Committee and the board of directors who do not carry this designation, or affect the duties, obligations or liability of any other member of the Audit Committee.

CODE OF ETHICS

The Registrant has adopted a Code of Business Conduct (the “Code of Ethics”) that applies to directors, officers and employees, including the Registrant’s principal executive officer, principal financial officer and principal accounting officer. The Code of Ethics materially complies with NASDAQ Listing Rule 5610, and meets the requirements for a “code of ethics” within the meaning of that term in Form 40-F. A copy of the Code of Ethics can be found on the Registrant’s website at www.methanex.com.

No waivers from or substantive amendments to the provisions of the Code were made in 2017.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

KPMG LLP, Chartered Professional Accountants, Vancouver, are the independent auditors of the Registrant. The holders of the Registrant’s common shares have resolved to have the directors of the Registrant determine the auditor’s remuneration.

The Registrant’s Audit Committee annually reviews and approves the terms and scope of the external auditors’ engagement. The Audit Committee oversees the Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions under which permissible services proposed to be performed by KPMG LLP, the Registrant’s external auditors, are pre-approved. The Audit Committee has delegated to the Chair of the Audit Committee pre-approval authority for any services not previously approved by the Audit Committee. All such services approved by the Chair of the Audit Committee are subsequently reviewed by the Audit Committee.

All non-audit service engagements, regardless of the cost estimate, are required to be coordinated and approved by the Chief Financial Officer to further ensure that adherence to this policy is monitored.

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Audit and Non-Audit Fees Billed by the Independent Auditors

KPMG LLP’s global fees relating to the years ended December 31, 2017 and December 31, 2016 are as follows:

US$000s	2017	2016
Audit Fees	1,459	1,307
Audit-Related Fees	80	50
Tax Fees	134	61
Total	1,673	1,418

The nature of each category of fees is described below.

Audit Fees

Audit fees for professional services rendered by the external auditors for the audit of the Registrant’s consolidated financial statements; statutory audits of the financial statements of the Registrant’s subsidiaries; quarterly reviews of the Registrant’s financial statements; consultations as to the accounting or disclosure treatment of transactions reflected in the financial statements; and services associated with registration statements, prospectuses, periodic reports and other documents filed with securities regulators.

Audit fees for professional services rendered by the external auditors for the audit of the Registrant’s consolidated financial statements were in respect of an “integrated audit” performed by KPMG LLP globally. The integrated audit encompasses an opinion on the fairness of presentation of the Registrant’s financial statements as well as an opinion on the effectiveness of the Registrant’s internal control over financial reporting.

Audit-Related Fees

Audit-related fees for professional services rendered by the auditors for financial audits of employee benefit plans; procedures and audit or attest services not required by statute or regulation; and consultations related to the accounting or disclosure treatment of other transactions.

Tax Fees

Tax fees for professional services rendered for tax compliance and tax advice. These services consisted of: tax compliance, including the review of tax returns; assistance in completing routine tax schedules and calculations; and advisory services relating to domestic and international taxation.

OFF-BALANCE SHEET ARRANGEMENTS

At December 31, 2017, we did not have any off-balance sheet arrangements, as defined by applicable securities regulators in Canada and the United States that have, or are reasonably likely to have, a current or future material effect on our results of operations or financial condition.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Tabular disclosure of contractual obligations is made on page 22 of the Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2017, filed as Exhibit 99.2 to this report.

NASDAQ CORPORATE GOVERNANCE

The Company is subject to corporate governance requirements prescribed under applicable Canadian securities laws, rule and policies. The Company is also subject to corporate governance requirements prescribed by the listing standards of the NASDAQ Stock Market, and the rules and regulations promulgated by the SEC under the Exchange Act (including those applicable rules and regulations mandated by the Sarbanes-Oxley Act of 2002).

NASDAQ Listing Rule 5615(a)(3) permits a foreign private issuer to follow its home country practice in lieu of certain corporate governance requirements of the NASDAQ Listing Rules. A foreign private issuer that follows a home country practice in lieu of one or more provisions of the NASDAQ Listing Rules is required to disclose in its annual report filed with

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the Commission, or on its website, each corporate governance requirement of the NASDAQ Listing Rules that it does not follow and describe the home country practice followed by the issuer in lieu of such NASDAQ corporate governance requirements.

We do not follow NASDAQ Equity Rule 5620(c), but instead follow our home country practice relating to quorum requirements at meetings of shareholders as more fully described on page 21 of the Registrant’s Annual Information Form for the year ended December 31, 2017, filed as Exhibit 99.1 to this report.

The Company believes that there are otherwise no significant differences between its corporate governance policies and those required to be followed by United States domestic issuers listed on the NASDAQ Stock Market. In particular, in addition to having a separate Audit Committee, the Registrant’s Board of Directors has established a separately-designated Human Resources Committee that materially meets the requirements for a compensation committee under NASDAQ Listing Rule 5605(d), as currently in force.

The Company is required by National Instrument 58-101 of the Canadian Securities Administrators, Disclosure of Corporate Governance Practices, to describe its practices and policies with regard to corporate governance in management information circulars that are furnished to the Company’s shareholders in connection with annual meetings of shareholders.

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 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

A Form F-X signed by the Registrant and the Registrant’s agents for service of process: (a) with respect to the Common Shares, was filed with the Commission together with the Form 40-F of the Registrant on June 16, 1995; (b) with respect to the 5.25% Senior Notes due March 1, 2022 was filed with the Commission together with the Form F-9 of the Registrant on October 31, 2011; (c) with respect to the 3.25% Senior Notes due December 15, 2019 was filed with the Commission together with the Form F-10 of the Registrant on December 7, 2012; (d) with respect to the 4.25% Senior Notes due December 1, 2024 was filed with the Commission together with the Form F-10 of the Registrant on October 31, 2014; and (e) with respect to the 5.65% Senior Notes due December 1, 2044 was filed with the Commission together with the Form F-10 of the Registrant on October 31, 2014.

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EXHIBITS

Exhibit No	Description
23.1	Consent of KPMG LLP
31.1	Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Senior Vice President, Finance and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Senior Vice President, Finance and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Annual Information Form of the Registrant dated March 5, 2018
99.2	Management’s Discussion and Analysis for the Year Ended December 31, 2017
99.3	Audited Consolidated Financial Statements of the Registrant for the years ended December 31, 2017 and 2016 and the Independent Auditor’s Reports thereon
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definitions Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

	METHANEX CORPORATION
Date: March 6, 2018	By:	/s/ KEVIN PRICE
	Name:	Kevin Price
	Title:	General Counsel & Corporate Secretary

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EX-23.1

Exhibit 23.1

KPMG LLP

PO Box 10426 777 Dunsmuir Street

Vancouver BC V7Y 1K3

Canada

Telephone (604) 691-3000

Fax (604) 691-3031

Consent of Independent Registered Public Accounting Firm

The Board of Directors of Methanex Corporation

We consent to the use of our reports, each dated March 5, 2018, with respect to the consolidated financial statements and the effectiveness of internal control over financial reporting included in this annual report on Form 40-F.

We also consent to the incorporation by reference of such reports in the Registration Statements (No. 333-112624, No. 333-141833, No. 333-194850 and No. 333-217591,) on Form S-8, and No. 333-199756 on Form-10/A of Methanex Corporation.

/s/ KPMG LLP

Chartered Professional Accountants

March 5, 2018

Vancouver, Canada

KPMG LLP is a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. KPMG Canada provides services to KPMG LLP.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, John Floren, certify that:

1. I have reviewed this annual report on Form 40-F of Methanex Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of 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 6, 2018

/s/ JOHN FLOREN

John Floren

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Ian Cameron, certify that:

1. I have reviewed this annual report on Form 40-F of Methanex Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of 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 6, 2018

/s/ IAN CAMERON

Ian Cameron

Senior Vice President, Finance

and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Methanex Corporation (the “Company”) on Form 40-F for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Floren, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ JOHN FLOREN

John Floren

President and Chief Executive Officer

March 6, 2018

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Methanex Corporation (the “Company”) on Form 40-F for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ian Cameron, Senior Vice President, Finance and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ IAN CAMERON

Ian Cameron

Senior Vice President, Finance

and Chief Financial Officer

March 6, 2018

EX-99.1

Exhibit 99.1

METHANEX CORPORATION

ANNUAL INFORMATION FORM

www.methanex.com

March 5, 2018

TABLE OF CONTENTS	Page
REFERENCE INFORMATION		3
CAUTION REGARDING FORWARD-LOOKING STATEMENTS		4
THE COMPANY		6
BUSINESS OF THE COMPANY		7
Overview of the Business		7
DEVELOPMENT OF THE BUSINESS AND CORPORATE STRATEGY		7
Three Year History		7
Our Strategy		8
Global Leadership		8
Low Cost		9
Operational Excellence		9
METHANOL INDUSTRY INFORMATION		10
General		10
Demand Factors		10
Supply Factors		12
Methanol Prices		13
PRODUCTION		13
Production Process		13
Operating Data and Other Information		13
MARKETING		14
DISTRIBUTION AND LOGISTICS		14
NATURAL GAS SUPPLY		15
General		15
New Zealand		15
United States		15
Trinidad		15
Canada		16
Egypt		16
Chile		16
FOREIGN OPERATIONS AND GOVERNMENT REGULATION		16
General		16
Chile		17
Egypt		17
RESPONSIBLE CARE		17
ENVIRONMENTAL MATTERS		18
Management of Emissions		19
INSURANCE		20
COMPETITION		20
EMPLOYEES		20
RISK FACTORS		20
DIVIDENDS		20
CAPITAL STRUCTURE		21
RATINGS		21
MARKET FOR SECURITIES		23
NORMAL COURSE ISSUER BID		23
DIRECTORS AND EXECUTIVE OFFICERS		23
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		25
EXPERTS		25
LEGAL PROCEEDINGS		25
AUDIT COMMITTEE INFORMATION		25
The Audit Committee Charter		25
Composition of the Audit Committee		26
Relevant Education and Experience		26
Pre-Approval Policies and Procedures		27
Audit and Non-Audit Fees Billed by the Independent Auditors		27
TRANSFER AGENT AND REGISTRAR		28
CONTROLS AND PROCEDURES		28
CODE OF ETHICS		28
ADDITIONAL INFORMATION		28
APPENDIX “A”		29

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REFERENCE INFORMATION

In this Annual Information Form (“AIF”), a reference to the “Company” refers to Methanex Corporation and a reference to “Methanex,” “we,” “us,” “our” and similar words refers to the Company and its subsidiaries or any one of them as the context requires, as well as their respective interests in joint ventures and partnerships.

We use the United States dollar as our reporting currency. Accordingly, unless otherwise indicated, all dollar amounts in this AIF are stated in United States dollars.

In this AIF, unless the context otherwise indicates, all references to “methanol” are to chemical-grade methanol. Methanol’s chemical formula is CH3OH and it is also known as methyl alcohol.

In this AIF, we incorporate by reference our 2017 Management’s Discussion and Analysis (“2017 MD&A”), which contains information required to be included in this AIF. The 2017 MD&A is publicly accessible and is filed on the Canadian Securities Administrators’ SEDAR website at www.sedar.com and on the U.S. Securities and Exchange Commission’s EDGAR website at www.sec.gov.

The approximate conversion of measurement used in this AIF is as follows:

1 tonne of methanol = 332.6 US gallons of methanol

Some of the historical price data and supply and demand statistics for methanol and certain other industry data contained in this AIF are derived by the Company from industry consultants or from recognized industry reports regularly published by independent consulting and data compilation organizations in the methanol industry, including IHS Inc., Tecnon OrbiChem Ltd., Argus, ICIS, Platts and Methanol Market Services Asia. Industry consultants and industry publications generally state that the information provided has been obtained from sources believed to be reliable. We have not independently verified any of the data from third-party sources nor have we ascertained the underlying economic assumptions relied upon in these reports.

Responsible Care^® is a registered trademark of the Chemistry Industry Association of Canada and is used under license by us.

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CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements with respect to us and our industry. These statements relate to future events or our future performance. All statements other than statements of historical fact are forward-looking statements. Statements that include the words “believes,” “expects,” “may,” “will,” “should,” “potential,” “estimates,” “anticipates,” “aim,” “goal” or other comparable terminology and similar statements of a future or forward-looking nature identify forward-looking statements.

More particularly and without limitation, any statements regarding the following are forward-looking statements:

• expected demand for methanol and its derivatives,

• expected new methanol supply or restart of idled capacity and timing for start-up of the same,

• expected shutdowns (either temporary or permanent) or restarts of existing methanol supply (including our own facilities), including, without limitation, the timing and length of planned maintenance outages,

• expected methanol and energy prices,

• expected levels of methanol purchases from traders or other third parties,

• expected levels, timing and availability of economically priced natural gas supply to each of our plants,

• capital committed by third parties towards future natural gas exploration and development in the vicinity of our plants,

• our expected capital expenditures,

• anticipated operating rates of our plants,

• expected operating costs, including natural gas feedstock costs and logistics costs,

• expected tax rates or resolutions to tax disputes,

• expected cash flows, earnings capability and share price,

• availability of committed credit facilities and other financing,

• our ability to meet covenants or obtain or continue to obtain waivers associated with our long-term debt obligations, including, without limitation, the Egypt limited recourse debt facilities that have conditions associated with the payment of cash or other distributions and the finalization of certain land title registrations and related mortgages which require actions by Egyptian governmental entities,

• expected impact on our results of operations in Egypt or our financial condition as a consequence of civil unrest or actions taken or inaction by Egyptian governmental entities,

• our shareholder distribution strategy and anticipated distributions to shareholders,

• commercial viability and timing of, or our ability to execute, future projects, plant restarts, capacity expansions, plant relocations, or other business initiatives or opportunities,

• our financial strength and ability to meet future financial commitments,

• expected global or regional economic activity (including industrial production levels),

• expected outcomes of litigation or other disputes, claims and assessments, and

• expected actions of governments, governmental agencies, gas suppliers, courts, tribunals or other third parties.

We believe that we have a reasonable basis for making such forward-looking statements. The forward-looking statements in this document are based on our experience, our perception of trends, current conditions and expected future developments as well as other factors. Certain material factors or assumptions were applied in drawing the conclusions or making the forecasts or projections that are included in these forward-looking statements, including, without limitation, future expectations and assumptions concerning the following:

• the supply of, demand for and price of methanol, methanol derivatives, natural gas, coal, oil and oil derivatives,

• our ability to procure natural gas feedstock on commercially acceptable terms,

• operating rates of our facilities,

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• receipt or issuance of third-party consents or approvals, including, without limitation, governmental registrations of land title and related mortgages in Egypt and governmental approvals related to rights to purchase natural gas,

• the establishment of new fuel standards,

• operating costs, including natural gas feedstock and logistics costs, capital costs, tax rates, cash flows, foreign exchange rates and interest rates,

• the availability of committed credit facilities and other financing,

• global and regional economic activity (including industrial production levels),

• absence of a material negative impact from major natural disasters,

• absence of a material negative impact from changes in laws or regulations,

• absence of a material negative impact from political instability in the countries in which we operate, and

• enforcement of contractual arrangements and ability to perform contractual obligations by customers, natural gas and other suppliers and other third parties.

However, forward-looking statements, by their nature, involve risks and uncertainties that could cause actual results to differ materially from those contemplated by the forward-looking statements. The risks and uncertainties primarily include those attendant with producing and marketing methanol and successfully carrying out major capital expenditure projects in various jurisdictions, including, without limitation:

• conditions in the methanol and other industries including fluctuations in the supply, demand and price for methanol and its derivatives, including demand for methanol for energy uses,

• the price of natural gas, coal, oil and oil derivatives,

• our ability to obtain natural gas feedstock on commercially acceptable terms to underpin current operations and future production growth opportunities,

• the ability to carry out corporate initiatives and strategies,

• actions of competitors, suppliers and financial institutions,

• conditions within the natural gas delivery systems that may prevent delivery of our natural gas supply requirements,

• competing demand for natural gas, especially with respect to domestic needs for gas and electricity in Chile and Egypt,

• actions of governments and governmental authorities, including, without limitation, the implementation of policies or other measures that could impact the supply of or demand for methanol or its derivatives,

• changes in laws or regulations,

• import or export restrictions, anti-dumping measures, increases in duties, taxes and government royalties and other actions by governments that may adversely affect our operations or existing contractual arrangements,

• worldwide economic conditions, and

• other risks described in our 2017 MD&A.

Having in mind these and other factors, investors and other readers are cautioned not to place undue reliance on forward-looking statements. They are not a substitute for the exercise of one’s own due diligence and judgment. The outcomes implied by forward-looking statements may not occur and we do not undertake to update forward-looking statements except as required by applicable securities laws.

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THE COMPANY

Methanex Corporation was incorporated under the laws of Alberta on March 11, 1968 and was continued under the Canada Business Corporations Act on March 5, 1992. Its registered and head office is located at 1800 Waterfront Centre, 200 Burrard Street, Vancouver, British Columbia, V6C 3M1 (telephone: 604-661-2600).

The following chart includes the Company’s principal operating subsidiaries as of December 31, 2017 and, for each subsidiary, its place of organization and the Company’s percentage of voting interests beneficially owned or over which the Company exercises control or direction. The chart also shows our principal production facilities and their locations.

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BUSINESS OF THE COMPANY

Overview of the Business

Methanol is a clear liquid commodity chemical that is predominantly produced from natural gas and is also produced from coal, particularly in China. Approximately 55% of all methanol demand is used to produce traditional chemical derivatives, including formaldehyde, acetic acid and a variety of other chemicals that form the basis of a large number of chemical derivatives for which demand is influenced by levels of global economic activity. The remaining 45% of methanol demand comes from a range of energy-related applications. These include methanol-to-olefins (“MTO”), methyl tertiary-butyl ether (“MTBE”), direct blending of methanol into gasoline (primarily in China), di-methyl ether (“DME”), biodiesel, methanol-to-gasoline (“MTG”), industrial boilers and marine fuel.

We are the world’s largest producer and supplier of methanol to the major international markets in Asia Pacific, North America, Europe and South America. Our total annual production capacity, including Methanex interests in jointly owned plants, is currently 9.4 million tonnes and is located in New Zealand, the United States, Trinidad, Egypt, Canada and Chile. In addition to the methanol produced at our sites, we purchase methanol produced by others under methanol offtake contracts and on the spot market. This gives us flexibility in managing our supply chain while continuing to meet customer needs and support our marketing efforts. We have marketing rights for 100% of the production from the jointly-owned plants in Trinidad and Egypt, which provides us with an additional 1.3 million tonnes per year of methanol offtake supply when the plants are operating at full capacity.

Refer to the Production Summary section on page 13 for more information regarding production at our plants.

DEVELOPMENT OF THE BUSINESS AND CORPORATE STRATEGY

Three Year History

2015

On January 24, 2015, the Company successfully produced first methanol from its new one million tonne plant in Geismar, Louisiana. The plant was relocated from the Company’s production site in Punta Arenas, Chile.

On January 28, 2015, the Company announced that it received approval from the Toronto Stock Exchange to amend the normal course issuer bid initiated on May 6, 2014 in order to increase the maximum number of common shares that may be acquired under the bid from 4,826,197 common shares to 8,577,716 common shares.

In the first quarter of 2015, the Company announced that it signed a Term Sheet with National Gas Company (Trinidad) to extend the supply of gas for the Titan plant for an additional five years. The existing Titan gas contract expired in 2014.

In the second quarter of 2015, the Company undertook a planned major refurbishment of its Medicine Hat facility. As a result of this refurbishment, the annual production capacity was re-rated to 600,000 tonnes from 560,000 tonnes.

On April 28, 2015, the Company announced that its Board of Directors approved a new normal course issuer bid to commence on May 6, 2015 pursuant to which the Company may purchase up to 4,554,115 common shares, representing approximately 5% of the 91,082,312 shares issues and outstanding at that time.

On December 27, 2015, the Company successfully produced first methanol from its newly completed one million tonne Geismar 2 methanol plant in Geismar, Louisiana. The plant was relocated from the Company’s production site in Punta Arenas, Chile. The total combined cost for the completion of the two Geismar plants is approximately $1.4 billion.

2016

In April 2016, the Company announced the launch of the world’s first ocean-going vessels that can run on methanol. In 2016, the Company took delivery of a total of seven such vessels. These vessels are built with the first-of-their kind 2-stroke dual fuel engines that can run on methanol and other conventional fuels. This initiative is part of the Company’s strategy to promote methanol as a viable, efficient, environmentally friendly and convenient fuel alternative.

On June 15, 2016, the Company announced that it reached an agreement with Petrobras Energía S.A. (“Petrobras”) of Argentina to settle a legal dispute in relation to Petrobras’s natural gas delivery obligations pursuant to a long-term natural gas supply agreement between the two companies. Petrobras made a lump sum payment of $32.5 million to the Company in order to terminate both the natural gas supply agreement and any and all claims in relation to such agreement.

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On July 28, 2016, the Company announced that it reached an agreement with Empresa Nacional del Petróleo (“ENAP”) for gas supply for the period through May 2018. The Company also announced its wholly-owned Chilean subsidiary signed a Term Sheet with GeoPark Fell SpA in order to extend its current gas supply agreement for an additional 10 year term, beyond April 2017.

2017

On March 6, 2017, the Company announced that its Board of Directors approved a normal course issuer bid to commence on March 13, 2017 pursuant to which the Company may purchase up to 4,492,141 common shares, representing approximately 5% of the 89,842,838 shares issued and outstanding at that time.

On July 26, 2017, the Company announced that it received approval from the Toronto Stock Exchange to amend the normal course issuer bid initiated on March 13, 2017 in order to increase the maximum number of common shares that may be acquired under the bid from 4,492,141 common shares to 6,152,358 common shares, representing 10% of the public float at the time of the announcement.

On November 8, 2017, the Company announced the signing of a long-term natural gas supply agreement to extend the supply of gas for the Medicine Hat plant to 2031.

On December 7, 2017, the Company announced that it reached an agreement with ENAP for additional gas supply for the Chile operations through to December 31, 2019.

Our Strategy

Our primary objective is to create value by maintaining and enhancing our leadership in the global production, marketing and delivery of methanol to customers. To achieve this objective we have a simple, clearly defined strategy: global leadership, low cost and operational excellence. We also pride ourselves in being a leader in Responsible Care. Our brand differentiator “The Power of Agility^®” defines our culture of flexibility, responsiveness and creativity that allows us to capitalize on opportunities quickly as they arise, and swiftly respond to customer needs.

Global Leadership

Global leadership is a key element of our strategy. We are focused on maintaining and enhancing our position as the major producer and supplier in the global methanol industry, improving our ability to cost-effectively deliver methanol to customers and supporting both traditional and energy-related global methanol demand growth.

We are the leading producer and supplier of methanol to the major international markets in Asia Pacific, North America, Europe and South America. Our 2017 sales volume of 10.7 million tonnes of methanol represented approximately 14% of global methanol demand. Our leadership position has enabled us to play an important role in the industry, which includes publishing Methanex reference prices that are used in each major market as the basis of pricing for our customer contracts.

The geographically diverse locations of our production sites allow us to deliver methanol cost-effectively to customers in all major global markets, while investments in global distribution and supply infrastructure, which include a fleet of ocean-going vessels and terminal capacity within all major international markets, enable us to enhance value to customers by providing reliable and secure supply.

A key component of our global leadership strategy is the strength of our asset position with over 8.5 million tonnes of operating capacity in 2017. We achieved record production in 2017 of 7.2 million tonnes, exceeding our previous record of 7.0 million tonnes set in 2016. Our Chile operations are currently operating at less than full production capacity and provide further potential to increase production.

Another key component of our global leadership strategy is our ability to supplement methanol production with methanol purchased from third parties to give us flexibility in our supply chain to meet customer commitments. We purchase methanol through a combination of methanol offtake contracts and spot purchases. We manage the cost of purchased methanol by taking advantage of our global supply chain infrastructure, which allows us to purchase methanol in the most cost-effective region while still maintaining overall security of supply.

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The Asia Pacific region continues to lead global methanol demand growth and we have invested in and developed our presence in this important region. We have storage capacity in China, South Korea and Japan that allows us to cost-effectively manage supply to customers and we have offices in Hong Kong, Shanghai, Tokyo, Seoul and Beijing to enhance customer service and industry positioning in the region. This enables us to participate in and improve our knowledge of the rapidly evolving and high growth methanol markets in China and other Asian countries. Our expanding presence in Asia Pacific has also helped us identify several opportunities to support the development of applications for methanol in the energy-related sector.

Low Cost

A low cost structure is an important competitive advantage in a commodity industry and is a key element of our strategy. Our approach to major business decisions is guided by a drive to improve our cost structure and create value for shareholders. The most significant components of total costs are natural gas for feedstock and distribution costs associated with delivering methanol to customers. Our cost structure per tonne continues to benefit from significant leverage on our fixed costs as production increases.

The New Zealand, Trinidad and Egypt facilities are underpinned by natural gas purchase agreements where the natural gas price varies with methanol prices. This pricing relationship enables these facilities to be competitive throughout the methanol price cycle. We have a fixed price contract to supply substantially all our Geismar 1 facility and forward contracts to hedge natural gas prices for approximately 40% of the natural gas requirements of our Geismar 2 facility through 2025 with the remainder of natural gas requirements at Geismar purchased in the spot market.

We have entered into fixed price contracts to supply the majority of our natural gas requirements for our Medicine Hat facility through 2031.

Our production facilities are well located to supply global methanol markets. Still, the cost to distribute methanol from production locations to customers is a significant component of total operating costs. These include costs for ocean shipping, in-market storage facilities and in-market distribution. We are focused on identifying initiatives to reduce these costs, including optimizing the use of our shipping fleet and taking advantage of prevailing conditions in the shipping market by varying the type and length of term of ocean vessel contracts. 2017 was our first full year with seven vessels equipped with flex-fuel engines that can run on conventional fuel or methanol, which provides us with further flexibility in our supply chain. We also look for opportunities to leverage our global asset position by entering into geographic product exchanges with other methanol producers to reduce distribution costs.

Operational Excellence

We maintain a focus on operational excellence in all aspects of our business. This includes excellence in manufacturing and supply chain processes, marketing and sales, human resources, corporate governance practices and financial management.

To differentiate ourselves from competitors, we strive to be the best operator in all aspects of our business and to be the preferred supplier to customers. We believe that reliability of supply is critical to the success of our customers’ businesses and our goal is to deliver methanol reliably and cost-effectively. We have a commitment to Responsible Care (an operating ethic and set of principles developed by the Chemistry Industry Association of Canada) and we use it as the umbrella under which we manage issues related to employee health and safety, environmental protection, community involvement, social responsibility, sustainability, security and emergency preparedness at each of our facilities and locations. Through the International Council of Chemical Associations, over 60 countries have adopted the Responsible Care Ethic and Principles for Sustainability. We believe a commitment to Responsible Care helps us achieve an excellent overall environmental and safety record.

Product stewardship is a vital component of a Responsible Care culture and guides our actions through the complete life cycle of our product. We aim for the highest safety standards to minimize risk to employees, customers and suppliers as well as to the environment and the communities in which we do business. We promote the proper use and safe handling of methanol at all times through a variety of internal and external health, safety and environmental initiatives, and we work with industry colleagues to improve safety standards. We readily share technical and safety expertise with key stakeholders, including customers, end-users, suppliers, logistics providers and industry associations in the methanol and methanol applications marketplace through active participation in local and international industry associations, seminars and conferences and online education initiatives.

As a natural extension of the Responsible Care ethic, we have a Social Responsibility policy that aligns corporate governance, employee engagement and development, community involvement and social investment strategies with our core values and corporate strategy.

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Our strategy of operational excellence also includes the financial management of the Company. We operate in a highly competitive commodity industry. Accordingly, we believe it is important to maintain financial flexibility and we have adopted a prudent approach to financial management. We have an undrawn $300 million credit facility provided by highly rated financial institutions that expires in December 2022. As at December 31, 2017, we had a strong balance sheet and a cash balance of $375 million. We believe we are well-positioned to meet our financial commitments, pursue our near-term growth opportunities in Chile and deliver on our commitment to return excess cash to shareholders through dividends and share repurchases.

METHANOL INDUSTRY INFORMATION

General

In 2017, approximately 55% of all methanol was used to produce a variety of traditional chemical derivatives, including formaldehyde and acetic acid, the demand for which is influenced by levels of global economic activity. These derivatives are used to manufacture a wide range of end products, including plywood, particleboard, foams, resins and plastics. The remainder of methanol demand comes from energy-related applications. MTO and MTBE are the largest of these energy-related demand drivers but this segment also includes direct blending of methanol into gasoline, DME, biodiesel, MTG, industrial boilers and marine fuel. The demand for methanol into energy-related applications will depend on a number of factors including pricing for their various final products, which in turn depends on the level of global energy prices.

The methanol market is global and, over the last several years, has become more complex and subject to increasingly diverse influences due to the expanding number of uses for methanol and its derivatives around the world.

Demand Factors

Reflecting the diversity of its uses, methanol demand is influenced by a wide range of economic, industrial, environmental, legal, regulatory and other factors, including energy prices due to the growing use of methanol in energy-related applications.

We estimate that total global demand for methanol in 2017, excluding methanol produced in integrated coal-to-olefins facilities, increased by over 4% versus 2016 to approximately 78 million tonnes. Energy-related demand growth accounted for the majority of the annual 2017 growth and grew by close to 8% year-over-year. Traditional chemical derivatives accounted for the remainder of the annual 2017 growth and grew by almost 2% year-over-year.

Traditional Chemical Derivative Demand

Historically, demand growth for methanol in chemical derivatives has been closely correlated to economic and industrial production growth rates. The use of methanol derivatives such as formaldehyde and acetic acid in the building industry means that building and construction cycles and the level of wood products production, housing starts, refurbishments and consumer spending are important factors in determining demand for such derivatives. Demand is also affected by automobile production, durable goods production, industrial investment and environmental and health trends, as well as new product development. Historically, chemical derivative demand for methanol has been relatively insensitive to changes in methanol prices. We believe this demand inelasticity is due to the fact that there are limited, if any, cost-effective substitutes for methanol-based chemical derivative products and because methanol costs in most cases account for only a small portion of the value of many of the end products.

Formaldehyde Demand

In 2017, methanol demand for the production of formaldehyde represented approximately 30% of global methanol demand. The largest use for formaldehyde is as a component of urea-formaldehyde and phenol-formaldehyde resins, which are used as wood adhesives for plywood, particleboard, oriented strand board, medium-density fibreboard and other reconstituted or engineered wood products. There is also demand for formaldehyde as a raw material for engineering plastics and in the manufacture of a variety of other products, including elastomers, paints, building products, foams, polyurethane and automotive products.

Acetic Acid Demand

In 2017, methanol used to produce acetic acid represented approximately 9% of global methanol demand. Acetic acid is a chemical intermediate used principally in the production of vinyl acetate monomer, acetic anhydride, purified terephthalic acid and acetate solvents, which are used in a wide variety of products, including adhesives, paper, paints, plastics, resins, solvents, pharmaceuticals and textiles.

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Other Chemical Derivative Demand

The remaining chemical derivative demand for methanol is in the manufacture of methylamines, methyl methacrylate and a diverse range of other chemical products that are ultimately used to make products such as adhesives, coatings, plastics, film, textiles, paints, solvents, paint removers, polyester resins and fibres, explosives, herbicides, pesticides and poultry feed additives. Other end uses include silicone products, aerosol products, de-icing fluid, windshield washer fluid for automobiles and antifreeze for pipeline dehydration.

Energy Demand

There are several energy-related uses for methanol that have developed in the past decade and many of these have experienced substantial growth in recent years. In 2017, methanol demand for energy-related use continued to grow and represented approximately 45% of total global methanol demand. This demand was comprised of merchant MTO, which represented approximately 15% of global demand in 2017, methanol for the production of MTBE, which represented about 12% of total 2017 demand as well as other applications including direct blending of methanol into gasoline, DME, biodiesel and MTG which together accounted for approximately 18% of total 2017 demand. Merchant MTO was the fastest-growing end-use segment for methanol in 2017. While methanol demand in energy-related applications is strongest in China, a number of countries around the world are considering adopting these applications on a wider scale. The future operating rates and methanol consumption from energy-related applications using methanol as a feedstock will depend on a number of factors, including pricing for their various final products, which in turn depends on the level of global energy prices.

Methanol-to-Olefins (MTO) Demand

Light olefins (ethylene and propylene) are the basic building blocks used to make many plastics that have wide application in packaging, textiles, plastic parts and containers, and automotive components. Olefins can be produced from various feedstocks, including naphtha, liquefied petroleum gas (“LPG”), ethane and methanol. In China, olefins have historically been produced using naphtha, a product derived from oil. Over the past five years, methanol demand into olefins has emerged as a significant new energy-related derivative for methanol. The first merchant MTO plant in China started up in 2012, and by the end of 2017, approximately 12 million tonnes of methanol in the merchant market was consumed by MTO plants in China (excluding demand from upstream-integrated coal-to-olefins plants). We estimate the current MTO capacity for merchant methanol to be about 14 million tonnes.

MTBE Demand

MTBE is used primarily as an oxygenate blended in gasoline to contribute octane and reduce the amount of harmful exhaust emissions from motor vehicles. MTBE is an efficient and cost-competitive gasoline component and, as such, is increasingly used in developing countries targeting gasoline pool extension and clean air benefits at a cost lower than that of alternatives. Asia represents the majority of global MTBE demand, with China being a significant and growing market. China is now the world’s largest automotive market and the combination of its growing gasoline demand, as well as China’s desire to reduce exhaust emissions, is driving new MTBE capacity additions. In the U.S., MTBE production continues to increase for export markets (Latin America and Europe mainly) as idled assets have restarted and a new project is under evaluation. By the end of 2017, over nine million tonnes of methanol was consumed for the production of MTBE. We believe that global demand for MTBE will experience growth over the coming years.

Methanol Demand for Fuel

Methanol is blended into gasoline or used as a substitute for gasoline for use as a transportation fuel because of its competitive pricing relative to gasoline as well as for its clean air benefits. Methanol can also be converted to gasoline. As of 2017, there were ten MTG plants in China; however, the majority of this capacity was idled or operating at low rates due to poor economics. Smaller quantities of methanol are also used in China directly as a cooking fuel and as fuel in industrial boilers. In 2017, we estimate that methanol demand for these fuel applications in China was approximately seven million tonnes. Automobile sales in China, and thus gasoline demand, have remained healthy in 2017, supporting methanol demand. China’s central and provincial governments have implemented a range of fuel-blending standards for methanol that promote the use of methanol as a fuel. In addition, China has introduced a mandate to ban small scale coal fired boilers in cities in north China creating growing demand opportunities for methanol use as fuel in industrial boilers. Methanol in small quantities is being used for direct methanol blending in the United Kingdom, the Netherlands and Iceland, and commercialization activities are underway in other countries, including New Zealand which legislated a limit of 3% methanol in gasoline (M3) in 2017, and Israel which approved a M15 (15% methanol, 85% gasoline) fuel standard in 2017. Driven by regulations in Europe and North America that limit sulphur emissions from marine vessels in

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certain regulated zones, methanol is now being used as a clean-burning marine fuel. In 2017, Waterfront Shipping operated seven dual-fuel vessels capable of running on methanol and we believe that others in the shipping industry will also choose methanol as a marine fuel. In 2017, global methanol demand for use in fuel applications was estimated at over seven million tonnes.

DME Demand

DME is a clean-burning fuel that can be stored and transported like LPG. DME, which is typically produced from methanol, can be blended up to approximately 20% with LPG and used for household cooking and heating. DME can also be used as a clean-burning substitute for diesel fuel in transportation. However, while the technology for using DME as a diesel fuel substitute is well advanced, it has not yet entered widespread commercialization. In 2017, global methanol demand for use in DME was estimated at over three million tonnes. In addition to DME production in China, DME is being produced and projects promoting the use of DME are under development in other countries including Japan, Turkey, Trinidad, the United States and parts of Europe.

Risk Factors Affecting Demand

Demand for methanol largely depends upon the level of energy prices, global economic growth rates and government regulations and policies. Changes in energy prices, a slowdown in global or regional economic growth and/or studies and legislative proposals currently under way in a number of countries with respect to the carcinogenicity classification of, and the reduction of permitted exposure levels for, methanol, formaldehyde and MTBE, as well as restrictions on methanol in consumer windshield wash fluid, could materially reduce demand for methanol.

Supply Factors

Methanol is predominantly produced from natural gas and is also produced from coal, particularly in China. In addition, the industry has historically operated significantly below stated capacity on a consistent basis, even in periods of high methanol prices, due primarily to shutdowns for planned and unplanned repairs and maintenance as well as shortages of feedstock and other production inputs.

There is typically a span of four to six years to plan and construct a new world-scale methanol plant. Additional methanol supply may also become available with the restart of methanol plants whose production has been idled, by relocating methanol plants or by carrying out expansions or debottlenecking of existing plants to increase their production capacity.

Typical of most commodity chemicals, periods of high methanol prices encourage high-cost producers to operate at maximum rates and also encourage the construction of new plants and expansion projects, leading to the possibility of oversupply in the market. However, historically, many of the announced capacity additions have not been constructed for a variety of reasons. There are significant barriers to entry in this industry. The construction of world-scale methanol facilities requires significant capital over a long lead time, a location with access to significant natural gas or coal feedstock with appropriate pricing, and an ability to cost-effectively and reliably deliver methanol to customers.

There were no significant new industry capacity additions outside of China in 2017. In China, we estimate that over two million tonnes of new non-integrated production capacity was added in 2017.

Over the next few years, the majority of large-scale capacity additions outside of China are expected to be in North America and the Middle East. OCI N.V. and Consolidated Energy Limited (through its subsidiary G2X Energy) continue to advance their jointly owned Natgasoline project, a 1.8 million tonne plant under construction in Beaumont, Texas with methanol production expected in 2018. There are a number of other large-scale projects under discussion in the United States; however, we believe that there has been limited committed capital to date. In Iran, there are a number of plants at various stages of construction. We expect just over four million tonnes of capacity to come onstream in Iran over the next two years; however, the start-up timing and future operating rates at these facilities will be dependent on various factors. Caribbean Gas Chemical Limited (“CGCL”) is constructing a 1.0 million tonne plant in Trinidad with announced production towards the end of the decade. To the end of 2018, we expect approximately two million tonnes of new capacity additions in China. Beyond 2018, we anticipate that new capacity additions in China will be modest due to increasing restrictions placed by the Chinese government on new coal-based capacity additions. We expect that production from new capacity in China will be consumed in that country.

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Methanol Prices

The methanol business is a highly competitive commodity industry and prices are affected by supply and demand fundamentals. Methanol prices have historically been, and are expected to continue to be, characterized by cyclicality.

We publish regional non-discounted reference prices for each major methanol market and these posted prices are reviewed and revised monthly or quarterly based on industry fundamentals and market conditions. Most of our customer contracts use published Methanex reference prices as a basis for pricing, and we offer discounts to customers based on various factors.

We are not able to predict future methanol supply and demand balances, market conditions, global economic activity, methanol prices or energy prices, all of which are affected by numerous factors beyond our control. Since methanol is the only product we produce and market, the price of methanol has a significant effect on our results of operations and financial condition.

PRODUCTION

Production Process

The methanol manufacturing process used in our facilities typically involves heating natural gas, mixing it with steam and passing it over a nickel catalyst where the mixture is converted into carbon monoxide, carbon dioxide and hydrogen. This reformed gas (also known as synthesis gas or syngas) is then cooled, compressed and passed over a copper-zinc catalyst to produce crude methanol. Crude methanol consists of approximately 80% methanol and 20% water by weight. To produce chemical-grade methanol, crude methanol is distilled to remove water, higher alcohols and other impurities.

Operating Data and Other Information

We endeavour to operate our production facilities around the world in an optimal manner to lower our overall delivered cost of methanol.

Scheduled shutdowns of plants are necessary to change catalysts or perform maintenance activities that cannot otherwise be completed with the plant operating (a process commonly known as a turnaround). These shutdowns typically take between three and five weeks. Catalysts generally need to be changed every three to six years depending on technology, although there is flexibility to extend catalyst life if conditions warrant. Careful planning and scheduling is required to ensure that maintenance and repairs can be carried out during turnarounds. In addition, both scheduled and unscheduled shutdowns may occur between turnarounds. We prepare a long-term turnaround schedule that is updated annually for all of our production facilities.

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The following table sets forth the annual production capacity and actual production for our facilities that operated for the last two years (in the case of Atlas and Egypt, the table reflects our equity interest share):

	Annual Production Capacity(1)		Annual Operating Capacity(2)		2017 Production		2016 Production
	(000 tonnes/year)		(000 tonnes/year)		(000 tonnes)		(000 tonnes)
New Zealand (3)		2,430		2,430		1,943		2,181
Geismar (USA)		2,000		2,000		1,935		2,055
Trinidad (Methanex interest) (4)		2,000		2,000		1,768		1,605
Egypt (50% interest)		630		630		534		293
Medicine Hat (Canada)		600		600		593		488
Chile (5)		1,720		880		414		395
		9,380		8,540		7,187		7,017

(1) Annual production capacity reflects, among other things, average expected plant outages, turnarounds and average age of the facility’s catalyst. As a result, the actual production of a facility may be higher or lower than the stated annual production capacity.

(2) Annual operating capacity includes only those facilities which are currently capable of operating, but excludes any portion of an asset that is underutilized due to a lack of natural gas feedstock over a prolonged period of time. Our current annual operating capacity is 8.5 million tonnes, including 0.9 million tonnes related to our Chile operations. The operating capacity of our production facilities may be higher than original nameplate capacity as, over time, these figures have been adjusted to reflect ongoing operating efficiencies at these facilities. Actual production for a facility in any given year may be higher or lower than operating capacity due to a number of factors, including natural gas composition or the age of the facility’s catalyst.

(3) The operating capacity of New Zealand is made up of the two Motunui facilities and the Waitara Valley facility (refer to the Natural Gas Supply - New Zealand section below).

(4) The operating capacity of Trinidad is made up of the Titan (100% interest) and Atlas (63.1% interest) facilities (refer to the Natural Gas Supply - Trinidad section below).

(5) The production capacity of our Chile I and IV facilities is 1.7 million tonnes annually assuming access to natural gas feedstock.

Refer to the Production Summary section of our 2017 MD&A for more information.

MARKETING

We sell methanol on a worldwide basis to every major market through an extensive marketing and distribution system with marketing offices in North America (Dallas and Vancouver), Europe (Brussels), Asia Pacific (Hong Kong, Shanghai, Tokyo, Seoul and Beijing), South America (Santiago) and the Middle East (Dubai). Most of our customers are large global or regional petrochemical manufacturers or distributors.

We believe our ability to sell methanol from a number of geographically dispersed production sites enhances our ability to serve major chemical and petrochemical producers as customers for whom reliability of supply and quality of service are important.

In addition to selling methanol that we produce at our own facilities, we also sell methanol that we purchase from other suppliers through methanol purchase agreements and on the spot market. This provides us with flexibility in our supply chain and allows us to continue to meet customer commitments.

DISTRIBUTION AND LOGISTICS

All of our methanol production facilities except Medicine Hat are located adjacent to deepwater ports. Methanol is pumped from our coastal plants by pipeline to these ports for shipping. We currently own or manage a fleet of approximately 28 ocean-going vessels to ship this methanol. We lease or own in-region storage and terminal facilities in North America, Europe, South America and Asia. We also use barge, rail, pipelines and, to a lesser extent, truck transport in our delivery system.

To retain optimal flexibility in managing our shipping fleet, we have entered into short-term and long-term time charter agreements covering vessels with a range of capacities. We also ship methanol under contracts of affreightment and through spot arrangements. We use larger vessels as key elements in our supply chain to move product from our production facilities to storage facilities located in major ports and for direct delivery to some customers. We also use smaller vessels capable of entering into restricted ports to deliver directly to other customers.

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The cost to distribute methanol to customers represents a significant component of our operating costs. These include costs for ocean shipping, storage and distribution. We are focused on identifying initiatives to reduce these costs and we seek to maximize the use of our shipping fleet to reduce costs. We take advantage of prevailing conditions in the shipping market by varying the type and length of term of ocean vessel charter contracts. We are continuously investigating opportunities to further improve the efficiency and cost-effectiveness of distributing methanol from our production facilities to customers. We also look for opportunities to leverage our global asset position by entering into product exchanges with other methanol producers to reduce distribution costs.

Our Atlas and Titan plants in Trinidad are ideally located to supply customers in all global markets. Our plants in New Zealand primarily supply customers in the Asia Pacific region, but also supply European, North American and South American markets when required. Our production site in Chile can supply all global regions due to its geographic location, but currently only supplies South America due to lower production levels. Our Egypt plant primarily services our European markets, but can also supply Asia. Our Medicine Hat plant serves our customer base in North America and the Geismar plants can serve customers across North America, Europe and Asia.

NATURAL GAS SUPPLY

General

Natural gas is the principal feedstock for producing methanol and it accounts for a significant portion of our operating costs. Accordingly, our results from operations depend in large part on the availability and security of supply and the price of natural gas. If, for any reason, we are unable to obtain sufficient natural gas for any of our plants on commercially acceptable terms or we experience interruptions in the supply of contracted natural gas, we could be forced to curtail production or close such plants, which could have an adverse effect on our results of operations and financial condition.

New Zealand

We have three plants in New Zealand with a total production capacity of up to 2.4 million tonnes of methanol per year, depending on natural gas composition. Two plants are located at Motunui and the third is located at nearby Waitara Valley. We have entered into several agreements with various natural gas suppliers to underpin our New Zealand operations with terms that range in length up to 2022. All agreements in New Zealand are take-or-pay agreements and include U.S. dollar base and variable price components where the variable price component is adjusted by a formula related to methanol prices above a certain level. We believe this pricing relationship enables these facilities to be competitive at all points in the methanol price cycle and provides gas suppliers with attractive returns. Certain of these contracts require the supplier to deliver a minimum amount of natural gas with additional volume dependent on the success of exploring and developing the related natural gas field.

We continue to pursue opportunities to contract additional natural gas to supply our plants in New Zealand.

United States

We have two plants in Geismar, Louisiana with a total production capacity of 2.0 million tonnes. The Geismar facilities commenced first methanol production in 2015.

We have a long-term fixed price agreement for the supply of substantially all of the natural gas requirements for the Geismar 1 facility that expires in 2025.

During 2015, we entered into forward contracts to hedge natural gas prices for the Geismar 2 facility through 2025. We have hedged approximately 40% of the natural gas requirements with the remainder of natural gas requirements at Geismar purchased in the spot market.

Trinidad

Natural gas for our two methanol production facilities in Trinidad, with our share of total production capacity being 2.0 million tonnes per year, is supplied under take-or-pay contracts with the National Gas Company of Trinidad and Tobago Limited (“NGC”), which purchases the natural gas from upstream gas producers. Gas paid for, but not taken, in any year may be received in subsequent years subject to limitations. The contracts for Titan and Atlas have U.S. dollar base and variable price components, where the variable portion is adjusted by a formula related to methanol prices above a certain level. The contract for Atlas expires in 2024 and the contract for Titan expires in 2019.

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Since 2011, large industrial consumers in Trinidad, including our Titan and Atlas facilities, have experienced curtailments of natural gas supply due to a mismatch between upstream supply to NGC and downstream demand from NGC’s customers. Although Trinidad’s gas supply has stabilized in 2017 as a result of commissioning certain upstream facilities, we expect that gas curtailments to our facilities will continue in 2018.

Canada

We have entered into fixed price contracts to supply substantially all of our natural gas requirements for our Medicine Hat facility through 2031. In addition to existing hedges in place through 2022, we entered into a long-term, fixed price physical supply contract in 2017 with a progressively growing supply commitment starting in 2018 and growing to 80-90% of the plant’s natural gas requirements from 2023 through 2031.

Egypt

We have a 25-year, take-or-pay natural gas supply agreement expiring in 2036 for the 1.26 million tonne per year methanol plant in Egypt in which we have a 50% equity interest. The price paid for gas is based on a U.S. dollar base price plus a variable price component that is adjusted by a formula related to methanol prices above a certain level. Under the contract, the gas supplier is obligated to supply, and we are obliged to take or pay for, a specified annual quantity of natural gas. Gas paid for, but not taken, in any year may be received in subsequent years subject to limitations. In addition, the natural gas supply agreement has a mechanism whereby we are partially compensated when gas delivery shortfalls in excess of a certain threshold occur. Natural gas is supplied to this facility from the same gas delivery grid infrastructure that supplies other industrial users in Egypt, as well as the general Egyptian population (refer to the Foreign Operations and Government Regulation - Egypt section on page 17 for more information).

Chile

In June 2007, our natural gas suppliers from Argentina curtailed all gas supplied to our plants in Chile pursuant to long-term gas supply agreements. In 2018, we do not expect to receive any further natural gas supply from Argentina under such long-term gas supply agreements. In November 2016, we executed a tolling agreement with YPF S.A. pursuant to which we receive natural gas from Argentina and convert the natural gas received into methanol and then re-deliver the methanol to Argentina. In January 2018, we started receiving some natural gas from Argentina under this arrangement.

Since 2015, Empresa Nacional del Petróleo (“ENAP”) has made significant investments in the development of natural gas from unconventional reservoirs in Chile and this effort has resulted in increased gas deliveries from ENAP to our facilities. In January 2016, the U.S. Geological Survey assessed a technically recoverable mean resource of 8.3 trillion cubic feet of unconventional tight gas in the Chilean Magallanes Province. However, the potential for a sustained increase in gas deliveries to our plants will depend on the economics of the development of gas discoveries and, ultimately, the price at which we can obtain gas. In November 2017, Methanex reached a new agreement with ENAP for additional gas supply through December 31, 2019.

We are continuing to work with gas suppliers in Chile and Argentina to secure sufficient natural gas to sustain our Chile operations beyond December 2019 and into the future.

FOREIGN OPERATIONS AND GOVERNMENT REGULATION

General

We have substantial operations and investments outside of North America, and as such we are affected by foreign political developments and federal, provincial, state and other local laws and regulations. We are subject to risks inherent in foreign operations, including loss of revenue, property and equipment as a result of expropriation; import or export restrictions; anti-dumping measures; nationalization, war, civil unrest, insurrection, acts of terrorism and other political risks; increases in duties, taxes and governmental royalties; renegotiation of contracts with governmental entities; as well as changes in laws or policies or other actions by governments that may adversely affect our operations.

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We derive a substantial portion of our revenue from production and sales by subsidiaries outside of Canada, and the payment of dividends or the making of other cash payments or advances by these subsidiaries to us may be subject to restrictions or exchange controls on the transfer of funds in or out of the respective countries or result in the imposition of taxes on such payments or advances. We have organized our foreign operations in part based on certain assumptions about various tax laws (including capital gains and withholding taxes), foreign currency exchange and capital repatriation laws and other relevant laws of a variety of foreign jurisdictions. While we believe that such assumptions are reasonable, we cannot provide assurance that foreign taxation or other authorities will reach the same conclusion. Further, if such foreign jurisdictions were to change or modify such laws, we could suffer adverse tax and financial consequences.

The dominant currency in which we conduct business is the United States dollar, which is also our reporting currency. The most significant components of our costs are natural gas feedstock and ocean-shipping costs and substantially all of these costs are incurred in United States dollars. Some of our underlying operating costs, capital expenditures and purchases of methanol, however, are incurred in currencies other than the United States dollar, principally the Canadian dollar, the Chilean peso, the Trinidad and Tobago dollar, the New Zealand dollar, the Euro, the Egyptian pound and the Chinese yuan. We are exposed to increases in the value of these currencies that could have the effect of increasing the United States dollar equivalent of cost of sales, operating expenses and capital expenditures. A portion of our revenue is earned in Euros, Canadian dollars and Chinese yuan. We are exposed to declines in the value of these currencies compared to the United States dollar, which could have the effect of decreasing the United States dollar equivalent of our revenue.

Trade in methanol is subject to duty in a number of jurisdictions. Methanol sold in China from any of our producing regions is currently subject to duties ranging from 0% to 5.5%. There can be no assurance that the duties will not increase, that duties will not be levied in other jurisdictions in the future or that we will be able to mitigate the impact of future duties, if levied, or that future duties will not have a significant negative effect.

Chile

Our wholly owned subsidiary, Methanex Chile SpA (“Methanex Chile”), owns two methanol plants on our Chilean production site. Chilean foreign investment regulations provide certain benefits and guarantees to companies that enter into a foreign investment contract (“DL 600 Contract”) with Chile. Methanex Chile has entered into DL 600 Contracts, substantially identical in all matters material for Methanex Chile, for both plants. Under the DL 600 Contracts, Methanex Chile is authorized to remit from Chile, in United States dollars or any other freely convertible currency, all or part of its profits and, after one year, its equity. The DL 600 Contracts provide that they cannot be amended or terminated except by written agreement.

Egypt

Since the plant commenced operations in 2011, Egypt has experienced significant social unrest, including acts of sabotage and government transitions resulting in an adverse impact on the country’s economy and our operations in Egypt. We believe that these factors have contributed to constraints in the development of new supplies of natural gas coming to market and to natural gas supply becoming constrained between mid-2012 and late-2016, resulting in our Egypt plant operating below full capacity.

Since late-2016, gas deliveries have improved significantly and we have received 100% of contracted gas supply. This is largely a result of the Egyptian government’s significant efforts to improve the gas supply situation in the country by encouraging natural gas exploration and establishing LNG import infrastructure. These efforts coupled with continuing natural gas discoveries have further strengthened the natural gas supply and demand balance and outlook for gas deliveries in Egypt.

RESPONSIBLE CARE

As a member of the Chemistry Industry Association of Canada (“CIAC”), the American Chemistry Council (“ACC”), Asociación Gremial de Industriales Quimicos de Chile, Responsible Care New Zealand, European Chemical Industry Council, Association of International Chemical Manufacturers (China), Japan Chemical Industry Association and Gulf Petrochemicals and Chemicals Association, we are committed to the ethics and principles of Responsible Care.

Responsible Care is the umbrella under which we manage our business in relation to health, safety, the environment, community involvement, social responsibility, sustainability, security and emergency preparedness at each of our facilities and locations.

Accordingly, we have established policies, systems and procedures to promote and encourage the responsible development, introduction, manufacture, transportation, storage, handling, distribution and use of methanol and ultimate disposal of hazardous waste and residual chemical products so as to do no harm to human health and well-being, the environment and the communities in which we operate while striving to improve the environment and people’s lives.

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Methanex’s Responsible Care/Social Responsibility (“RC/SR”) related policies and programs are based on Chemical Industry Association of Canada’s RC Ethic and Principles for Sustainability and the CIAC RC Codes of Practice. Some of the countries where we operate have different standards than those applied in North America. Our policy is to adopt the more stringent of either Responsible Care practices or local regulatory or association requirements at each of our facilities.

Sound corporate governance is the foundation of our long-term success and the sustainability of our operations. Our corporate governance policies ensure that we have strong management and clear direction for all of Methanex’s business affairs. The application of Responsible Care begins with our Board of Directors, which has appointed a Responsible Care Committee and Public Policy Committee, and extends throughout our organization.

The Company’s Board of Directors and senior management team establish the direction for Methanex’s RC/SR practices. The Board’s Responsible Care Committee provides oversight of the RC program performance and related matters at the policy level, while the Public Policy Committee provides focus on the SR program. The two committees consider ethics, accountability, governance, business relationships, products and services, community involvement and the protection of people and the environment. The senior management team has overall responsibility for Methanex’s RC/SR policies and programs, ensuring that they align with the Board’s requirements and the Company’s business strategy. These programs are directed and managed by the Vice President, Responsible Care and the Vice President, Global Market Development & Stakeholder Relations, who lead Methanex’s Global Responsible Care Team and Global Market Development & Stakeholder Relations Team, respectively.

Methanex evaluates the performance of its RC/SR management system through internal and third-party external audit and assessment programs. The internal program includes ongoing in-region self-audits as well as global audits conducted by Methanex subject matter experts. Third-party verification of the performance of Methanex’s RC/SR program occurs through the CIAC RC verification process or the ACC RC 14001 certification process. The most recent CIAC RC verification was successfully completed in 2014. A first-time CIAC verification took place at our Egypt facilities in February 2015. Our Trinidad facility successfully completed ACC RC 14001 recertification in 2016. The next CIAC RC verification will occur in the first half of 2018.

Our overarching RC Ethic & Principles for Sustainability Purpose and Values statement sets out the Company’s commitment to RC and describes all key elements of the RC program. We also have an established Health, Safety, Security, Environment, Quality Policy that includes the requirement that we operate our facilities in a manner that protects the safety and health of all employees, contractors, customers and the general public. It requires that we have systems in place to monitor and comply with all local safety, health and environmental regulations as well as internal standards, periodically audit performance and compliance, measure performance against key performance indicators, report incidents with the potential to cause harm to people or the environment and demonstrate continual improvement.

We have also adopted a number of risk assessment tools that are formally applied as part of our normal business processes to identify and mitigate current and future environmental and process safety-related risks. When incidents do occur, we have a formal incident investigation process to allow for effective mitigation as well as application of lessons learned throughout our organization.

As a natural extension of our RC ethic, we have a Manage Reputation Purpose and Values statement that aligns our corporate governance, employee engagement and development, community involvement and social investment strategies with our core values and corporate strategy. Specifically, our Manage Reputation Policy commits the Company to recognize and respond to community concerns about the manufacture, storage, handling, transportation and disposal of our products and promptly provide information concerning any potential health or environmental hazard to the appropriate authorities, employees and all stakeholders. The Policy further commits the Company to have an open, honest and proactive relationship with the communities where we have a significant presence; to be accountable and responsive to the public; to have effective processes to identify and respond to community concerns; and to inform the community of risks associated with our operations.

We believe that Responsible Care helps us achieve safe and reliable operations, which in turn results in strong financial performance, effective and innovative minimization of environmental impacts and improved quality of life.

ENVIRONMENTAL MATTERS

The countries in which we operate all have laws and regulations to which we are subject, governing the environment and the management of natural resources as well as the handling, storage, transportation and disposal of hazardous or waste materials. We are also subject to laws and regulations governing emissions and the import, export, use, discharge, storage, disposal and transportation of toxic substances. The products we use and produce are subject to regulation under various health, safety and environmental laws. Non-compliance with these laws and regulations may give rise to compliance orders, fines, injunctions, civil liability and criminal sanctions.

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Laws and regulations protecting the environment have become more stringent in recent years and may, in certain circumstances, impose absolute liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may also expose us to liability for the conduct of, or conditions caused by others or for our own acts even if we complied with applicable laws at the time such acts were performed. To date, environmental laws and regulations have not had a significant adverse effect on our capital expenditures, earnings or competitive position. However, operating petrochemical manufacturing plants and distributing methanol exposes us to risks in connection with compliance with such laws and we cannot provide assurance that we will not incur significant costs or liabilities in the future.

Management of Emissions

Carbon dioxide (“CO₂”) is a by-product of the methanol production process. The amount of CO₂ generated by the methanol production process depends on the production technology, plant age, feedstock and any export of the by-product hydrogen. CO₂ emissions are also generated from our marine operations when fuel is consumed during the global transport of methanol. We monitor and manage our CO₂ emissions intensity, defined as the quantity of CO₂ released per unit of production or transported tonne, relating to both methanol production and marine operations. Our CO₂ emissions intensity has decreased over time due to newer technology and higher efficiency at our plants and in our vessel fleet. Plant efficiency, and thus CO₂ emissions, is highly dependent on the design of the methanol plant, and accordingly the CO₂ emission figure may vary from year to year depending on the mix of production assets and vessels in operation.

Under the United Nations Framework Convention on Climate Change through the Kyoto Protocol and more recently the Paris Agreement (in effect from 2020), many of the countries we operate in have agreed to put forth efforts to reduce GHG emissions.

We are currently subject to GHG regulations in New Zealand, Canada and Chile, but our production in the United States, Trinidad and Egypt are not subject to such regulations.

In New Zealand, an Emissions Trading Scheme (“ETS”) imposes a carbon price on producers of fossil fuels, including natural gas, which is passed on to Methanex, increasing the cost of gas that Methanex purchases in New Zealand. However, as a trade-exposed company, Methanex is entitled to a free allocation of emissions units to partially offset those increased costs.

Recent reviews of the ETS and a newly elected government led by the Labour Party in New Zealand may make changes to climate change policies that might impact the price of carbon in New Zealand or industry entitlements to free allocations. In December 2017, the newly appointed Minister for Climate Change announced plans to introduce a Zero Carbon Act by October 2018, following public consultation during 2018. At this stage there is no meaningful detail as to the content of the proposed Act.

We do not expect the changes that have been implemented to date to have a material impact on our New Zealand business. Methanex has no information to believe that the new government will implement rapid or drastic revisions to current policy settings that would adversely affect our operations in New Zealand. Nevertheless, we cannot provide assurance that unanticipated changes to the ETS will not have a material impact on our business beyond 2018.

Our Medicine Hat facility is located in the Canadian province of Alberta, which has an established GHG reduction regulation that applies to our plant. In 2017, the emissions reduction target was increased from 15% to 20%. To the extent Methanex cannot meet these emissions reduction targets we will incur additional cost to purchase offset credits. The cost of purchasing offset credits, based on the plant’s 2017 emissions intensity and its established GHG baseline intensity, was not material in 2017.

Starting in 2018, a new regulation in Alberta, the Carbon Competitiveness Incentive Regulation, (“CCIR”) will come into effect and will impact our compliance obligations. The CCIR sets a benchmark of 80% of baseline emissions. The total regulated emissions calculation incorporates indirect emissions (e.g., electricity consumption), but also provides a deduction to our facility emissions calculation recognizing the benefit of the injection of CO₂. Although certain regulations under the CCIR are still being drafted, we do not believe that the cost of compliance will be material. Nevertheless, we cannot provide assurance that unanticipated changes to the CCIR will not have a material impact on our business beyond 2018.

Chile has imposed a carbon tax of $5/tonne from 2017 on certain CO₂ emissions. The cost to our business of this tax was not material in 2017. However, the cost could increase if the scope of the legislation changes.

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INSURANCE

The majority of our revenues are derived from the sale of methanol produced at our plants. Our business is subject to the normal hazards of methanol production operations that could result in damage to our plants. Under certain conditions, prolonged shutdowns of plants due to unforeseen equipment breakdowns, interruptions in the supply of natural gas or oxygen, power failures, loss of port facilities or any other event, including any event of force majeure, could adversely affect our revenues and operating income. We maintain operational and construction insurance, including business interruption insurance, subject to certain deductibles, that we consider to be adequate under the circumstances. However, there can be no assurance that we will not incur losses beyond the limits or outside the coverage of such insurance. From time to time, various types of insurance for companies in the chemical and petrochemical industries have not been available on commercially acceptable terms or, in some cases, have been unavailable. There can be no assurance that in the future we will be able to maintain existing coverage, or that premiums will not increase substantially.

COMPETITION

Methanex is the largest producer and supplier of methanol, with approximately 14% of the global market demand in 2017, and is the only global supplier with a significant presence in all major markets in Asia, Europe, North America and South America. Methanex has established itself as a clear methanol industry leader. From a demand perspective, the methanol industry is highly competitive. Methanol is a global commodity and customers base their purchasing decisions primarily on the delivered price of methanol and reliability of supply. A supplier’s ability to withstand price competition and volatile market conditions will depend on a number of factors, with the most important being its position on the industry cost curve. This in turn depends on the relative cost and availability of natural gas or coal feedstock, and the efficiency of production facilities and distribution systems. Our methanol assets are competitively positioned on the industry cost curve. Furthermore, more than half of our natural gas supply is underpinned by medium to long-term contracts that feature a fixed base price of gas and a variable component that is linked to the price of methanol. This contractual structure allows Methanex to reduce its cost structure in periods of low methanol pricing, mitigating its exposure to fluctuations in methanol price. Some of our competitors are not dependent on a single product for revenues, and some have greater financial resources. However, given our ability to service our customers globally, the reliability and cost-effectiveness of our distribution system and the enhanced service we provide customers, we believe we are well positioned to compete in each of the major international methanol markets.

EMPLOYEES

As at December 31, 2017, we had 1,357 employees (including all employees at our joint venture facilities in Egypt and Trinidad).

RISK FACTORS

The risks relating to our business are described under the heading Risk Factors and Risk Management in our 2017 MD&A, and are incorporated in this document by reference. Any of those risks, as well as risks and uncertainties currently not known to us, could adversely affect our business, financial condition, results of operations or the market price of our securities.

DIVIDENDS

Dividends are payable to the holders of common shares of the Company (“Common Shares”) if, as and when declared by our Board of Directors and in such amounts as the Board of Directors may, from time to time, determine. The Company’s current dividend policy is designed so that the Company maintains conservative financial management appropriate to the historically cyclical nature of the methanol industry to preserve financial flexibility and creditworthiness.

We pay a quarterly dividend on the Common Shares. The first quarterly dividend of $0.05 per Common Share was paid on September 30, 2002 and the dividend amount has been increased every year since then with the exception of 2009, 2010 and 2016 when the dividend was unchanged. The table below shows the amount and percentage increases to the dividend since its inception in 2002:

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Date	Quarterly Dividend Amount	% Increase
September 30, 2002	$0.050	n/a
September 30, 2003	$0.060	20%
September 30, 2004	$0.080	33%
June 30, 2005	$0.110	37.5%
June 30, 2006	$0.125	14%
June 30, 2007	$0.140	12%
June 30, 2008	$0.155	11%
June 30, 2009	$0.155	0%
June 30, 2010	$0.155	0%
June 30, 2011	$0.170	10%
June 30, 2012	$0.185	9%
June 30, 2013	$0.200	8%
June 30, 2014	$0.250	25%
June 30, 2015	$0.275	10%
June 30, 2016	$0.275	0%
June 30, 2017	$0.300	9%
March 31, 2018(1)	$0.330	10%

(1)     On February 1, 2018, the Board of Directors declared a dividend payable on March 31, 2018.

The following table sets out the total amount of regular dividends per Common Share paid on the Common Shares in each of the last three most recently completed financial years:

Financial Year Ended	Regular Dividend   Paid per Common Share
December 31, 2015	$1.075
December 31, 2016	$1.100
December 31, 2017	$1.175

CAPITAL STRUCTURE

We are authorized to issue an unlimited number of Common Shares without nominal or par value and 25,000,000 preferred shares without nominal or par value (“Preferred Shares”).

Holders of Common Shares are entitled to receive notice of and attend all annual and special meetings of shareholders and to one vote in respect of each Common Share held; receive dividends if, as and when declared by our Board of Directors; and participate in any distribution of the assets of the Company in the event of liquidation, dissolution or winding up.

Preferred Shares may be issued in one or more series and the Board of Directors may fix the designation, rights, restrictions, conditions and limitations attached to the Preferred Shares of each such series. Currently, there are no Preferred Shares outstanding.

Our by-laws provide that at any meeting of our shareholders a quorum shall be two persons present in person, or represented by proxy, holding Common Shares representing not less than 25% of the votes entitled to be cast at the meeting. NASDAQ Global Select Market’s listing standards require a quorum for shareholder meetings to be not less than 33-1/3% of a company’s outstanding voting shares. As a foreign private issuer and because our quorum requirements are consistent with practices in Canada, we are exempt from the quorum requirement under the NASDAQ Global Select Market rules.

RATINGS

The following information relating to the Company’s credit ratings is provided as it relates to the Company’s financing costs, liquidity and operations. Credit ratings affect the Company’s cost and ability to obtain short-term and long-term financing and to engage in certain business activities on a cost-effective basis. A reduction in the current rating on the Company by a rating agency, or a negative change in the Company’s ratings outlook, could adversely affect the Company’s cost of financing and its access to sources of liquidity and capital. In addition, changes in credit ratings may affect the Company’s ability to, and the associated costs of (i) entering into ordinary course derivative or hedging transactions, and (ii) entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.

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The following table sets forth the ratings assigned to the Company by Standard & Poor’s Financial Services LLC (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings, Inc. (“Fitch”).

	S&P  (1)	Moody’s (2)	Fitch  (3)
Issuer Credit Rating	BB+	n/a(2)	BBB-
Unsecured Notes	BB+	Baa3	BBB-
Ratings Outlook	Stable	Stable	Stable

(1) S&P long-term debt ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality. According to the S&P rating system, issuers and debt securities rated BBB exhibit adequate protection parameters, however adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. According to the S&P rating system, issuers and debt securities rated BB are less vulnerable in the near term than other lower-rated obligors, however, face major ongoing uncertainties and exposure to adverse business, financial, or economic conditions, which could lead to the obligor’s inadequate capacity to meet its financial commitments and debt securities. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

(2) Moody’s rates the Company’s debt securities and does not provide an Issuer Credit Rating. Moody’s long-term debt ratings are on a rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality. According to the Moody’s rating system, issuers and debt securities rated Baa are subject to moderate risk. They are considered as medium-grade obligations and, as such, may possess certain speculative characteristics. Moody’s applies numerical modifiers 1, 2 and 3 in each generic rating classification from Aa through Caa in its corporate bond rating system. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of its generic rating category.

(3) Fitch long-term debt ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality. According to the Fitch rating system, issuers and debt securities rated BBB indicate that expectations of default risk are currently low and that the capacity for payment of financial commitments is considered adequate but adverse business or economic conditions are more likely to impair this capacity. The ratings from AA to B may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

The rating agencies regularly evaluate the Company, and their ratings of the Company are based on a number of factors, including the Company’s financial strength and factors not entirely within the Company’s control, including conditions affecting the methanol industry generally and the wider state of the economy.

The foregoing ratings should not be construed as a recommendation to buy, sell or hold any securities, as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant. If any such rating is so revised or withdrawn, we are under no obligation to update this AIF.

During the last two years, the Company has paid each of the rating agencies its customary fees in connection with the provision of the above ratings.

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MARKET FOR SECURITIES

Our Common Shares are listed on the Toronto Stock Exchange in Canada (trading symbol: MX) and on the NASDAQ Global Select Market in the U.S. (trading symbol: MEOH). The following table sets out the market price ranges and trading volumes of our Common Shares on the Toronto Stock Exchange as well as on other Canadian and US equity marketplaces, including exchanges and alternative trading systems, for each month of our most recently completed financial year (January 1, 2017 through December 31, 2017).

2017 Trading Volumes 1
Trading Symbol: MX					Trading Symbol:   MEOH	Total Volume
The Toronto Stock Exchange				Other Canadian   Trading	NASDAQ Global Select   Market and Other US   Trading
Month	High   (CDN$)	Low   (CDN$)	Volume	Volume	Volume
January	67.57	58.60	8,403,812	4,267,444	15,242,318	27,913,574
February	69.88	63.14	5,920,100	3,084,003	15,776,631	24,780,734
March	69.79	56.95	7,384,311	3,984,457	21,328,962	32,697,730
April	65.45	59.02	5,595,503	3,108,441	16,409,966	25,113,910
May	63.18	55.20	6,302,118	3,479,570	21,108,624	30,890,312
June	58.35	52.63	5,951,653	3,515,173	17,750,119	27,216,945
July	59.82	54.40	5,442,212	3,287,267	17,542,485	26,271,994
August	64.09	54.17	7,340,855	3,400,270	13,153,284	23,894,409
September	65.46	60.20	8,827,699	3,302,137	17,081,574	29,211,410
October	65.99	61.30	9,385,121	3,730,616	16,679,213	29,794,950
November	69.15	62.30	6,433,690	2,871,946	10,326,694	19,632,330
December	77.31	67.20	5,688,207	3,122,815	11,279,968	20,090,990

(1) Source: Bloomberg

NORMAL COURSE ISSUER BID

On March 6, 2017, the Company announced a normal course issuer bid (the “2017 Bid”) authorizing the Company to purchase up to 4,492,141 Common Shares, representing approximately 5% of the issued and outstanding Common Shares as at March 6, 2017. The 2017 Bid commenced on March 13, 2017, with purchases being made on the open market through the facilities of the NASDAQ Global Select Market.

On July 26, 2017, the Company announced an amendment to the 2017 Bid which increased the number of Common Shares that may be purchased from 4,492,141 to 6,152,358, representing 10% of the public float as at March 6, 2017. The amended 2017 Bid commenced on August 1, 2017, with purchases being made on the open market through the facilities of the TSX. The Company completed the 2017 Bid in October 2017 when 6,152,358 Common Shares had been purchased.

On March 5, 2018, the Company announced a normal course issuer bid (the “2018 Bid”) authorizing the Company to purchase up to 6,590,095 Common Shares, representing 10% of the public float as of March 5, 2018. The 2018 Bid will commence on March 13, 2018 with purchases being made on the open market through the facilities of the TSX, the NASDAQ Global Select Market and alternative trading systems in the United States.

DIRECTORS AND EXECUTIVE OFFICERS

As at December 31, 2017, the directors and executive officers of the Company owned, controlled or directed, directly or indirectly, 459,065 Common Shares, representing approximately 0.55% of the outstanding Common Shares as at December 31, 2017.

The following tables set forth the names and places of residence of the current directors and executive officers of the Company, the offices held by them in the Company, their current principal occupations, their principal occupations during the last five years and, in the case of the directors, the month and year in which they became directors:

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Name and Municipality of Residence	Office	Principal Occupations and Positions During the Last Five Years	Director Since(12)
AITKEN, BRUCE(4)(5) Auckland New Zealand	Director	Corporate Director. President and Chief Executive Officer of the Company from May 2004 to December 31, 2012.	July 2004
ARNELL, DOUGLAS(2)(3)(4) West Vancouver British Columbia, Canada	Director	President and Chief Executive Officer of Helm Energy Advisors Inc.(6) since March 2015; prior thereto Chief Executive Officer of Golar LNG Ltd. since February 2011.	October 2016
BALLOCH, HOWARD(1)(4)(13)     Sheung Wan Hong Kong	Director	Corporate Director. Chairman of Canaccord Genuity Asia Limited(7) from January 2011 to March 2013.	December 2004
COOK, PHILLIP(2)(3) Austin, Texas USA	Director	Corporate Director.	May 2006
FLOREN, JOHN Eastham, Massachusetts USA	Director, President   and Chief Executive Officer	President and Chief Executive Officer of the Company since January 1, 2013.	January 2013
HAMILTON, THOMAS(14) Houston, Texas USA	Director and Chairman of the Board	Corporate Director. Co-owner of Medora Investments, LLC(8) since April 2003.	May 2007
KOSTELNIK, ROBERT(2)(5) Fulshear, Texas USA	Director	Corporate Director. Since February 2012, principal in GlenRock Recovery Partners, LLC(9).	September 2008
MAHAFFY, DOUGLAS(2)(3) Toronto, Ontario Canada	Director	Corporate Director.	May 2006
POOLE, A. TERENCE(1)(4)(15) Calgary, Alberta Canada	Director	Corporate Director.	February 1994 except for June – September 2003
RENNIE, JANICE(1)(3) Edmonton, Alberta Canada	Director	Corporate Director.	May 2006
WALKER, MARGARET(3)(5) Austin, Texas USA	Director	Corporate Director. Since January 2011, owner of MLRW Group, LLC(10).	April 2015
WARMBOLD, BENITA(1)(5) Toronto, Ontario Canada	Director	Corporate Director. Senior Managing Director and Chief Financial Officer of the Canada Pension Plan Investment Board from 2013 to 2017; prior thereto Senior Vice President and Chief Operations Officer of the Canada Pension Plan Investment Board(11) since 2008.	February 2016

(1) Member of the Audit, Finance and Risk Committee.

(2) Member of the Corporate Governance Committee.

(3) Member of the Human Resources Committee.

(4) Member of the Public Policy Committee.

(5) Member of the Responsible Care Committee.

(6) Helm Energy Advisors, Inc. is a private company which provides advisory services to the global energy sector.

(7) Canaccord Genuity Asia Limited is an investment banking firm specializing in China and international firms active in the Chinese market.

(8) Medora Investments, LLC is a private investment firm.

(9) GlenRock Recovery Partners, LLC is a company that facilitates the sale of non-fungible hydrocarbons in the United States.

(10) MLRW Group Inc. is a consulting firm focusing on working with companies to improve capital investment outcomes and to improve overall safety performance.

(11) Canada Pension Plan Investment Board is a professional investment management organization responsible for investing funds on behalf of the Canada Pension Plan.

(12) The directors of the Company are elected each year at the Annual General Meeting of the Company and hold office until the close of the next Annual General Meeting or until their successors are elected or appointed.

(13) Mr. Balloch was a director of Ivanhoe Energy Inc. (“Ivanhoe”), an oil exploration and development company, from 2002 to May 2015. Effective June 1, 2015, Ivanhoe was deemed bankrupt under the Bankruptcy and Insolvency Act (Canada).

(14) Mr. Hamilton was a director of Hercules Offshore Inc. (“Hercules”), a drilling company, from 2004 to 2015. In August 2015, Hercules filed a pre-packaged plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. In November 2015, Hercules completed its financial restructuring and emerged from the protection of Chapter 11 of the U.S. Bankruptcy Code.

(15) Mr. Poole is not standing for re-election at the 2018 Annual General Meeting of the Company.

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Name and Municipality of Residence	Office	Principal Occupations and Positions During the Last Five Years
BOYD, BRADLEY W. North Vancouver, British Columbia Canada	Senior Vice President, Corporate Resources	Senior Vice President, Corporate Resources of the Company since January 2018; prior thereto Vice President, Human Resources of the Company since May 2016; prior thereto Managing Director, Egypt of the Company since April 2015; prior thereto Vice President, Finance and Business Integration, Egypt of the Company since August 2012.
CAMERON, IAN P. Vancouver, British Columbia Canada	Senior Vice President, Finance and Chief Financial   Officer	Senior Vice President, Finance and Chief Financial Officer of the Company since 2003.
HENDERSON, KEVIN L. Medicine Hat, Alberta Canada	Senior Vice President, Manufacturing	Senior Vice President, Manufacturing of the Company since May 2016; prior thereto Vice President, North America of the Company since January 2014; prior thereto Vice President, Manufacturing since January 2012.
HERZ, MICHAEL J. North Vancouver, British Columbia Canada	Senior Vice President, Corporate Development	Senior Vice President, Corporate Development of the Company since January 2013.
JAMES, VANESSA L. North Vancouver, British Columbia   Canada	Senior Vice President, Global Marketing and Logistics	Senior Vice President, Global Marketing and Logistics of the Company since January 2013.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Since the start of our most recently completed financial year, and for the three most recently completed financial years, no director or executive officer of the Company, and no person or company that beneficially owns, controls or directs, directly or indirectly, more than 10% of the Company’s voting securities, or any associate or affiliate of such persons, has had any material interest in any transaction involving the Company.

EXPERTS

KPMG LLP are the auditors of the Company and have confirmed that they are independent with respect to the Company within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulation and that they are independent accountants with respect to the Company under all relevant U.S. professional and regulatory standards.

LEGAL PROCEEDINGS

The Board of Inland Revenue of Trinidad and Tobago has issued assessments against our 63.1% owned joint venture, Atlas, in respect of the 2005 to 2011 financial years. All subsequent tax years remain open to assessment. The assessments relate to the pricing arrangements of certain long-term fixed-price sales contracts from 2005 to 2019 related to methanol produced by Atlas. Atlas had partial relief from corporation income tax until 2014.

We have lodged objections to the assessments. Although there can be no assurance that these tax assessments will not have a material adverse impact, based on the merits of the cases and legal interpretation, we believe our position should be sustained.

AUDIT COMMITTEE INFORMATION

The Audit Committee Charter

The Audit, Finance and Risk Committee (the “Audit Committee”) is appointed by the Board to assist the Board in fulfilling its oversight responsibility relating to: the integrity of the Company’s financial statements; the financial reporting process; the systems of internal accounting and financial controls; the professional qualifications and independence of the external auditors; the performance of the external auditors; risk management processes; financing plans; pension plans; and compliance by the Company with ethics policies and legal and regulatory requirements.

The Audit Committee’s mandate sets out its responsibilities and duties. A copy of the Committee’s mandate is attached here as Appendix “A”.

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Composition of the Audit Committee

The Audit Committee is comprised of four directors: A. Terence Poole (Chair), Howard Balloch, Janice Rennie and Benita Warmbold. Each Audit Committee member is independent and financially literate. Mr. Poole is currently designated as the “audit committee financial expert”. The U.S. Securities and Exchange Commission has indicated that the designation of a director as an audit committee financial expert does not make such director an “expert” for any other purpose, impose any duties, obligations or liability on such director that are greater than those imposed on members of the Audit Committee and Board who do not carry this designation or affect the duties, obligations or liability of any other member of the Audit Committee.

Relevant Education and Experience

The following is a brief summary of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee, including any education or experience that has provided the member with an understanding of the accounting principles we use to prepare our annual and interim financial statements.

Mr. A. Terence Poole

Mr. Poole is a corporate director. Prior to his retirement in June 2006, he was Executive Vice President, Corporate Strategy and Development of NOVA Chemicals Corporation (“NOVA”), a commodity chemical company with international operations. Prior to that position, Mr. Poole was the Executive Vice President, Finance and Strategy of NOVA from 1998 to 2000; Senior Vice President and Chief Financial Officer of NOVA from 1994 to 1998; and held other senior financial positions with NOVA from 1988. He has worked at other large public companies in various financial and business management capacities since 1971.

Mr. Poole is a Chartered Professional Accountant and holds a Bachelor of Commerce degree from Dalhousie University in Halifax, Nova Scotia. Mr. Poole is a member of the Canadian, Quebec and Ontario Institutes of Chartered Professional Accountants and is also a member of Financial Executives International.

Mr. Poole serves on the board of Pengrowth Energy Corporation and chairs its Audit Committee.

Mr. Poole has served on the Audit Committee since September 2003, as well as from February 1994 to June 2003. Mr. Poole has chaired the Committee since May 2006.

Mr. Poole is not standing for re-election at the 2018 Annual General Meeting of the Company.

Mr. Howard Balloch

Mr. Balloch is a corporate director and private investor resident in Hong Kong, China. From 2002 to 2011, he was President of The Balloch Group (“TBG”), a Beijing-based investment advisory and merchant banking firm he founded following his retirement as Canadian Ambassador to China, a position he had held since early 1996. TBG was acquired by Canaccord Genuity in 2011 and Mr. Balloch served as the Chairman of their Asian operations until he stepped down in March 2013.

Through Mr. Balloch’s 12 years’ experience leading private investment banking firms, he has a deep understanding of finance and capital markets.

Mr. Balloch holds a Bachelor of Arts (Honours) in Political Science and Economics and a master’s degree in International Relations, both from McGill University, Montreal.

Mr. Balloch also serves on the board of a private company, Sinopec Canada Inc. and sits on its Audit Committee.

Mr. Balloch has served on the Audit Committee since January 2013.

Ms. Janice Rennie

Ms. Rennie is a corporate director. From 2004 to 2005, Ms. Rennie was Senior Vice President, Human Resources and Organizational Effectiveness for EPCOR Utilities Inc. (“EPCOR”). At that time, EPCOR built, owned and operated power plants, electrical transmission and distribution networks, water and wastewater treatment facilities and infrastructure in Canada and the United States. Prior to 2004, Ms. Rennie held senior management positions in a number of private firms, including Principal of Rennie & Associates, which provided investment and related advice to small and mid-sized companies.

Ms. Rennie holds a Bachelor of Commerce degree from the University of Alberta and is a Fellow of the Institute of Chartered Accountants of Alberta and the Institute of Corporate Directors.

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Ms. Rennie serves on the boards of Major Drilling Group International Inc., WestJet Airlines Ltd. and West Fraser Timber Co. Ltd and is a member of all their Audit Committees, as well as Chair of the Audit Committee of both Major Drilling Group International Inc. and West Fraser Timber Co. Ltd. In addition, Ms. Rennie serves on the board and chairs the Audit Committee of Greystone Capital Management Inc., a private company, and was previously a member of the Audit Committee of Teck Resources Limited. Ms. Rennie was designated as the “financial expert” of NOVA Chemicals Corporation when she served on its Board in the past.

Ms. Rennie has served on the Audit Committee since May 2006.

Ms. Benita Warmbold

From 2013 until her retirement in 2017, Ms. Warmbold was the Senior Managing Director and Chief Financial Officer of the Canada Pension Plan Investment Board (“CPPIB”). Prior to 2013, Ms. Warmbold was Senior Vice President and Chief Operations Officer of the CPPIB. CPPIB is a professional investment management organization responsible for investing funds on behalf of the Canada Pension Plan. Prior to joining CPPIB, Ms. Warmbold was the Managing Director and Chief Financial Officer for Northwater Capital Management Inc. and prior to that she held senior positions with Canada Development Investment Corporation and KPMG.

Ms. Warmbold holds an Honours Bachelor of Commerce degree from Queen’s University, is a Fellow of the Institute of Chartered Accountants of Ontario and has been granted the ICD.D designation by the Institute of Corporate Directors.

Ms. Warmbold serves on the board of SNC-Lavalin Group Inc. and the private company Crestone Peak Resources and is Chair of both their Audit Committees. She is also a director of the Canadian Public Accountability Board.

Ms. Warmbold has served on the Audit Committee since February 2016 and will become Chair of the Audit Committee commencing after Mr. Poole’s retirement at the 2018 Annual General Meeting of the Company.

Pre-Approval Policies and Procedures

The Audit Committee annually reviews and approves the terms and scope of the external auditors’ engagement. The Audit Committee oversees the Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions by which permissible services proposed to be performed by KPMG LLP are pre-approved. The Audit Committee has delegated to the Chair of the Audit Committee pre-approval authority for any services not previously approved by the Audit Committee. All such services approved by the Chair of the Audit Committee are subsequently reviewed by the Audit Committee.

All non-audit service engagements, regardless of the cost estimate, must be coordinated and approved by the Chief Financial Officer to further ensure that adherence to this policy is monitored.

Audit and Non-Audit Fees Billed by the Independent Auditors

KPMG LLP’s global fees relating to the years ended December 31, 2017 and December 31, 2016 are as follows:

US$000s	2017	2016
Audit Fees	1,459	1,307
Audit-Related Fees	80	50
Tax Fees	134	61
Total	1,673	1,418

Each fee category is described below.

Audit Fees

Audit fees for professional services rendered by the external auditors for the audit of the Company’s consolidated financial statements; statutory audits of the financial statements of the Company’s subsidiaries; quarterly reviews of the Company’s financial statements; consultations as to the accounting or disclosure treatment of transactions reflected in the financial statements; and services associated with registration statements, prospectuses, periodic reports and other documents filed with securities regulators.

Audit fees for professional services rendered by the external auditors for the audit of the Company’s consolidated financial statements were in respect of an “integrated audit” performed by KPMG LLP globally. The integrated audit encompasses an opinion on the fairness of presentation of the Company’s financial statements as well as an opinion on the effectiveness of the Company’s internal controls over financial reporting.

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Audit-Related Fees

Audit-related fees for professional services rendered by the auditors for financial audits of employee benefit plans; procedures and audit or attest services not required by statute or regulation; and consultations related to the accounting or disclosure treatment of other transactions.

Tax Fees

Tax fees for professional services rendered for tax compliance and tax advice. These services consisted of: tax compliance, including the review of tax returns; assistance in completing routine tax schedules and calculations; and advisory services relating to domestic and international taxation.

TRANSFER AGENT AND REGISTRAR

Our principal transfer agent for our Common Shares is AST Trust Company (Canada) at its offices in Vancouver, British Columbia. Our co-transfer agent in the United States for our Common Shares is American Stock Transfer & Trust Company LLC at its offices in New Jersey.

CONTROLS AND PROCEDURES

Our disclosure controls and procedures are described under the heading Controls and Procedures in our 2017 MD&A and are incorporated in this AIF by reference.

CODE OF ETHICS

We have a written code of ethics that applies to our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. A copy of our code, entitled “Code of Business Conduct”, can be found on our website at www.methanex.com or upon request from the Corporate Secretary at the address below under the heading Additional Information.

ADDITIONAL INFORMATION

Additional information relating to the Company, including directors’ and officers’ remuneration and indebtedness, principal holders of the Company’s securities and securities authorized for issuance under equity compensation plans, is contained in our Information Circular dated March 2, 2018 relating to our Annual General Meeting that will be held on April 26, 2018.

Additional financial information about the Company is provided in the Company’s financial statements for the year ended December 31, 2017 and in our 2017 MD&A.

Copies of the documents referred to above are available on the Canadian Securities Administrators’ SEDAR website at www.sedar.com and may also be obtained upon request from:

Methanex Corporation

Kevin Price

General Counsel and Corporate Secretary

1800 Waterfront Centre

200 Burrard Street

Vancouver, British Columbia V6C 3M1

Telephone: 604 661 2600

Facsimile: 604 661 2602

Additional information relating to the Company may be found on the Canadian Securities Administrators’ SEDAR website at www.sedar.com, on the United States Securities and Exchange Commission’s EDGAR website at www.sec.gov and on our website at www.methanex.com.

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APPENDIX “A”

METHANEX CORPORATION

AUDIT, FINANCE AND RISK COMMITTEE MANDATE

1.        Creation

A committee of the directors to be known as the “Audit, Finance and Risk Committee” (hereinafter referred to as the “Committee”) is hereby established.

2.        Purpose and Responsibility

The Committee is appointed by the Board to assist the Board in fulfilling its oversight responsibility relating to: the integrity of the Corporation’s financial statements; the financial reporting process; the systems of internal accounting and financial controls; the professional qualifications and independence of the external auditors; the performance of the external auditors; risk management processes; financing plans; pension plans; and compliance by the Corporation with ethics policies and legal and regulatory requirements.

The Committee’s role is one of oversight. It is the responsibility of the Corporation’s management to plan audits and to prepare consolidated financial statements in accordance with generally accepted accounting principles (“GAAP”), and it is the responsibility of the Corporation’s external auditor to audit these financial statements. Therefore, each member of the Committee, in exercising his or her business judgment, shall be entitled to rely on the integrity of those persons and organizations within and outside the Corporation from whom he or she receives information, and on the accuracy of the financial and other information provided to the Committee by such persons or organizations. The Committee does not provide any expert or other special assurances as to the Corporation’s financial statements or any expert or professional certification as to the work of the Corporation’s external auditor. In addition, all members of the Committee are equally responsible for discharging the responsibilities of the Committee and the designation of one member as an “audit committee financial expert” pursuant to the Applicable Rules (as defined below) is not a statement of intention by the Corporation to impose upon such designee duties, obligations or liability greater than those imposed on such a director in the absence of such designation.

3.        Committee Membership

Composition of the Committee	a)      The Committee must be composed of a minimum of three directors.
Appointment and Term of Members	b)      The members of the Committee must be appointed or reappointed at the organizational meeting of the Board concurrent with each Annual General Meeting of the shareholders of the Corporation. Each member of the Committee continues to be a Committee member until a successor is appointed, unless he or she resigns or is removed by the Board or ceases to be a director of the Corporation. Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board and shall be filled by the Board if the membership of the Committee is less than three directors as a result of the vacancy.
Financial Literacy and Independence	c)      Each member of the Committee shall meet the independence and experience requirements, and at least one member of the Committee shall qualify as an “audit committee financial expert.” These requirements shall be in accordance with the applicable rules and regulations (the “Applicable Rules”) of the Canadian Securities Administrators, the U.S. Securities and Exchange Commission, the Toronto Stock Exchange and the Nasdaq Stock Market.
Appointment of Chair and Secretary	d)      The Board or, if it does not do so, the members of the Committee, must appoint one of their members as Chair. If the Chair of the Committee is not present at any meeting of the Committee, the Chair of the meeting must be chosen by the Committee from the Committee members present. The Chair presiding at any meeting of the Committee has a deciding vote in case of deadlock. The Committee must also appoint a Secretary who need not be a director.

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Use of Outside Experts e)     Where Committee members believe that, to properly discharge their fiduciary obligations to the Corporation, it is necessary to obtain the advice of independent legal, accounting or other experts, the Chair shall, at the request of the Committee, engage the necessary experts at the Corporation’s expense. The Board must be kept apprised of both the selection of the experts and the experts’ findings through the Committee’s regular reports to the Board.

4.        Meetings

Time, Place and Procedure of Meetings	a)     The time and place of Committee meetings, and the procedures for the conduct of such meetings, shall be determined from time to time by Committee members, provided that:
Quorum	i)     a quorum for meetings must be two members, present in person or by telephone or other telecommunication device that permits all persons participating in the meeting to communicate with each other;
Quarterly Meetings	ii)     the Committee must meet at least quarterly;
Notice of Meetings	iii)     notice of the time and place of every meeting must be given in writing or by electronic transmission to each member of the Committee and the external auditors of the Corporation at least 24 hours prior to the Committee meeting;
Waiver of Notice	iv)     a member may waive notice of a meeting, and attendance at the meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called;
Attendance of External Auditors	v)     the external auditors are entitled to attend each meeting at the Corporation’s expense;
Meeting with Financial Management	vi)     the Committee will, at least annually, meet with senior financial management, including the Chief Financial Officer and the Corporate Controller, without other members of management present;
Meeting without Management	vii)     each regular meeting of the Committee will conclude with a session without any management personnel present;
Calling a Meeting	viii)     a meeting of the Committee may be called by the Secretary of the Committee on the direction of the Chair or Chief Executive Officer of the Corporation, by any member of the Committee or the external auditors; and
Committee Determines Attendees	ix)     notwithstanding the provisions of this paragraph, the Committee has the right to request any officer or employee of the Corporation or the Corporation’s outside counsel or external auditor to be present or not present at any part of the Committee meeting.
Reports to the Board	b)     The Committee shall make regular reports to the Board.

5.        Duties and Responsibilities of the Committee

1)        Financial Statements and Disclosure

Annual Report and Disclosures a)     Review and discuss with management and the external auditor, and recommend for approval by the Board, the Corporation’s annual report, Annual Information Form, audited Annual Consolidated Financial Statements, annual Management’s Discussion and Analysis, Management Information Circular, any reports on adequacy of internal controls, and all financial statements in prospectuses or other disclosure documents.

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Prospectuses	b)     Review and recommend for approval by the Board all prospectuses and documents that may be incorporated by reference into a prospectus, including without limitation, material change reports and proxy circulars.
Quarterly Interim Reports and Disclosures	c)     Review, discuss with management and the external auditor, and approve the Corporation’s interim reports, including the quarterly financial statements, interim Management’s Discussion and Analysis and press releases on quarterly and year-end financial results, prior to public release.
Accounting Policies and Estimates	d)     Review and approve all accounting policies and estimates that would have a significant effect on the Corporation’s financial statements, and any changes to such policies. This review will include a discussion with management and the external auditor concerning:
	i)     any areas of management judgment and estimates that may have a critical effect on the financial statements;
	ii)     the effect of using alternative accounting treatments that are acceptable under GAAP;
	iii)     the appropriateness, acceptability and quality of the Corporation’s accounting policies; and
	iv)     any material written communication between the external auditor and management, such as the annual management letter and the schedule of unadjusted differences.
Non-GAAP Financial Information	e)     Discuss with management the use of ‘‘pro forma’’ or ‘‘non-GAAP information’’ in the Corporation’s continuous disclosure documents.
Regulatory and Accounting Initiatives	f)     Discuss with management and the external auditor the effect of regulatory and accounting initiatives as well as the use of off-balance sheet structures on the Corporation’s financial statements.
Litigation	g)     Discuss with the Corporation’s General Counsel, and with external legal counsel if necessary, any litigation, claim or other contingency (including tax assessments) that could have a material effect on the financial position or operating results of the Corporation, and the manner in which these matters have been disclosed in the financial statements.
Financing Plans	h)     Review the financing plans and objectives of the Corporation, as received from and discussed with management.

2)        Risk Management and Internal Control

Risk Management Policies	a)     Review and recommend for approval by the Board changes considered advisable, after consultation with management, to the Corporation’s policies relating to:
	i)     the risks inherent in the Corporation’s businesses, facilities and strategic direction;
	ii)     financial risks, including foreign exchange, interest rate and investment of cash;
	iii)     overall risk management strategies and the financing of risks, including insurance coverage in the context of competitive and operational considerations;

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	iv)     the risk retention philosophy and the resulting uninsured exposure of the Corporation;
	v)     shipping risk; and
	vi)     IT security risks.
Risk Management Processes	b)     Review with management at least annually the Corporation’s processes to identify, monitor, evaluate and address important enterprise-wide strategic and business risks.
Adequacy of Internal Controls	c)     Review, at least quarterly, the results of management’s evaluation of the adequacy and effectiveness of internal controls within the Corporation in connection with the certifications signed by the CEO and CFO. Management’s evaluation will include a review of:
	i)     policies and procedures to ensure completeness and accuracy of information disclosed in the quarterly and annual reports, prevent earnings management and detect material financial statement misstatements due to fraud and error; and
	ii)     internal control recommendations of the external auditors and arising from the results of the internal audit procedures, including any special steps taken to address material control deficiencies and any fraud, whether or not material, that involves management or other employees who have a significant role in the Corporation’s internal controls.
Financial Risk Management	d)     Review with management activity related to managing financial risks to the Corporation, including hedging programs.

3)        External Auditors

Appointment and Remuneration	a)     Review and recommend to the Board:
	i)     the selection, evaluation, reappointment or, where appropriate, replacement of external auditors; and
	ii)     the nomination and remuneration of external auditors to be appointed at each Annual General Meeting of Shareholders.
Resolving Disagreements	b)     Resolve any disagreements between management and the external auditor regarding financial reporting.
Direct Reporting to Committee	c)     The external auditors shall report directly to the Committee and the Committee has the authority to communicate directly with the external auditors.
Quality Control and Independence	d)     Review a formal written statement requested at least annually from the external auditor describing:
	i)     the firm’s internal quality control procedures;
	ii)     any material issues raised by the most recent internal quality control review, peer review of the firm or any investigation by governmental or professional authorities within the preceding five years respecting one or more independent audits of the Corporation carried out by the firm;

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	iii)     any steps taken to deal with any such issues; and iv)     all relationships between the external auditors and the Corporation.
	The Committee will actively engage in a dialogue with the external auditor with respect to whether the firm’s quality controls are adequate, and whether any of the disclosed relationships or non-audit services may impact the objectivity and independence of the external auditor based on the independence requirements of the Applicable Rules. The Committee shall present its conclusion with respect to the independence of the external auditor to the Board.
External Audit Plan	e)     Review the external audit plan and enquire as to the extent the planned audit scope can be relied upon to detect weaknesses in internal control or fraud or other illegal acts. Any significant recommendations made by the auditors for strengthening internal controls will be reviewed.
Rotation of Senior Audit Partner	f)     Ensure the rotation of senior audit personnel who have primary responsibility for the audit work, as required by law.
Remuneration of External Auditors	g)     Review and approve (in advance) the scope and related fees for all auditing services and non-audit services permitted by regulation that are to be provided by the external auditor in accordance with the Corporation’s Audit and Non-Audit Services Pre-Approval Policy, which is to be annually reviewed and approved by the Committee.
Restrictions on Hiring Employees of External Auditor	h)     Ensure the establishment of policies relating to the Corporation’s hiring of employees of or former employees of the external auditor, if such individuals have participated in the audit of the Corporation, as required by law.
Report from the External Auditors	i)     Prior to filing the Quarterly Consolidated Financial Statements and the Annual Consolidated Financial Statements, the Committee should receive a report from the external auditors on the results of their review or audit.
Meeting with Auditors and Management	j)     The Committee should meet with the external auditors without management present and discuss any issues related to performance of the audit work, any restrictions and any significant disagreement with management. The Committee should also meet separately with management to discuss the same matters as those discussed with the external auditors.

4)        Internal Audit

Internal Audit Plans	a)     Review and approve the annual Internal Audit Plan and objectives.
Audit Findings and Recommendations	b)     Review the significant control issues identified in internal audit reports issued to management and the responses and actions taken by management to address weaknesses in controls.
Meeting with Auditors	c)     The Committee will meet, without management present, with representatives of the accounting firm and/or the Corporation’s Internal Auditor that executed the annual Internal Audit Plan.

5)        Pension Plans

With respect to all corporate sponsored pension plans of the Corporation and its wholly-owned subsidiaries and any future additional or replacement plans that have estimated actuarial liabilities in excess of US$10 million (collectively the “Retirement Plans”):

Constitute Pension Committees a)     Annually constitute committees (the “Pension Committees”), to be comprised of officers and employees of the Corporation, with responsibility which includes the investment activities of the Retirement Plans’ trust funds.

33

Statements of Pension Investment Policy and Procedures	b)     Review the Corporation’s Statement of Pension Investment Policy for the Retirement Plans’ trust funds whenever a major change is apparent or necessary.
Amendments to Retirement Plans and Material Agreements	c)     Review and recommend to the Board any amendments to the Retirement Plans’ trust agreements and any material document written or entered into pursuant to the Retirement Plans’ trust agreements.
Appointment of Auditors, Actuaries and Investment Managers	d)     Approve the recommendations of the officers of the Corporation regarding the reappointment or appointment of auditors and recommendations of the Pension Committees regarding appointment of investment managers and actuaries of the Retirement Plans.
Retirement Plan Financial Statements	e)     Review and approve the annual financial statements of the Retirement Plans, and related trust funds, and the auditors’ reports thereon.
Retirement Plan Report	f)     Review and recommend for approval by the Board, the annual report on the operation and administration of the Retirement Plans and related trust funds.
Terms of Reference of the Pension Committees	g)     Review and recommend to the Board for approval the Terms of Reference of the Pension Committees and any material amendments thereto.
Delegation to the Pension Committees	h)     Be responsible for the delegation to the Pension Committees responsibility for all matters related to the administration of the Retirement Plans including, but not limited to:
	i)     the authority to delegate to such persons as the Pension Committee determines appropriate any of the administrative functions of the Retirement Plans including, but not limited to, any of the responsibilities of the Pension Committees set out below;
	ii)     approval for filing and filing of such reports, returns and submissions as are required by all persons and bodies having competent jurisdiction over the Retirement Plans;
	iii)     determination of all questions of interpretation and application of the Retirement Plans and any document or agreement written or entered into pursuant to the Retirement Plans;
	iv)     recommending to the Committee any amendments to the Retirement Plans and any material document or agreement written or entered into pursuant to the Retirement Plans;
	v)     approval of any non-material document or agreement written or entered into pursuant to the Retirement Plans other than Retirement Plans trust agreements;
	vi)     approval of the appointment of the custodian/ administrator of the Defined Contribution segment of the Retirement Plans;
	vii)     the administration and maintenance of the Retirement Plans including the approval of benefit calculations; and
	viii) the authority to instruct the trustee to release funds.
Actuarial Reports and Funding Assumptions	i)     Review the actuarial reports on the Retirement Plan as required by applicable regulations and any special actuarial reports.

34

With respect to all aspects of all defined contribution pension plans and defined benefit pension plans that have estimated actuarial liabilities of less than US$10 million of the wholly owned subsidiaries of the Corporation (“other Retirement Plans”):

Other Retirement Plans Report	j)     Receive from management and review with the Board, at least annually, a report on the operation and administration of other Retirement Plans’ trust funds, including investment performance.
Delegation of Authority	k)     Administer and delegate to management-committees as considered advisable all other matters related to other Retirement Plans’ trust funds to which the Committee has been delegated authority.

6)        General Duties

Code of Business Conduct Compliance	a)     Obtain a report at least annually from the General Counsel on the Corporation’s and its subsidiary/foreign- affiliated entities’ conformity with applicable legal and ethical compliance programs (e.g., the Corporation’s Code of Business Conduct).
Code of Ethics	b)     Review and recommend to the Board for approval a code of ethics for senior financial officers.
Compliance Reporting Process	c)     Ensure that a process and procedure has been established by the Corporation for receipt, retention-, and treatment of complaints regarding non-compliance with the Corporation’s Code of Business Conduct, violations of laws or regulations, or concerns regarding accounting, internal accounting controls or auditing matters. The Committee must ensure that procedures for receipt of complaints allow for confidential, anonymous submission of complaints from employees.
Regulatory Matters	d)     Discuss with management and the external auditor any correspondence with regulators or governmental agencies and any published reports that raise material issues regarding the Corporation’s compliance policies.
Disclosure Policy	e)     Review annually and recommend to the Board for approval, the Corporation’s Disclosure policies. In particular, the Committee will review annually the Corporation’s procedures for public disclosure of financial information extracted or derived from the Corporation’s financial statements.
Related-Party Transactions	f)     Review and approve all related-party transactions.
Mandate Review	g)     Review and recommend to the Board for approval changes considered advisable based on the Committee’s assessment of the adequacy of this Mandate. Such review will occur on an annual basis and the recommendations, if any, will be made to the Board for approval.
Annual Evaluation	h)     The Committee will conduct an annual evaluation to ensure that it has satisfied its responsibilities in the prior year in compliance with this Mandate.

35

EX-99.2

Exhibit 99.2

Management’s Discussion and Analysis

Index

	Overview of the Business
	Our Strategy
	Financial Highlights
	Production Summary
	How We Analyze Our Business

	Financial Results
	Liquidity and Capital Resources
	Risk Factors and Risk Management
	Critical Accounting Estimates
	Anticipated Changes to International Financial Reporting Standards

	Supplemental Non-GAAP Measures
	Quarterly Financial Data (Unaudited)
	Selected Annual Information
	Controls and Procedures
	Forward-Looking Statements

This Management’s Discussion and Analysis (“MD&A”) is dated March 5, 2018 and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2017. Except where otherwise noted, the financial information presented in this MD&A is prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (the “IASB”). We use the United States dollar as our reporting currency and, except where otherwise noted, all currency amounts are stated in United States dollars. In this MD&A, a reference to the “Company” refers to Methanex Corporation and a reference to “Methanex”, “we”, “our” and “us” refers to the Company and its subsidiaries or any one of them as the context requires, as well as their respective interests in joint ventures and partnerships.

As at March 5, 2018, we had 83,783,704 common shares issued and outstanding and stock options exercisable for 1,497,296 additional common shares.

Additional information relating to Methanex, including our Annual Information Form, is available on our website at www.methanex.com, the Canadian Securities Administrators’ SEDAR website at www.sedar.com and on the United States Securities and Exchange Commission’s EDGAR website at www.sec.gov.

OVERVIEW OF THE BUSINESS

Methanol is a clear liquid commodity chemical that is predominantly produced from natural gas and is also produced from coal, particularly in China. Approximately 55% of all methanol demand is used to produce traditional chemical derivatives, including formaldehyde, acetic acid and a variety of other chemicals that form the basis of a large number of chemical derivatives for which demand is influenced by levels of global economic activity. The remaining 45% of methanol demand comes from a range of energy-related applications. These include methanol-to-olefins (“MTO”), methyl tertiary-butyl ether (“MTBE”), direct blending of methanol into gasoline (primarily in China), di-methyl ether (“DME”), biodiesel, methanol-to-gasoline (“MTG”), industrial boilers and marine fuel.

We are the world’s largest producer and supplier of methanol to the major international markets in Asia Pacific, North America, Europe and South America. Our total annual production capacity, including Methanex interests in jointly owned plants, is currently 9.4 million tonnes and is located in New Zealand, the United States, Trinidad, Egypt, Canada and Chile. In addition to the methanol produced at our sites, we purchase methanol produced by others under methanol offtake contracts and on the spot market. This gives us flexibility in managing our supply chain while continuing to meet customer needs and support our marketing efforts. We have marketing rights for 100% of the production from the jointly-owned plants in Trinidad and Egypt, which provides us with an additional 1.3 million tonnes per year of methanol offtake supply when the plants are operating at full capacity.

Refer to the Production Summary section on page 11 for more information.

2017 Industry Overview & Outlook

Methanol is a global commodity and our earnings are significantly affected by fluctuations in the price of methanol, which is directly impacted by changes in methanol supply and demand. Demand for methanol is driven primarily by levels of industrial production, energy prices and the strength of the global economy.

6    2017 Methanex Corporation Annual Report

Demand

Demand for methanol grew by approximately 4% or 3 million tonnes in 2017, resulting in total demand of 78 million tonnes in 2017, excluding demand from integrated coal-to-olefins (“CTO”) facilities.

Energy-related demand, which represented approximately 45% of total demand, grew by approximately 8% in 2017. Included in that sector, MTO represented approximately 15% of total methanol demand, and led demand growth as MTO units operated at high rates when they were not experiencing technical issues. This demand segment is anticipated to grow further as three additional MTO units are currently under construction, with the combined capacity to consume over three million tonnes of methanol annually at full operating rates, and we expect these plants to be completed in 2018. The future operating rates and methanol consumption from MTO facilities will depend on a number of factors, including pricing for their various final products, the degree of downstream integration of these units with other products and the impact of the olefin industry feedstock costs, including naptha, on relative competitiveness.

Global regulations to promote the use of clean-burning fuels support long-term demand growth for a number of emerging energy applications for methanol.

In China, stricter air quality emissions regulations are leading to a phase-out of coal-fueled industrial boilers in favour of cleaner fuels, creating a growing market for methanol as an alternative fuel. We estimate that this growing demand segment already represents over 1.5 million tonnes of methanol demand.

Demand for other fuel applications in China remains healthy with interest from other countries growing. China’s high blend (M85-M100) methanol vehicle pilot program staged by the Ministry of Industry and Information Technology has achieved positive results during the official review in 2017 with further expansion planned for 2018. Blending continues to gain momentum outside of China. Several other countries are in the assessment or near-commercial stage for low-level methanol fuel blending.

Regulatory changes are playing an increasing role in encouraging new applications for methanol due to its emissions benefits as a fuel. As a result of the International Maritime Organization’s expansion of future sulphur limits from ocean-going vessels, methanol has emerged as a promising competitive alternative. A number of projects are underway with cruise ships, ferries as well as tug boats and barges. In China, Methanex is partnering with the Ministry of Agriculture to initiate a marine fuel pilot and working with the Ministry of Transport and relevant stakeholders to support the development of methanol marine fuel guidelines.

Demand from traditional applications for methanol grew by approximately 2% in 2017 and we estimate that traditional chemical derivatives consume approximately 55% of methanol globally.

Supply

There were no significant new industry capacity additions outside of China in 2017. In China, we estimate that approximately two million tonnes of new production capacity was added in 2017, excluding methanol production that is integrated with production of other downstream products and not sold on the merchant market.

Over the next few years, the majority of large-scale capacity additions outside of China are expected to be in North America and the Middle East. OCI N.V. and Consolidated Energy Limited (through its subsidiary G2X Energy) continue to advance their jointly owned Natgasoline project, a 1.8 million tonne plant under construction in Beaumont, Texas with methanol production expected in 2018. There are a number of other large-scale projects under discussion in the United States; however, we believe that there has been limited committed capital to date. In Iran, there are a number of plants at various stages of construction. We expect just over four million tonnes of capacity to come onstream in Iran over the next two years; however, the start-up timing and future operating rates at these facilities will be dependent on various factors. Caribbean Gas Chemical Limited (“CGCL”) is constructing a 1.0 million tonne plant in Trinidad with announced production towards the end of the decade. To the end of 2018, we expect approximately two million tonnes of new capacity additions in China. Beyond 2018, we anticipate that new capacity additions in China will be modest due to increasing restrictions placed by the Chinese government on new coal-based capacity additions. We expect that production from new capacity in China will be consumed in that country.

2017 Methanex Corporation Annual Report    7

Price

Methanex’s average realized price in 2017 increased to $337 per tonne from $242 per tonne in 2016. Although methanol pricing was volatile in 2017, the stronger average methanol price was supported by a number of factors. Demand for methanol in traditional and energy applications continued to grow, led by methanol-to-olefins demand in China. Higher energy prices also supported the affordability of methanol into energy applications. Rising coal and natural gas prices increased the relative cost of production and increased the cost curve support for methanol prices. In addition, a number of planned and unplanned outages throughout the year impacted global production, particularly towards the end of 2017 when methanol prices significantly exceeded the cost curve due to a shortage of supply. Methanol prices continued to move higher in the first quarter of 2018.

Future methanol prices will ultimately depend on the strength of the global economy, industry operating rates, global energy prices, new supply additions and the strength of global demand.

OUR STRATEGY

Our primary objective is to create value by maintaining and enhancing our leadership in the global production, marketing and delivery of methanol to customers. To achieve this objective we have a simple, clearly defined strategy: global leadership, low cost and operational excellence. We also pride ourselves in being a leader in Responsible Care. Our brand differentiator “The Power of Agility^®” defines our culture of flexibility, responsiveness and creativity that allows us to capitalize on opportunities quickly as they arise, and swiftly respond to customer needs.

Global Leadership

Global leadership is a key element of our strategy. We are focused on maintaining and enhancing our position as the major producer and supplier in the global methanol industry, improving our ability to cost-effectively deliver methanol to customers and supporting both traditional and energy-related global methanol demand growth.

We are the leading producer and supplier of methanol to the major international markets in Asia Pacific, North America, Europe and South America. Our 2017 sales volume of 10.7 million tonnes of methanol represented approximately 14% of global methanol demand. Our leadership position has enabled us to play an important role in the industry, which includes publishing Methanex reference prices that are used in each major market as the basis of pricing for our customer contracts.

The geographically diverse locations of our production sites allow us to deliver methanol cost-effectively to customers in all major global markets, while investments in global distribution and supply infrastructure, which include a fleet of ocean-going vessels and terminal capacity within all major international markets, enable us to enhance value to customers by providing reliable and secure supply.

A key component of our global leadership strategy is the strength of our asset position with over 8.5 million tonnes of operating capacity in 2017. We achieved record production in 2017 of 7.2 million tonnes, exceeding our previous record of 7.0 million tonnes set in 2016. Our Chile operations are currently operating at less than full production capacity and provide further potential to increase production.

Another key component of our global leadership strategy is our ability to supplement methanol production with methanol purchased from third parties to give us flexibility in our supply chain to meet customer commitments. We purchase methanol through a combination of methanol offtake contracts and spot purchases. We manage the cost of purchased methanol by taking advantage of our global supply chain infrastructure, which allows us to purchase methanol in the most cost-effective region while still maintaining overall security of supply.

The Asia Pacific region continues to lead global methanol demand growth and we have invested in and developed our presence in this important region. We have storage capacity in China, South Korea and Japan that allows us to cost-effectively manage supply to customers and we have offices in Hong Kong, Shanghai, Tokyo, Seoul and Beijing to enhance customer service and industry positioning in the region. This enables us to participate in and improve our knowledge of the rapidly evolving and high growth methanol markets in China and other Asian countries. Our expanding presence in Asia Pacific has also helped us identify several opportunities to support the development of applications for methanol in the energy-related sector.

8    2017 Methanex Corporation Annual Report

Low Cost

A low cost structure is an important competitive advantage in a commodity industry and is a key element of our strategy. Our approach to major business decisions is guided by a drive to improve our cost structure and create value for shareholders. The most significant components of total costs are natural gas for feedstock and distribution costs associated with delivering methanol to customers. Our cost structure per tonne continues to benefit from significant leverage on our fixed costs as production increases.

The New Zealand, Trinidad and Egypt facilities are underpinned by natural gas purchase agreements where the natural gas price varies with methanol prices. This pricing relationship enables these facilities to be competitive throughout the methanol price cycle. We have a fixed price contract to supply substantially all our Geismar 1 facility and forward contracts to hedge natural gas prices for approximately 40% of the natural gas requirements of our Geismar 2 facility through 2025 with the remainder of natural gas requirements at Geismar purchased in the spot market. We have entered into fixed price contracts to supply the majority of our natural gas requirements for our Medicine Hat facility through 2031.

Our production facilities are well located to supply global methanol markets. Still, the cost to distribute methanol from production locations to customers is a significant component of total operating costs. These include costs for ocean shipping, in-market storage facilities and in-market distribution. We are focused on identifying initiatives to reduce these costs, including optimizing the use of our shipping fleet and taking advantage of prevailing conditions in the shipping market by varying the type and length of term of ocean vessel contracts. 2017 was our first full year with seven vessels equipped with flex-fuel engines that can run on conventional fuel or methanol, which provides us with further flexibility in our supply chain. We also look for opportunities to leverage our global asset position by entering into geographic product exchanges with other methanol producers to reduce distribution costs.

Operational Excellence

We maintain a focus on operational excellence in all aspects of our business. This includes excellence in manufacturing and supply chain processes, marketing and sales, human resources, corporate governance practices and financial management.

To differentiate ourselves from competitors, we strive to be the best operator in all aspects of our business and to be the preferred supplier to customers. We believe that reliability of supply is critical to the success of our customers’ businesses and our goal is to deliver methanol reliably and cost-effectively. We have a commitment to Responsible Care (an operating ethic and set of principles developed by the Chemistry Industry Association of Canada) and we use it as the umbrella under which we manage issues related to employee health and safety, environmental protection, community involvement, social responsibility, sustainability, security and emergency preparedness at each of our facilities and locations. Through the International Council of Chemical Associations, over 60 countries have adopted the Responsible Care Ethic and Principles for Sustainability. We believe a commitment to Responsible Care helps us achieve an excellent overall environmental and safety record.

Product stewardship is a vital component of a Responsible Care culture and guides our actions through the complete life cycle of our product. We aim for the highest safety standards to minimize risk to employees, customers and suppliers as well as to the environment and the communities in which we do business. We promote the proper use and safe handling of methanol at all times through a variety of internal and external health, safety and environmental initiatives, and we work with industry colleagues to improve safety standards. We readily share technical and safety expertise with key stakeholders, including customers, end-users, suppliers, logistics providers and industry associations in the methanol and methanol applications marketplace through active participation in local and international industry associations, seminars and conferences and online education initiatives.

As a natural extension of the Responsible Care ethic, we have a Social Responsibility policy that aligns corporate governance, employee engagement and development, community involvement and social investment strategies with our core values and corporate strategy.

Our strategy of operational excellence also includes the financial management of the Company. We operate in a highly competitive commodity industry. Accordingly, we believe it is important to maintain financial flexibility and we have adopted a prudent approach to financial management. We have an undrawn $300 million credit facility provided by highly rated financial institutions that expires

2017 Methanex Corporation Annual Report    9

in December 2022. As at December 31, 2017, we had a strong balance sheet and a cash balance of $375 million. We believe we are well-positioned to meet our financial commitments, pursue our near-term growth opportunities in Chile and deliver on our commitment to return excess cash to shareholders through dividends and share repurchases.

FINANCIAL HIGHLIGHTS

($ Millions, except as noted)	2017		2016
Production (thousands of tonnes) (attributable to Methanex shareholders)		7,187		7,017
Sales volume (thousands of tonnes)
Methanex-produced methanol		7,229		6,828
Purchased methanol		2,289		1,892
Commission sales		1,151		758
Total sales volume1		10,669		9,478
Methanex average non-discounted posted price ($ per tonne)2		396		279
Average realized price ($ per tonne)3		337		242
Revenue		3,061		1,998
Adjusted revenue4		3,227		2,118
Adjusted EBITDA4		838		287
Cash flows from operating activities		788		227
Adjusted net income (loss)4		409		(15	)
Net income (loss) (attributable to Methanex shareholders)		316		(13	)
Adjusted net income (loss) per common share ($ per share)4		4.71		(0.17	)
Basic net income (loss) per common share ($ per share)		3.64		(0.14	)
Diluted net income (loss) per common share ($ per share)		3.64		(0.14	)
Common share information (millions of shares)
Weighted average number of common shares		87		90
Diluted weighted average number of common shares		87		90
Number of common shares outstanding, end of period		84		90

¹  Methanex-produced methanol represents our equity share of volume produced at our facilities and excludes volume marketed on a commission basis related to 36.9% of the Atlas facility and 50% of the Egypt facility that we do not own. Methanex-produced methanol includes any volume produced in Chile using natural gas supplied from Argentina under a tolling arrangement (“Tolling Volume”). There has been no Tolling Volume produced in the periods presented.

²  Methanex average non-discounted posted price represents the average of our non-discounted posted prices in North America, Europe and Asia Pacific weighted by sales volume. Current and historical pricing information is available at www.methanex.com.

³  Average realized price is calculated as revenue, excluding commissions earned and the Egypt non-controlling interest share of revenue, but including an amount representing our share of Atlas revenue, divided by the total sales volume of Methanex-produced and purchased methanol, but excluding Tolling Volume.

⁴  The Company has used the terms Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share, Adjusted revenue, and Operating income throughout this document. These items are non-GAAP measures that do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Refer to the Supplemental Non-GAAP Measures section on page 36 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures.

10    2017 Methanex Corporation Annual Report

PRODUCTION SUMMARY

The following table details the annual production capacity and actual production of our facilities in 2017 and 2016:

(Thousands of tonnes)	Annual production capacity1		Annual operating capacity2		2017 Production		2016 Production
New Zealand3		2,430		2,430		1,943		2,181
Geismar (USA)		2,000		2,000		1,935		2,055
Trinidad (Methanex interest)4		2,000		2,000		1,768		1,605
Egypt (50% interest)		630		630		534		293
Medicine Hat (Canada)		600		600		593		488
Chile5		1,720		880		414		395
		9,380		8,540		7,187		7,017

¹ Annual production capacity reflects, among other things, average expected plant outages, turnarounds and average age of the facility’s catalyst. As a result, the actual production of a facility may be higher or lower than the stated annual production capacity.

² Annual operating capacity includes only those facilities which are currently capable of operating, but excludes any portion of an asset that is underutilized due to a lack of natural gas feedstock over a prolonged period of time. Our current annual operating capacity is 8.5 million tonnes, including 0.9 million tonnes related to our Chile operations. The operating capacity of our production facilities may be higher than original nameplate capacity as, over time, these figures have been adjusted to reflect ongoing operating efficiencies at these facilities. Actual production for a facility in any given year may be higher or lower than operating capacity due to a number of factors, including natural gas composition or the age of the facility’s catalyst.

³ The operating capacity of New Zealand is made up of the two Motunui facilities and the Waitara Valley facility (refer to the New Zealand section below).

⁴ The operating capacity of Trinidad is made up of the Titan (100% interest) and Atlas (63.1% interest) facilities (refer to the Trinidad section below).

⁵  The production capacity of our Chile I and IV facilities is 1.7 million tonnes annually assuming access to natural gas feedstock.

New Zealand

In New Zealand, we produced 1.9 million tonnes of methanol in 2017 compared with 2.2 million tonnes in 2016. A planned turnaround and repairs at the Motunui facilities impacted production in 2017. The plants are able to produce at an annual production capacity of up to 2.4 million tonnes of methanol, depending on natural gas composition. Our New Zealand facilities are ideally situated to supply the growing Asia Pacific market. Refer to the Risk Factors and Risk Management – New Zealand section on page 26 for more information.

United States

The Geismar facilities produced 1.9 million tonnes of methanol in 2017 compared with 2.1 million tonnes in 2016. Lower production in 2017 compared with 2016 was a result of planned maintenance activities undertaken at both Geismar plants in the year. Refer to the Risk Factors and Risk Management – United States section on page 26 for more information.

Trinidad

Our ownership interest in the methanol facilities in Trinidad represents 2.0 million tonnes of annual capacity. The Titan and Atlas facilities in Trinidad are well located to supply global methanol markets and are underpinned by natural gas purchase agreements where the natural gas price varies with methanol prices. The Trinidad facilities produced a total of 1.8 million tonnes of methanol (Methanex share) in 2017 compared with 1.6 million tonnes in 2016. Our results in 2016 reflected a turnaround performed at the Atlas facility.

During 2016 and 2017, we continued to experience natural gas curtailments to our Trinidad facilities due to a mismatch between upstream supply to the National Gas Company of Trinidad and Tobago Limited (“NGC”) and downstream demand from NGC’s customers. We are engaged with key stakeholders to find a solution to this issue, but expect to continue to experience gas curtailments to the Trinidad site. Refer to the Risk Factors and Risk Management – Trinidad section on page 27 for more information.

2017 Methanex Corporation Annual Report    11

Egypt

We operate a 1.26 million tonne per year methanol facility in Egypt and have marketing rights for 100% of the production. The Egypt methanol facility is well located to supply European and Asia Pacific methanol markets. We produced 1,068,000 tonnes of methanol (Methanex share of 534,000) at the plant during 2017, compared to 586,000 tonnes (Methanex share of 293,000) in 2016. Production in 2017 was impacted by a planned turnaround in the third quarter. Following the turnaround, the plant restarted and ran at high rates for the remainder of the year.

The Egypt facility has experienced periodic natural gas supply restrictions since mid-2012 and gas restrictions worsened through 2014 and 2015. Gas deliveries for the year ended December 31, 2017 have improved significantly compared to the same period in 2016. We are optimistic that the strong efforts by Egyptian governmental entities to fast-track existing and new upstream gas supply in Egypt are leading to improved gas deliveries and an improved outlook for gas deliveries in the medium term. Refer to the Risk Factors and Risk Management – Egypt section on page 27 for more information.

Canada

The Medicine Hat facility produced 593,000 tonnes of methanol in 2017 compared to 488,000 tonnes in 2016. A mechanical issue at the Medicine Hat facility impacted production in 2016 and early 2017. Repairs to address the issue were completed early in 2017 with the plant running at high rates for the remainder of the year. Refer to the Risk Factors and Risk Management – Canada section on page 27 for more information.

Chile

The Chile facility produced 414,000 tonnes of methanol in 2017 compared to 395,000 tonnes in 2016. Production increased for 2017 as compared to 2016 as a result of improved natural gas availability from Chilean suppliers. For the second consecutive year, we produced methanol throughout the southern hemisphere winter months, which are a period of typically lower gas deliveries.

The future of our Chile operations is primarily dependent on the level of natural gas exploration and development in southern Chile and our ability to secure a sustainable natural gas supply to our facilities on economic terms from Chile and Argentina. We are optimistic that our underutilized 1.7 million tonne Chile facilities represent a very low capital cost growth opportunity for Methanex due to significant progress in developing natural gas reserves in the area. Project work has commenced for the restart of our Chile IV plant and, if additional gas supply can be secured, will be followed by the refurbishment of our Chile I plant in order to restore Chile to a two-plant operation at a very low capital cost. Refer to the Risk Factors and Risk Management – Chile section on page 28 for more information.

HOW WE ANALYZE OUR BUSINESS

Our operations consist of a single operating segment – the production and sale of methanol. We review our financial results by analyzing changes in the components of Adjusted EBITDA, mark-to-market impact of share-based compensation, depreciation and amortization, Argentina gas settlement, finance costs, finance income and other expenses, and income taxes.

The Company has used the terms Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share, Adjusted revenue and Operating income throughout this document. These items are non-GAAP measures that do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Refer to the Supplemental Non-GAAP Measures section on page 36 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures.

12    2017 Methanex Corporation Annual Report

In addition to the methanol that we produce at our facilities, we also purchase and resell methanol produced by others and we sell methanol on a commission basis. We analyze the results of all methanol sales together, excluding commission sales volume. The key drivers of changes in Adjusted EBITDA are average realized price, cash costs and sales volume, which are defined and calculated as follows:

PRICE	The change in Adjusted EBITDA as a result of changes in average realized price is calculated as the difference from period to period in the selling price of methanol multiplied by the current period total methanol sales volume, excluding commission sales volume and Tolling Volume, plus the difference from period to period in commission revenue.
CASH COSTS	The change in Adjusted EBITDA as a result of changes in cash costs is calculated as the difference from period to period in cash costs per tonne multiplied by the current period total methanol sales volume, excluding commission sales volume and Tolling Volume in the current period. The cash costs per tonne is the weighted average of the cash cost per tonne of Methanex-produced methanol and the cash cost per tonne of purchased methanol. The cash cost per tonne of Methanex-produced methanol includes absorbed fixed cash costs per tonne and variable cash costs per tonne. The cash cost per tonne of purchased methanol consists principally of the cost of methanol itself. In addition, the change in Adjusted EBITDA as a result of changes in cash costs includes the changes from period to period in unabsorbed fixed production costs, consolidated selling, general and administrative expenses and fixed storage and handling costs.
SALES VOLUME	The change in Adjusted EBITDA as a result of changes in sales volume is calculated as the difference from period to period in total methanol sales volume, excluding commission sales volume and Tolling Volume, multiplied by the margin per tonne for the prior period. The margin per tonne for the prior period is the weighted average margin per tonne of Methanex-produced methanol and margin per tonne of purchased methanol. The margin per tonne for Methanex-produced methanol is calculated as the selling price per tonne of methanol less absorbed fixed cash costs per tonne and variable cash costs per tonne. The margin per tonne for purchased methanol is calculated as the selling price per tonne of methanol less the cost of purchased methanol per tonne.

We own 63.1% of the Atlas methanol facility and market the remaining 36.9% of its production through a commission offtake agreement. A contractual agreement between us and our partners establishes joint control over Atlas. As a result, we account for this investment using the equity method of accounting, which results in 63.1% of the net assets and net earnings of Atlas being presented separately in the consolidated statements of financial position and consolidated statements of income (loss), respectively. For purposes of analyzing our business, Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share and Adjusted revenue include an amount representing our 63.1% equity share in Atlas. Our analysis of depreciation and amortization, finance costs, finance income and other expenses, and income taxes is consistent with the presentation of our consolidated statements of income (loss) and excludes amounts related to Atlas.

We own 50% of the 1.26 million tonne per year Egypt methanol facility and market the remaining 50% of its production through a commission offtake agreement. We account for this investment using consolidation accounting, which results in 100% of the revenues and expenses being included in our financial statements. We also consolidate less then wholly-owned entities for which we have a controlling interest. Non-controlling interests are included in the Company’s consolidated financial statements and represent the non-controlling shareholders’ interests in the Egypt methanol facility and any entity where we have control. For purposes of analyzing our business, Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share and Adjusted revenue exclude the amounts associated with non-controlling interests.

FINANCIAL RESULTS

For the year ended December 31, 2017, we reported net income attributable to Methanex shareholders of $316 million ($3.64 income per common share on a diluted basis), compared with net loss attributable to Methanex shareholders of $13 million ($0.14 loss per common share on a diluted basis) for the year ended December 31, 2016.

For the year ended December 31, 2017, we reported Adjusted EBITDA of $838 million and Adjusted net income of $409 million ($4.71 Adjusted net income per common share), compared with Adjusted EBITDA of $287 million and Adjusted net loss of $15 million ($0.17 Adjusted net loss per common share) for the year ended December 31, 2016.

2017 Methanex Corporation Annual Report    13

We calculate Adjusted EBITDA and Adjusted net income (loss) by including amounts related to our equity share of the Atlas facility (63.1% interest) and by excluding the non-controlling interests’ share, the mark-to-market impact of share-based compensation as a result of changes in our share price and the impact of certain items associated with specific identified events.

In 2017, we recorded a non-cash charge of $37 million to net income from the revaluation of a net deferred tax asset as a result of tax reform in the United States. In 2016, we recorded a gain of $32.5 million ($21 million after-tax) after reaching a settlement with Petrobras Energía S.A. (“Petrobras”) of Argentina to terminate Petrobras’ natural gas delivery obligations pursuant to a long-term natural gas supply agreement in Chile (the “Argentina gas settlement”).

A reconciliation from net income (loss) attributable to Methanex shareholders to Adjusted net income (loss) and the calculation of Adjusted diluted net income (loss) per common share is as follows:

($ Millions, except number of shares and per share amounts)	2017			2016
Net income (loss) attributable to Methanex shareholders	$	316		$	(13	)
U.S. tax reform charge		37			–
Mark-to-market impact of share-based compensation, net of tax		56			19
Argentina gas settlement, net of tax		–			(21	)
Adjusted net income (loss)	$	409		$	(15	)
Diluted weighted average shares outstanding (millions)		87			90
Adjusted net income (loss) per common share	$	4.71		$	(0.17	)
A summary of our consolidated statements of income (loss) for 2017 and 2016 is as follows:
($ Millions)	2017			2016
Consolidated statements of income:
Revenue	$	3,061		$	1,998
Cost of sales and operating expenses		(2,352	)		(1,774	)
Mark-to-market impact of share-based compensation		68			22
Adjusted EBITDA (attributable to associate)		148			63
Amounts excluded from Adjusted EBITDA attributable to non-controlling interests		(87	)		(22	)
Adjusted EBITDA (attributable to Methanex shareholders)		838			287
U.S. tax reform charge		(37	)		–
Mark-to-market impact of share-based compensation		(68	)		(22	)
Argentina gas settlement		–			33
Depreciation and amortization		(232	)		(228	)
Finance costs		(95	)		(90	)
Finance income and other expenses		13			4
Income tax recovery (expense)		(59	)		9
Earnings of associate adjustment1		(72	)		(43	)
Non-controlling interests adjustment1		28			37
Net income (loss) attributable to Methanex shareholders	$	316		$	(13	)
Net income (loss)	$	375		$	(28	)

¹  These adjustments represent depreciation and amortization, finance costs, finance income and other expenses and income taxes associated with our 63.1% interest in the Atlas methanol facility and the non-controlling interests.

Revenue

There are many factors that impact our global and regional revenue levels. The methanol business is a global commodity industry affected by supply and demand fundamentals. Due to the diversity of the end products in which methanol is used, demand for methanol largely depends upon levels of industrial production, energy prices and changes in general economic conditions, which can vary across the major international methanol markets. Revenue increased to $3.1 billion in 2017 from $2.0 billion in 2016. The higher revenue reflects an increase in our average realized price and higher sales volume in 2017.

14    2017 Methanex Corporation Annual Report

We publish regional non-discounted reference prices for each major methanol market and these posted prices are reviewed and revised monthly or quarterly based on industry fundamentals and market conditions. Most of our customer contracts use published Methanex reference prices as a basis for pricing, and we offer discounts to customers based on various factors. Our average non-discounted published reference price in 2017 was $396 per tonne compared with $279 per tonne in 2016. Our average realized price in 2017 increased to $337 per tonne from $242 per tonne in 2016.

Distribution of Revenue

The geographic distribution of revenue by customer location for 2017 was similar to 2016. Details are as follows:

($ Millions, except where noted)	2017				2016
China	$	802	26	%	$	518	26	%
Europe		609	20	%		404	20	%
United States		570	19	%		359	18	%
South Korea		348	11	%		258	13	%
South America		279	9	%		179	9	%
Canada		168	6	%		110	6	%
Other Asia		285	9	%		170	8	%
	$	3,061	100	%	$	1,998	100	%

Adjusted EBITDA (Attributable to Methanex Shareholders)

2017 Adjusted EBITDA was $838 million compared with 2016 Adjusted EBITDA of $287 million, an increase of $551 million. The key drivers of change in our Adjusted EBITDA are average realized price, sales volume and cash costs as described below (refer to the How We Analyze Our Business section on page 12 for more information).

($ Millions)	2017 vs. 2016
Average realized price	$	910
Sales volume		43
Total cash costs		(402	)
Increase in Adjusted EBITDA	$	551

Average Realized Price

Our average realized price for the year ended December 31, 2017 increased to $337 per tonne from $242 per tonne for 2016, and this increased Adjusted EBITDA by $910 million (refer to the Financial Results – Revenue section on page 14 for more information).

Sales Volume

Methanol sales volume, excluding commission sales volume, for the year ended December 31, 2017 increased by 798,000 tonnes to 9.5 million tonnes from 8.7 million tonnes in 2016, and this increased Adjusted EBITDA by $43 million. Including commission sales volume from the Atlas and Egypt facilities, our total methanol sales volume was 10.7 million tonnes in 2017 compared with 9.5 million tonnes in 2016.

Total Cash Costs

The primary drivers of change in our total cash costs are changes in the cost of Methanex-produced methanol and changes in the cost of methanol we purchase from others (“purchased methanol”). We supplement our production with methanol produced by others through methanol offtake contracts and purchases on the spot market to meet customer needs and support our marketing efforts within the major global markets.

We have adopted the first-in, first-out method of accounting for inventories and it generally takes between 30 and 60 days to sell the methanol we produce or purchase. Accordingly, the changes in Adjusted EBITDA as a result of changes in Methanex-produced and purchased methanol costs primarily depend on changes in methanol pricing and the timing of inventory flows.

2017 Methanex Corporation Annual Report    15

In a rising price environment, our margins at a given price are higher than in a stable price environment as a result of methanol purchases and production versus sales. Generally, the opposite applies when methanol prices are decreasing.

The changes in Adjusted EBITDA due to changes in total cash costs for 2017 compared with 2016 were due to the following:

($ Millions)	2017 vs. 2016
Methanex-produced methanol costs	$	(154	)
Proportion of Methanex-produced methanol sales		(13	)
Purchased methanol costs		(238	)
Other, net		3
Decrease in Adjusted EBITDA due to changes in total cash costs	$	(402	)

Methanex-Produced Methanol Costs

Natural gas is the primary feedstock at our methanol facilities and is the most significant component of Methanex-produced methanol costs. We purchase natural gas for more than half of our production under natural gas purchase agreements where the unique terms of each contract include a base price and a variable price component linked to the price of methanol to reduce our commodity price risk exposure. The variable price component of each gas contract is adjusted by a formula related to methanol prices above a certain level. Methanex-produced methanol costs were higher in 2017 compared with 2016 by $154 million, primarily due to the impact of changes in realized methanol prices on the variable portion of our natural gas costs and changes in the mix of production sold from inventory. For additional information regarding our natural gas supply agreements, refer to the Liquidity and Capital Resources – Summary of Contractual Obligations and Commercial Commitments section on page 22.

Proportion of Methanex-produced methanol sales

The cost of purchased methanol is directly linked to the selling price for methanol at the time of purchase and the cost of purchased methanol is generally higher than the cost of Methanex-produced methanol. Accordingly, an increase in the proportion of Methanex-produced methanol sales results in a decrease in our overall cost structure for a given period. The proportion of Methanex-produced methanol sales decreased in 2017 due to total sales volume increasing more than production volume and this decreased Adjusted EBITDA by $13 million for 2017 compared with 2016.

Purchased Methanol Costs

A key element of our corporate strategy is global leadership and, as such, we have built a leading market position in each of the major global markets where methanol is sold. We supplement our production with purchased methanol through methanol offtake contracts and on the spot market to meet customer needs and support our marketing efforts within the major global markets. In structuring purchase agreements, we look for opportunities that provide synergies with our existing supply chain that allow us to purchase methanol in the most cost effective region. The cost of purchased methanol consists principally of the cost of the methanol itself, which is directly related to the price of methanol at the time of purchase. As a result of changes in methanol prices in 2017 and the timing of inventory flows and purchases, the cost of purchased methanol per tonne increased and this decreased Adjusted EBITDA by $238 million compared with 2016.

Other, Net

Our investment in global distribution and supply infrastructure includes a dedicated fleet of ocean-going vessels. We utilize these vessels to enhance value to customers by providing reliable and secure supply and to optimize supply chain costs overall, including through third-party backhaul arrangements when available. Logistics costs can also vary from period to period depending on the levels of production from each of our production facilities and the resulting impact on our supply chain. Other, net relates to logistics costs, selling, general and administrative expenses and other operational charges.

16    2017 Methanex Corporation Annual Report

Mark-to-Market Impact of Share-Based Compensation

We grant share-based awards as an element of compensation. Share-based awards granted include stock options, share appreciation rights, tandem share appreciation rights, deferred share units, restricted share units and performance share units. For all share-based awards, share-based compensation is recognized over the related vesting period for the proportion of the service that has been rendered at each reporting date. Share-based compensation includes an amount related to the grant-date value and a mark-to-market impact as a result of subsequent changes in the Company’s share price. The grant-date value amount is included in Adjusted EBITDA and Adjusted net income (loss). The mark-to-market impact of share-based compensation as a result of changes in our share price is excluded from Adjusted EBITDA and Adjusted net income (loss) and analyzed separately.

($ Millions, except share price)	2017		2016
Methanex Corporation share price1	$	60.55	$	43.80
Grant-date fair value expense included in Adjusted EBITDA and Adjusted net income (loss)		11		11
Mark-to-market impact due to change in share price		68		22
Total share-based compensation expense, before tax	$	79	$	33

¹  U.S. dollar share price of Methanex Corporation as quoted on the NASDAQ Global Select Market on the last trading day of the respective period.

For stock options, the cost is measured based on an estimate of the fair value at the date of grant using the Black-Scholes option pricing model, and this grant-date fair value is recognized as compensation expense over the related vesting period with no subsequent re-measurement in fair value. Accordingly, share-based compensation expense associated with stock options will not vary significantly from period to period.

Share appreciation rights (“SARs”) are units that grant the holder the right to receive a cash payment upon exercise for the difference between the market price of the Company’s common shares and the exercise price that is determined at the date of grant. Tandem share appreciation rights (“TSARs”) give the holder the choice between exercising a regular stock option or a SAR. The fair values of SARs and TSARs are re-measured each quarter using the Black-Scholes option pricing model, which considers the market value of the Company’s common shares on the last trading day of each quarter.

Deferred, restricted and performance share units are grants of notional common shares that are redeemable for cash based on the market value of the Company’s common shares and are non-dilutive to shareholders. Performance share units have an additional feature where the ultimate number of units that vest will be determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The number of performance share units that will ultimately vest will be in the range of 25% to 150% based on the weighted-average closing share price for the 90 calendar days on the NASDAQ Global Select Market immediately preceding the year end date that the performance share units vest. For deferred, restricted and performance share units, the value is initially measured at the grant date and subsequently re-measured based on the market value of the Company’s common shares on the last trading day of each quarter. The price of the Company’s common shares as quoted on the NASDAQ Global Select Market increased from $43.80 per share at December 31, 2016 to $60.55 per share at December 31, 2017. As a result of the increase in the share price and the resulting impact on the fair value of the outstanding units, we recorded a $68 million mark-to-market expense related to share-based compensation during 2017.

Depreciation and Amortization

Depreciation and amortization was $232 million for the year ended December 31, 2017 compared with $228 million for the year ended December, 31 2016. The increase in depreciation and amortization in 2017 compared with 2016 is primarily the result of higher sales volume of Methanex-produced methanol.

U.S. Tax Reform

In 2017, we recorded a non-cash charge of $37 million to net income related to the revaluation of a net deferred tax asset as a result of tax reform in the United States (refer to the Financial Results – Income Taxes section on page 18 for more information).

Argentina Gas Settlement

In 2016, we recorded a gain of $32.5 million ($21 million after-tax) after reaching a settlement with Petrobras to terminate Petrobras’ natural gas delivery obligations pursuant to a long-term natural gas supply agreement in Chile. The Company received the settlement amount in 2016.

2017 Methanex Corporation Annual Report    17

Finance Costs

Finance costs are primarily comprised of interest on borrowings and finance lease obligations and were $95 million for the year ended December 31, 2017 compared to $90 million for the year ended December 31, 2016. The increase in finance costs for the year ended December 31, 2017 compared to the same period in 2016 is primarily due to interest incurred relating to new ocean going vessels treated as finance leases put in use part way through 2016.

Finance Income and Other Expenses

Finance income and other expenses was a gain of $13 million for the year ended December 31, 2017 compared to a gain of $4 million for the year ended December 31, 2016. The change in finance income and other expenses in 2017 compared with 2016 is primarily related to the impact of changes in foreign exchange rates.

Income Taxes

A summary of our income taxes for 2017 compared with 2016 is as follows:

($ Millions, except where noted)	2017						2016
	Net Income			Adjusted Net Income			Net Loss			Adjusted Net Loss
Amount before income tax	$	471		$	524		$	(37	)	$	(26	)
U.S. tax reform charge		(37	)		–			–			–
Income tax recovery (expense)		(59	)		(115	)		9			11
Amount after income tax	$	375		$	409		$	(28	)	$	(15	)
Effective tax rate		20	%		22	%		25	%		44	%

We earn the majority of our income in New Zealand, Trinidad, the United States, Egypt, Canada and Chile. In Trinidad and Chile, the statutory tax rate is 35%. The statutory rates in Canada and New Zealand are 27% and 28%, respectively. The United States statutory tax rate applicable to Methanex was 36% in 2017 and is 23% starting in 2018 and the Egypt statutory tax rate is 22.5%. As the Atlas entity is accounted for using the equity method, any income taxes related to Atlas are included in earnings of associate and therefore excluded from total income taxes but included in the calculation of Adjusted net income.

In December 2017, the United States passed the Tax Cuts and Jobs Act of 2017 (“U.S. tax reform” or “the Act”) which reduced the US federal corporate tax rate from 35% to 21% effective from January 1, 2018. The Act includes a number of other provisions related to corporate taxation that will impact Methanex. The decrease in the corporate tax rate and these other provisions will impact taxes payable on our income earned in the United States going forward. Up to December 31, 2017, Methanex had claimed certain interest deductions in the United States on debt instruments. There are provisions in the Act that going forward will reduce the value of these interest deductions. The impact of the passing of the U.S. tax reform recorded in the fourth quarter of 2017 is a non-cash tax charge recorded to net income of $37 million and to other comprehensive income of $9 million associated with the revaluation of net deferred tax assets. These charges have resulted in a total decrease of $46 million to net deferred tax assets and reflect our initial estimate and may be refined in the future as additional guidance emerges.

The effective tax rate related to Adjusted net income was 22% for the year ended December 31, 2017 compared with 44% on an Adjusted net loss for the year ended December 31, 2016. Adjusted net income (loss) represents the amount that is attributable to Methanex shareholders and excludes the mark-to-market impact of share-based compensation and the impact of certain items associated with specific identified events. The effective tax rate differs from period to period depending on the source of earnings and the impact of foreign exchange fluctuations against the United States dollar on our tax balances. In periods with low income levels, the distribution of income and loss between jurisdictions can result in income tax rates that are not indicative of the longer term corporate tax rate. In addition, the effective tax rate is impacted by changes in tax legislation in the jurisdictions in which we operate.

For additional information regarding income taxes, refer to note 15 of our 2017 consolidated financial statements.

18    2017 Methanex Corporation Annual Report

LIQUIDITY AND CAPITAL RESOURCES

A summary of our consolidated statements of cash flows is as follows:

($ Millions)	2017			2016
Cash flows from / (used in) operating activities:
Cash flows from operating activities before changes in non-cash working capital	$	837		$	314
Changes in non-cash working capital		(49	)		(87	)
		788			227
Cash flows from / (used in) financing activities:
Dividend payments		(101	)		(99	)
Interest paid		(86	)		(83	)
Repayment of long-term debt		(57	)		(48	)
Payments for the repurchase of shares		(286	)		–
Net proceeds on issue of long-term debt		–			66
Other		(1	)		(6	)
		(531	)		(170	)
Cash flows from / (used in) investing activities:
Property, plant and equipment		(103	)		(100	)
Changes in non-cash working capital relating to investing activities		(3	)		12
		(106	)		(88	)
Increase (decrease) in cash and cash equivalents		151			(31	)
Cash and cash equivalents, end of year	$	375		$	224

Cash Flow Highlights

Cash Flows from Operating Activities

Cash flows from operating activities for the year ended December 31, 2017 were $788 million compared with $227 million for the year ended December 31, 2016. The increase in cash flows from operating activities is primarily due to higher net income resulting from a higher realized methanol price. The following table provides a summary of these items for 2017 and 2016:

($ Millions)	2017			2016
Net income (loss)	$	375		$	(28	)
Deduct earnings of associate		(76	)		(20	)
Add dividends received from associate		85			47
Add (deduct) non-cash items:
Depreciation and amortization		232			228
Income tax expense (recovery)		96			(9	)
Share-based compensation expense		79			33
Finance costs		95			90
Other		(49	)		(27	)
Cash flows from operating activities before changes in non-cash working capital		837			314
Changes in non-cash working capital:
Trade and other receivables		(49	)		(14	)
Inventories		(20	)		(28	)
Prepaid expenses		(6	)		(1	)
Accounts payable and accrued liabilities, including long-term payables		26			(44	)
		(49	)		(87	)
Cash flows from operating activities	$	788		$	227

For a discussion of the changes in net income (loss), depreciation and amortization, share-based compensation recovery and finance costs, refer to the Financial Results section on page 13.

2017 Methanex Corporation Annual Report    19

Changes in non-cash working capital decreased cash flows from operating activities by $49 million for the year ended December 31, 2017, compared with a decrease of $87 million for the year ended December 31, 2016. Trade and other receivables increased in 2017 and this decreased cash flows from operating activities by $49 million, primarily due to the impact of trade receivables related to higher sales in 2017 compared to 2016. Inventories increased primarily due to the impact of higher methanol prices which decreased cash flows from operating activities by $20 million.

Cash Flows from Financing Activities

During 2017, we increased our regular quarterly dividend to $0.30 per common share from $0.275 per common share. Total dividend payments in 2017 were $101 million compared with $99 million in 2016 and total interest payments in 2017 were $86 million compared with $83 million in 2016. In October 2017, we completed a 10% normal course issuer bid initiated in March 2017, repurchasing the maximum 6,152,358 common shares for approximately $286 million. In 2017, we repaid $57 million of other limited recourse debt compared to $48 million of other limited recourse debt repayments in 2016.

Cash Flows from Investing Activities

During 2017, we incurred capital expenditures relating to our consolidated operations of $103 million primarily related to sustaining projects in New Zealand, Geismar, Egypt and Trinidad and project work for the restart of our Chile IV plant. The restart of the Chile IV plant is targeted for the third quarter of 2018 and the project is budgeted for $55 million.

Liquidity and Capitalization

Our objectives in managing liquidity and capital are to provide financial capacity and flexibility to meet our strategic objectives, to provide an adequate return to shareholders commensurate with the level of risk and to return excess cash through a combination of dividends and share repurchases.

The following table provides information on our liquidity and capitalization position as at December 31, 2017 and December 31, 2016:

($ Millions, except where noted)	2017			2016
Liquidity:
Cash and cash equivalents	$	375		$	224
Undrawn credit facilities		300			300
Total liquidity	$	675		$	524
Capitalization:
Unsecured notes	$	1,188		$	1,186
Limited recourse debt facilities, including current portion		314			370
Total debt		1,502			1,556
Non-controlling interests		244			209
Shareholders’ equity		1,501			1,597
Total capitalization	$	3,247		$	3,362
Total debt to capitalization1		46	%		46	%
Net debt to capitalization2		39	%		42	%

¹  Defined as total debt (including 100% of Egypt limited recourse debt facilities) divided by total capitalization.

²  Defined as total debt (including 100% of Egypt limited recourse debt facilities) less cash and cash equivalents divided by total capitalization less cash and cash equivalents.

We manage our liquidity and capital structure and make adjustments to it in light of changes to economic conditions, the underlying risks inherent in our operations and the capital requirements to maintain and grow our business. The strategies we have employed include the issue or repayment of general corporate debt, the issue of project debt, the payment of dividends and the repurchase of shares.

We are not subject to any statutory capital requirements and have no commitments to sell or otherwise issue common shares except pursuant to outstanding employee stock options and TSARs.

20    2017 Methanex Corporation Annual Report

We operate in a highly competitive commodity industry and believe that it is appropriate to maintain a strong balance sheet and retain financial flexibility. As at December 31, 2017, we had a cash balance of $375 million, access to a $300 million undrawn credit facility and no significant debt maturities until 2019 other than normal course obligations for principal repayments related to our limited recourse debt facilities. We invest our cash only in highly rated instruments that have maturities of three months or less to ensure preservation of capital and appropriate liquidity.

We have covenant and default provisions under our long-term debt obligations and we also have certain covenants that could restrict access to the credit facility. The covenants governing the unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding the Egypt entity, and include restrictions on liens, sale and lease-back transactions, a merger or consolidation with another corporation or sale of all or substantially all of our assets. The indenture also contains customary default provisions. The significant covenants and default provisions under the credit facility include:

a) the obligation to maintain an EBITDA to interest coverage ratio of greater than 2:1 calculated on a four-quarter trailing basis and a debt to capitalization ratio of less than or equal to 55%, both ratios calculated in accordance with definitions in the credit agreement that include adjustments related to the limited recourse subsidiaries;

b) a default if payment is accelerated by a creditor on any indebtedness of $50 million or more of the Company and its subsidiaries, except for the limited recourse subsidiaries; and

c) a default if a default occurs that permits a creditor to demand repayment on any other indebtedness of $50 million or more of the Company and its subsidiaries, except for the limited recourse subsidiaries.

The Egypt limited recourse debt facilities have covenants and default provisions that apply only to the Egypt entity, including restrictions on the incurrence of additional indebtedness and requirement to fulfill certain conditions before the payment of cash or other shareholder distributions. Certain conditions had not been met, resulting in a restriction on shareholder distributions from the Egypt entity to December 31, 2017. Under amended terms reached in 2017, shareholder distributions are permitted if the average gas deliveries over the prior 12 months are greater than 70% of gas requirements. The first $100 million of shareholder distributions must be matched with $100 million of principal repayments on the Egypt limited recourse debt facilities. As at December 31, 2017, the Egypt cash balance on a 100% ownership basis was $131 million. The Egypt entity continues to be able to fully utilize its funds for operating, capital and financing needs, including the repayment of the Egypt limited recourse debt facilities and over the last 12 months has received all gas requirements.

As at December 31, 2017, management believes the Company was in compliance with all significant terms and default provisions related to its long-term debt obligations.

In 2017, we reached agreement with Empresa Nacional del Petróleo (“ENAP”) for additional gas supply in Chile and remain optimistic that our underutilized 1.7 million tonne Chile facilities represent a very low capital cost growth opportunity for Methanex due to the significant progress in developing natural gas reserves in the area. Project work has commenced for the restart of our Chile IV plant and remains targeted for the third quarter of 2018 and is budgeted for $55 million. If additional gas supply can be secured in Chile, the Chile IV project will be followed by the refurbishment of our Chile I plant in order to restore Chile to a two-plant operation at a very low capital cost. Our planned capital maintenance expenditure program directed towards maintenance, turnarounds and catalyst changes for existing operations is currently estimated to be in the range of $90 to $135 million to the end of 2018, dependent on the timing of turnarounds.

In January 2018, we announced a 10% increase in the quarterly dividend to $0.33 per share from $0.30 per share for the dividend payable March 31, 2018. We also announced in March 2018 that our Board of Directors has approved a new 10% share repurchase program, through a normal course issuer bid.

We believe we are well positioned to meet our financial commitments, pursue our near-term growth opportunities in Chile and deliver on our commitment to return excess cash to shareholders through dividends and share repurchases.

2017 Methanex Corporation Annual Report    21

Summary of Contractual Obligations and Commercial Commitments

A summary of the amount and estimated timing of cash flows related to our contractual obligations and minimum commercial commitments as at December 31, 2017 is as follows:

($ Millions)	2018		2019-2020		2021-2022		After 2022		Total
Long-term debt repayments	$	57	$	472	$	391	$	600	$	1,520
Long-term debt interest obligations		65		114		81		398		658
Repayments of other long-term liabilities		52		101		69		248		470
Natural gas and other		474		678		554		1,301		3,007
Operating lease commitments		91		147		77		164		479
	$	739	$	1,512	$	1,172	$	2,711	$	6,134

Long-Term Debt Repayments and Interest Obligations

We have $350 million of unsecured notes that mature in 2019, $250 million of unsecured notes that mature in 2022, $300 million of unsecured notes that mature in 2024 and $300 million of unsecured notes that mature in 2044. The remaining debt repayments represent the normal course obligations for principal repayments related to our limited recourse debt facilities. Interest obligations related to variable interest rate long-term debt were estimated using current interest rates in effect as at December 31, 2017. For additional information, refer to note 8 of our 2017 consolidated financial statements.

Repayments of Other Long-Term Liabilities

Repayments of other long-term liabilities represent contractual payment dates or, if the timing is not known, we have estimated the timing of repayment based on management’s expectations.

Natural Gas and Other

We have commitments under take-or-pay contracts to purchase natural gas, to pay for transportation capacity related to the delivery of natural gas and to purchase oxygen and other feedstock requirements. Take-or-pay means that we are obliged to pay for the supplies regardless of whether we take delivery. Such commitments are common in the methanol industry. These contracts generally provide a quantity that is subject to take-or-pay terms that is lower than the maximum quantity that we are entitled to purchase. The amounts disclosed in the table above represent only the minimum take-or-pay quantity.

The natural gas supply contracts for our facilities in New Zealand, Trinidad and Egypt are take-or-pay contracts denominated in United States dollars and include base and variable price components to reduce our commodity price risk exposure. The variable price component of each natural gas contract is adjusted by a formula related to methanol prices above a certain level. We believe this pricing relationship enables these facilities to be competitive throughout the methanol price cycle. The amounts disclosed in the table for these contracts represent only the base price component.

We also have multi-year fixed price natural gas contracts to supply one production facility in Geismar and Medicine Hat, and natural gas hedges in Geismar and Medicine Hat to manage exposure to natural gas price risk. We believe that the long-term natural gas dynamics in North America will support the long-term operation of these facilities. In the above table, we have included natural gas commitments in North America for Geismar and Medicine Hat at the contractual volume and prices.

The above table does not include costs for planned capital maintenance or expansion expenditures or any obligations with original maturities of less than one year.

Since June 2007, the Company’s natural gas suppliers from Argentina have curtailed all gas supply to the Company’s plants in Chile pursuant to long-term gas supply agreements. The Company has not received natural gas under these long-term agreements since 2007 and therefore potential future purchase obligations have been excluded from the table above.

We have marketing rights for 100% of the production from our jointly owned Atlas and Egypt plants which results in purchase commitments of an additional 1.3 million tonnes per year of methanol offtake supply when these plants operate at capacity. As at December 31, 2017, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2018 and 1.5 million tonnes in aggregate thereafter. The pricing under these purchase commitments is referenced to pricing at the time of purchase or sale, and accordingly, no amounts have been included in the table above.

22    2017 Methanex Corporation Annual Report

Operating Lease Commitments

We have future minimum lease payments under operating leases relating primarily to vessel charter, terminal facilities, office space and equipment. For additional information refer to the Anticipated Changes to International Financial Reporting Standards section on page 35 and Note 21 of our 2017 consolidated financial statements.

Off-Balance Sheet Arrangements

As at December 31, 2017, we did not have any off-balance sheet arrangements, as defined by applicable securities regulators in Canada and the United States, that have, or are reasonably likely to have, a current or future material effect on our results of operations or financial condition.

Financial Instruments

A financial instrument is any contract that gives rise to a financial asset of one party and a financial liability or equity instrument of another party. Financial instruments are either measured at amortized cost or fair value.

In the normal course of business, the Company’s assets, liabilities and forecasted transactions, as reported in U.S. dollars, are impacted by various market risks including, but not limited to, natural gas prices and currency exchange rates. The time frame and manner in which the Company manages those risks varies for each item based on the Company’s assessment of the risk and the available alternatives for mitigating risks.

The Company uses derivatives as part of its risk management program to mitigate variability associated with changing market values. Changes in fair value of derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges, in which case the changes in fair value are recorded in other comprehensive income and are reclassified to profit or loss when the underlying hedged transaction is recognized in earnings. The Company designates as cash flow hedges certain derivative financial instruments to hedge its risk exposure to fluctuations in natural gas prices and to hedge its risk exposure to fluctuations on certain foreign currency denominated transactions.

Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in commodity prices or foreign currency exchange rates.

The following table shows the carrying value of each of our categories of financial assets and liabilities and the related balance sheet item as at December 31, 2017 and December 31, 2016:

($ Millions)	2017		2016
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges1	$	–	$	7
Financial assets not measured at fair value:
Cash and cash equivalents		375		224
Trade and other receivables, excluding tax receivable		527		479
Project financing reserve accounts included in other assets		28		35
Total financial assets2	$	930	$	745
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges1	$	91	$	69
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable		528		449
Long-term debt, including current portion		1,502		1,556
Total financial liabilities	$	2,121	$	2,074

¹  The Geismar 2 and Medicine Hat natural gas hedges and euro foreign currency hedges designated as cash flow hedges are measured at fair value based on industry accepted valuation models and inputs obtained from active markets.

²  The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods.

As at December 31, 2017, all of the financial instruments were recorded on the consolidated statements of financial position at amortized cost with the exception of derivative financial instruments, which are recorded at fair value unless exempted.

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The fair value of derivative instruments is determined based on industry-accepted valuation models using market observable inputs and are classified within Level 2 of the fair value hierarchy. The fair value of all the Company’s derivative contracts includes an adjustment for credit risk. The effective portion of the changes in fair value of derivative financial instruments designated as cash flow hedges is recorded in other comprehensive income. The spot element of forward contracts in the hedging relationships is recorded in other comprehensive income as the change in fair value of cash flow hedges. The change in the fair value of the forward element of forward contracts is recorded separately in other comprehensive income as the forward element excluded from hedging relationships.

The Company has elected to manage its exposure to changes in natural gas prices for the Geismar 2 and Medicine Hat facilities by executing a number of forward contracts which it has designated as cash flow hedges for its highly probable forecast natural gas purchases in North America.

The Company also designates as cash flow hedges forward exchange contracts to sell certain foreign currencies at a fixed U.S. dollar exchange rate to hedge its exposure to exchange rate fluctuations on certain foreign currency denominated transactions.

RISK FACTORS AND RISK MANAGEMENT

We are subject to risks that require prudent risk management. We believe the following risks, in addition to those described in the Critical Accounting Estimates section on page 33, to be among the most important for understanding the issues that face our business and our approach to risk management.

Methanol Price

The methanol business is a highly competitive commodity industry and prices are affected by supply and demand fundamentals. Methanol prices have historically been, and are expected to continue to be, characterized by cyclicality. Factors influencing supply and demand for methanol and related risks are found below. We are not able to predict future methanol supply and demand balances, global economic activity, methanol prices or energy prices, all of which are affected by numerous factors beyond our control. Since methanol is the only product we produce and market, a decline in the price of methanol has a significant negative effect on our results of operations and financial condition.

Methanol Demand

Demand for methanol largely depends upon the level of energy prices, global economic growth rates and government regulations and policies.

Energy Prices

Approximately 45% of methanol demand is from energy-related applications. Over the past number of years, methanol demand growth has been led by strong demand from these applications, as relatively high oil prices generated an economic incentive to substitute lower cost methanol for petroleum products or as a feedstock in energy-related products. The fastest growing application where methanol serves as a substitute for an energy product is MTO, where methanol is an alternative feedstock in the production of olefins. Olefins have historically been made from ethane and naptha which are energy based feedstocks. Methanol can be blended directly with gasoline, and DME (a methanol derivative) can be blended with liquefied petroleum gas (propane). Because of this relationship, methanol demand is sensitive to the pricing of these energy products, which in turn are generally linked to global energy prices. We cannot provide assurance that energy prices will not negatively impact methanol demand growth, which could have an adverse effect on our results of operations and financial condition.

Global Economic Growth Rates

Approximately 55% of methanol demand is from traditional chemical applications. As these applications manufacture products used in a wide variety of industrial products and consumer goods, the rate of growth in demand for methanol from these applications tends to be correlated with overall global economic growth. Any slowdown in the global or regional economies can negatively impact demand for methanol and have a detrimental impact on methanol prices.

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Government Regulations and Policies

Changes in environmental, health and safety laws, regulations or requirements could impact methanol demand. The United States Environmental Protection Agency (“EPA”) is currently evaluating the human health effects of methanol as part of a standard review of chemicals under its Integrated Risk Information System (“IRIS”), a database of chemical health effects. No authoritative body has classified methanol as a carcinogen. A draft assessment for methanol was released by the EPA in 2010 classifying methanol as “Likely to be Carcinogenic to Humans.” In 2011, the EPA divided the draft assessment for methanol into cancer and non-cancer assessments. In September 2013, the EPA released the final non-cancer assessment, in which it established the maximum ingestion and inhalation levels for methanol that it claims will not result in adverse health impacts. The timeline for the final cancer assessment remains unknown, and no activity on the cancer assessment for methanol is currently contained on the EPA’s work plan. We are unable to determine whether the current draft classification will be maintained in the final cancer assessment or if this will lead other government agencies to reclassify methanol. Any reclassification could reduce future methanol demand, which could have an adverse effect on our results of operations and financial condition.

In 2017, methanol demand for the production of formaldehyde represented approximately 30% of global demand. The largest use for formaldehyde is as a component of urea-formaldehyde and phenol-formaldehyde resins, which are used in adhesives for plywood, particleboard, oriented strand board, medium-density fibreboard and other reconstituted or engineered wood products. There is also demand for formaldehyde as a raw material for engineering plastics and in the manufacture of a variety of other products, including elastomers, paints, building products, foams, polyurethane and automotive products.

The current EPA IRIS carcinogenicity classification for formaldehyde is “Likely to be Carcinogenic to Humans;” however, the EPA is reviewing this classification for formaldehyde as part of a standard review of chemicals. There is no firm time-line for the final assessment. In 2010, the EPA released its draft formaldehyde assessment, proposing formaldehyde as “Known to be Carcinogenic to Humans.” The National Toxicology Program (“NTP”) lists formaldehyde as “Known to be a Human Carcinogen” under the NTP Report on Carcinogens. EPA uses IRIS assessments as a basis for regulatory actions such as restricting emissions from products containing formaldehyde. The EPA continues to develop a revised IRIS assessment of formaldehyde.

In 2009, the US National Cancer Institute (“NCI”) published a report on the health effects of occupational exposure to formaldehyde and a possible link to leukemia, multiple myeloma and Hodgkin’s disease. The NCI report concluded that there may be an increased risk of cancers of the blood and bone marrow related to a measure of peak formaldehyde exposure. The NCI report was the first part of an update of the 2004 NCI study that indicated possible links between formaldehyde exposure and nasopharyngeal cancer and leukemia. The International Agency for Research on Cancer also concluded that there is sufficient evidence in humans of a causal association of formaldehyde with leukemia. In 2011, the U.S. Department of Health and Human Services’ National Toxicology Program released its 12th Report on Carcinogens, modifying its listing of formaldehyde from “Reasonably Anticipated to be a Human Carcinogen” to “Known to be a Human Carcinogen.”

We are unable to determine at this time if the EPA or other governments or government agencies will reclassify formaldehyde or what limits could be imposed related to formaldehyde emissions in the United States or elsewhere. Any such actions could reduce future methanol demand for use in producing formaldehyde, which could have an adverse effect on our results of operations and financial condition.

Methanol Supply

An increase in competitively priced methanol supply, all else equal, can displace supply from higher cost producers and have a negative impact on methanol price. Methanol supply is influenced by the cost of production including the availability and cost of raw materials, freight costs, capital costs and government policies. Methanol supply can become available from the construction of new methanol plants, by restarting idle methanol plants, by carrying out major expansions of existing plants or by debottlenecking existing plants to increase their production capacity.

There was no significant new industry capacity additions outside of China in 2017. In China, we estimate that approximately two million tonnes of new production capacity was added in 2017.

Over the next few years, the majority of large-scale capacity additions outside of China are expected to be in North America and the Middle East. OCI N.V. and Consolidated Energy Limited (through its subsidiary G2X Energy) continue to advance their jointly owned

2017 Methanex Corporation Annual Report    25

Natgasoline project, a 1.8 million tonne plant under construction in Beaumont, Texas with methanol production expected in 2018. There are a number of other large-scale projects under discussion in the United States; however, we believe that there has been limited committed capital to date. In Iran, there are a number of plants at various stages of construction. We expect just over four million tonnes of capacity to come onstream in Iran over the next two years; however, the start-up timing and future operating rates at these facilities will be dependent on various factors. Caribbean Gas Chemical Limited (“CGCL”) is constructing a 1.0 million tonne plant in Trinidad with announced production towards the end of the decade. To the end of 2018, we expect approximately two million tonnes of new capacity additions in China. Beyond 2018, we anticipate that new capacity additions in China will be modest due to increasing restrictions placed by the Chinese government on new coal-based capacity additions. We expect that production from new capacity in China will be consumed in that country.

We cannot provide assurance that new supply additions will not outpace the level of future demand growth thereby contributing to negative pressure on methanol price.

Security of Natural Gas Supply and Price

Natural gas is the principal feedstock for producing methanol and it accounts for a significant portion of our operating costs. Accordingly, our results from operations depend in large part on the availability and security of supply and the price of natural gas. If, for any reason, we are unable to obtain sufficient natural gas for any of our plants on commercially acceptable terms or we experience interruptions in the supply of contracted natural gas, we could be forced to curtail production or close such plants, which could have an adverse effect on our results of operations and financial condition.

New Zealand

We have three plants in New Zealand with a total production capacity of up to 2.4 million tonnes of methanol per year, depending on natural gas composition. Two plants are located at Motunui and the third is located at nearby Waitara Valley. We have entered into several agreements with various natural gas suppliers to underpin our New Zealand operations with terms that range in length up to 2022. All agreements in New Zealand are take-or-pay agreements and include U.S. dollar base and variable price components where the variable price component is adjusted by a formula related to methanol prices above a certain level. We believe this pricing relationship enables these facilities to be competitive at all points in the methanol price cycle and provides gas suppliers with attractive returns. Certain of these contracts require the supplier to deliver a minimum amount of natural gas with additional volume dependent on the success of exploring and developing the related natural gas field.

We continue to pursue opportunities to contract additional natural gas to supply our plants in New Zealand.

The future operation of our New Zealand facilities depends on the ability of our contracted suppliers to meet their commitments and the success of ongoing exploration and development activities in the region. We cannot provide assurance that our contracted suppliers will be able to meet their commitments or that their ongoing exploration and development activities in New Zealand will be successful to enable our operations to operate at capacity. We cannot provide assurance that we will be able to obtain natural gas with the optimum composition. These factors could have an adverse impact on our results of operations and financial condition.

United States

We have two plants in Geismar, Louisiana with a total production capacity of 2.0 million tonnes. The Geismar facilities commenced first methanol production in 2015.

We have a long-term fixed price agreement for the supply of substantially all of the natural gas requirements for the Geismar 1 facility that expires in 2025.

During 2015, we entered into forward contracts to hedge natural gas prices for the Geismar 2 facility through 2025. We have hedged approximately 40% of the natural gas requirements with the remainder of natural gas requirements at Geismar purchased in the spot market.

We believe that the long-term natural gas dynamics in North America will support the long-term operations of these facilities; however, we cannot provide assurance that our contracted suppliers will be able to meet their commitments or that we will be able to secure additional natural gas on commercially acceptable terms and this could have an adverse impact on our results of operations and financial condition.

26    2017 Methanex Corporation Annual Report

Trinidad

Natural gas for our two methanol production facilities in Trinidad, with our share of total production capacity being 2.0 million tonnes per year, is supplied under take-or-pay contracts with the National Gas Company of Trinidad and Tobago Limited (“NGC”), which purchases the natural gas from upstream gas producers. Gas paid for, but not taken, in any year may be received in subsequent years subject to limitations. The contracts for Titan and Atlas have U.S. dollar base and variable price components, where the variable portion is adjusted by a formula related to methanol prices above a certain level. The contract for Atlas expires in 2024 and the contract for Titan expires in 2019. We believe the supply and demand fundamentals for natural gas in Trinidad will support the continued operation of these facilities.

Since 2011, large industrial consumers in Trinidad, including our Titan and Atlas facilities, have experienced curtailments of natural gas supply due to a mismatch between upstream supply to NGC and downstream demand from NGC’s customers. Although Trinidad’s gas supply has stabilized in 2017 as a result of commissioning certain upstream facilities, we expect that gas curtailments to our facilities will continue in 2018. We cannot provide assurance that our contracted gas suppliers will be able to fully meet their commitments, that we will not experience longer or greater than anticipated curtailments due to upstream outages or other issues in Trinidad and that these curtailments will not be material. These factors could have an adverse impact on our results of operations and financial condition.

Egypt

We have a 25-year, take-or-pay natural gas supply agreement expiring in 2036 for the 1.26 million tonne per year methanol plant in Egypt in which we have a 50% equity interest. The price paid for gas is based on a U.S. dollar base price plus a variable price component that is adjusted by a formula related to methanol prices above a certain level. Under the contract, the gas supplier is obligated to supply, and we are obliged to take or pay for, a specified annual quantity of natural gas. Gas paid for, but not taken, in any year may be received in subsequent years subject to limitations. In addition, the natural gas supply agreement has a mechanism whereby we are partially compensated when gas delivery shortfalls in excess of a certain threshold occur. Natural gas is supplied to this facility from the same gas delivery grid infrastructure that supplies other industrial users in Egypt, as well as the general Egyptian population.

Since the plant commenced operations in 2011, Egypt has experienced significant social unrest, including acts of sabotage and government transitions resulting in an adverse impact on the country’s economy and our operations in Egypt. We believe that these factors have contributed to constraints in the development of new supplies of natural gas coming to market and to natural gas supply becoming constrained between mid-2012 and late-2016, resulting in our Egypt plant operating below full capacity.

Since late-2016, gas deliveries have improved significantly and we have received 100% of contracted gas supply. This is largely a result of the Egyptian government’s significant efforts to improve the gas supply situation in the country by encouraging natural gas exploration and establishing LNG import infrastructure. These efforts coupled with continuing natural gas discoveries have further strengthened the natural gas supply and demand balance and outlook for gas deliveries in Egypt.

In spite of these positive developments in Egypt, the restrictions experienced in recent years may persist in the future. We cannot provide assurance that we will not experience natural gas restrictions and that this would not have an adverse impact on our results of operations and financial condition.

Canada

We have entered into fixed price contracts to supply substantially all of our natural gas requirements for our Medicine Hat facility through 2031. In addition to existing hedges in place through 2022, we entered into a long-term, fixed price physical supply contract in 2017 with a progressively growing supply commitment starting in 2018 and growing to 80-90% of the plant’s natural gas requirements from 2023 through 2031.

We cannot provide assurance that our contracted suppliers will be able to meet their commitments or that we will be able to continue to secure sufficient natural gas for our Medicine Hat facility on commercially acceptable terms and that this will not have an adverse impact on our results of operations and financial condition.

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Chile

In June 2007, our natural gas suppliers from Argentina curtailed all gas supplied to our plants in Chile pursuant to long-term gas supply agreements. In 2018, we do not expect to receive any further natural gas supply from Argentina under such long-term gas supply agreements. In November 2016, we executed a tolling agreement with YPF S.A. pursuant to which we receive natural gas from Argentina and convert the natural gas received into methanol and then re-deliver the methanol to Argentina. In January 2018, we started receiving some natural gas from Argentina under this arrangement.

Since 2015, Empresa Nacional del Petróleo (“ENAP”) has made significant investments in the development of natural gas from unconventional reservoirs in Chile and this effort has resulted in increased gas deliveries from ENAP to our facilities. In January 2016, the U.S. Geological Survey assessed a technically recoverable mean resource of 8.3 trillion cubic feet of unconventional tight gas in the Chilean Magallanes Province. However, the potential for a sustained increase in gas deliveries to our plants will depend on the economics of the development of gas discoveries and, ultimately, the price at which we can obtain gas. In November 2017, Methanex reached a new agreement with ENAP for additional gas supply through December 31, 2019.

We are continuing to work with gas suppliers in Chile and Argentina to secure sufficient natural gas to sustain our Chile operations beyond December 2019 and into the future.

The future of our Chile operations is primarily dependent on the level of exploration and development of natural gas in southern Chile and our ability to secure a sustainable natural gas supply to our facilities on economic terms from Chile and Argentina. We cannot provide assurance that we will be able to continue to secure a sustainable natural gas supply to our facilities on economic terms and that this will not have an adverse impact on our results of operations or financial condition.

Global Economic Conditions

In addition to the potential influence of global economic activity levels on methanol demand and price, changing global economic conditions can result in changes in capital markets. A deterioration in economic conditions could have a negative impact on our investments, diminish our ability to access existing or future credit and increase the risk of defaults by customers, suppliers, insurers and other counterparties.

Foreign Operations

A significant portion of our operations and investments are located outside of North America, in New Zealand, Trinidad, Egypt, Chile, Europe and Asia. We are subject to risks inherent in foreign operations such as loss of revenue, property and equipment as a result of expropriation; import or export restrictions; anti-dumping measures; nationalization, war, insurrection, civil unrest, sabotage, terrorism and other political risks; increases in duties, taxes and governmental royalties; renegotiation of contracts with governmental entities; as well as changes in laws or policies or other actions by governments that may adversely affect our operations. Many of the foregoing risks related to foreign operations may also exist for our domestic operations in North America.

Because we derive a significant portion of our revenues from production and sales by subsidiaries outside of Canada, the payment of dividends or the making of other cash payments or advances by these subsidiaries may be subject to restrictions or exchange controls on the transfer of funds in or out of the respective countries or result in the imposition of taxes on such payments or advances.

We have organized our foreign operations in part based on certain assumptions about various tax laws (including capital gains and withholding taxes), foreign currency exchange and capital repatriation laws and other relevant laws of a variety of foreign jurisdictions. While we believe that such assumptions are reasonable, we cannot provide assurance that foreign taxation or other authorities will reach the same conclusion. Further, if such foreign jurisdictions were to change or modify such laws, we could suffer adverse tax and financial consequences.

The dominant currency in which we conduct business is the United States dollar, which is also our reporting currency. The most significant components of our costs are natural gas feedstock and ocean-shipping costs and substantially all of these costs are incurred in United States dollars. Some of our underlying operating costs, capital expenditures and purchases of methanol, however, are incurred in currencies other than the United States dollar, principally the Canadian dollar, the Chilean peso, the Trinidad and Tobago dollar, the New Zealand dollar, the Euro, the Egyptian pound and the Chinese yuan. We are exposed to increases in the value of these currencies that could have the effect of increasing the United States dollar equivalent of cost of sales, operating expenses

28    2017 Methanex Corporation Annual Report

and capital expenditures. A portion of our revenue is earned in Euros, Canadian dollars and Chinese yuan. We are exposed to declines in the value of these currencies compared to the United States dollar, which could have the effect of decreasing the United States dollar equivalent of our revenue.

Trade in methanol is subject to duty in a number of jurisdictions. Methanol sold in China from any of our producing regions is currently subject to duties ranging from 0% to 5.5%. There can be no assurance that the duties will not increase, that duties will not be levied in other jurisdictions in the future or that we will be able to mitigate the impact of future duties, if levied, or that future duties will not have a significant negative effect.

Methanol is a globally traded commodity that is produced by many producers at facilities located around the world. Some producers and marketers may have direct or indirect contacts with countries that may, from time to time, be subject to international trade sanctions or other similar prohibitions (“Sanctioned Countries”). In addition to the methanol we produce, we purchase methanol from third parties under purchase contracts or on the spot market in order to meet our commitments to customers, and we also engage in product exchanges with other producers and marketers. We believe that we are in compliance with all applicable laws with respect to sales and purchases of methanol and product exchanges. However, as a result of the participation of Sanctioned Countries in our industry, we cannot provide assurance that we will not be exposed to reputational or other risks that could have an adverse impact on our results of operations and financial condition.

Liquidity Risk

As at December 31, 2017, we had a cash balance of $375 million, including $131 million of cash relating to our Egypt entity consolidated on a 100% basis and $25 million of cash related to our 50% equity interest in multiple ocean going vessels consolidated on a 100% basis. We have an undrawn $300 million revolving credit facility with a syndicate of banks that expires in December 2022 and our ability to maintain access to the facility is subject to meeting certain financial covenants, including an EBITDA to interest coverage ratio and a debt to capitalization ratio, both ratios calculated in accordance with definitions in the credit agreement that include adjustments related to the Company’s limited recourse subsidiaries. As previously described in the Liquidity and Capital Resources – Liquidity and Capitalization section on page 20, certain conditions had not been met under the Egypt limited recourse debt facilities, which resulted in a restriction on shareholder distributions from the Egypt entity to December 31, 2017. Under amended terms reached in 2017, shareholder distributions are permitted if the average gas deliveries over the prior 12 months are greater than 70% of gas requirements. The first $100 million of shareholder distributions must be matched with $100 million of principal repayments on the Egypt limited recourse debt facilities.

As at December 31, 2017, our long-term debt obligations include $1,200 million in unsecured notes, $241 million related to the Egypt limited recourse debt facilities (100% basis) and $73 million related to other limited recourse debt. The covenants governing the unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding the Egypt entity, and include restrictions on liens, sale and lease-back transactions, a merger or consolidation with another corporation or a sale of all or substantially all of the Company’s assets. The indenture also contains customary default provisions. The Egypt limited recourse debt facilities are described as limited recourse as they are secured only by the assets of the Egypt entity. Accordingly, the lenders to the limited recourse debt facilities have no recourse to the Company or its other subsidiaries. The Egypt limited recourse debt facilities have covenants and default provisions that apply only to the Egypt entity, including restrictions on the incurrence of additional indebtedness and a requirement to fulfill certain conditions before the payment of cash or other distributions.

For additional information regarding long-term debt, refer to note 8 of our 2017 consolidated financial statements.

We cannot provide assurance that we will be able to access new financing in the future on commercially acceptable terms or at all, or that the financial institutions providing the credit facility will have the ability to honour future draws. Additionally, failure to comply with any of the covenants or default provisions of the long-term debt facilities described above could result in a default under the applicable credit agreement that would allow the lenders to not fund future loan requests, accelerate the due date of the principal and accrued interest on any outstanding loans or restrict the payment of cash or other distributions. Any of these factors could have a significant negative effect on our results of operations, our ability to pursue and complete strategic initiatives or on our financial condition.

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Customer Credit Risk

Our customers are large global or regional petrochemical manufacturers or distributors and a number are highly leveraged. We monitor our customers’ financial status closely; however, some customers may not have the financial ability to pay for methanol in the future and this could have an adverse effect on our results from operations and financial condition. Credit losses have not been significant in the past.

Operational Risks

Production Risks

Most of our earnings are derived from the sale of methanol produced at our plants. Our business is subject to the risks of operating methanol production facilities, such as equipment breakdowns, interruptions in the supply of natural gas and other feedstocks, power failures, longer-than-anticipated planned maintenance activities, loss of port facilities, natural disasters or any other event, including unanticipated events beyond our control, that could result in a prolonged shutdown of any of our plants or impede our ability to deliver methanol to customers. A prolonged plant shutdown at any of our major facilities could have an adverse effect on our results of operations and financial condition.

Purchased Product Price Risk

In addition to the sale of methanol produced at our plants, we also purchase methanol produced by others on the spot market and through purchase contracts to meet our customer commitments and support our marketing efforts. We have adopted the first-in, first-out method of accounting for inventories and it generally takes between 30 and 60 days to sell the methanol we purchase. Consequently, we have the risk of holding losses on the resale of this product to the extent that methanol prices decrease from the date of purchase to the date of sale. Holding losses, if any, on the resale of purchased methanol could have an adverse effect on our results of operations and financial condition.

Distribution Risks

Excess capacity within our fleet of ocean vessels resulting from a prolonged plant shutdown or other event could have an adverse effect on our results of operations and financial condition as our vessel fleet is subject to fixed time charter costs. In the event we have excess shipping capacity, we may be able to mitigate some of the excess costs by entering into sub-charters or third-party backhaul arrangements, although the success of this mitigation is dependent on conditions within the broader global shipping industry. If we suffer any disruptions in our distribution system and are unable to mitigate these costs, this could have an adverse effect on our results from operations and financial condition.

Insurance Risks

Although we maintain operational and construction insurance, including business interruption insurance, we cannot provide assurance that we will not incur losses beyond the limits of, or outside the coverage of, such insurance or that insurers will be financially capable of honouring future claims. From time to time, various types of insurance for companies in the chemical and petrochemical industries have not been available on commercially acceptable terms or, in some cases, have been unavailable. We cannot provide assurance that in the future we will be able to maintain existing coverage or that premiums will not increase substantially.

Chile IV Project

We believe that our estimate for budgeted project costs and targeted completion date for our Chile IV restart project is reasonable. However, as we could be impacted by potential cost increases including the impact of costs due to labour shortages, we cannot provide any assurance that the cost estimates will not be exceeded or that the facility will begin commercial production within the targeted schedule, if at all, or that the facility will operate at its designed capacity or on a sustained basis. Any changes to the targeted timing of completion or estimated cost to complete the project or future ability to operate at production capacity could have an adverse impact on our results of operations and financial condition.

30    2017 Methanex Corporation Annual Report

New Capital Projects

As part of our strategy to strengthen our position as the global leader in the production and marketing of methanol, we intend to continue pursuing new opportunities to enhance our strategic position in the methanol industry. Our ability to successfully identify, develop and complete new capital projects is subject to a number of risks, including finding and selecting favourable locations for new facilities where sufficient natural gas and other feedstock is available with acceptable commercial terms, obtaining project or other financing on satisfactory terms, constructing and completing the projects within the contemplated budgets and schedules and other risks commonly associated with the design, construction and start-up of large complex industrial projects. We cannot provide assurance that we will be able to identify or develop new methanol projects.

Environmental Regulation

The countries in which we operate all have laws and regulations to which we are subject, governing the environment and the management of natural resources as well as the handling, storage, transportation and disposal of hazardous or waste materials. We are also subject to laws and regulations governing emissions and the import, export, use, discharge, storage, disposal and transportation of toxic substances. The products we use and produce are subject to regulation under various health, safety and environmental laws. Non-compliance with these laws and regulations may give rise to compliance orders, fines, injunctions, civil liability and criminal sanctions.

Laws and regulations protecting the environment have become more stringent in recent years and may, in certain circumstances, impose absolute liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may also expose us to liability for the conduct of, or conditions caused by others or for our own acts even if we complied with applicable laws at the time such acts were performed. To date, environmental laws and regulations have not had a significant adverse effect on our capital expenditures, earnings or competitive position. However, operating petrochemical manufacturing plants and distributing methanol exposes us to risks in connection with compliance with such laws and we cannot provide assurance that we will not incur significant costs or liabilities in the future.

Management of Emissions

Carbon dioxide (“CO₂”) is a by-product of the methanol production process. The amount of CO₂ generated by the methanol production process depends on the production technology, plant age, feedstock and any export of the by-product hydrogen. CO₂ emissions are also generated from our marine operations when fuel is consumed during the global transport of methanol. We monitor and manage our CO₂ emissions intensity, defined as the quantity of CO₂ released per unit of production or transported tonne, relating to both methanol production and marine operations. Our CO₂ emissions intensity has decreased over time due to newer technology and higher efficiency at our plants and in our vessel fleet. Plant efficiency, and thus CO₂ emissions, is highly dependent on the design of the methanol plant, and accordingly the CO₂ emission figure may vary from year to year depending on the mix of production assets and vessels in operation.

Under the United Nations Framework Convention on Climate Change through the Kyoto Protocol and more recently the Paris Agreement (in effect from 2020), many of the countries we operate in have agreed to put forth efforts to reduce GHG emissions. We are currently subject to GHG regulations in New Zealand, Canada and Chile, but our production in the United States, Trinidad and Egypt are not subject to such regulations.

In New Zealand, an Emissions Trading Scheme (“ETS”) imposes a carbon price on producers of fossil fuels, including natural gas, which is passed on to Methanex, increasing the cost of gas that Methanex purchases in New Zealand. However, as a trade-exposed company, Methanex is entitled to a free allocation of emissions units to partially offset those increased costs.

Recent reviews of the ETS and a newly elected government led by the Labour Party in New Zealand may make changes to climate change policies that might impact the price of carbon in New Zealand or industry entitlements to free allocations. In December 2017, the newly appointed Minister for Climate Change announced plans to introduce a Zero Carbon Act by October 2018, following public consultation during 2018. At this stage there is no meaningful detail as to the content of the proposed Act.

We do not expect the changes that have been implemented to date to have a material impact on our New Zealand business. Methanex has no information to believe that the new government will implement rapid or drastic revisions to current policy settings that would adversely affect our operations in New Zealand. Nevertheless, we cannot provide assurance that unanticipated changes to the ETS will not have a material impact on our business beyond 2018.

2017 Methanex Corporation Annual Report    31

Our Medicine Hat facility is located in the Canadian province of Alberta, which has an established GHG reduction regulation that applies to our plant. In 2017, the emissions reduction target was increased from 15% to 20%. To the extent Methanex cannot meet these emissions reduction targets we will incur additional cost to purchase offset credits. The cost of purchasing offset credits, based on the plant’s 2017 emissions intensity and its established GHG baseline intensity, was not material in 2017.

Starting in 2018, a new regulation in Alberta, the Carbon Competitiveness Incentive Regulation, (“CCIR”) will come into effect and will impact our compliance obligations. The CCIR sets a benchmark of 80% of baseline emissions. The total regulated emissions calculation incorporates indirect emissions (e.g., electricity consumption), but also provides a deduction to our facility emissions calculation recognizing the benefit of the injection of CO₂. Although certain regulations under the CCIR are still being drafted, we do not believe that the cost of compliance will be material. Nevertheless, we cannot provide assurance that unanticipated changes to the CCIR will not have a material impact on our business beyond 2018.

Chile has imposed a carbon tax of $5/tonne from 2017 on certain CO₂ emissions. The cost to our business of this tax was not material in 2017. However, the cost could increase if the scope of the legislation changes.

We cannot provide assurance over ongoing compliance with existing legislation or that future laws and regulations to which we are subject governing the environment and the management of natural resources as well as the handling, storage, transportation and disposal of hazardous or waste materials will not have an adverse effect on our results of operations and financial condition.

Reputational Risk

Damage to our reputation could result from the actual or perceived occurrence of any number of events, and could include any negative publicity (for example, with respect to our handling of environmental, health or safety matters), whether true or not. Although we believe that we conduct our operations in a prudent manner and that we take care in protecting our reputation, we do not ultimately have direct control over how we are perceived by others. Reputation loss may result in decreased investor confidence, an impediment to our overall ability to advance our projects or increased challenges in maintaining our social license to operate, which could have an adverse impact on our results of operations and financial condition.

Cyber Security

Our business processes rely on Information Technology (“IT”) systems that are interconnected with external networks, which increases the threat of cyber attack and the importance of cyber security. In particular, if a cyber attack was targeted at our production facilities or our ability to transport methanol, the result could harm our plants, people and our ability to meet customer commitments for a period of time. In addition, targeted attacks on our systems (or third parties that we rely on), failure of a key IT system or a breach in security measures designed to protect our IT systems could have an adverse impact on our results of operations, financial condition and reputation. We have previously been the subject of cyber attacks on our internal systems, but these incidents have not had a significant negative impact on our results of operations.

We have a comprehensive program to protect our assets, detect an intrusion and respond in the event of a cyber security incident. As the cyber threat landscape continues to evolve, we implement continuous mitigation efforts, including: cyber education for our staff, risk prioritized controls to protect against known and emerging threats; tools to provide automated monitoring and alerting; and backup and recovery systems to restore systems and return to normal operations. We may be required to commit additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks.

Methanex collects, uses and stores sensitive data in the normal course of business, including intellectual property, proprietary business information and personal information of Methanex’s employees and third parties. Despite our security measures in place, our IT systems may be vulnerable to cyber attacks or breaches. Any such breach could compromise information used or stored on our IT systems and/or networks and, as a result, the information could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties or other negative consequences, including disruption to our operations and damage to Methanex’s reputation, which could have an adverse impact on our results of operations and financial condition.

32    2017 Methanex Corporation Annual Report

Legal Proceedings

The Board of Inland Revenue of Trinidad and Tobago has issued assessments against our 63.1% owned joint venture, Atlas, in respect of the 2005 to 2011 financial years. All subsequent tax years remain open to assessment. The assessments relate to the pricing arrangements of certain long-term fixed-price sales contracts from 2005 to 2019 related to methanol produced by Atlas. Atlas had partial relief from corporation income tax until 2014.

We have lodged objections to the assessments. Although there can be no assurance that these tax assessments will not have a material adverse impact, based on the merits of the cases and legal interpretation, we believe our position should be sustained.

CRITICAL ACCOUNTING ESTIMATES

We believe the following selected accounting policies and issues are critical to understanding the estimates, assumptions and uncertainties that affect the amounts reported and disclosed in our consolidated financial statements and related notes. Certain of our accounting policies, including depreciation and amortization, recoverability of asset carrying values and income taxes require us to make assumptions about the price and availability of natural gas feedstock. See additional discussion of the risk factors and risk management by region in the Security of Natural Gas Supply and Price section on page 26. See note 2 to our 2017 consolidated financial statements for our significant accounting policies.

Property, Plant and Equipment

Our business is capital intensive and has required, and will continue to require, significant investments in property, plant and equipment. As at December 31, 2017, the net book value of our property, plant and equipment was $3.0 billion.

Capitalization

Property, plant and equipment are initially recorded at cost. The cost of purchased equipment includes expenditures that are directly attributable to the purchase price, delivery and installation. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to the location and condition for their intended use, the costs of dismantling and removing the items and restoring the site on which they are located and borrowing costs on self-constructed assets that meet certain criteria. Routine repairs and maintenance costs are expensed as incurred.

As at December 31, 2017, we had accrued $34 million for site restoration costs relating to the decommissioning and reclamation of our methanol production sites. Inherent uncertainties exist in this estimate because the restoration activities will take place in the future and there may be changes in governmental and environmental regulations and changes in removal technology and costs. It is difficult to estimate the future costs of these activities as our estimate of fair value is based on current regulations and technology. Because of uncertainties related to estimating the cost and timing of future site restoration activities, future costs could differ materially from the amounts estimated.

Depreciation and Amortization

Depreciation and amortization is generally provided on a straight-line basis at rates calculated to amortize the cost of property, plant and equipment from the commencement of commercial operations over their estimated useful lives to estimated residual value.

The estimated useful lives of the Company’s buildings, plant installations and machinery, excluding costs related to turnarounds, range from 10 to 25 years depending on the specific asset component and the production facility to which it is related. The Company determines the estimated useful lives of individual asset components based on the shorter of its physical life or economic life. The physical life of these assets is generally longer than the economic life. The economic life is primarily determined by the nature of the natural gas feedstock available to our various production facilities. Factors that influence the nature of natural gas feedstock availability include the terms of individual natural gas supply contracts, access to natural gas supply through open markets, regional factors influencing the exploration and development of natural gas and the expected price of securing natural gas supply. We review the factors related to each production facility on an annual basis to determine if changes are required to the estimated useful lives.

2017 Methanex Corporation Annual Report    33

Recoverability of Asset Carrying Values

Long-lived assets are tested for recoverability whenever events or changes in circumstances, either internal or external, indicate that the carrying amount may not be recoverable (“triggering events”). Examples of such triggering events related to our long-lived assets include, but are not restricted to: a significant adverse change in the extent or manner in which the asset is being used or in its physical condition; a change in management’s intention or strategy for the asset, which includes a plan to dispose of or idle the asset; a significant adverse change in our long-term methanol price assumption or in the price or availability of natural gas feedstock required to manufacture methanol; a significant adverse change in legal factors or in the business climate that could affect the asset’s value, including an adverse action or assessment by a foreign government that impacts the use of the asset; or a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the asset’s use.

When a triggering event is identified, recoverability of long-lived assets is measured by comparing the carrying value of an asset or cash-generating unit to the estimated recoverable amount, which is the higher of its estimated fair value less costs to sell or its value in use. Value in use is determined by measuring the pre-tax cash flows expected to be generated from the cash-generating unit over its estimated useful life discounted by a pre-tax discount rate. An impairment writedown is recorded if the carrying value exceeds the estimated recoverable amount. An impairment writedown recognized in prior periods for an asset or cash-generating unit is reversed if there has been a subsequent recovery in the value of the asset or cash-generating unit due to changes in events and circumstances. For the purposes of recognition and measurement of an impairment writedown or reversal, we group our long-lived assets with other assets and liabilities to form a “cash-generating unit” at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. To the extent that our methanol facilities in a particular location are interdependent as a result of common infrastructure and/or feedstock from shared sources that can be shared within a facility location, we group our assets based on site locations for the purpose of determining impairment.

There are two key variables that impact our estimate of future cash flows from producing assets: (1) the methanol price and (2) the price and availability of natural gas feedstock. Short-term methanol price estimates are based on current supply and demand fundamentals and current methanol prices. Long-term methanol price estimates are based on our view of long-term supply and demand, and consideration is given to many factors, including, but not limited to, estimates of global industrial production rates, energy prices, changes in general economic conditions, the ability for the industry to add further global methanol production capacity and earn an appropriate return on capital, industry operating rates and the global industry cost structure. Our estimate of the price and availability of natural gas takes into consideration the current contracted terms, as well as factors that we believe are relevant to supply under these contracts and supplemental natural gas sources. Other assumptions included in our estimate of future cash flows include the estimated cost incurred to maintain the facilities, estimates of transportation costs and other variable costs incurred in producing methanol in each period. Changes in these assumptions will impact our estimates of future cash flows and could impact our estimates of the useful lives of property, plant and equipment. Consequently, it is possible that our future operating results could be adversely affected by further asset impairment charges or by changes in depreciation and amortization rates related to property, plant and equipment.

The two methanol facilities at the Company’s Chile site are considered as a single cash-generating unit (“Chile cash-generating unit”). The current carrying value of the Chile cash-generating unit is approximately $110 million.

We recorded an impairment charge in the year ended December 31, 2012 to reduce the carrying value of our Chile assets to their estimated recoverable amount. We believe that there have been significant investments in the development of natural gas resources in Chile since 2015 that provide positive indications of gas availability in the region in the medium term; however, there is still uncertainty of our ability to access sufficient natural gas supply to our two plants economically. We do not believe that there are significant changes in events or circumstances that would support the reversal of the impairment charge recorded in the year ended December 31, 2012.

Income Taxes

We calculate current and deferred tax provisions for each of the jurisdictions in which we operate. Actual amounts of income tax expense are not final until tax returns are filed and accepted by the relevant tax authorities. This occurs subsequent to the issuance

34    2017 Methanex Corporation Annual Report

of the financial statements and the final determination of actual amounts may not be completed for a number of years. Transactions may be challenged by tax authorities and the Company’s operations may be assessed in subsequent periods, which could result in significant additional taxes, penalties and interest.

Deferred income tax assets and liabilities are determined using enacted or substantially enacted tax rates for the effects of net operating losses and temporary differences between the book and tax bases of assets and liabilities. We recognize deferred tax assets to the extent it is probable that taxable profit will be available against which the asset can be utilized. In making this determination, certain judgments are made relating to the level of expected future taxable income and to available tax-planning strategies and their impact on the use of existing loss carryforwards and other income tax deductions. Judgment is required in the application of income tax legislation. We are subject to assessments by various taxation authorities who may interpret tax legislation differently. These differences may affect the final amount or timing of the payment of taxes. We also consider historical profitability and volatility to assess whether we believe it is probable that the existing loss carryforwards and other income tax deductions will be used to offset future taxable income otherwise calculated. Management routinely reviews these judgments. As at December 31, 2017, we had recognized deferred tax assets of $102 million relating to non-capital loss carryforwards in the United States, $384 million of unrecognized deductible temporary differences in the United States and $110 million of unrecognized non-capital loss carryforwards in Egypt that expire in 2020 and 2021. If judgments or estimates in the determination of our current and deferred tax provision prove to be inaccurate, or if certain tax rates or laws change, or new interpretations or guidance emerge on the application of tax legislation, our results from operations and financial position could be materially impacted.

Financial Instruments

The Company uses derivatives as part of its risk management program to mitigate variability associated with changing market values. Changes in fair value of derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges, in which case the changes in fair value are recorded in other comprehensive income and are reclassified to profit or loss when the underlying hedged transaction is recognized in earnings. The Company designates as cash flow hedges certain derivative financial instruments to hedge its risk exposure to fluctuations in natural gas prices and to hedge its risk exposure to fluctuations on certain foreign currency denominated transactions. Assessment of contracts as derivative instruments, applicability of the own use exemption, the valuation of financial instruments and derivatives and hedge effectiveness assessments require a high degree of judgment and are considered critical accounting estimates due to the complex nature of these products and the potential impact on our financial statements.

ANTICIPATED CHANGES TO INTERNATIONAL FINANCIAL REPORTING STANDARDS

In May 2014, the IASB issued IFRS 15, Revenue from Contracts with Customers (“IFRS 15”) establishing a comprehensive framework for revenue recognition. The standard replaces IAS 18, Revenue and IAS 11, Construction Contracts and related interpretations and is effective for annual periods beginning on or after January 1, 2018, with early adoption permitted. The Company has performed its assessment of the impact of the new standard and anticipates no impact on its consolidated financial statements.

In January 2016, the IASB issued IFRS 16, Leases (“IFRS 16”), which eliminates the current operating/finance lease dual accounting model for lessees and replaces it with a single, on-balance sheet accounting model, similar to the current finance lease accounting. The standard replaces IAS 17, Leases (“IAS 17”) and related interpretations and is effective for annual periods beginning on or after January 1, 2019, with early application permitted. The Company plans to apply this standard at the date it becomes effective.

The Company is currently assessing the impact of the new standard including the optional exemptions available. The recognition of all leases on balance sheet is expected to increase the assets and liabilities on the Consolidated Statement of Financial Position upon adoption. The increase primarily relates to ocean vessels, terminal facilities and other right of use assets currently accounted for as operating leases. In addition, the nature and timing of certain expenses related to leases previously classified as operating and presented in cost of sales and operating expenses will now change and be presented in depreciation and amortization and finance costs. As a result, the Company expects that adoption of IFRS 16 will significantly impact the consolidated financial statements. The Company has not yet decided whether it will use the optional exemptions available under the standard. Refer to note 21, commitments and contingencies, for operating lease commitments as at December 31, 2017 disclosed under IAS 17.

2017 Methanex Corporation Annual Report    35

The Company does not expect that any other new or amended standards or interpretations that are effective as of January 1, 2018 will have a significant impact on the Company’s results of operations or financial position.

SUPPLEMENTAL NON-GAAP MEASURES

In addition to providing measures prepared in accordance with IFRS, we present certain supplemental measures that are not defined terms under IFRS (non-GAAP measures). These are Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share, Adjusted revenue, cash flow from operating activities before changes in non-cash working capital, and Operating income. These measures do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other companies. We believe these measures are useful in assessing the operating performance and liquidity of the Company’s ongoing business. We also believe Adjusted EBITDA is frequently used by securities analysts and investors when comparing our results with those of other companies.

These measures should be considered in addition to, and not as a substitute for, net income (loss), cash flows and other measures of financial performance and liquidity reported in accordance with IFRS.

Adjusted EBITDA (attributable to Methanex shareholders)

Adjusted EBITDA differs from the most comparable GAAP measure, net income (loss) attributable to Methanex shareholders, because it excludes finance costs, finance income and other expenses, income tax expense, depreciation and amortization, mark-to-market impact of share-based compensation and the Argentina gas settlement. Adjusted EBITDA includes an amount representing our 63.1% share of the Atlas facility and excludes the non-controlling shareholders’ interests in entities which we control but do not fully own.

Adjusted EBITDA and Adjusted net income (loss) exclude the mark-to-market impact of share-based compensation related to the impact of changes in our share price on SARs, TSARs, deferred share units, restricted share units and performance share units. The mark-to-market impact related to share-based compensation that is excluded from Adjusted EBITDA and Adjusted net income (loss) is calculated as the difference between the grant-date value and the fair value recorded at each period-end. As share-based awards will be settled in future periods, the ultimate value of the units is unknown at the date of grant and therefore the grant-date value recognized in Adjusted EBITDA and Adjusted net income (loss) may differ from the total settlement cost.

The following table shows a reconciliation from net income (loss) attributable to Methanex shareholders to Adjusted EBITDA:

($ Millions)	2017			2016
Net income (loss) attributable to Methanex shareholders	$	316		$	(13	)
U.S. tax reform charge		37			–
Mark-to-market impact of share-based compensation		68			22
Depreciation and amortization		232			228
Argentina gas settlement		–			(33	)
Finance costs		95			90
Finance income and other expenses		(13	)		(4	)
Income tax expense (recovery)		59			(9	)
Earnings of associate adjustment1		72			43
Non-controlling interests adjustment1		(28	)		(37	)
Adjusted EBITDA (attributable to Methanex shareholders)	$	838		$	287

¹  These adjustments represent finance costs, finance income and other expenses, income tax expense, and depreciation and amortization associated with our 63.1% interest in the Atlas methanol facility and the non-controlling interests.

36    2017 Methanex Corporation Annual Report

Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per Common Share

Adjusted net income (loss) and Adjusted net income (loss) per common share are non-GAAP measures because they exclude the mark-to-market impact of share-based compensation and the impact of certain items associated with specific identified events, including the U.S. tax reform charge and the Argentina gas settlement. The following table shows a reconciliation from net income (loss) attributable to Methanex shareholders to Adjusted net income (loss) and the calculation of Adjusted diluted net income (loss) per common share:

($ Millions, except number of shares and per share amounts)	2017			2016
Net income (loss) attributable to Methanex shareholders	$	316		$	(13	)
U.S. tax reform charge		37			–
Mark-to-market impact of share-based compensation, net of tax		56			19
Argentina gas settlement, net of tax		–			(21	)
Adjusted net income (loss)	$	409		$	(15	)
Diluted weighted average shares outstanding (millions)		87			90
Adjusted net income (loss) per common share	$	4.71		$	(0.17	)
Adjusted Revenue (attributable to Methanex shareholders) Adjusted revenue differs from the most comparable GAAP measure, revenue, because it excludes the non-controlling interests’ share of revenue, but includes an amount representing our 63.1% share of Atlas revenue and revenue on volume marketed on a commission basis related to 36.9% of the Atlas methanol facility and 50% of the Egypt methanol facility that we do not own. A reconciliation from revenue to Adjusted revenue is as follows:
($ Millions)	2017			2016
Revenue	$	3,061		$	1,998
Methanex share of Atlas revenue1		347			190
Non-controlling interests’ share of revenue1		(175	)		(67	)
Other adjustments		(6	)		(3	)
Adjusted revenue (attributable to Methanex shareholders)	$	3,227		$	2,118

¹ Excludes intercompany transactions with the Company.

Operating Income and Cash Flows from Operating Activities before Changes in Non-Cash Working Capital

Operating income and cash flows from operating activities before changes in non-cash working capital are reconciled to GAAP measures in our consolidated statements of income and consolidated statements of cash flows, respectively.

2017 Methanex Corporation Annual Report    37

QUARTERLY FINANCIAL DATA (UNAUDITED)

	Three months ended
($ Millions, except per share amounts)	Dec 31		Sep 30			Jun 30			Mar 31
2017
Revenue	$	861	$	720		$	669		$	810
Adjusted EBITDA		254		143			174			267
Adjusted net income		143		52			74			140
Net income (attributable to Methanex shareholders)		68		32			84			132
Adjusted net income per common share		1.70		0.60			0.85			1.56
Basic net income per common share		0.81		0.38			0.96			1.47
Diluted net income per common share		0.81		0.38			0.89			1.46
2016
Revenue	$	585	$	510		$	468		$	435
Adjusted EBITDA		139		74			38			36
Adjusted net income (loss)		41		(1	)		(31	)		(24	)
Net income (loss) (attributable to Methanex shareholders)		24		(11	)		(3	)		(23	)
Adjusted net income (loss) per common share		0.46		(0.01	)		(0.34	)		(0.27	)
Basic net income (loss) per common share		0.28		(0.12	)		(0.03	)		(0.26	)
Diluted net income (loss) per common share		0.28		(0.12	)		(0.08	)		(0.26	)

A discussion and analysis of our results for the fourth quarter of 2017 is set out in our fourth quarter of 2017 Management’s Discussion and Analysis filed with the Canadian Securities Administrators on SEDAR at www.sedar.com and the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov and is incorporated herein by reference.

SELECTED ANNUAL INFORMATION

($ Millions, except per share amounts)	2017		2016			2015
Revenue	$	3,061	$	1,998		$	2,226
Adjusted EBITDA		838		287			401
Adjusted net income (loss)		409		(15	)		110
Net income (loss) (attributable to Methanex shareholders)		316		(13	)		201
Adjusted net income (loss) per common share		4.71		(0.17	)		1.20
Basic net income (loss) per common share		3.64		(0.14	)		2.21
Diluted net income (loss) per common share		3.64		(0.14	)		2.01
Cash dividends declared per common share		1.175		1.100			1.075
Total assets		4,611		4,557			4,556
Total long-term financial liabilities		1,851		1,853			1,720

38    2017 Methanex Corporation Annual Report

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures are those controls and procedures that are designed to ensure that the information required to be disclosed in the filings under applicable securities regulations is recorded, processed, summarized and reported within the time periods specified. As of December 31, 2017, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective as of that date.

Management’s Annual Report on Internal Control over Financial Reporting

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

The design of any system of controls and procedures is based in part upon certain assumptions about the likelihood of future events. There can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.

Under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, management conducted an evaluation of the effectiveness of our internal control over financial reporting, as of December 31, 2017, based on the framework set forth in Internal Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under this framework, management concluded that our internal control over financial reporting was effective as of that date.

KPMG LLP, an independent registered public accounting firm that audited and reported on our consolidated financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2017. The attestation report is included in our consolidated financial statements on page 44.

Changes in Internal Control over Financial Reporting

There have been no changes during the year ended December 31, 2017 to internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.

2017 Methanex Corporation Annual Report    39

FORWARD-LOOKING STATEMENTS

This 2017 Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements with respect to us and our industry. These statements relate to future events or our future performance. All statements other than statements of historical fact are forward-looking statements. Statements that include the words “believes,” “expects,” “may,” “will,” “should,” “potential,” “estimates,” “anticipates,” “aim”, “goal” or other comparable terminology and similar statements of a future or forward-looking nature identify forward-looking statements.

More particularly, and without limitation, any statements regarding the following are forward-looking statements:

∎ expected demand for methanol and its derivatives,

∎ expected new methanol supply or restart of idled capacity and timing for start-up of the same,

∎ expected shutdowns (either temporary or permanent) or restarts of existing methanol supply (including our own facilities), including, without limitation, the timing and length of planned maintenance outages,

∎ expected methanol and energy prices,

∎ expected levels of methanol purchases from traders or other third parties,

∎ expected levels, timing and availability of economically priced natural gas supply to each of our plants,

∎ capital committed by third parties towards future natural gas exploration and development in the vicinity of our plants,

∎ our expected capital expenditures,

∎ anticipated operating rates of our plants,

∎ expected operating costs, including natural gas feedstock costs and logistics costs,

∎ expected tax rates or resolutions to tax disputes,

∎ expected cash flows, earnings capability and share price,

∎ availability of committed credit facilities and other financing,

∎ our ability to meet covenants or obtain or continue to obtain waivers associated with our long-term debt obligations, including, without limitation, the Egypt limited recourse debt facilities that have conditions associated with the payment of cash or other distributions and the finalization of certain land title registrations and related mortgages which require actions by Egyptian governmental entities,

∎ expected impact on our results of operations in Egypt or our financial condition as a consequence of civil unrest or actions taken or inaction by Egyptian governmental entities,

∎ our shareholder distribution strategy and anticipated distributions to shareholders,

∎ commercial viability and timing of, or our ability to execute, future projects, plant restarts, capacity expansions, plant relocations or other business initiatives or opportunities,

∎ our financial strength and ability to meet future financial commitments,

∎ expected global or regional economic activity (including industrial production levels),

∎ expected outcomes of litigation or other disputes, claims and assessments, and

∎ expected actions of governments, governmental agencies, gas suppliers, courts, tribunals or other third parties.

We believe that we have a reasonable basis for making such forward-looking statements. The forward-looking statements in this document are based on our experience, our perception of trends, current conditions and expected future developments as well as other factors. Certain material factors or assumptions were applied in drawing the conclusions or making the forecasts or projections that are included in these forward-looking statements, including, without limitation, future expectations and assumptions concerning the following:

∎ the supply of, demand for and price of methanol, methanol derivatives, natural gas, coal, oil and oil derivatives,

∎ our ability to procure natural gas feedstock on commercially acceptable terms,

∎ operating rates of our facilities,

∎ receipt or issuance of third-party consents or approvals, including, without limitation, governmental registrations of land title and related mortgages in Egypt and governmental approvals related to rights to purchase natural gas,

∎ the establishment of new fuel standards,

40    2017 Methanex Corporation Annual Report

∎ operating costs, including natural gas feedstock and logistics costs, capital costs, tax rates, cash flows, foreign exchange rates and interest rates,

∎ the availability of committed credit facilities and other financing,

∎ global and regional economic activity (including industrial production levels),

∎ absence of a material negative impact from major natural disasters,

∎ absence of a material negative impact from changes in laws or regulations,

∎ absence of a material negative impact from political instability in the countries in which we operate, and

∎ enforcement of contractual arrangements and ability to perform contractual obligations by customers, natural gas and other suppliers and other third parties.

However, forward-looking statements, by their nature, involve risks and uncertainties that could cause actual results to differ materially from those contemplated by the forward-looking statements. The risks and uncertainties primarily include those attendant with producing and marketing methanol and successfully carrying out major capital expenditure projects in various jurisdictions, including, without limitation:

∎ conditions in the methanol and other industries including fluctuations in the supply, demand and price for methanol and its derivatives, including demand for methanol for energy uses,

∎ the price of natural gas, coal, oil and oil derivatives,

∎ our ability to obtain natural gas feedstock on commercially acceptable terms to underpin current operations and future production growth opportunities,

∎ the ability to carry out corporate initiatives and strategies,

∎ actions of competitors, suppliers and financial institutions,

∎ conditions within the natural gas delivery systems that may prevent delivery of our natural gas supply requirements,

∎ competing demand for natural gas, especially with respect to domestic needs for gas and electricity in Chile and Egypt,

∎ actions of governments and governmental authorities, including, without limitation, implementation of policies or other measures that could impact the supply of or demand for methanol or its derivatives,

∎ changes in laws or regulations,

∎ import or export restrictions, anti-dumping measures, increases in duties, taxes and government royalties and other actions by governments that may adversely affect our operations or existing contractual arrangements,

∎ worldwide economic conditions, and

∎ other risks described in this 2017 MD&A.

Having in mind these and other factors, investors and other readers are cautioned not to place undue reliance on forward-looking statements. They are not a substitute for the exercise of one’s own due diligence and judgment. The outcomes implied in forward-looking statements may not occur and we do not undertake to update forward-looking statements except as required by applicable securities laws.

2017 Methanex Corporation Annual Report    41

EX-99.3

Exhibit 99.3

Responsibility for Financial Reporting

The consolidated financial statements and all financial information contained in the annual report are the responsibility of management.

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards and, where appropriate, have incorporated estimates based on the best judgment of management.

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the internal control framework set out in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2017.

The Board of Directors (“the Board”) is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control, and is responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through the Audit, Finance and Risk Committee (“the Committee”).

The Committee consists of four non-management directors, all of whom are independent as defined by the applicable rules in Canada and the United States. The Committee is appointed by the Board to assist the Board in fulfilling its oversight responsibility relating to: the integrity of the Company’s financial statements, news releases and securities filings; the financial reporting process; the systems of internal accounting and financial controls; the professional qualifications and independence of the external auditor; the performance of the external auditors; risk management processes; financing plans; pension plans; and the Company’s compliance with ethics policies and legal and regulatory requirements.

The Committee meets regularly with management and the Company’s auditors, KPMG LLP, Chartered Professional Accountants, to discuss internal controls and significant accounting and financial reporting issues. KPMG has full and unrestricted access to the Committee. KPMG audited the consolidated financial statements and the effectiveness of internal controls over financial reporting. Their opinions are included in the annual report.

  A. Terence Poole Chairman of the Audit, Finance and Risk Committee March 5, 2018   John Floren President and Chief Executive Officer   Ian Cameron Senior Vice President, Finance and Chief Financial Officer

42    2017 Methanex Corporation Annual Report

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Methanex Corporation:

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of Methanex Corporation (the “Company”) as of December 31, 2017, and 2016, the related consolidated statements of income (loss), comprehensive income (loss), changes in equity and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”).

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

Report on Internal Control over Financial Reporting

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 5, 2018, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements 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 and in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

Chartered Professional Accountants

We have served as the Company’s auditor since 1992.

Vancouver, Canada

March 5, 2018

2017 Methanex Corporation Annual Report    43

Report of Independent Registered Public Accounting Firm

The Shareholders and Board of Directors of Methanex Corporation:

Opinion on Internal Control Over Financial Reporting

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

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

Report on the Financial Statements

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated statements of financial position of the Company as of December 31, 2017, and 2016, the related consolidated statements of income (loss), comprehensive income (loss), changes in equity and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”) and our report dated March 5, 2018 expressed an unqualified opinion on those financial statements.

Basis for Opinion

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

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

44    2017 Methanex Corporation Annual Report

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

Vancouver, Canada

March 5, 2018

2017 Methanex Corporation Annual Report    45

Consolidated Statements of Financial Position

(thousands of U.S. dollars, except number of common shares)

As at	Dec 31 2017			Dec 31 2016
ASSETS
Current assets:
Cash and cash equivalents	$	375,479		$	223,890
Trade and other receivables (note 3)		536,636			499,603
Inventories (note 4)		304,464			281,328
Prepaid expenses		26,548			20,846
		1,243,127			1,025,667
Non-current assets:
Property, plant and equipment (note 5)		2,998,326			3,117,469
Investment in associate (note 6)		188,922			197,402
Deferred income tax assets (note 15)		102,341			137,341
Other assets (note 7)		78,026			78,784
		3,367,615			3,530,996
	$	4,610,742		$	4,556,663
LIABILITIES AND EQUITY
Current liabilities:
Trade, other payables and accrued liabilities	$	626,817		$	523,216
Current maturities on long-term debt (note 8)		55,905			53,997
Current maturities on other long-term liabilities (note 9)		65,226			29,720
		747,948			606,933
Non-current liabilities:
Long-term debt (note 8)		1,446,366			1,502,209
Other long-term liabilities (note 9)		404,885			351,191
Deferred income tax liabilities (note 15)		266,432			290,980
		2,117,683			2,144,380
Equity:
Capital stock
25,000,000 authorized preferred shares without nominal or par value
Unlimited authorization of common shares without nominal or par value
Issued and outstanding common shares at December 31, 2017 were 83,770,254 (2016 – 89,824,338)		480,331			511,465
Contributed surplus		2,124			2,568
Retained earnings		1,088,150			1,124,104
Accumulated other comprehensive loss		(69,841	)		(41,302	)
Shareholders’ equity		1,500,764			1,596,835
Non-controlling interests		244,347			208,515
Total equity		1,745,111			1,805,350
	$	4,610,742		$	4,556,663

Commitments and contingencies (notes 6 and 21)

Subsequent events (note 8)

See accompanying notes to consolidated financial statements.

Approved by the Board:

  A. Terence Poole (Director)   John Floren (Director)

46    2017 Methanex Corporation Annual Report

Consolidated Statements of Income (Loss)

(thousands of U.S. dollars, except number of common shares and per share amounts)

For the years ended December 31	2017			2016
Revenue	$	3,060,642		$	1,998,429
Cost of sales and operating expenses (note 10)		(2,351,949	)		(1,774,429	)
Depreciation and amortization (note 10)		(232,225	)		(228,054	)
Argentina gas settlement		–			32,500
Operating income		476,468			28,446
Earnings of associate (note 6)		75,995			19,930
Finance costs (note 11)		(94,955	)		(90,060	)
Finance income and other expenses		13,377			4,180
Income (loss) before income taxes		470,885			(37,504	)
Income tax recovery (expense) (note 15):
Current		(85,504	)		(54,677	)
Deferred		(10,284	)		63,956
		(95,788	)		9,279
Net income (loss)	$	375,097		$	(28,225	)
Attributable to:
Methanex Corporation shareholders	$	316,135		$	(12,545	)
Non-controlling interests (note 23)		58,962			(15,680	)
	$	375,097		$	(28,225	)
Income (loss) per common share for the period attributable to Methanex Corporation shareholders:
Basic net income (loss) per common share (note 12)	$	3.64		$	(0.14	)
Diluted net income (loss) per common share (note 12)	$	3.64		$	(0.14	)
Weighted average number of common shares outstanding		86,768,589			89,783,883
Diluted weighted average number of common shares outstanding		86,824,948			89,783,883

See accompanying notes to consolidated financial statements.

2017 Methanex Corporation Annual Report    47

Consolidated Statements of Comprehensive Income (Loss)

(thousands of U.S. dollars)

For the years ended December 31	2017			2016
Net income (loss)	$	375,097		$	(28,225	)
Other comprehensive income (loss):
Items that may be reclassified to income:
Change in fair value of cash flow hedges (note 18)		(74,790	)		153,863
Forward elements excluded from hedging relationship (note 18)		45,416			(174,078	)
Items that will not be reclassified to income:
Actuarial gains (losses) on defined benefit pension plans (note 20(a))		564			(77	)
Taxes on above items		674			6,597
		(28,136	)		(13,695	)
Comprehensive income (loss)	$	346,961		$	(41,920	)
Attributable to:
Methanex Corporation shareholders	$	287,999		$	(26,240	)
Non-controlling interests (note 23)		58,962			(15,680	)
	$	346,961		$	(41,920	)

See accompanying notes to consolidated financial statements.

48    2017 Methanex Corporation Annual Report

Consolidated Statements of Changes in Equity

(thousands of U.S. dollars, except number of common shares)

	Number of common shares			Capital stock			Contributed surplus			Retained earnings			Accumulated other comprehensive loss			Shareholders’ equity			Non-controlling interests			Total equity
Balance, December 31, 2015		89,671,198		$	509,464		$	2,426		$	1,235,615		$	(27,776)		$	1,719,729		$	248,844		$	1,968,573
Net loss		–			–			–			(12,545	)		–			(12,545	)		(15,680	)		(28,225	)
Other comprehensive loss		–			–			–			(169	)		(13,526	)		(13,695	)		–			(13,695	)
Compensation expense recorded for stock options		–			–			637			–			–			637			–			637
Issue of shares on exercise of stock options		153,140			1,506			–			–			–			1,506			–			1,506
Reclassification of grant-date fair value on exercise of stock options		–			495			(495	)		–			–			–			–			–
Dividend payments to Methanex Corporation shareholders ($1.10 per common share)		–			–			–			(98,797	)		–			(98,797	)		–			(98,797	)
Distributions made and accrued to non-controlling interests		–			–			–			–			–			–			(24,674	)		(24,674	)
Equity contributions by non-controlling interests		–			–			–			–			–			–			25			25
Balance, December 31, 2016		89,824,338		$	511,465		$	2,568		$	1,124,104		$	(41,302	)	$	1,596,835		$	208,515		$	1,805,350
Net income		–			–			–			316,135			–			316,135			58,962			375,097
Other comprehensive income (loss)		–			–			–			403			(28,539	)		(28,136	)		–			(28,136	)
Compensation expense recorded for stock options		–			–			488			–			–			488			–			488
Issue of shares on exercise of stock options		98,274			3,059			–			–			–			3,059			–			3,059
Reclassification of grant-date fair value on exercise of stock options		–			932			(932	)		–			–			–			–			–
Payment for shares repurchased		(6,152,358	)		(35,125	)		–			(250,995	)		–			(286,120	)		–			(286,120	)
Dividend payments to Methanex Corporation shareholders ($1.175 per common share)		–			–			–			(101,497	)		–			(101,497	)		–			(101,497	)
Distributions made and accrued to non-controlling interests		–			–			–			–			–			–			(31,300	)		(31,300	)
Equity contributions by non-controlling interests		–			–			–			–			–			–			8,170			8,170
Balance, December 31, 2017		83,770,254		$	480,331		$	2,124		$	1,088,150		$	(69,841	)	$	1,500,764		$	244,347		$	1,745,111

See accompanying notes to consolidated financial statements.

2017 Methanex Corporation Annual Report    49

Consolidated Statements of Cash Flows

(thousands of U.S. dollars)

For the years ended December 31	2017			2016
CASH FLOWS FROM / (USED IN) OPERATING ACTIVITIES
Net income (loss)	$	375,097		$	(28,225	)
Deduct earnings of associate		(75,995	)		(19,930	)
Dividends received from associate		84,553			47,325
Add (deduct) non-cash items:
Depreciation and amortization		232,225			228,054
Income tax expense (recovery)		95,788			(9,279	)
Share-based compensation expense		78,821			33,493
Finance costs		94,955			90,060
Other		4,033			1,559
Income taxes paid		(35,890	)		(5,241	)
Other cash payments, including share-based compensation		(16,477	)		(23,505	)
Cash flows from operating activities before undernoted		837,110			314,311
Changes in non-cash working capital (note 16(a))		(49,368	)		(87,644	)
		787,742			226,667
CASH FLOWS FROM / (USED IN) FINANCING ACTIVITIES
Payments for repurchase of shares		(286,120	)		–
Dividend payments to Methanex Corporation shareholders		(101,497	)		(98,797	)
Interest paid		(86,041	)		(82,965	)
Net proceeds on issue of long-term debt		–			65,700
Repayment of long-term debt and financing fees		(56,997	)		(48,417	)
Finance leases		(6,880	)		(5,144	)
Equity contributions by non-controlling interests		8,170			25
Cash distributions to non-controlling interests		(4,330	)		(1,410	)
Proceeds on issue of shares on exercise of stock options		3,059			1,506
		(530,636	)		(169,502	)
CASH FLOWS FROM / (USED IN) INVESTING ACTIVITIES
Property, plant and equipment		(103,170	)		(99,881	)
Other assets		–			(66	)
Changes in non-cash working capital related to investing activities (note 16(a))		(2,347	)		11,738
		(105,517	)		(88,209	)
Increase (decrease) in cash and cash equivalents		151,589			(31,044	)
Cash and cash equivalents, beginning of year		223,890			254,934
Cash and cash equivalents, end of year	$	375,479		$	223,890

See accompanying notes to consolidated financial statements.

50    2017 Methanex Corporation Annual Report

Notes to Consolidated Financial Statements

(Tabular dollar amounts are shown in thousands of U.S. dollars, except where noted)

Year ended December 31, 2017

1. Nature of operations:

Methanex Corporation (“the Company”) is an incorporated entity with corporate offices in Vancouver, Canada. The Company’s operations consist of the production and sale of methanol, a commodity chemical. The Company is the world’s largest producer and supplier of methanol to the major international markets of Asia Pacific, North America, Europe and South America.

2. Significant accounting policies:

a) Statement of compliance:

These consolidated financial statements are prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). These consolidated financial statements were approved and authorized for issue by the Board of Directors on March 5, 2018.

b) Basis of presentation and consolidation:

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, less than wholly-owned entities for which it has a controlling interest and its equity-accounted joint venture. Wholly-owned subsidiaries are entities in which the Company has control, directly or indirectly, where control is defined as the power to govern the financial and operating policies of an enterprise so as to obtain benefits from its activities. For less than wholly-owned entities for which the Company has a controlling interest, a non-controlling interest is included in the Company’s consolidated financial statements and represents the non-controlling shareholders’ interest in the net assets of the entity. The Company also consolidates any special purpose entity where the substance of the relationship indicates the Company has control. All significant intercompany transactions and balances have been eliminated. Preparation of these consolidated financial statements requires estimates, judgments and assumptions that affect the amounts reported and disclosed in the financial statements and related notes. The areas of estimation and judgment that management considers most significant are property, plant and equipment (note 2(g)), financial instruments (note 2(o)), fair value measurements (note 2(p)) and income taxes (note 2(q)). Actual results could differ from those estimates.

c) Reporting currency and foreign currency translation:

Functional currency is the currency of the primary economic environment in which an entity operates. The majority of the Company’s business in all jurisdictions is transacted in United States dollars and, accordingly, these consolidated financial statements have been measured and expressed in that currency. The Company translates foreign currency denominated monetary items at the period-end exchange rates, foreign currency denominated non-monetary items at historic rates and revenues and expenditures at the exchange rates at the dates of the transactions. Foreign exchange gains and losses are included in earnings.

d) Cash and cash equivalents:

Cash and cash equivalents include securities with maturities of three months or less when purchased.

e) Receivables:

The Company provides credit to its customers in the normal course of business. The Company performs ongoing credit evaluations of its customers and maintains reserves for potential credit losses. The Company records an allowance for doubtful accounts or writes down the receivable to estimated net realizable value if not collectible in full. Credit losses have historically been within the range of management’s expectations.

f) Inventories:

Inventories are valued at the lower of cost and estimated net realizable value. Cost is determined on a first-in, first-out basis and includes direct purchase costs, cost of production, allocation of production overhead and depreciation based on normal operating capacity and transportation.

g) Property, plant and equipment:

Initial recognition

Property, plant and equipment are initially recorded at cost. The cost of purchased equipment includes expenditures that are directly attributable to the purchase price, delivery and installation. The cost of self-constructed assets includes the cost of materials and

2017 Methanex Corporation Annual Report    51

direct labour, any other costs directly attributable to bringing the assets to the location and condition for their intended use, the costs of dismantling and removing the items and restoring the site on which they are located, and borrowing costs on self-constructed assets that meet certain criteria. Borrowing costs incurred during construction and commissioning are capitalized until the plant is operating in the manner intended by management.

Subsequent costs

Routine repairs and maintenance costs are expensed as incurred. At regular intervals, the Company conducts a planned shutdown and inspection (turnaround) at its plants to perform major maintenance and replacement of catalysts. Costs associated with these shutdowns are capitalized and amortized over the period until the next planned turnaround and the carrying amounts of replaced components are derecognized and included in earnings.

Depreciation

Depreciation and amortization is generally provided on a straight-line basis at rates calculated to amortize the cost of property, plant and equipment from the commencement of commercial operations over their estimated useful lives to estimated residual value.

The estimated useful lives of the Company’s buildings, plant installations and machinery, excluding costs related to turnarounds, ranges from 10 to 25 years depending on the specific asset component and the production facility to which it is related. The Company determines the estimated useful lives of individual asset components based on the shorter of its physical life or economic life. The physical life of these assets is generally longer than the economic life. The economic life is primarily determined by the nature of the natural gas feedstock available to the various production facilities. Factors that influence the nature of natural gas feedstock availability include the terms of individual natural gas supply contracts, access to natural gas supply through open markets, regional factors influencing the exploration and development of natural gas and the expected price of securing natural gas supply. The Company reviews the factors related to each production facility on an annual basis to determine if changes are required to the estimated useful lives.

Assets under finance lease are depreciated to their estimated residual value based on the shorter of their useful lives and the lease term.

Impairment

The Company reviews the carrying value of long-lived assets for impairment whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. Examples of such events or changes in circumstances include, but are not restricted to: a significant adverse change in the extent or manner in which the asset is being used or in its physical condition; a significant change in the long-term methanol price or in the price or availability of natural gas feedstock required to manufacture methanol; a significant adverse change in legal factors or in the business climate that could affect the asset’s value, including an adverse action or assessment by a foreign government that impacts the use of the asset; or a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the asset’s use.

Recoverability of long-lived assets is measured by comparing the carrying value of an asset or cash-generating unit to the estimated recoverable amount, which is the higher of its estimated fair value less cost to sell or its value in use. Value in use is determined by estimating the pre-tax cash flows expected to be generated from the asset or cash-generating unit over its estimated useful life discounted by a pre-tax discount rate. An impairment writedown is recorded for the difference that the carrying value exceeds the estimated recoverable amount. An impairment writedown recognized in prior periods for an asset or cash-generating unit is reversed if there has been a subsequent recovery in the value of the asset or cash-generating unit due to changes in events and circumstances. For purposes of recognition and measurement of an impairment writedown, the Company groups long-lived assets with other assets and liabilities to form a “cash-generating unit” at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. To the extent that methanol facilities in a particular location are interdependent as a result of common infrastructure and/or feedstock from sources that can be shared within a facility location, the Company groups assets based on site locations for the purpose of determining impairment.

h) Other assets:

Intangible assets are capitalized to other assets and amortized to depreciation and amortization expense on an appropriate basis to charge the cost of the assets against earnings.

52    2017 Methanex Corporation Annual Report

Financing fees related to undrawn credit facilities are capitalized to other assets and amortized to finance costs over the term of the credit facility.

i) Leases:

Leasing contracts are classified as either finance or operating leases based on the substance of the contractual arrangement at inception date. A lease is classified as a finance lease if it transfers substantially all of the risks and rewards of ownership of the leased asset. Where the contracts are classified as finance leases, upon initial recognition, the asset and liability are recorded at the lower of fair value and the present value of the minimum lease payments, net of executory costs. Finance lease payments are apportioned between interest expense and repayments of the liability. Where the contracts are classified as operating leases, they are not recognized in the Company’s consolidated statements of financial position and lease payments are charged to income as they are incurred on a straight line basis over the lease term.

j) Site restoration costs:

The Company recognizes a liability to dismantle and remove assets or to restore a site upon which the assets are located. The Company estimates the present value of the expenditures required to settle the liability by determining the current market cost required to settle the site restoration costs, adjusts for inflation through to the expected date of the expenditures and then discounts this amount back to the date when the obligation was originally incurred. As the liability is initially recorded on a discounted basis, it is increased each period until the estimated date of settlement. The resulting expense is referred to as accretion expense and is included in finance costs. The Company reviews asset retirement obligations and adjusts the liability and corresponding asset as necessary to reflect changes in the estimated future cash flows, timing, inflation and discount rates underlying the measurement of the obligation.

k) Employee future benefits:

The Company has non-contributory defined benefit pension plans covering certain employees and defined contribution pension plans. The Company does not provide any significant post-retirement benefits other than pension plan benefits. For defined benefit pension plans, the net of the present value of the defined benefit obligation and the fair value of plan assets is recorded to the consolidated statements of financial position. The determination of the defined benefit obligation and associated pension cost is based on certain actuarial assumptions including inflation rates, mortality, plan expenses, salary growth and discount rates. The present value of the net defined benefit obligation (asset) is determined by discounting the net estimated future cash flows using current market bond yields that have terms to maturity approximating the terms of the net obligation. Actuarial gains and losses arising from differences between these assumptions and actual results are recognized in other comprehensive income and recorded in retained earnings. The Company recognizes gains and losses on the settlement of a defined benefit plan in income when the settlement occurs. The cost for defined contribution benefit plans is recognized in net income (loss) as earned by the employees.

l) Share-based compensation:

The Company grants share-based awards as an element of compensation. Share-based awards granted by the Company can include stock options, tandem share appreciation rights, share appreciation rights, deferred share units, restricted share units or performance share units.

For stock options granted by the Company, the cost of the service received is measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus. On the exercise of stock options, consideration received, together with the compensation expense previously recorded to contributed surplus, is credited to share capital. The Company uses the Black-Scholes option pricing model to estimate the fair value of each stock option tranche at the date of grant.

Share appreciation rights (“SARs”) are units that grant the holder the right to receive a cash payment upon exercise for the difference between the market price of the Company’s common shares and the exercise price that is determined at the date of grant. Tandem share appreciation rights (“TSARs”) give the holder the choice between exercising a regular stock option or a SAR. For SARs and TSARs, the cost of the service received is initially measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in liabilities. For SARs and TSARs, the liability is re-measured at each reporting date based on an estimate of the fair value with changes in fair value

2017 Methanex Corporation Annual Report    53

recognized as compensation expense for the proportion of the service that has been rendered at that date. The Company uses the Black-Scholes option pricing model to estimate the fair value for SARs and TSARs.

Deferred, restricted and performance share units are grants of notional common shares that are redeemable for cash based on the market value of the Company’s common shares and are non-dilutive to shareholders. Performance share units have an additional feature where the ultimate number of units that vest will be determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The number of units that will ultimately vest will be in the range of 50% to 120% of the original grant for grants prior to 2014 and in the range of 25% to 150% for subsequent grants based on the weighted-average closing share price for the 90 calendar days on the NASDAQ Global Select Market immediately preceding the year end date that the performance share units vest. For deferred, restricted and performance share units, the cost of the service received as consideration is initially measured based on the market value of the Company’s common shares at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in liabilities. Deferred, restricted and performance share units are re-measured at each reporting date based on the market value of the Company’s common shares with changes in fair value recognized as compensation expense for the proportion of the service that has been rendered at that date.

Additional information related to the stock option plan, TSARs, SARs and the deferred, restricted and performance share units is described in note 13.

m) Net income (loss) per common share:

The Company calculates basic net income (loss) per common share by dividing net income (loss) attributable to Methanex shareholders by the weighted average number of common shares outstanding and calculates diluted net income (loss) per common share under the treasury stock method. Under the treasury stock method, diluted net income (loss) per common share is calculated by considering the potential dilution that would occur if outstanding stock options and, under certain circumstances, TSARs were exercised or converted to common shares. Stock options and TSARs are considered dilutive when the average market price of the Company’s common shares during the period disclosed exceeds the exercise price of the stock option or TSAR.

Outstanding TSARs may be settled in cash or common shares at the holder’s option. For the purposes of calculating diluted net income (loss) per common share, the more dilutive of the cash-settled or equity-settled method is used, regardless of how the plan is accounted for. Accordingly, TSARs that are accounted for using the cash-settled method will require adjustments to the numerator and denominator if the equity-settled method is determined to have a dilutive effect on diluted net income (loss) per common share.

The calculation of basic net income (loss) per common share and a reconciliation to diluted net income (loss) per common share is presented in note 12.

n) Revenue recognition:

Revenue is recognized based on individual contract terms when the risk of loss to the product transfers to the customer, which usually occurs at the time shipment is made. Revenue is recognized at the time of delivery to the customer’s location if the Company retains risk of loss during shipment. For methanol sold on a consignment basis, revenue is recognized when the customer consumes the methanol. For methanol sold on a commission basis, the commission income is included in revenue when earned.

o) Financial instruments:

All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Financial instruments are classified into one of three categories and, depending on the category, will either be measured at amortized cost or fair value with fair value changes either recorded through profit or loss or other comprehensive income. All non-derivative financial instruments held by the Company are classified and measured at amortized cost.

The Company enters into derivative financial instruments to manage certain exposures to commodity price and foreign exchange volatility. Under these standards, derivative financial instruments, including embedded derivatives, are classified as fair value through profit or loss and are recorded in the consolidated statements of financial position at fair value unless they are in accordance with the Company’s normal purchase, sale or usage requirements. The valuation of derivative financial instruments is a critical accounting estimate due to the complex nature of these instruments, the degree of judgment required to appropriately value

54    2017 Methanex Corporation Annual Report

these instruments and the potential impact of such valuation on the Company’s financial statements. The Company records all changes in fair value of derivative financial instruments in profit or loss unless the instruments are designated as cash flow hedges. The Company enters into and designates as cash flow hedges certain forward contracts to hedge its highly probable forecast natural gas purchases and certain forward exchange purchase and sales contracts to hedge foreign exchange exposure on anticipated purchases or sales. The Company assesses at inception and on an ongoing basis whether the hedges are and continue to be effective in offsetting changes in the cash flows of the hedged transactions. The effective portion of changes in the fair value of these hedging instruments is recognized in other comprehensive income. Any gain or loss in fair value relating to the ineffective portion is recognized immediately in profit or loss. Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in commodity prices, foreign currency exchange rates or variable interest rates.

p) Fair value measurements:

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements within the scope of IFRS 13 are categorized into Level 1, 2 or 3 based on the degree to which the inputs are observable and the significance of the inputs to the fair value measurement in its entirety. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can access at the measurement date. Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Financial instruments measured at fair value and categorized within the fair value hierarchy are disclosed in note 18.

q) Income taxes:

Income tax expense represents current tax and deferred tax. The Company records current tax based on the taxable profits for the period calculated using tax rates that have been enacted or substantively enacted by the reporting date. Income taxes relating to uncertain tax positions are provided for based on the Company’s best estimate. Deferred income taxes are accounted for using the liability method. The liability method requires that income taxes reflect the expected future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their tax bases. Deferred income tax assets and liabilities are determined for each temporary difference based on currently enacted or substantially enacted tax rates that are expected to be in effect when the underlying items are expected to be realized. The effect of a change in tax rates or tax legislation is recognized in the period of substantive enactment. Deferred tax assets, such as non-capital loss carryforwards, are recognized to the extent it is probable that taxable profit will be available against which the asset can be utilized.

The Company accrues for taxes that will be incurred upon distributions from its subsidiaries when it is probable that the earnings will be repatriated.

r) Provisions:

Provisions are recognized where a legal or constructive obligation has been incurred as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation.

s) Segmented information:

The Company’s operations consist of the production and sale of methanol, which constitutes a single operating segment.

t) Application of new and revised accounting standards:

The Company has adopted the amendments to IAS 7, Statement of Cash Flows, which were effective for annual periods beginning on or after January 1, 2017. As a result of applying the amendment, the Company presented new disclosures relating to change in financial liabilities arising from financing activities (note 16(b)).

u) Anticipated changes to International Financial Reporting Standards:

In May 2014, the IASB issued IFRS 15, Revenue from Contracts with Customers (“IFRS 15”) establishing a comprehensive framework for revenue recognition. The standard replaces IAS 18, Revenue and IAS 11, Construction Contracts and related interpretations and is effective for annual periods beginning on or after January 1, 2018, with early adoption permitted. The Company has performed its assessment of the impact of the new standard and anticipates no impact on its consolidated financial statements.

In January 2016, the IASB issued IFRS 16, Leases (“IFRS 16”), which eliminates the current operating/finance lease dual accounting model for lessees and replaces it with a single, on-balance sheet accounting model, similar to the current finance lease accounting. The standard replaces IAS 17, Leases (“IAS 17”) and related interpretations and is effective for annual periods beginning on or after January 1, 2019, with early application permitted. The Company plans to apply this standard at the date it becomes effective.

The Company is currently assessing the impact of the new standard including the optional exemptions available. The recognition of all leases on balance sheet is expected to increase the assets and liabilities on the Consolidated Statement of Financial Position upon

2017 Methanex Corporation Annual Report    55

adoption. The increase primarily relates to ocean vessels, terminal facilities and other right of use assets currently accounted for as operating leases. In addition, the nature and timing of certain expenses related to leases previously classified as operating and presented in cost of sales and operating expenses will now change and be presented in depreciation and amortization and finance costs. As a result, the Company expects that adoption of IFRS 16 will significantly impact the consolidated financial statements. The Company has not yet decided whether it will use the optional exemptions available under the standard. Refer to note 21, commitments and contingencies, for operating lease commitments as at December 31, 2017 disclosed under IAS 17.

The Company does not expect that any other new or amended standards or interpretations that are effective as of January 1, 2018 will have a significant impact on the Company’s results of operations or financial position.

3. Trade and other receivables:

As at	Dec 31 2017		Dec 31 2016
Trade	$	429,582	$	335,606
Value-added and other tax receivables		36,584		63,738
Egypt gas contract recoveries(a)		24,466		41,578
Other		46,004		58,681
	$	536,636	$	499,603

a) Egypt gas contract recoveries:

The natural gas supply agreement in Egypt has a mechanism whereby the Company is partially compensated when gas delivery shortfalls exceed a certain threshold. The receivable is secured by a combination of funds held in escrow and a bank guarantee.

4. Inventories:

Inventories are valued at the lower of cost, determined on a first-in first-out basis, and estimated net realizable value. The amount of inventories recognized as an expense in cost of sales and operating expenses and depreciation and amortization for the year ended December 31, 2017 is $2,219 million (2016 – $1,704 million).

5. Property, plant and equipment:

	Buildings, plant installations and machinery			Finance leases		Other			TOTAL
Cost at January 1, 2017	$	4,549,816		$	206,260	$	272,878		$	5,028,954
Additions		98,780			7,667		5,001			111,448
Disposals and other		328			1,846		(2,386	)		(212	)
Cost at December 31, 2017		4,648,924			215,773		275,493			5,140,190
Accumulated depreciation at January 1, 2017		1,752,540			18,557		140,388			1,911,485
Disposals and other		(2,066	)		–		(673	)		(2,739	)
Depreciation		205,843			15,370		11,905			233,118
Accumulated depreciation at December 31, 2017		1,956,317			33,927		151,620			2,141,864
Net book value at December 31, 2017	$	2,692,607		$	181,846	$	123,873		$	2,998,326

	Buildings, plant installations and machinery			Finance leases			Other			TOTAL
Cost at January 1, 2016	$	4,521,835		$	121,849		$	204,483		$	4,848,167
Additions		35,644			87,800			74,303			197,747
Disposals and other		(7,663	)		(3,389	)		(5,908	)		(16,960	)
Cost at December 31, 2016		4,549,816			206,260			272,878			5,028,954
Accumulated depreciation at January 1, 2016		1,545,834			6,853			136,698			1,689,385
Disposals and other		(945	)		–			(5,908	)		(6,853	)
Depreciation		207,651			11,704			9,598			228,953
Accumulated depreciation at December 31, 2016		1,752,540			18,557			140,388			1,911,485
Net book value at December 31, 2016	$	2,797,276		$	187,703		$	132,490		$	3,117,469

56    2017 Methanex Corporation Annual Report

Included in finance leases as at December 31, 2017 are capitalized costs related to a methanol terminal and storage tanks in Geismar, Louisiana, an oxygen production facility in Trinidad, and two ocean going vessels.

6. Investment in associate:

a) The Company has a 63.1% equity interest in Atlas Methanol Company Unlimited (“Atlas”). Atlas owns a 1.8 million tonne per year methanol production facility in Trinidad. The Company accounts for its interest in Atlas using the equity method. Summarized financial information of Atlas (100% basis) is as follows:

Consolidated statements of financial position as at	Dec 31 2017			Dec 31 2016
Cash and cash equivalents	$	8,361		$	15,530
Other current assets1		79,738			45,219
Non-current assets		289,671			324,297
Current liabilities1		(41,388	)		(24,783	)
Other long-term liabilities, including current maturities		(157,935	)		(168,253	)
Net assets at 100%		178,447			192,010
Net assets at 63.1%		112,600			121,158
Long-term receivable from Atlas1		76,322			76,244
Investment in associate	$	188,922		$	197,402

Consolidated statements of income for the years ended December 31	2017			2016
Revenue1	$	459,367		$	213,533
Cost of sales and depreciation and amortization		(261,121	)		(145,126	)
Operating income		198,246			68,407
Finance costs, finance income and other expenses		(11,170	)		(12,771	)
Income tax expense		(66,640	)		(24,052	)
Net earnings at 100%		120,436			31,584
Earnings of associate at 63.1%		75,995			19,930
Dividends received from associate	$	84,553		$	47,325

¹  Includes related party transactions between Atlas and the Company (see note 22).

b) Contingent liability:

The Board of Inland Revenue of Trinidad and Tobago has issued assessments against Atlas in respect of the 2005 to 2011 financial years. All subsequent tax years remain open to assessment. The assessments relate to the pricing arrangements of certain long-term fixed price sales contracts from 2005 to 2019 related to methanol produced by Atlas. Atlas had partial relief from corporation income tax until late July 2014.

The Company has lodged objections to the assessments. Based on the merits of the cases and legal interpretation, management believes its position should be sustained.

7. Other assets:

As at	Dec 31 2017		Dec 31 2016
Restricted cash	$	27,863	$	35,386
Chile VAT receivable		25,456		23,406
Investment in Carbon Recycling International		4,502		4,502
Defined benefit pension plans (note 20)		6,650		5,862
Other		13,555		9,628
	$	78,026	$	78,784

2017 Methanex Corporation Annual Report    57

8. Long-term debt:

As at	Dec 31 2017			Dec 31 2016
Unsecured notes
(i) 3.25% due December 15, 2019	$	348,060		$	347,126
(ii) 5.25% due March 1, 2022		248,072			247,685
(iii) 4.25% due December 1, 2024		296,873			296,529
(iv) 5.65% due December 1, 2044		295,158			295,084
		1,188,163			1,186,424
Egypt limited recourse debt facilities		241,190			288,515
Other limited recourse debt facilities		72,918			81,267
Total long-term debt1		1,502,271			1,556,206
Less current maturities1		(55,905	)		(53,997	)
	$	1,446,366		$	1,502,209

¹  Long-term debt and current maturities are presented net of discounts and deferred financing fees of $17.8 million as at December 31, 2017 (2016 – $17.8 million).

The Egypt limited recourse debt facilities have interest payable semi-annually with rates based on LIBOR plus a spread ranging from 0.9% to 1.6% per annum. Principal is paid in 24 semi-annual payments, which commenced in September 2010.

Other limited recourse debt facilities relate to financing for certain of our ocean going vessels which we own through less than wholly-owned entities under the Company’s control. Other limited recourse debt facilities have remaining terms of two to four years with principal and interest payable quarterly with rates based on LIBOR plus a spread ranging from 0.75% to 2.5% per annum. Subsequent to the year ended December 31, 2017, the Company, through a 50% owned entity, issued other limited recourse debt for $86 million ($43 million Methanex share) bearing an interest rate of 5.35% due September 2033. The debt will be used to acquire two ocean going vessels.

For the year ended December 31, 2017, non-cash accretion, on an effective interest basis, of deferred financing costs included in finance costs was $3.1 million (2016 – $3.0 million).

The minimum principal payments for long-term debt in aggregate and for each of the five succeeding years are as follows:

	Limited recourse debt facilities		Unsecured notes		Total
2018	$	57,072	$	–	$	57,072
2019		60,100		350,000		410,100
2020		62,115		–		62,115
2021		109,462		–		109,462
2022		31,279		250,000		281,279
Thereafter		–		600,000		600,000
	$	320,028	$	1,200,000	$	1,520,028

The covenants governing the Company’s unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding entities which we control but do not fully own, and include restrictions on liens, sale and lease-back transactions, a merger or consolidation with another corporation or sale of all or substantially all of the Company’s assets. The indenture also contains customary default provisions.

The Company maintains a $300 million committed revolving credit facility with a syndicate of highly rated financial institutions that expires in December 2022. Significant covenants and default provisions under this facility include:

i) the obligation to maintain an EBITDA to interest coverage ratio of greater than 2:1 calculated on a four-quarter trailing basis and a debt to capitalization ratio of less than or equal to 55%, both ratios calculated in accordance with definitions in the credit agreement that include adjustments related to the limited recourse subsidiaries,

ii) a default if payment is accelerated by a creditor on any indebtedness of $50 million or more of the Company and its subsidiaries, except for the limited recourse subsidiaries, and

iii) a default if a default occurs that permits a creditor to demand repayment on any other indebtedness of $50 million or more of the Company and its subsidiaries, except for the limited recourse subsidiaries.

58    2017 Methanex Corporation Annual Report

The limited recourse debt facilities are described as limited recourse as they are secured only by the assets of the entity that carries the debt. Accordingly, the lenders to the limited recourse debt facilities have no recourse to the Company or its other subsidiaries.

The Egypt limited recourse debt facilities have covenants and default provisions that apply only to the Egypt entity, including restrictions on the incurrence of additional indebtedness and a requirement to fulfill certain conditions before the payment of cash or other shareholder distributions. Certain conditions had not been met, resulting in a restriction on shareholder distributions from the Egypt entity to December 31, 2017. Under amended terms reached in 2017, shareholder distributions are permitted starting in 2018 if the average gas deliveries over the prior 12 months are greater than 70% of gas requirements. The first $100 million of shareholder distributions must be matched with $100 million of principal repayments on the Egypt limited recourse debt facilities. As of December 31, 2017, the Egypt cash balance on a 100% ownership basis was $131 million.

Failure to comply with any of the covenants or default provisions of the long-term debt facilities described above could result in a default under the applicable credit agreement that would allow the lenders to not fund future loan requests, accelerate the due date of the principal and accrued interest on any outstanding loans or restrict the payment of cash or other distributions.

As at December 31, 2017, management believes the Company was in compliance with all significant terms and default provisions related to long-term debt obligations.

9. Other long-term liabilities:

As at	Dec 31 2017			Dec 31 2016
Site restoration costs(a)	$	33,975		$	30,512
Finance lease obligations(b)		204,242			201,268
Share-based compensation liability (note 13)		111,405			53,725
Cash flow hedges (note 18)		90,199			68,664
Defined benefit pension plans (note 20)		25,076			22,403
Other		5,214			4,339
		470,111			380,911
Less current maturities		(65,226	)		(29,720	)
	$	404,885		$	351,191
a) Site restoration costs: The Company has accrued liabilities related to the decommissioning and reclamation of its methanol production sites and oil and gas properties. Because of uncertainties in estimating the amount and timing of the expenditures related to the sites, actual results could differ from the amounts estimated. As at December 31, 2017, the total undiscounted amount of estimated cash flows required to settle the liabilities was $44.9 million (2016 – $41.1 million). The movement in the provision during the year is explained as follows:
	2017			2016
Balance at January 1	$	30,512		$	29,892
New or revised provisions		2,823			51
Accretion expense		640			569
Balance at December 31	$	33,975		$	30,512

b) Finance lease obligations:

As at December 31, 2017, the Company has finance lease obligations related to a methanol terminal and storage tanks in Geismar, Louisiana, an oxygen production facility in Trinidad, and two ocean-going vessels. Total finance lease payments for 2017 of $30.6 million include an interest component of $23.7 million.

2017 Methanex Corporation Annual Report    59

Finance lease obligations are payable as follows:

	Lease payments		Interest component		Finance lease obligations
2018	$	31,447	$	23,549	$	7,898
2019		31,826		22,727		9,099
2020		32,213		21,756		10,457
2021		32,608		20,612		11,996
2022		33,010		19,271		13,739
Thereafter		236,772		85,719		151,053
	$	397,876	$	193,634	$	204,242

10. Expenses:

For the years ended December 31	2017		2016
Cost of sales	$	2,035,545	$	1,533,915
Selling and distribution		449,593		408,893
Administrative expenses		99,036		59,675
Total expenses by function	$	2,584,174	$	2,002,483
Cost of raw materials and purchased methanol	$	1,637,085	$	1,140,551
Ocean freight and other logistics		374,717		351,609
Employee expenses, including share-based compensation		243,707		204,762
Other expenses		96,440		77,507
Cost of sales and operating expenses		2,351,949		1,774,429
Depreciation and amortization		232,225		228,054
Total expenses by nature	$	2,584,174	$	2,002,483

For the year ended December 31, 2017 we recorded a share-based compensation expense of $78.8 million (2016 – $33.5 million), the majority of which is included in administrative expenses for the total expenses by function presentation above.

11. Finance costs:

Finance costs are primarily comprised of interest on borrowings and finance lease obligations, amortization of deferred financing fees and accretion expense associated with site restoration costs. Finance costs were $95.0 million for the year ended December 31, 2017 (2016 – $90.1 million).

12. Net income (loss) per common share:

Diluted net income (loss) per common share is calculated by considering the potential dilution that would occur if outstanding stock options and, under certain circumstances, TSARs were exercised or converted to common shares.

Outstanding TSARs may be settled in cash or common shares at the holder’s option and for purposes of calculating diluted net income (loss) per common share, the more dilutive of the cash-settled and equity-settled method is used, regardless of how the plan is accounted for. Accordingly, TSARs that are accounted for using the cash-settled method will require adjustments to the numerator and denominator if the equity-settled method is determined to have a dilutive effect on diluted net income (loss) per common share as compared to the cash-settled method. The cash-settled method was more dilutive for the years ended December 31, 2017 and 2016, and no adjustment was required for the numerator or the denominator for TSARs.

Stock options and, if calculated using the equity-settled method, TSARs are considered dilutive when the average market price of the Company’s common shares during the period disclosed exceeds the exercise price of the stock option or TSAR. For the year ended December 31, 2017, stock options were considered dilutive resulting in an adjustment to the denominator. For the year ended December 31, 2016, the Company incurred a net loss attributable to Methanex shareholders and therefore exclusion of the stock options was more dilutive.

60    2017 Methanex Corporation Annual Report

Basic and diluted net income (loss) per common share for the year ended December 31, 2017 was calculated using basic and diluted net income of $316.1 million (2016 – basic and diluted net loss of $12.5 million). A reconciliation of the denominator used for the purposes of calculating basic and diluted net income (loss) per common share is as follows:

For the years ended December 31	2017		2016
Denominator for basic net income (loss) per common share		86,768,589		89,783,883
Effect of dilutive stock options		56,359		–
Denominator for diluted net income (loss) per common share		86,824,948		89,783,883
For the years ended December 31, 2017 and 2016, basic and diluted net income (loss) per common share attributable to Methanex shareholders were as follows:
For the years ended December 31	2017		2016
Basic net income (loss) per common share	$	3.64	$	(0.14	)
Diluted net income (loss) per common share	$	3.64	$	(0.14	)

13. Share-based compensation:

The Company provides share-based compensation to its directors and certain employees through grants of stock options, TSARs, SARs and deferred, restricted or performance share units.

As at December 31, 2017, the Company had 3,953,471 common shares reserved for future grants of stock options and tandem share appreciation rights under the Company’s stock option plan.

a) Share appreciation rights and tandem share appreciation rights:

All SARs and TSARs granted have a maximum term of seven years with one-third vesting each year after the date of grant. SARs and TSARs units outstanding at December 31, 2017 are as follows:

	SARs					TSARs
	Number of units			Exercise price USD		Number of units			Exercise price USD
Outstanding at December 31, 2015		1,259,208		$	44.48		2,108,965		$	42.73
Granted		375,500			34.59		574,600			34.59
Exercised		(73,291	)		27.43		(212,505	)		25.38
Cancelled		(49,932	)		49.77		(54,949	)		52.55
Outstanding at December 31, 2016		1,511,485		$	42.68		2,416,111		$	42.10
Granted		167,600			50.15		340,200			50.17
Exercised		(213,207	)		32.03		(710,616	)		32.98
Cancelled		(10,801	)		50.18		(2,200	)		34.59
Expired		(5,000	)		25.22		–			–
Outstanding at December 31, 2017		1,450,077		$	45.11		2,043,495		$	46.62

2017 Methanex Corporation Annual Report    61

Information regarding the SARs and TSARs outstanding as at December 31, 2017 is as follows:

	Units outstanding at December 31, 2017						Units exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)		Number of units outstanding		Weighted average exercise price		Number of units exercisable		Weighted average exercise price
SARs
$25.97 to $35.51		3.36		585,317	$	32.94		345,629	$	31.79
$38.24 to $73.13		3.77		864,760		53.35		609,687		53.94
		3.61		1,450,077	$	45.11		955,316	$	45.93
TSARs
$25.97 to $35.51		3.94		779,194	$	33.67		401,049	$	32.80
$38.24 to $73.13		4.09		1,264,301		54.60		794,658		56.33
		4.03		2,043,495	$	46.62		1,195,707	$	48.44

The fair value of each outstanding SARs and TSARs grant was estimated on December 31, 2017 using the Black-Scholes option pricing model with the following weighted average assumptions:

	2017		2016
Risk-free interest rate		1.8%		1.0%
Expected dividend yield		2.0%		2.5%
Expected life of SARs and TSARs (years)		1.2		1.4
Expected volatility		31%		41%
Expected forfeitures		0.2%		0.2%
Weighted average fair value (USD per share)	$	19.02	$	10.19

Compensation expense for SARs and TSARs is measured based on their fair value and is recognized over the vesting period. Changes in fair value in each period are recognized in net income (loss) for the proportion of the service that has been rendered at each reporting date. The fair value as at December 31, 2017 was $69.8 million compared with the recorded liability of $65.2 million. The difference between the fair value and the recorded liability of $4.6 million will be recognized over the weighted average remaining vesting period of approximately 1.5 years.

For the year ended December 31, 2017, compensation expense related to SARs and TSARs included an expense in cost of sales and operating expenses of $45.1 million (2016 – $26.9 million). This included an expense of $37.8 million (2016 – $20.0 million) related to the effect of the change in the Company’s share price.

62    2017 Methanex Corporation Annual Report

b) Deferred, restricted and performance share units:

Deferred, restricted and performance share units outstanding as at December 31, 2017 are as follows:

	Number of deferred share units			Number of restricted share units			Number of performance share units
Outstanding at December 31, 2015		285,816			13,864			610,578
Granted		8,269			11,500			261,760
Granted performance factor1		–			–			55,592
Granted in lieu of dividends		8,430			773			18,082
Redeemed		(51,498	)		(7,488	)		(355,415	)
Cancelled		–			–			(18,325	)
Outstanding at December 31, 2016		251,017			18,649			572,272
Granted		10,452			8,100			163,500
Performance factor impact on redemption1		–			–			(102,557	)
Granted in lieu of dividends		5,669			613			14,383
Redeemed		(42,292	)		(6,907	)		(34,186	)
Cancelled		–			–			(8,517	)
Outstanding at December 31, 2017		224,846			20,455			604,895

¹  Performance share units have a feature where the ultimate number of units that vest are adjusted by a performance factor of the original grant as determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The performance factor is measured based on the weighted-average closing share price for the 90 calendar days on the NASDAQ Global Select Market immediately preceding the year end date that the performance share units vest.

Compensation expense for deferred, restricted and performance share units is measured at fair value based on the market value of the Company’s common shares and is recognized over the vesting period. Changes in fair value are recognized in net income (loss) for the proportion of the service that has been rendered at each reporting date. The fair value of deferred, restricted and performance share units as at December 31, 2017 was $55.9 million compared with the recorded liability of $46.1 million. The difference between the fair value and the recorded liability of $9.8 million will be recognized over the weighted average remaining vesting period of approximately 1.5 years.

For the year ended December 31, 2017, compensation expense related to deferred, restricted and performance share units included in cost of sales and operating expenses was an expense of $33.0 million (2016 – $6.0 million). This included an expense of $29.9 million (2016 – $2.8 million) related to the effect of the change in the Company’s share price.

c) Stock options:

The exercise price of each stock option is equal to the quoted market price of the Company’s common shares at the date of the grant. Options granted have a maximum term of seven years with one-third of the options vesting each year after the date of grant.

Common shares reserved for outstanding incentive stock options as at December 31, 2017 and 2016 are as follows:

	Number of stock options			Weighted average exercise price
Outstanding at December 31, 2015		448,507		$	30.52
Granted		75,500			34.59
Exercised		(153,140	)		9.80
Cancelled		(14,100	)		44.04
Expired		(12,000	)		6.33
Outstanding at December 31, 2016		344,767		$	40.91
Granted		31,400			50.17
Exercised		(98,274	)		30.90
Cancelled		(15,358	)		52.43
Outstanding at December 31, 2017		262,535		$	45.09

2017 Methanex Corporation Annual Report    63

Information regarding the stock options outstanding as at December 31, 2017 is as follows:

	Options outstanding at December 31, 2017						Options exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)		Number of stock options outstanding		Weighted average exercise price		Number of stock options exercisable		Weighted average exercise price
Options
$25.97 to $35.51		3.40		103,850	$	33.08		60,980	$	32.02
$38.24 to $73.13		3.69		158,685		52.95		114,380		53.28
		3.58		262,535	$	45.09		175,360	$	45.88

For the year ended December 31, 2017, compensation expense related to stock options was $0.5 million (2016 – $0.6 million).

14. Segmented information:

The Company’s operations consist of the production and sale of methanol, which constitutes a single operating segment.

During the years ended December 31, 2017 and 2016, revenues attributed to geographic regions, based on the location of customers, were as follows:

Revenue	China		Europe		United States		South Korea		South America		Canada		Other Asia		TOTAL
2017	$	801,838	$	608,668	$	570,482	$	347,896	$	279,270	$	167,436	$	285,052	$	3,060,642
2016	$	518,499	$	403,879	$	359,476	$	257,658	$	179,287	$	109,706	$	169,924	$	1,998,429

As at December 31, 2017 and 2016, the net book value of property, plant and equipment by country was as follows:

Property, plant and equipment	United States		Egypt		New Zealand		Trinidad		Canada		Chile		Other		TOTAL
2017	$	1,412,394	$	720,397	$	265,153	$	155,525	$	148,420	$	107,495	$	188,942	$	2,998,326
2016	$	1,468,283	$	742,446	$	261,482	$	176,256	$	154,982	$	108,065	$	205,955	$	3,117,469

15. Income and other taxes:

a) Income tax expense:

For the years ended December 31	2017			2016
Current tax recovery (expense):
Current period before undernoted items	$	(85,287	)	$	(44,743	)
Impact of Argentina gas settlement		–			(7,800	)
Adjustments to prior years		(217	)		(2,134	)
		(85,504	)		(54,677	)
Deferred tax recovery (expense):
Origination and reversal of temporary differences		23,310			82,838
Impact of Argentina gas settlement		–			(3,575	)
Derecognition of non-capital loss carryforwards		–			(17,861	)
Adjustments to prior years		200			1,667
Change in U.S. tax rate		(36,567	)		–
Change in other jurisdictions tax rates		734			–
Other		2,039			887
		(10,284	)		63,956
Total income tax recovery (expense)	$	(95,788	)	$	9,279

64    2017 Methanex Corporation Annual Report

b) Reconciliation of the effective tax rate:

The Company operates in several tax jurisdictions and therefore its income is subject to various rates of taxation. Income tax expense differs from the amounts that would be obtained by applying the Canadian statutory income tax rate to net income (loss) before income taxes as follows:

For the years ended December 31	2017			2016
Income (loss) before income taxes	$	470,885		$	(37,504	)
Deduct earnings of associate		(75,995	)		(19,930	)
		394,890			(57,434	)
Canadian statutory tax rate		26.5	%		26.5	%
Income tax recovery (expense) calculated at Canadian statutory tax rate		(104,646	)		15,220
Increase (decrease) in income tax recovery resulting from:
Impact of income and losses taxed in foreign jurisdictions		30,223			34,857
Derecognition of non-capital loss carryforwards		–			(17,861	)
Unrecognised loss carryforwards and temporary differences		20,468			(6,468	)
Impact of tax rate changes in the U.S.		(36,567	)		–
Impact of tax rate changes in other jurisdictions		734			–
Impact of foreign exchange		3,104			(4,332	)
Other business taxes		(4,105	)		(5,404	)
Adjustments to prior years		(17	)		(467	)
Other		(4,982	)		(6,266	)
Total income tax recovery (expense)	$	(95,788	)	$	9,279

c) Net deferred income tax liabilities:

(i) The tax effect of temporary differences that give rise to deferred income tax liabilities and deferred income tax assets are as follows:

As at	Dec 31 2017									Dec 31 2016
	Net			Deferred tax assets			Deferred tax liabilities			Net			Deferred tax assets			Deferred tax liabilities
Property, plant and equipment	$	(403,705	)	$	(189,368	)	$	(214,337	)	$	(419,982	)	$	(197,931	)	$	(222,051	)
Repatriation taxes		(87,239	)		–			(87,239	)		(85,364	)		–			(85,364	)
Other		(11,670	)		(3,740	)		(7,930	)		(19,956	)		(4,981	)		(14,975	)
		(502,614	)		(193,108	)		(309,506	)		(525,302	)		(202,912	)		(322,390	)
Non-capital loss carryforwards		244,576			244,576			–			280,931			280,931			–
Share-based compensation		19,920			2,946			16,974			8,590			935			7,655
Other		74,027			47,927			26,100			82,142			58,387			23,755
		338,523			295,449			43,074			371,663			340,253			31,410
Net deferred income tax assets (liabilities)	$	(164,091	)	$	102,341		$	(266,432	)	$	(153,639	)	$	137,341		$	(290,980	)

The Company recognizes deferred income tax assets to the extent that it is probable that the benefit of these assets will be realized. As at December 31, 2017, the Company had $110 million (2016 – $153 million) of unrecognized non-capital loss carryforwards in Egypt that expire in 2020 and 2021 and $384 million (2016 – $ 415 million) of deductible temporary differences in the United States that have not been recognized.

2017 Methanex Corporation Annual Report    65

(ii) Analysis of the change in deferred income tax assets and liabilities:

	2017									2016
	Net			Deferred tax assets			Deferred tax liabilities			Net			Deferred tax assets			Deferred tax liabilities
Balance, January 1	$	(153,639	)	$	137,341		$	(290,980	)	$	(223,757	)	$	61,881		$	(285,638	)
Deferred income tax recovery (expense) included in net income (loss)		(10,284	)		(34,517	)		24,233			63,956			69,110			(5,154	)
Impact of U.S. tax rate change in other comprehensive income		(8,621	)		(8,621	)		–			–			–			–
Deferred income tax recovery (expense) included in other comprehensive income (loss)		9,295			8,398			897			6,597			6,364			233
Other		(842	)		(260	)		(582	)		(435	)		(14	)		(421	)
Balance, December 31	$	(164,091	)	$	102,341		$	(266,432	)	$	(153,639	)	$	137,341		$	(290,980	)

16. Supplemental cash flow information:

a) Changes in non-cash working capital:

Changes in non-cash working capital for the years ended December 31, 2017 and 2016 are as follows:

For the years ended December 31	2017			2016
Changes in non-cash working capital:
Trade and other receivables	$	(37,033	)	$	4,747
Inventories		(23,136	)		(28,094	)
Prepaid expenses		(5,702	)		(1,286	)
Trade, other payables and accrued liabilities, including long-term payables included in other long-term liabilities		103,601			14,577
		37,730			(10,056	)
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid		(89,445	)		(65,850	)
Changes in non-cash working capital	$	(51,715	)	$	(75,906	)
These changes relate to the following activities:
Operating	$	(49,368	)	$	(87,644	)
Financing		–			–
Investing		(2,347	)		11,738
Changes in non-cash working capital	$	(51,715	)	$	(75,906	)

The Company has reclassified the presentation of amounts relating to accrued distributions to non-controlling interests in Changes in non-cash working capital from Operating activities to Financing activities. The reclassification has been reflected in the comparative figures.

b) Reconciliation of movements in liabilities to cash flows arising from financing activities:

	Long term debt (note 8)			Finance lease obligations (note 9)
Balance at December 31, 2016	$	1,556,206		$	201,268
Changes from financing cash flows
Repayment of long-term debt and financing fees		(56,997	)		–
Payment of finance lease liabilities		–			(6,880	)
Total changes from financing cash flows	$	(56,997	)	$	(6,880	)
Liability-related other changes
Finance costs	$	3,062		$	–
New finance leases		–			9,512
Other		–			342
Total liability-related other changes	$	3,062		$	9,854
Balance at December 31, 2017	$	1,502,271		$	204,242

66    2017 Methanex Corporation Annual Report

17. Capital disclosures:

The Company’s objectives in managing its liquidity and capital are to safeguard the Company’s ability to continue as a going concern, to provide financial capacity and flexibility to meet its strategic objectives, to provide an adequate return to shareholders commensurate with the level of risk and to return excess cash through a combination of dividends and share repurchases.

As at	Dec 31 2017			Dec 31 2016
Liquidity:
Cash and cash equivalents	$	375,479		$	223,890
Undrawn credit facilities		300,000			300,000
Total liquidity	$	675,479		$	523,890
Capitalization:
Unsecured notes	$	1,188,163		$	1,186,424
Limited recourse debt facilities, including current portion		314,108			369,782
Total debt		1,502,271			1,556,206
Non-controlling interests		244,347			208,515
Shareholders’ equity		1,500,764			1,596,835
Total capitalization	$	3,247,382		$	3,361,556
Total debt to capitalization1		46	%		46	%
Net debt to capitalization2		39	%		42	%

¹  Total debt (including 100% of Egypt limited recourse debt facilities) divided by total capitalization.

²  Total debt (including 100% of Egypt limited recourse debt facilities) less cash and cash equivalents divided by total capitalization less cash and cash equivalents.

The Company manages its liquidity and capital structure and makes adjustments to it in light of changes to economic conditions, the underlying risks inherent in its operations and capital requirements to maintain and grow its operations. The strategies employed by the Company may include the issue or repayment of general corporate debt, the issue of project debt, the issue of equity, the payment of dividends and the repurchase of shares.

The Company is not subject to any statutory capital requirements and has no commitments to sell or otherwise issue common shares except pursuant to outstanding employee stock options.

During the year, the Company renewed and extended a $300 million revolving credit facility for a five year term to December 2022. The undrawn credit facility is provided by highly rated financial institutions and is subject to certain financial covenants (note 8).

18. Financial instruments:

Financial instruments are either measured at amortized cost or fair value.

In the normal course of business, the Company’s assets, liabilities and forecasted transactions, as reported in U.S. dollars, are impacted by various market risks including, but not limited to, natural gas prices and currency exchange rates. The time frame and manner in which the Company manages those risks varies for each item based on the Company’s assessment of the risk and the available alternatives for mitigating risks.

The Company uses derivatives as part of its risk management program to mitigate variability associated with changing market values. Changes in fair value of derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges, in which case the changes in fair value are recorded in other comprehensive income and are reclassified to profit or loss when the underlying hedged transaction is recognized in earnings. The Company designates as cash flow hedges certain derivative financial instruments to hedge its risk exposure to fluctuations in natural gas prices and to hedge its risk exposure to fluctuations on certain foreign currency denominated transactions.

2017 Methanex Corporation Annual Report    67

The following table provides the carrying value of each category of financial assets and liabilities and the related balance sheet item:

As at	Dec 31 2017		Dec 31 2016
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges1	$	–	$	7,024
Financial assets not measured at fair value:
Cash and cash equivalents		375,479		223,890
Trade and other receivables, excluding tax receivable		527,084		479,272
Project financing reserve accounts included in other assets		27,863		35,386
Total financial assets2	$	930,426	$	745,572
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges1	$	91,014	$	68,664
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable		528,182		449,213
Long-term debt, including current portion		1,502,271		1,556,206
Total financial liabilities	$	2,121,467	$	2,074,083

¹  The Geismar 2 and Medicine Hat natural gas hedges and euro foreign currency hedges designated as cash flow hedges are measured at fair value based on industry accepted valuation models and inputs obtained from active markets.

²  The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods.

As at December 31, 2017, all of the financial instruments were recorded on the consolidated statements of financial position at amortized cost with the exception of derivative financial instruments, which are recorded at fair value unless exempted.

The fair value of derivative instruments is determined based on industry-accepted valuation models using market observable inputs and are classified within Level 2 of the fair value hierarchy. The fair value of all the Company’s derivative contracts includes an adjustment for credit risk. The effective portion of the changes in fair value of derivative financial instruments designated as cash flow hedges is recorded in other comprehensive income. The spot element of forward contracts in the hedging relationships is recorded in other comprehensive income as the change in fair value of cash flow hedges. The change in the fair value of the forward element of forward contracts is recorded separately in other comprehensive income as the forward element excluded from hedging relationships.

Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in commodity prices or foreign currency exchange rates.

Natural gas forward contracts

The Company has elected to manage its exposure to changes in natural gas prices for a portion of its North American natural gas requirements by executing a number of fixed price forward contracts. The Company has entered into forward contracts to manage its exposure to changes in natural gas prices for the Geismar 2 facility for 40% of its gas requirements to 2025, which it has designated as cash flow hedges. The Company has also entered into physical forward contracts to manage its exposure to changes in natural gas prices for the Medicine Hat facility over the period 2017 to 2022. The Company has designated contracts for the 2021 and 2022 periods as cash flow hedges for its highly probable forecast natural gas purchases in Medicine Hat. Other costs incurred to transport natural gas from the contracted delivery point, either Henry Hub or AECO, to the relevant production facility represent an insignificant portion of the overall underlying risk and are recognized as incurred outside of the hedging relationship. The Company has elected to designate the spot element of the forward contracts as cash flow hedges. The forward element of the forward contracts are excluded from the designation and only the spot element is considered for the purpose of assessing effectiveness and measuring ineffectiveness. The excluded forward element of the swap contracts will be accounted for as a cost of hedging (transaction cost) to be recognized in profit or loss over the term of the hedging relationships. Ineffectiveness may arise in the hedging relationship due to changes in the timing of the anticipated transactions and/or due to changes in credit risk of the hedging instrument not replicated in the hedged item. No hedge ineffectiveness has been recognized in 2017.

68    2017 Methanex Corporation Annual Report

As at December 31, 2017, the Company had outstanding forward contracts designated as cash flow hedges with a notional amount of $473 million (2016 – $484 million) and a net negative fair value of $90.2 million (2016 – $ 61.9 million) included in other long-term liabilities. As at December 31, 2017, the forward contracts for the Geismar 2 facility had an average contract price of $3.74 per mmbtu (2016 – $3.68 per mmbtu) over the remaining eight year term, and for the forward contracts for the Medicine Hat facility has an average contract price of $1.96 per mmbtu.

Forward exchange contracts

The Company also designates as cash flow hedges forward exchange contracts to sell certain foreign currencies at a fixed U.S. dollar exchange rate to hedge its exposure to exchange rate fluctuations on certain foreign currency denominated transactions. The Company has elected to designate the spot element of the forward contracts as cash flow hedges. The forward element of the forward contracts are excluded from the designation and only the spot element is considered for the purpose of assessing effectiveness and measuring ineffectiveness. The excluded forward element of the swap contracts will be accounted for as a cost of hedging (transaction cost) to be recognized in profit or loss over the term of the hedging relationships. Ineffectiveness may arise in the hedging relationship due to changes in the timing of the anticipated transactions and/or due to changes in credit risk of the hedging instrument not replicated in the hedged item. No hedge ineffectiveness has been recognized in 2017.

As at December 31, 2017, the Company had outstanding forward exchange contracts designated as cash flow hedges to sell euros at a fixed U.S. dollar exchange rate with a notional amount of 109 million euros (2016 – 92 million euros) and a negative fair value of $0.8 million included in current liabilities (2016 – positive fair value of $0.3 million included in current assets) .

Fair value liabilities

The table below shows net cash outflows for derivative hedging instruments including natural gas forward contracts and forward exchange contracts, excluding credit risk adjustments, based upon contracted payment dates. The amounts reflect the maturity profile of the fair value liabilities and are subject to change based on the prevailing market rate at each of the future settlement dates. Financial asset derivative positions, if any, are held with investment-grade counterparties and therefore the settlement day risk exposure is considered to be negligible.

As at	Dec 31 2017		Dec 31 2016
Within one year	$	7,114	$	–
1-3 years		17,057		8,481
3-5 years		28,864		18,962
More than 5 years		52,085		56,029
	$	105,120	$	83,472

The fair value of the Company’s derivative financial instruments as disclosed above are determined based on Bloomberg quoted market prices and confirmations received from counterparties, which are adjusted for credit risk.

The Company is exposed to credit-related losses in the event of non-performance by counterparties to derivative financial instruments but does not expect any counterparties to fail to meet their obligations. The Company deals with only highly rated counterparties, normally major financial institutions. The Company is exposed to credit risk when there is a positive fair value of derivative financial instruments at a reporting date. The maximum amount that would be at risk if the counterparties to derivative financial instruments with positive fair values failed completely to perform under the contracts was nil as at December 31, 2017 (2016 – $7.0 million).

The carrying values of the Company’s financial instruments approximate their fair values, except as follows:

As at	December 31, 2017				December 31, 2016
	Carrying value		Fair value		Carrying value		Fair value
Long-term debt excluding deferred financing fees	$	1,515,544	$	1,561,392	$	1,568,822	$	1,538,543

2017 Methanex Corporation Annual Report    69

Long-term debt consists of limited recourse debt facilities and unsecured notes. There is no publicly traded market for the limited recourse debt facilities. The fair value of the limited recourse debt facilities as disclosed on a recurring basis and categorized as Level 2 within the fair value hierarchy is estimated by reference to current market rates as at the reporting date. The fair value of the unsecured notes disclosed on a recurring basis and also categorized as Level 2 within the fair value hierarchy is estimated using quoted prices and yields as at the reporting date. The fair value of the Company’s long term debt will fluctuate until maturity.

19. Financial risk management:

a) Market risks:

The Company’s operations consist of the production and sale of methanol. Market fluctuations may result in significant cash flow and profit volatility risk for the Company. Its worldwide operating business as well as its investment and financing activities are affected by changes in methanol and natural gas prices and interest and foreign exchange rates. The Company seeks to manage and control these risks primarily through its regular operating and financing activities and uses derivative instruments to hedge these risks when deemed appropriate. This is not an exhaustive list of all risks, nor will the risk management strategies eliminate these risks.

Methanol price risk

The methanol industry is a highly competitive commodity industry and methanol prices fluctuate based on supply and demand fundamentals and other factors. The profitability of the Company is directly related to the market price of methanol. A decline in the market price of methanol could negatively impact the Company’s future operations. The Company does not hedge its methanol sales through derivative contracts. The Company manages its methanol price risk, to a certain degree, through natural gas supply contracts that include a variable price component related to methanol prices, as described below.

Natural gas price risk

Natural gas is the primary feedstock for the production of methanol. The Company has entered into multi-year natural gas supply contracts for its production facilities in New Zealand, Trinidad, Egypt and certain contracts in Chile that include base and variable price components to reduce the commodity price risk exposure. The variable price component is adjusted by formulas related to methanol prices above a certain level. The Company also has multi-year fixed price natural gas contracts to supply its production facilities in Geismar, Medicine Hat and Chile and natural gas hedges in Geismar and Medicine Hat to manage its exposure to natural gas price risk.

Interest rate risk

Interest rate risk is the risk that the Company suffers financial loss due to changes in the value of an asset or liability or in the value of future cash flows due to movements in interest rates.

The Company’s interest rate risk exposure is mainly related to long-term debt obligations.

As at	Dec 31 2017		Dec 31 2016
Fixed interest rate debt:
Unsecured notes	$	1,188,163	$	1,186,424
	$	1,188,163	$	1,186,424
Variable interest rate debt:
Egypt limited recourse debt facilities	$	241,190	$	288,515
Other limited recourse debt facilities		72,918		81,267
	$	314,108	$	369,782

For fixed interest rate debt, a 1% change in interest rates would result in a change in the fair value of the debt (disclosed in note 18) of approximately $84.0 million as of December 31, 2017 (2016 – $80.2 million).

The fair value of variable interest rate debt fluctuates primarily with changes in credit spreads.

For the variable interest rate debt, a 1% change in LIBOR would result in a change in annual interest payments of $3.2 million as of December 31, 2017 (2016 – $3.7 million).

70    2017 Methanex Corporation Annual Report

Foreign currency risk

The Company’s international operations expose the Company to foreign currency exchange risks in the ordinary course of business. Accordingly, the Company has established a policy that provides a framework for foreign currency management and hedging strategies and defines the approved hedging instruments. The Company reviews all significant exposures to foreign currencies arising from operating and investing activities and hedges exposures if deemed appropriate.

The dominant currency in which the Company conducts business is the United States dollar, which is also the reporting currency.

Methanol is a global commodity chemical that is priced in United States dollars. In certain jurisdictions, however, the transaction price is set either quarterly or monthly in the local currency. Accordingly, a portion of the Company’s revenue is transacted in Canadian dollars, euros, Chinese yuan and, to a lesser extent, other currencies. For the period from when the price is set in local currency to when the amount due is collected, the Company is exposed to declines in the value of these currencies compared to the United States dollar. The Company also purchases varying quantities of methanol for which the transaction currency is the euro, Chinese yuan and, to a lesser extent, other currencies. In addition, some of the Company’s underlying operating costs and capital expenditures are incurred in other currencies. The Company is exposed to increases in the value of these currencies that could have the effect of increasing the United States dollar equivalent of cost of sales and operating expenses and capital expenditures. The Company has elected not to actively manage these exposures at this time except for a portion of the net exposure to euro revenues, which is hedged through forward exchange contracts each quarter when the euro price for methanol is established.

As at December 31, 2017, the Company had a net working capital asset of $85.3 million in non U.S. dollar currencies (2016 – $75.3 million). Each 10% strengthening (weakening) of the U.S. dollar against these currencies would decrease (increase) the value of net working capital and pre-tax cash flows and earnings by approximately $8.5 million (2016 – $7.5 million).

b) Liquidity risks:

Liquidity risk is the risk that the Company will not have sufficient funds to meet its liabilities, such as the settlement of financial debt and lease obligations and payment to its suppliers. The Company maintains liquidity and makes adjustments to it in light of changes to economic conditions, underlying risks inherent in its operations and capital requirements to maintain and grow its operations. As at December 31, 2017, the Company had $375 million of cash and cash equivalents. In addition, the Company has an undrawn credit facility of $300 million provided by highly rated financial institutions that expires in December 2022.

In addition to the above-mentioned sources of liquidity, the Company monitors funding options available in the capital markets, as well as trends in the availability and costs of such funding, with a view to maintaining financial flexibility and limiting refinancing risks.

The expected cash flows of financial liabilities from the date of the balance sheet to the contractual maturity date are as follows:

As at December 31, 2017	Carrying amount		Contractual cash flows		1 year or less		1-3 years		3-5 years		More than 5 years
Trade and other payables1	$	519,352	$	519,352	$	519,352	$	–	$	–	$	–
Finance lease obligations		204,242		397,876		31,447		64,039		65,618		236,772
Long-term debt2		1,502,271		2,178,011		121,689		586,091		471,831		998,400
Cash flow hedges		91,014		105,120		7,114		17,057		28,864		52,085
	$	2,316,879	$	3,200,359	$	679,602	$	667,187	$	566,313	$	1,287,257

¹  Excludes tax and accrued interest.

²  Contractual cash flows include contractual interest payments related to debt obligations. Interest rates on variable rate debt are based on prevailing rates as at December 31, 2017.

c) Credit risks:

Counterparty credit risk is the risk that the financial benefits of contracts with a specific counterparty will be lost if a counterparty defaults on its obligations under the contract. This includes any cash amounts owed to the Company by those counterparties, less any amounts owed to the counterparty by the Company where a legal right of offset exists and also includes the fair values of contracts with individual counterparties that are recorded in the financial statements.

Trade credit risk

Trade credit risk is defined as an unexpected loss in cash and earnings if the customer is unable to pay its obligations in due time or if the value of the security provided declines. The Company has implemented a credit policy that includes approvals for new customers, annual credit evaluations of all customers and specific approval for any exposures beyond approved limits. The

2017 Methanex Corporation Annual Report    71

Company employs a variety of risk-mitigation alternatives, including credit insurance, certain contractual rights in the event of deterioration in customer credit quality and various forms of bank and parent company guarantees and letters of credit to upgrade the credit risk to a credit rating equivalent or better than the stand-alone rating of the counterparty. Trade credit losses have historically been minimal and as at December 31, 2017 substantially all of the trade receivables were classified as current.

Cash and cash equivalents

To manage credit and liquidity risk, the Company’s investment policy specifies eligible types of investments, maximum counterparty exposure and minimum credit ratings. Therefore, the Company invests only in highly rated investment-grade instruments that have maturities of three months or less.

Derivative financial instruments

The Company’s hedging policies specify risk management objectives and strategies for undertaking hedge transactions. The policies also include eligible types of derivatives and required transaction approvals, as well as maximum counterparty exposures and minimum credit ratings. The Company does not use derivative financial instruments for trading or speculative purposes.

To manage credit risk, the Company only enters into derivative financial instruments with highly rated investment-grade counterparties. Hedge transactions are reviewed, approved and appropriately documented in accordance with Company policies.

20. Retirement plans:

a) Defined benefit pension plans:

The Company has non-contributory defined benefit pension plans covering certain employees. The Company does not provide any significant post-retirement benefits other than pension plan benefits. Information concerning the Company’s defined benefit pension plans, in aggregate, is as follows:

As at	Dec 31 2017			Dec 31 2016
Accrued benefit obligations:
Balance, beginning of year	$	60,771		$	55,966
Current service cost		1,879			1,677
Past service cost		812			–
Interest cost on accrued benefit obligations		2,242			2,269
Benefit payments		(5,280	)		(2,570	)
Settlements		–			–
Actuarial loss		166			2,393
Foreign exchange loss		4,803			1,036
Balance, end of year		65,393			60,771
Fair values of plan assets:
Balance, beginning of year		44,230			40,286
Interest income on assets		1,522			1,553
Contributions		1,970			2,722
Benefit payments		(5,280	)		(2,570	)
Settlements		–			–
Return on plan assets		1,330			2,345
Foreign exchange gain (loss)		3,219			(106	)
Balance, end of year		46,991			44,230
Unfunded status		18,402			16,541
Minimum funding requirement		–			–
Defined benefit obligation, net	$	18,402		$	16,541

The Company has an unfunded retirement obligation of $25.1 million as at December 31, 2017 (2016 – $22.4 million) for its employees in Chile that will be funded at retirement in accordance with Chilean law. The accrued benefit for the unfunded retirement arrangement in Chile is paid when an employee leaves the Company in accordance with plan terms and Chilean regulations. The Company estimates that it may make benefit payments based on actuarial assumptions related to the unfunded retirement obligation in Chile of $5.1 million in 2018. Actual benefit payments in future periods will fluctuate based on employee retirements.

72    2017 Methanex Corporation Annual Report

The Company has a net funded retirement asset of $6.6 million as at December 31, 2017 (2016 – $5.7 million) for certain employees and retirees in Canada and a net funded retirement asset of $0.1 million as at December 31, 2017 (2016 – $0.2 million) in Europe. The Company estimates that it will make additional contributions relating to its defined benefit pension plan in Canada of $0.6 million in 2018.

These defined benefit plans expose the Company to actuarial risks, such as longevity risk, currency risk, interest rate risk and market risk on the funded plans. Additionally, as the plans provide benefits to plan members predominantly in Canada and Chile, the plans expose the Company to foreign currency risk for funding requirements. The primary long-term risk is that the Company will not have sufficient plan assets and liquidity to meet obligations when they fall due. The weighted average duration of the net defined benefit obligation is 10 years.

The Company’s net defined benefit pension plan expense charged to the consolidated statements of income for the years ended December 31, 2017 and 2016 is as follows:

For the years ended December 31	2017			2016
Net defined benefit pension plan expense:
Current service cost	$	1,879		$	1,677
Past service cost		812			–
Net interest cost		720			715
Cost of settlement		–			–
	$	3,411		$	2,392
The Company’s current year actuarial gains (losses), recognized in the consolidated statements of comprehensive income (loss) for the years ended December 31, 2017 and 2016, are as follows:
For the years ended December 31	2017			2016
Actuarial gain (loss)	$	564		$	(77	)
Minimum funding requirement		–			–
Actuarial gain (loss), net	$	564		$	(77	)
The Company uses a December 31 measurement date for its defined benefit pension plans. Actuarial reports for the Company’s defined benefit pension plans were prepared by independent actuaries for funding purposes as of December 31, 2016 in Canada. The next actuarial reports for funding purposes for the Company’s Canadian defined benefit pension plans are scheduled to be completed as of December 31, 2019. The discount rate is the most significant actuarial assumption used in accounting for the defined benefit pension plans. As at December 31, 2017, the weighted average discount rate for the defined benefit obligation was 3.7% (2016 - 3.7%). A decrease of 1% in the weighted average discount rate at the end of the reporting period, while holding all other assumptions constant, would result in an increase to the defined benefit obligation of approximately $6.3 million. The asset allocation for the defined benefit pension plan assets as at December 31, 2017 and 2016 is as follows:
As at	Dec 31 2017			Dec 31 2016
Equity securities		46	%		49	%
Debt securities		29	%		27	%
Cash and other short-term securities		25	%		24	%
Total		100	%		100	%

The fair values of the above equity and debt instruments are determined based on quoted market prices in active markets whereas the fair values of cash and other short-term securities are not based on quoted market prices in active markets. The plan assets are held separately from those of the Company in funds under the control of trustees.

b) Defined contribution pension plans:

The Company has defined contribution pension plans. The Company’s funding obligations under the defined contribution pension plans are limited to making regular payments to the plans, based on a percentage of employee earnings. Total net pension expense for the defined contribution pension plans charged to operations during the year ended December 31, 2017 was $8.1 million (2016 - $7.6 million).

2017 Methanex Corporation Annual Report    73

21. Commitments and contingencies:

a) Take-or-pay purchase contracts and related commitments:

The Company has commitments under take-or-pay contracts to purchase natural gas, to pay for transportation capacity related to the delivery of natural gas and to purchase oxygen and other feedstock requirements up to 2035. The minimum estimated commitment under these contracts, except as noted below, is as follows:

As at December 31, 2017

2018	2019	2020	2021	2022	Thereafter
$    473,927	$    371,167	$    306,400	$    308,338	$    245,989	$    1,300,609

In the above table, the Company has included natural gas commitments at the contractual volume and prices.

b) Argentina natural gas supply contracts:

Since June 2007, the Company’s natural gas suppliers from Argentina have curtailed all gas supply to the Company’s plants in Chile pursuant to long-term gas supply agreements. The Company has not received natural gas under these long-term agreements since 2007 and therefore potential future purchase obligations have been excluded from the table above.

c) Operating lease commitments:

The Company has future minimum lease payments under operating leases relating primarily to vessel charter, terminal facilities, office space, equipment and other operating lease commitments as follows:

As at December 31, 2017

2018	2019	2020	2021	2022	Thereafter
$    90,820	$    90,035	$    56,973	$    38,982	$    37,858	$    163,822

The minimum lease payments relate to the right of use of the leased asset and exclude non-lease elements such as the reimbursement of operating costs.

For the year ended December 31, 2017, the Company recognized as an expense $181.4 million (2016 – expense of $165.1 million) relating to operating lease payments. The expense recognized includes amounts related to leased assets and the reimbursement of operating costs for time charter vessels.

d) Leased assets not yet in service:

The Company has future minimum lease payments under operating leases related to two time charter agreements for vessels which are currently under construction and expected to be delivered in 2019. The minimum lease payments under these leases have been excluded from the operating lease commitments table above as the contracts contain certain cancellation features which are dependent on the delivery of the vessels. Once delivered, these vessels will have a total minimum commitment of approximately $80 million per vessel over a 15 year life.

e) Purchased methanol:

The Company has marketing rights for 100% of the production from its jointly owned plants (the Atlas plant in Trinidad in which it has a 63.1% interest and the plant in Egypt in which it has a 50% interest), which results in purchase commitments of an additional 1.3 million tonnes per year of methanol offtake supply when these plants operate at capacity. As at December 31, 2017, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2018 and 1.5 million tonnes in aggregate thereafter. The pricing under these purchase commitments is referenced to pricing at the time of purchase or sale, and accordingly, no amounts have been included in the table above.

74    2017 Methanex Corporation Annual Report

22. Related parties:

The Company has interests in significant subsidiaries and joint ventures as follows:

Name	Country of incorporation		Principal activities		Interest%
					Dec 31 2017			Dec 31 2016
Significant subsidiaries:
Methanex Asia Pacific Limited		Hong Kong		Marketing & distribution		100	%		100	%
Methanex Europe NV		Belgium		Marketing & distribution		100	%		100	%
Methanex Methanol Company, LLC		United States		Marketing & distribution		100	%		100	%
Egyptian Methanex Methanol Company S.A.E. (“Methanex Egypt”)		Egypt		Production		50	%		50	%
Methanex Chile S.A.		Chile		Production		100	%		100	%
Methanex New Zealand Limited		New Zealand		Production		100	%		100	%
Methanex Trinidad (Titan) Unlimited		Trinidad		Production		100	%		100	%
Methanex U.S.A. LLC		United States		Production		100	%		100	%
Methanex Louisiana LLC		United States		Production		100	%		100	%
Waterfront Shipping Company Limited2		Cayman Islands		Shipping		100	%		100	%
Significant joint ventures:
Atlas Methanol Company Unlimited1		Trinidad		Production		63.1	%		63.1	%

¹  Summarized financial information for the group’s investment in Atlas is disclosed in note 6.

²  Waterfront Shipping Company Limited has a controlling interest in multiple ocean going vessels owned through less than wholly-owned entities as disclosed in note 23.

Transactions between the Company and Atlas are considered related party transactions and are included within the summarized financial information in note 6. Atlas revenue for the year ended December 31, 2017 of $459 million (2016 – $214 million) is a related party transaction as the Company has marketing rights for 100% of the methanol produced by Atlas. Balances outstanding with Atlas as at December 31, 2017 and provided in the summarized financial information in note 6 include receivables owing from Atlas to the Company of $13 million (2016 – $7 million), and payables to Atlas of $98 million (2016 – $55 million). The Company has total loans outstanding to Atlas as at December 31, 2017 of $76 million (2016 – $76 million) which are unsecured and due at maturity.

Remuneration of non-management directors and senior management, which includes the members of the executive leadership team, is as follows:

For the years ended December 31	2017		2016
Short-term employee benefits	$	5,214	$	5,315
Post-employment benefits		583		650
Other long-term employee benefits		43		47
Share-based compensation expense1		40,668		16,172
Total	$	46,508	$	22,184

¹  Balance includes realized and unrealized gains (losses) from share-based compensation awards granted.

2017 Methanex Corporation Annual Report    75

23. Non-controlling interests:

Set out below is summarized financial information for each of our subsidiaries that have non-controlling interests. The amounts disclosed are before inter-company eliminations.

As at	Dec 31 2017									Dec 31 2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Current assets	$	248,032		$	27,240		$	275,272		$	155,422		$	12,123		$	167,545
Non-current assets		720,356			105,375			825,731			746,202			116,314			862,516
Current liabilities		(231,259	)		(12,489	)		(243,748	)		(177,088	)		(14,622	)		(191,710	)
Non-current liabilities		(293,184	)		(76,090	)		(369,274	)		(339,369	)		(84,540	)		(423,909	)
Net assets		443,945			44,036			487,981			385,167			29,275			414,442
Carrying amount of Methanex non-controlling interests	$	216,599		$	27,748		$	244,347		$	188,099		$	20,416		$	208,515
For the years ended December 31				2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Revenue	$	285,017		$	32,094		$	317,111		$	111,728		$	26,148		$	137,876
Net and total comprehensive income (loss)		65,241			6,981			72,222			(79,963	)		4,781			(75,182	)
Net and total comprehensive income (loss) allocated to Methanex non-controlling interests		55,470			3,492			58,962			(18,069	)		2,389			(15,680	)
Equity contributions by non-controlling interests	$	–		$	8,170		$	8,170		$	–		$	25		$	25
Distributions paid and accrued to non-controlling interests	$	(26,970	)	$	(4,330	)	$	(31,300	)	$	(23,264	)	$	(1,410	)	$	(24,674	)
For the years ended December 31				2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Cash flows from (used in) operating activities	$	131,175		$	19,538		$	150,713		$	(23,992	)	$	17,718		$	(6,274	)
Cash flows from (used in) financing activities		(27,365	)		(3,250	)		(30,615	)		(24,929	)		55,891			30,962
Cash flows from (used in) investing activities	$	(18,839	)	$	(605	)	$	(19,444	)	$	(4,637	)	$	(70,516	)	$	(75,153	)

¹  Other is comprised of multiple ocean going vessels controlled by Waterfront Shipping Company Limited through less than wholly-owned entities.

The Company has reclassified the presentation of amounts relating to accrued distributions to Methanex Egypt in Changes in non-cash working capital from Operating activities to Financing activities. The reclassification has been reflected in the comparative figures.

76    2017 Methanex Corporation Annual Report

XML

Document and Entity Information - shares	12 Months Ended
	Dec. 31, 2017	Mar. 05, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	METHANEX CORP
Entity Central Index Key	0000886977
Current Fiscal Year End Date	--12-31
Document Type	40-F
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		83,783,704
Entity Current Reporting Status	Yes

XML

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 375,479	$ 223,890
Trade and other receivables (note 3)	536,636	499,603
Inventories (note 4)	304,464	281,328
Prepaid expenses	26,548	20,846
Current assets	1,243,127	1,025,667
Non-current assets:
Property, plant and equipment (note 5)	2,998,326	3,117,469
Investment in associate (note 6)	188,922	197,402
Deferred income tax assets (note 15)	102,341	137,341
Other assets (note 7)	78,026	78,784
Non-current assets	3,367,615	3,530,996
Assets	4,610,742	4,556,663
Current liabilities:
Trade, other payables and accrued liabilities	626,817	523,216
Current maturities on long-term debt (note 8)	55,905	53,997
Current maturities on other long-term liabilities (note 9)	65,226	29,720
Current liabilities	747,948	606,933
Non-current liabilities:
Long-term debt (note 8)	1,446,366	1,502,209
Other long-term liabilities (note 9)	404,885	351,191
Deferred income tax liabilities (note 15)	266,432	290,980
Non-current liabilities	2,117,683	2,144,380
Equity:
Capital stock, 25,000,000 authorized preferred shares without nominal or par value; Unlimited authorization of common shares without nominal or par value; Issued and outstanding common shares at December 31, 2017 were 83,770,254 (2016 - 89,824,338)	480,331	511,465
Contributed surplus	2,124	2,568
Retained earnings	1,088,150	1,124,104
Accumulated other comprehensive loss	(69,841)	(41,302)
Shareholders’ equity	1,500,764	1,596,835
Non-controlling interests	244,347	208,515
Total equity	1,745,111	1,805,350
Equity and liabilities	$ 4,610,742	$ 4,556,663

XML

Consolidated Statements of Financial Position (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Preferred shares
Statement [Line Items]
Number of shares authorised	25,000,000	25,000,000
Capital stock | Common shares
Statement [Line Items]
Number of shares issued	83,770,254	89,824,338
Number of shares outstanding	83,770,254	89,824,338

XML

Consolidated Statements of Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Profit or loss [abstract]
Revenue	$ 3,060,642	$ 1,998,429
Cost of sales and operating expenses (note 10)	(2,351,949)	(1,774,429)
Depreciation and amortization (note 10)	(232,225)	(228,054)
Argentina gas settlement	0	32,500
Operating income	476,468	28,446
Earnings of associate (note 6)	75,995	19,930
Finance costs (note 11)	(94,955)	(90,060)
Finance income and other expenses	13,377	4,180
Income (loss) before income taxes	470,885	(37,504)
Income tax recovery (expense) (note 15):
Current	(85,504)	(54,677)
Deferred	(10,284)	63,956
Tax expense (income), continuing operations	(95,788)	9,279
Net income (loss)	375,097	(28,225)
Attributable to:
Methanex Corporation shareholders	316,135	(12,545)
Non-controlling interests (note 23)	58,962	(15,680)
Net income (loss)	$ 375,097	$ (28,225)
Income (loss) per common share for the period attributable to Methanex Corporation shareholders:
Basic net income (loss) per common share (note 12) (in usd per share)	$ 3.64	$ (0.14)
Diluted net income (loss) per common share (note 12) (in usd per share)	$ 3.64	$ (0.14)
Weighted average number of common shares outstanding	86,768,589	89,783,883
Diluted weighted average number of common shares outstanding	86,824,948	89,783,883

XML

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of comprehensive income [abstract]
Net income (loss)	$ 375,097	$ (28,225)
Items that may be reclassified to income:
Change in fair value of cash flow hedges (note 18)	(74,790)	153,863
Forward elements excluded from hedging relationship (note 18)	45,416	(174,078)
Items that will not be reclassified to income:
Actuarial gains (losses) on defined benefit pension plans (note 20(a))	564	(77)
Taxes on above items	674	6,597
Other comprehensive loss	(28,136)	(13,695)
Comprehensive income (loss)	346,961	(41,920)
Attributable to:
Methanex Corporation shareholders	287,999	(26,240)
Non-controlling interests (note 23)	$ 58,962	$ (15,680)

XML

Consolidated Statements of Changes in Equity - USD ($) $ in Thousands	Total	Capital stock	Capital stock Common shares	Contributed surplus	Retained earnings	Accumulated other comprehensive loss	Shareholders’ equity	Non-controlling interests
Number of common shares, beginning of period at Dec. 31, 2015			89,671,198
Balance, beginning of period at Dec. 31, 2015	$ 1,968,573	$ 509,464		$ 2,426	$ 1,235,615	$ (27,776)	$ 1,719,729	$ 248,844
Net income (loss)	(28,225)				(12,545)		(12,545)	(15,680)
Other comprehensive income (loss)	(13,695)				(169)	(13,526)	(13,695)
Compensation expense recorded for stock options	637			637			637
Issue of shares on exercise of stock options (in shares)			153,140
Issue of shares on exercise of stock options	1,506	1,506					1,506
Reclassification of grant-date fair value on exercise of stock options	0	495		(495)
Dividend payments to Methanex Corporation shareholders	(98,797)				(98,797)		(98,797)
Distributions made and accrued to non-controlling interests	(24,674)							(24,674)
Equity contributions by non-controlling interests	25							25
Number of common shares, end of period at Dec. 31, 2016			89,824,338
Balance, end of period at Dec. 31, 2016	1,805,350	511,465		2,568	1,124,104	(41,302)	1,596,835	208,515
Net income (loss)	375,097				316,135		316,135	58,962
Other comprehensive income (loss)	(28,136)				403	(28,539)	(28,136)
Compensation expense recorded for stock options	488			488			488
Issue of shares on exercise of stock options (in shares)			98,274
Issue of shares on exercise of stock options	3,059	3,059					3,059
Reclassification of grant-date fair value on exercise of stock options	0	932		(932)
Payments for shares repurchased (in shares)			(6,152,358)
Payment for shares repurchased	(286,120)	(35,125)			(250,995)		(286,120)
Dividend payments to Methanex Corporation shareholders	(101,497)				(101,497)		(101,497)
Distributions made and accrued to non-controlling interests	(31,300)							(31,300)
Equity contributions by non-controlling interests	8,170							8,170
Number of common shares, end of period at Dec. 31, 2017			83,770,254
Balance, end of period at Dec. 31, 2017	$ 1,745,111	$ 480,331		$ 2,124	$ 1,088,150	$ (69,841)	$ 1,500,764	$ 244,347

XML

Consolidated Statements of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of changes in equity [abstract]
Dividends payments to Methanex Corporation shareholders (in usd per common share)	$ 1.175	$ 1.10

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM / (USED IN) OPERATING ACTIVITIES
Net income (loss)	$ 375,097	$ (28,225)
Deduct earnings of associate	(75,995)	(19,930)
Dividends received from associate	84,553	47,325
Add (deduct) non-cash items:
Depreciation and amortization	232,225	228,054
Income tax expense (recovery)	95,788	(9,279)
Share-based compensation expense	78,821	33,493
Finance costs	94,955	90,060
Other	4,033	1,559
Income taxes paid	(35,890)	(5,241)
Other cash payments, including share-based compensation	(16,477)	(23,505)
Cash flows from operating activities before undernoted	837,110	314,311
Changes in non-cash working capital (note 16(a))	(49,368)	(87,644)
Cash flows from / (used in) operating activities	787,742	226,667
CASH FLOWS FROM / (USED IN) FINANCING ACTIVITIES
Payments for repurchase of shares	(286,120)	0
Dividend payments to Methanex Corporation shareholders	(101,497)	(98,797)
Interest paid	(86,041)	(82,965)
Net proceeds on issue of long-term debt	0	65,700
Repayment of long-term debt and financing fees	(56,997)	(48,417)
Finance leases	(6,880)	(5,144)
Equity contributions by non-controlling interests	8,170	25
Cash distributions to non-controlling interests	(4,330)	(1,410)
Proceeds on issue of shares on exercise of stock options	3,059	1,506
Cash flows from / (used in) financing activities	(530,636)	(169,502)
CASH FLOWS FROM / (USED IN) INVESTING ACTIVITIES
Property, plant and equipment	(103,170)	(99,881)
Other assets	0	(66)
Changes in non-cash working capital related to investing activities (note 16(a))	(2,347)	11,738
Cash flows from / (used in) investing activities	(105,517)	(88,209)
Increase (decrease) in cash and cash equivalents	151,589	(31,044)
Cash and cash equivalents, beginning of year	223,890	254,934
Cash and cash equivalents, end of year	$ 375,479	$ 223,890

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Nature of operations

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

Nature of operations

Nature of operations:

Methanex Corporation ("the Company") is an incorporated entity with corporate offices in Vancouver, Canada. The Company’s operations consist of the production and sale of methanol, a commodity chemical. The Company is the world’s largest producer and supplier of methanol to the major international markets of Asia Pacific, North America, Europe and South America.

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Significant accounting policies

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

Significant accounting policies

Significant accounting policies:

a) Statement of compliance:

These consolidated financial statements are prepared in accordance with International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB"). These consolidated financial statements were approved and authorized for issue by the Board of Directors on March 5, 2018.

b) Basis of presentation and consolidation:

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, less than wholly-owned entities for which it has a controlling interest and its equity-accounted joint venture. Wholly-owned subsidiaries are entities in which the Company has control, directly or indirectly, where control is defined as the power to govern the financial and operating policies of an enterprise so as to obtain benefits from its activities. For less than wholly-owned entities for which the Company has a controlling interest, a non-controlling interest is included in the Company’s consolidated financial statements and represents the non-controlling shareholders’ interest in the net assets of the entity. The Company also consolidates any special purpose entity where the substance of the relationship indicates the Company has control. All significant intercompany transactions and balances have been eliminated. Preparation of these consolidated financial statements requires estimates, judgments and assumptions that affect the amounts reported and disclosed in the financial statements and related notes. The areas of estimation and judgment that management considers most significant are property, plant and equipment (note 2(g)), financial instruments (note 2(o)), fair value measurements (note 2(p)) and income taxes (note 2(q)). Actual results could differ from those estimates.

c) Reporting currency and foreign currency translation:

Functional currency is the currency of the primary economic environment in which an entity operates. The majority of the Company’s business in all jurisdictions is transacted in United States dollars and, accordingly, these consolidated financial statements have been measured and expressed in that currency. The Company translates foreign currency denominated monetary items at the period-end exchange rates, foreign currency denominated non-monetary items at historic rates and revenues and expenditures at the exchange rates at the dates of the transactions. Foreign exchange gains and losses are included in earnings.

d) Cash and cash equivalents:

Cash and cash equivalents include securities with maturities of three months or less when purchased.

e) Receivables:

The Company provides credit to its customers in the normal course of business. The Company performs ongoing credit evaluations of its customers and maintains reserves for potential credit losses. The Company records an allowance for doubtful accounts or writes down the receivable to estimated net realizable value if not collectible in full. Credit losses have historically been within the range of management’s expectations.

f) Inventories:

Inventories are valued at the lower of cost and estimated net realizable value. Cost is determined on a first-in, first-out basis and includes direct purchase costs, cost of production, allocation of production overhead and depreciation based on normal operating capacity and transportation.

g) Property, plant and equipment:

Initial recognition

Property, plant and equipment are initially recorded at cost. The cost of purchased equipment includes expenditures that are directly attributable to the purchase price, delivery and installation. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to the location and condition for their intended use, the costs of dismantling and removing the items and restoring the site on which they are located, and borrowing costs on self-constructed assets that meet certain criteria. Borrowing costs incurred during construction and commissioning are capitalized until the plant is operating in the manner intended by management.

Subsequent costs

Routine repairs and maintenance costs are expensed as incurred. At regular intervals, the Company conducts a planned shutdown and inspection (turnaround) at its plants to perform major maintenance and replacement of catalysts. Costs associated with these shutdowns are capitalized and amortized over the period until the next planned turnaround and the carrying amounts of replaced components are derecognized and included in earnings.

Depreciation

Depreciation and amortization is generally provided on a straight-line basis at rates calculated to amortize the cost of property, plant and equipment from the commencement of commercial operations over their estimated useful lives to estimated residual value.

The estimated useful lives of the Company’s buildings, plant installations and machinery, excluding costs related to turnarounds, ranges from 10 to 25 years depending on the specific asset component and the production facility to which it is related. The Company determines the estimated useful lives of individual asset components based on the shorter of its physical life or economic life. The physical life of these assets is generally longer than the economic life. The economic life is primarily determined by the nature of the natural gas feedstock available to the various production facilities. Factors that influence the nature of natural gas feedstock availability include the terms of individual natural gas supply contracts, access to natural gas supply through open markets, regional factors influencing the exploration and development of natural gas and the expected price of securing natural gas supply. The Company reviews the factors related to each production facility on an annual basis to determine if changes are required to the estimated useful lives.

Assets under finance lease are depreciated to their estimated residual value based on the shorter of their useful lives and the lease term.

Impairment

The Company reviews the carrying value of long-lived assets for impairment whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. Examples of such events or changes in circumstances include, but are not restricted to: a significant adverse change in the extent or manner in which the asset is being used or in its physical condition; a significant change in the long-term methanol price or in the price or availability of natural gas feedstock required to manufacture methanol; a significant adverse change in legal factors or in the business climate that could affect the asset’s value, including an adverse action or assessment by a foreign government that impacts the use of the asset; or a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the asset’s use.

Recoverability of long-lived assets is measured by comparing the carrying value of an asset or cash-generating unit to the estimated recoverable amount, which is the higher of its estimated fair value less cost to sell or its value in use. Value in use is determined by estimating the pre-tax cash flows expected to be generated from the asset or cash-generating unit over its estimated useful life discounted by a pre-tax discount rate. An impairment writedown is recorded for the difference that the carrying value exceeds the estimated recoverable amount. An impairment writedown recognized in prior periods for an asset or cash-generating unit is reversed if there has been a subsequent recovery in the value of the asset or cash-generating unit due to changes in events and circumstances. For purposes of recognition and measurement of an impairment writedown, the Company groups long-lived assets with other assets and liabilities to form a "cash-generating unit" at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. To the extent that methanol facilities in a particular location are interdependent as a result of common infrastructure and/or feedstock from sources that can be shared within a facility location, the Company groups assets based on site locations for the purpose of determining impairment.

h) Other assets:

Intangible assets are capitalized to other assets and amortized to depreciation and amortization expense on an appropriate basis to charge the cost of the assets against earnings.

Financing fees related to undrawn credit facilities are capitalized to other assets and amortized to finance costs over the term of the credit facility.

i) Leases:

Leasing contracts are classified as either finance or operating leases based on the substance of the contractual arrangement at inception date. A lease is classified as a finance lease if it transfers substantially all of the risks and rewards of ownership of the leased asset. Where the contracts are classified as finance leases, upon initial recognition, the asset and liability are recorded at the lower of fair value and the present value of the minimum lease payments, net of executory costs. Finance lease payments are apportioned between interest expense and repayments of the liability. Where the contracts are classified as operating leases, they are not recognized in the Company's consolidated statements of financial position and lease payments are charged to income as they are incurred on a straight line basis over the lease term.

j) Site restoration costs:

The Company recognizes a liability to dismantle and remove assets or to restore a site upon which the assets are located. The Company estimates the present value of the expenditures required to settle the liability by determining the current market cost required to settle the site restoration costs, adjusts for inflation through to the expected date of the expenditures and then discounts this amount back to the date when the obligation was originally incurred. As the liability is initially recorded on a discounted basis, it is increased each period until the estimated date of settlement. The resulting expense is referred to as accretion expense and is included in finance costs. The Company reviews asset retirement obligations and adjusts the liability and corresponding asset as necessary to reflect changes in the estimated future cash flows, timing, inflation and discount rates underlying the measurement of the obligation.

k) Employee future benefits:

The Company has non-contributory defined benefit pension plans covering certain employees and defined contribution pension plans. The Company does not provide any significant post-retirement benefits other than pension plan benefits. For defined benefit pension plans, the net of the present value of the defined benefit obligation and the fair value of plan assets is recorded to the consolidated statements of financial position. The determination of the defined benefit obligation and associated pension cost is based on certain actuarial assumptions including inflation rates, mortality, plan expenses, salary growth and discount rates. The present value of the net defined benefit obligation (asset) is determined by discounting the net estimated future cash flows using current market bond yields that have terms to maturity approximating the terms of the net obligation. Actuarial gains and losses arising from differences between these assumptions and actual results are recognized in other comprehensive income and recorded in retained earnings. The Company recognizes gains and losses on the settlement of a defined benefit plan in income when the settlement occurs. The cost for defined contribution benefit plans is recognized in net income (loss) as earned by the employees.

l) Share-based compensation:

The Company grants share-based awards as an element of compensation. Share-based awards granted by the Company can include stock options, tandem share appreciation rights, share appreciation rights, deferred share units, restricted share units or performance share units.

For stock options granted by the Company, the cost of the service received is measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus. On the exercise of stock options, consideration received, together with the compensation expense previously recorded to contributed surplus, is credited to share capital. The Company uses the Black-Scholes option pricing model to estimate the fair value of each stock option tranche at the date of grant.

Share appreciation rights ("SARs") are units that grant the holder the right to receive a cash payment upon exercise for the difference between the market price of the Company’s common shares and the exercise price that is determined at the date of grant. Tandem share appreciation rights ("TSARs") give the holder the choice between exercising a regular stock option or a SAR. For SARs and TSARs, the cost of the service received is initially measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in liabilities. For SARs and TSARs, the liability is re-measured at each reporting date based on an estimate of the fair value with changes in fair value recognized as compensation expense for the proportion of the service that has been rendered at that date. The Company uses the Black-Scholes option pricing model to estimate the fair value for SARs and TSARs.

Deferred, restricted and performance share units are grants of notional common shares that are redeemable for cash based on the market value of the Company’s common shares and are non-dilutive to shareholders. Performance share units have an additional feature where the ultimate number of units that vest will be determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The number of units that will ultimately vest will be in the range of 50% to 120% of the original grant for grants prior to 2014 and in the range of 25% to 150% for subsequent grants based on the weighted-average closing share price for the 90 calendar days on the NASDAQ Global Select Market immediately preceding the year end date that the performance share units vest. For deferred, restricted and performance share units, the cost of the service received as consideration is initially measured based on the market value of the Company’s common shares at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in liabilities. Deferred, restricted and performance share units are re-measured at each reporting date based on the market value of the Company’s common shares with changes in fair value recognized as compensation expense for the proportion of the service that has been rendered at that date.

Additional information related to the stock option plan, TSARs, SARs and the deferred, restricted and performance share units is described in note 13.

m) Net income (loss) per common share:

The Company calculates basic net income (loss) per common share by dividing net income (loss) attributable to Methanex shareholders by the weighted average number of common shares outstanding and calculates diluted net income (loss) per common share under the treasury stock method. Under the treasury stock method, diluted net income (loss) per common share is calculated by considering the potential dilution that would occur if outstanding stock options and, under certain circumstances, TSARs were exercised or converted to common shares. Stock options and TSARs are considered dilutive when the average market price of the Company’s common shares during the period disclosed exceeds the exercise price of the stock option or TSAR.

Outstanding TSARs may be settled in cash or common shares at the holder’s option. For the purposes of calculating diluted net income (loss) per common share, the more dilutive of the cash-settled or equity-settled method is used, regardless of how the plan is accounted for. Accordingly, TSARs that are accounted for using the cash-settled method will require adjustments to the numerator and denominator if the equity-settled method is determined to have a dilutive effect on diluted net income (loss) per common share.

The calculation of basic net income (loss) per common share and a reconciliation to diluted net income (loss) per common share is presented in note 12.

n) Revenue recognition:

Revenue is recognized based on individual contract terms when the risk of loss to the product transfers to the customer, which usually occurs at the time shipment is made. Revenue is recognized at the time of delivery to the customer’s location if the Company retains risk of loss during shipment. For methanol sold on a consignment basis, revenue is recognized when the customer consumes the methanol. For methanol sold on a commission basis, the commission income is included in revenue when earned.

o) Financial instruments:

All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Financial instruments are classified into one of three categories and, depending on the category, will either be measured at amortized cost or fair value with fair value changes either recorded through profit or loss or other comprehensive income. All non-derivative financial instruments held by the Company are classified and measured at amortized cost.

The Company enters into derivative financial instruments to manage certain exposures to commodity price and foreign exchange volatility. Under these standards, derivative financial instruments, including embedded derivatives, are classified as fair value through profit or loss and are recorded in the consolidated statements of financial position at fair value unless they are in accordance with the Company’s normal purchase, sale or usage requirements. The valuation of derivative financial instruments is a critical accounting estimate due to the complex nature of these instruments, the degree of judgment required to appropriately value these instruments and the potential impact of such valuation on the Company’s financial statements. The Company records all changes in fair value of derivative financial instruments in profit or loss unless the instruments are designated as cash flow hedges. The Company enters into and designates as cash flow hedges certain forward contracts to hedge its highly probable forecast natural gas purchases and certain forward exchange purchase and sales contracts to hedge foreign exchange exposure on anticipated purchases or sales. The Company assesses at inception and on an ongoing basis whether the hedges are and continue to be effective in offsetting changes in the cash flows of the hedged transactions. The effective portion of changes in the fair value of these hedging instruments is recognized in other comprehensive income. Any gain or loss in fair value relating to the ineffective portion is recognized immediately in profit or loss. Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in commodity prices, foreign currency exchange rates or variable interest rates.

p) Fair value measurements:

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements within the scope of IFRS 13 are categorized into Level 1, 2 or 3 based on the degree to which the inputs are observable and the significance of the inputs to the fair value measurement in its entirety. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can access at the measurement date. Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Financial instruments measured at fair value and categorized within the fair value hierarchy are disclosed in note 18.

q) Income taxes:

Income tax expense represents current tax and deferred tax. The Company records current tax based on the taxable profits for the period calculated using tax rates that have been enacted or substantively enacted by the reporting date. Income taxes relating to uncertain tax positions are provided for based on the Company’s best estimate. Deferred income taxes are accounted for using the liability method. The liability method requires that income taxes reflect the expected future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their tax bases. Deferred income tax assets and liabilities are determined for each temporary difference based on currently enacted or substantially enacted tax rates that are expected to be in effect when the underlying items are expected to be realized. The effect of a change in tax rates or tax legislation is recognized in the period of substantive enactment. Deferred tax assets, such as non-capital loss carryforwards, are recognized to the extent it is probable that taxable profit will be available against which the asset can be utilized.

The Company accrues for taxes that will be incurred upon distributions from its subsidiaries when it is probable that the earnings will be repatriated.

r) Provisions:

Provisions are recognized where a legal or constructive obligation has been incurred as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation.

s) Segmented information:

The Company’s operations consist of the production and sale of methanol, which constitutes a single operating segment.

t) Application of new and revised accounting standards:

The Company has adopted the amendments to IAS 7, Statement of Cash Flows, which were effective for annual periods beginning on or after January 1, 2017. As a result of applying the amendment, the Company presented new disclosures relating to change in financial liabilities arising from financing activities (note16(b)).

u) Anticipated changes to International Financial Reporting Standards:

In May 2014, the IASB issued IFRS 15, Revenue from Contracts with Customers ("IFRS 15") establishing a comprehensive framework for revenue recognition. The standard replaces IAS 18, Revenue and IAS 11, Construction Contracts and related interpretations and is effective for annual periods beginning on or after January 1, 2018, with early adoption permitted. The Company has performed its assessment of the impact of the new standard and anticipates no impact on its consolidated financial statements.

In January 2016, the IASB issued IFRS 16, Leases ("IFRS 16"), which eliminates the current operating/finance lease dual accounting model for lessees and replaces it with a single, on-balance sheet accounting model, similar to the current finance lease accounting. The standard replaces IAS 17, Leases ("IAS 17") and related interpretations and is effective for annual periods beginning on or after January 1, 2019, with early application permitted. The Company plans to apply this standard at the date it becomes effective.

The Company is currently assessing the impact of the new standard including the optional exemptions available. The recognition of all leases on balance sheet is expected to increase the assets and liabilities on the Consolidated Statement of Financial Position upon adoption. The increase primarily relates to ocean vessels, terminal facilities and other right of use assets currently accounted for as operating leases. In addition, the nature and timing of certain expenses related to leases previously classified as operating and presented in cost of sales and operating expenses will now change and be presented in depreciation and amortization and finance costs. As a result, the Company expects that adoption of IFRS 16 will significantly impact the consolidated financial statements. The Company has not yet decided whether it will use the optional exemptions available under the standard. Refer to note 21, commitments and contingencies, for operating lease commitments as at December 31, 2017 disclosed under IAS 17.

The Company does not expect that any other new or amended standards or interpretations that are effective as of January 1, 2018 will have a significant impact on the Company’s results of operations or financial position.

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Trade and other receivables

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

Trade and other receivables

Trade and other receivables:

As at	Dec 31 2017		Dec 31 2016
Trade	$	429,582	$	335,606
Value-added and other tax receivables	36,584		63,738
Egypt gas contract recoveries(a)	24,466		41,578
Other	46,004		58,681
	$	536,636	$	499,603

a) Egypt gas contract recoveries:

The natural gas supply agreement in Egypt has a mechanism whereby the Company is partially compensated when gas delivery shortfalls exceed a certain threshold. The receivable is secured by a combination of funds held in escrow and a bank guarantee.

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Inventories

12 Months Ended

Dec. 31, 2017

Inventories [Abstract]

Inventories

Inventories:

Inventories are valued at the lower of cost, determined on a first-in first-out basis, and estimated net realizable value. The amount of inventories recognized as an expense in cost of sales and operating expenses and depreciation and amortization for the year ended December 31, 2017 is $2,219 million (2016 - $1,704 million).

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Property, plant and equipment

12 Months Ended

Dec. 31, 2017

Property, plant and equipment [abstract]

Property, plant and equipment

Property, plant and equipment:

	Buildings, plant installations and machinery			Finance leases		Other			TOTAL
Cost at January 1, 2017	$	4,549,816		$	206,260	$	272,878		$	5,028,954
Additions	98,780			7,667		5,001			111,448
Disposals and other	328			1,846		(2,386		)	(212		)
Cost at December 31, 2017	4,648,924			215,773		275,493			5,140,190
Accumulated depreciation at January 1, 2017	1,752,540			18,557		140,388			1,911,485
Disposals and other	(2,066		)	—		(673		)	(2,739		)
Depreciation	205,843			15,370		11,905			233,118
Accumulated depreciation at December 31, 2017	1,956,317			33,927		151,620			2,141,864
Net book value at December 31, 2017	$	2,692,607		$	181,846	$	123,873		$	2,998,326

	Buildings, plant installations and machinery			Finance leases			Other			TOTAL
Cost at January 1, 2016	$	4,521,835		$	121,849		$	204,483		$	4,848,167
Additions	35,644			87,800			74,303			197,747
Disposals and other	(7,663		)	(3,389		)	(5,908		)	(16,960		)
Cost at December 31, 2016	4,549,816			206,260			272,878			5,028,954
Accumulated depreciation at January 1, 2016	1,545,834			6,853			136,698			1,689,385
Disposals and other	(945		)	—			(5,908		)	(6,853		)
Depreciation	207,651			11,704			9,598			228,953
Accumulated depreciation at December 31, 2016	1,752,540			18,557			140,388			1,911,485
Net book value at December 31, 2016	$	2,797,276		$	187,703		$	132,490		$	3,117,469

Included in finance leases as at December 31, 2017 are capitalized costs related to a methanol terminal and storage tanks in Geismar, Louisiana, an oxygen production facility in Trinidad, and two ocean going vessels.

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Investment in associate

12 Months Ended

Dec. 31, 2017

Interests In Other Entities [Abstract]

Investment in associate

Investment in associate:

a) The Company has a 63.1% equity interest in Atlas Methanol Company Unlimited ("Atlas"). Atlas owns a 1.8 million tonne per year methanol production facility in Trinidad. The Company accounts for its interest in Atlas using the equity method. Summarized financial information of Atlas (100% basis) is as follows:

Consolidated statements of financial position as at	Dec 31 2017			Dec 31 2016
Cash and cash equivalents	$	8,361		$	15,530
Other current assets1	79,738			45,219
Non-current assets	289,671			324,297
Current liabilities1	(41,388		)	(24,783		)
Other long-term liabilities, including current maturities	(157,935		)	(168,253		)
Net assets at 100%	178,447			192,010
Net assets at 63.1%	112,600			121,158
Long-term receivable from Atlas1	76,322			76,244
Investment in associate	$	188,922		$	197,402

Consolidated statements of income for the years ended December 31	2017			2016
Revenue1	$	459,367		$	213,533
Cost of sales and depreciation and amortization	(261,121		)	(145,126		)
Operating income	198,246			68,407
Finance costs, finance income and other expenses	(11,170		)	(12,771		)
Income tax expense	(66,640		)	(24,052		)
Net earnings at 100%	120,436			31,584
Earnings of associate at 63.1%	75,995			19,930
Dividends received from associate	$	84,553		$	47,325

¹ Includes related party transactions between Atlas and the Company (see note 22).

b) Contingent liability:

The Board of Inland Revenue of Trinidad and Tobago has issued assessments against Atlas in respect of the 2005 to 2011 financial years. All subsequent tax years remain open to assessment. The assessments relate to the pricing arrangements of certain long-term fixed price sales contracts from 2005 to 2019 related to methanol produced by Atlas. Atlas had partial relief from corporation income tax until late July 2014.

The Company has lodged objections to the assessments. Based on the merits of the cases and legal interpretation, management believes its position should be sustained.

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Other assets

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

Other assets

Other assets:

As at	Dec 31 2017		Dec 31 2016
Restricted cash	$	27,863	$	35,386
Chile VAT receivable	25,456		23,406
Investment in Carbon Recycling International	4,502		4,502
Defined benefit pension plans (note 20)	6,650		5,862
Other	13,555		9,628
	$	78,026	$	78,784

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Long-term debt

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Long-term debt

Long-term debt:

As at	Dec 31 2017			Dec 31 2016
Unsecured notes
(i) 3.25% due December 15, 2019	$	348,060		$	347,126
(ii) 5.25% due March 1, 2022	248,072			247,685
(iii) 4.25% due December 1, 2024	296,873			296,529
(iv) 5.65% due December 1, 2044	295,158			295,084
	1,188,163			1,186,424
Egypt limited recourse debt facilities	241,190			288,515
Other limited recourse debt facilities	72,918			81,267
Total long-term debt1	1,502,271			1,556,206
Less current maturities1	(55,905		)	(53,997		)
	$	1,446,366		$	1,502,209

¹ Long-term debt and current maturities are presented net of discounts and deferred financing fees of $17.8 million as at December 31, 2017 (2016 - $17.8 million).

The Egypt limited recourse debt facilities have interest payable semi-annually with rates based on LIBOR plus a spread ranging from 0.9% to 1.6% per annum. Principal is paid in 24 semi-annual payments, which commenced in September 2010.

Other limited recourse debt facilities relate to financing for certain of our ocean going vessels which we own through less than wholly-owned entities under the Company's control. Other limited recourse debt facilities have remaining terms of two to fouryears with principal and interest payable quarterly with rates based on LIBOR plus a spread ranging from 0.75% to 2.5% per annum. Subsequent to the year ended December 31, 2017, the Company, through a 50% owned entity, issued other limited recourse debt for $86 million ($43 million Methanex share) bearing an interest rate of 5.35% due September 2033. The debt will be used to acquire two ocean going vessels.

For the year ended December 31, 2017, non-cash accretion, on an effective interest basis, of deferred financing costs included in finance costs was $3.1 million (2016 - $3.0 million).

The minimum principal payments for long-term debt in aggregate and for each of the five succeeding years are as follows:

	Limited recourse debt facilities		Unsecured notes		Total
2018	$	57,072	$	—	$	57,072
2019	60,100		350,000		410,100
2020	62,115		—		62,115
2021	109,462		—		109,462
2022	31,279		250,000		281,279
Thereafter	—		600,000		600,000
	$	320,028	$	1,200,000	$	1,520,028

The covenants governing the Company’s unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding entities which we control but do not fully own, and include restrictions on liens, sale and lease-back transactions, a merger or consolidation with another corporation or sale of all or substantially all of the Company’s assets. The indenture also contains customary default provisions.

The Company maintains a $300 million committed revolving credit facility with a syndicate of highly rated financial institutions that expires in December 2022. Significant covenants and default provisions under this facility include:

i) the obligation to maintain an EBITDA to interest coverage ratio of greater than 2:1 calculated on a four-quarter trailing basis and a debt to capitalization ratio of less than or equal to 55%, both ratios calculated in accordance with definitions in the credit agreement that include adjustments related to the limited recourse subsidiaries,

ii) a default if payment is accelerated by a creditor on any indebtedness of $50 million or more of the Company and its subsidiaries, except for the limited recourse subsidiaries, and  

iii) a default if a default occurs that permits a creditor to demand repayment on any other indebtedness of $50 million or more of the Company and its subsidiaries, except for the limited recourse subsidiaries.

The limited recourse debt facilities are described as limited recourse as they are secured only by the assets of the entity that carries the debt. Accordingly, the lenders to the limited recourse debt facilities have no recourse to the Company or its other subsidiaries.

The Egypt limited recourse debt facilities have covenants and default provisions that apply only to the Egypt entity, including restrictions on the incurrence of additional indebtedness and a requirement to fulfill certain conditions before the payment of cash or other shareholder distributions. Certain conditions had not been met, resulting in a restriction on shareholder distributions from the Egypt entity to December 31, 2017. Under amended terms reached in 2017, shareholder distributions are permitted starting in 2018 if the average gas deliveries over the prior 12 months are greater than 70% of gas requirements. The first $100 million of shareholder distributions must be matched with $100 million of principal repayments on the Egypt limited recourse debt facilities. As of December 31, 2017, the Egypt cash balance on a 100% ownership basis was $131 million.

Failure to comply with any of the covenants or default provisions of the long-term debt facilities described above could result in a default under the applicable credit agreement that would allow the lenders to not fund future loan requests, accelerate the due date of the principal and accrued interest on any outstanding loans or restrict the payment of cash or other distributions.

As at December 31, 2017, management believes the Company was in compliance with all significant terms and default provisions related to long-term debt obligations.

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Other long-term liabilities

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

Other long-term liabilities

Other long-term liabilities:

As at	Dec 31 2017			Dec 31 2016
Site restoration costs(a)	$	33,975		$	30,512
Finance lease obligations(b)	204,242			201,268
Share-based compensation liability (note 13)	111,405			53,725
Cash flow hedges (note 18)	90,199			68,664
Defined benefit pension plans (note 20)	25,076			22,403
Other	5,214			4,339
	470,111			380,911
Less current maturities	(65,226		)	(29,720		)
	$	404,885		$	351,191

a) Site restoration costs:

The Company has accrued liabilities related to the decommissioning and reclamation of its methanol production sites and oil and gas properties. Because of uncertainties in estimating the amount and timing of the expenditures related to the sites, actual results could differ from the amounts estimated. As at December 31, 2017, the total undiscounted amount of estimated cash flows required to settle the liabilities was $44.9 million (2016 - $41.1 million). The movement in the provision during the year is explained as follows:

	2017		2016
Balance at January 1	$	30,512	$	29,892
New or revised provisions	2,823		51
Accretion expense	640		569
Balance at December 31	$	33,975	$	30,512

b) Finance lease obligations:

As at December 31, 2017, the Company has finance lease obligations related to a methanol terminal and storage tanks in Geismar, Louisiana, an oxygen production facility in Trinidad, and two ocean-going vessels. Total finance lease payments for 2017 of $30.6 million include an interest component of $23.7 million.

Finance lease obligations are payable as follows:

	Lease payments		Interest component		Finance lease obligations
2018	$	31,447	$	23,549	$	7,898
2019	31,826		22,727		9,099
2020	32,213		21,756		10,457
2021	32,608		20,612		11,996
2022	33,010		19,271		13,739
Thereafter	236,772		85,719		151,053
	$	397,876	$	193,634	$	204,242

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Expenses

12 Months Ended

Dec. 31, 2017

Analysis of income and expense [abstract]

Expenses

Expenses:

For the years ended December 31	2017		2016
Cost of sales	$	2,035,545	$	1,533,915
Selling and distribution	449,593		408,893
Administrative expenses	99,036		59,675
Total expenses by function	$	2,584,174	$	2,002,483
Cost of raw materials and purchased methanol	$	1,637,085	$	1,140,551
Ocean freight and other logistics	374,717		351,609
Employee expenses, including share-based compensation	243,707		204,762
Other expenses	96,440		77,507
Cost of sales and operating expenses	2,351,949		1,774,429
Depreciation and amortization	232,225		228,054
Total expenses by nature	$	2,584,174	$	2,002,483

For the year ended December 31, 2017 we recorded a share-based compensation expense of $78.8 million (2016 - $33.5 million), the majority of which is included in administrative expenses for the total expenses by function presentation above.

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Finance Costs

12 Months Ended

Dec. 31, 2017

Borrowing costs [abstract]

Finance cost

Finance costs:

Finance costs are primarily comprised of interest on borrowings and finance lease obligations, amortization of deferred financing fees and accretion expense associated with site restoration costs. Finance costs were $95.0 million for the year ended December 31, 2017 (2016 - $90.1 million).

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Net income (loss) per common share

12 Months Ended

Dec. 31, 2017

Earnings per share [abstract]

Net income (loss) per common share

Net income (loss) per common share:

Diluted net income (loss) per common share is calculated by considering the potential dilution that would occur if outstanding stock options and, under certain circumstances, TSARs were exercised or converted to common shares.

Outstanding TSARs may be settled in cash or common shares at the holder’s option and for purposes of calculating diluted net income (loss) per common share, the more dilutive of the cash-settled and equity-settled method is used, regardless of how the plan is accounted for. Accordingly, TSARs that are accounted for using the cash-settled method will require adjustments to the numerator and denominator if the equity-settled method is determined to have a dilutive effect on diluted net income (loss) per common share as compared to the cash-settled method. The cash-settled method was more dilutive for the years ended December 31, 2017 and 2016, and no adjustment was required for the numerator or the denominator for TSARs.

Stock options and, if calculated using the equity-settled method, TSARs are considered dilutive when the average market price of the Company’s common shares during the period disclosed exceeds the exercise price of the stock option or TSAR. For the year ended December 31, 2017, stock options were considered dilutive resulting in an adjustment to the denominator. For the year ended December 31, 2016, the Company incurred a net loss attributable to Methanex shareholders and therefore exclusion of the stock options was more dilutive.

Basic and diluted net income (loss) per common share for the year ended December 31, 2017 was calculated using basic and diluted net income of $316.1 million (2016 - basic and diluted net loss of $12.5 million). A reconciliation of the denominator used for the purposes of calculating basic and diluted net income (loss) per common share is as follows:

For the years ended December 31	2017	2016
Denominator for basic net income (loss) per common share	86,768,589	89,783,883
Effect of dilutive stock options	56,359	—
Denominator for diluted net income (loss) per common share	86,824,948	89,783,883

For the years ended December 31, 2017 and 2016, basic and diluted net income (loss) per common share attributable to Methanex shareholders were as follows:

For the years ended December 31	2017		2016
Basic net income (loss) per common share	$	3.64	$	(0.14	)
Diluted net income (loss) per common share	$	3.64	$	(0.14	)

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Share-based compensation

12 Months Ended

Dec. 31, 2017

Share-Based Payment Arrangements [Abstract]

Share-based compensation

Share-based compensation:

The Company provides share-based compensation to its directors and certain employees through grants of stock options, TSARs, SARs and deferred, restricted or performance share units.

As at December 31, 2017, the Company had 3,953,471 common shares reserved for future grants of stock options and tandem share appreciation rights under the Company’s stock option plan.

a) Share appreciation rights and tandem share appreciation rights:

All SARs and TSARs granted have a maximum term of seven years with one-third vesting each year after the date of grant. SARs and TSARs units outstanding at December 31, 2017 are as follows:

	SARs				TSARs
	Number of units		Exercise price USD		Number of units		Exercise price USD
Outstanding at December 31, 2015	1,259,208		$	44.48	2,108,965		$	42.73
Granted	375,500		34.59		574,600		34.59
Exercised	(73,291	)	27.43		(212,505	)	25.38
Cancelled	(49,932	)	49.77		(54,949	)	52.55
Outstanding at December 31, 2016	1,511,485		$	42.68	2,416,111		$	42.10
Granted	167,600		50.15		340,200		50.17
Exercised	(213,207	)	32.03		(710,616	)	32.98
Cancelled	(10,801	)	50.18		(2,200	)	34.59
Expired	(5,000	)	25.22		—		—
Outstanding at December 31, 2017	1,450,077		$	45.11	2,043,495		$	46.62

Information regarding the SARs and TSARs outstanding as at December 31, 2017 is as follows:

	Units outstanding at December 31, 2017				Units exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)	Number of units outstanding	Weighted average exercise price		Number of units exercisable	Weighted average exercise price
SARs
$25.97 to $35.51	3.36	585,317	$	32.94	345,629	$	31.79
$38.24 to $73.13	3.77	864,760	53.35		609,687	53.94
	3.61	1,450,077	$	45.11	955,316	$	45.93
TSARs
$25.97 to $35.51	3.94	779,194	$	33.67	401,049	$	32.80
$38.24 to $73.13	4.09	1,264,301	54.60		794,658	56.33
	4.03	2,043,495	$	46.62	1,195,707	$	48.44

The fair value of each outstanding SARs and TSARs grant was estimated on December 31, 2017 using the Black-Scholes option pricing model with the following weighted average assumptions:

	2017			2016
Risk-free interest rate	1.8		%	1.0		%
Expected dividend yield	2.0		%	2.5		%
Expected life of SARs and TSARs (years)	1.2			1.4
Expected volatility	31		%	41		%
Expected forfeitures	0.2		%	0.2		%
Weighted average fair value (USD per share)	$	19.02		$	10.19

Compensation expense for SARs and TSARs is measured based on their fair value and is recognized over the vesting period. Changes in fair value in each period are recognized in net income (loss) for the proportion of the service that has been rendered at each reporting date. The fair value as at December 31, 2017 was $69.8 million compared with the recorded liability of $65.2 million. The difference between the fair value and the recorded liability of $4.6 million will be recognized over the weighted average remaining vesting period of approximately 1.5 years.

For the year ended December 31, 2017, compensation expense related to SARs and TSARs included an expense in cost of sales and operating expenses of $45.1 million (2016 - $26.9 million). This included an expense of $37.8 million (2016 - $20.0 million) related to the effect of the change in the Company’s share price.

b) Deferred, restricted and performance share units:

Deferred, restricted and performance share units outstanding as at December 31, 2017 are as follows:

	Number of deferred share units		Number of restricted share units		Number of performance share units
Outstanding at December 31, 2015	285,816		13,864		610,578
Granted	8,269		11,500		261,760
Granted performance factor1	—		—		55,592
Granted in lieu of dividends	8,430		773		18,082
Redeemed	(51,498	)	(7,488	)	(355,415	)
Cancelled	—		—		(18,325	)
Outstanding at December 31, 2016	251,017		18,649		572,272
Granted	10,452		8,100		163,500
Performance factor impact on redemption1	—		—		(102,557	)
Granted in lieu of dividends	5,669		613		14,383
Redeemed	(42,292	)	(6,907	)	(34,186	)
Cancelled	—		—		(8,517	)
Outstanding at December 31, 2017	224,846		20,455		604,895

¹ Performance share units have a feature where the ultimate number of units that vest are adjusted by a performance factor of the original grant as determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The performance factor is measured based on the weighted-average closing share price for the 90 calendar days on the NASDAQ Global Select Market immediately preceding the year end date that the performance share units vest.

Compensation expense for deferred, restricted and performance share units is measured at fair value based on the market value of the Company’s common shares and is recognized over the vesting period. Changes in fair value are recognized in net income (loss) for the proportion of the service that has been rendered at each reporting date. The fair value of deferred, restricted and performance share units as at December 31, 2017 was $55.9 million compared with the recorded liability of $46.1 million. The difference between the fair value and the recorded liability of $9.8 million will be recognized over the weighted average remaining vesting period of approximately1.5 years.

For the year ended December 31, 2017, compensation expense related to deferred, restricted and performance share units included in cost of sales and operating expenses was an expense of $33.0 million (2016 - $6.0 million). This included an expense of $29.9 million (2016 - $2.8 million) related to the effect of the change in the Company’s share price.

c) Stock options:

The exercise price of each stock option is equal to the quoted market price of the Company’s common shares at the date of the grant. Options granted have a maximum term of seven years with one-third of the options vesting each year after the date of grant.

Common shares reserved for outstanding incentive stock options as at December 31, 2017 and 2016 are as follows:

	Number of stock options		Weighted average exercise price
Outstanding at December 31, 2015	448,507		$30.52
Granted	75,500		34.59
Exercised	(153,140	)	9.80
Cancelled	(14,100	)	44.04
Expired	(12,000	)	6.33
Outstanding at December 31, 2016	344,767		$40.91
Granted	31,400		50.17
Exercised	(98,274	)	30.90
Cancelled	(15,358	)	52.43
Outstanding at December 31, 2017	262,535		$45.09

Information regarding the stock options outstanding as at December 31, 2017 is as follows:  

	Options outstanding at December 31, 2017			Options exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)	Number of stock options outstanding	Weighted average exercise price	Number of stock options exercisable	Weighted average exercise price
Options
$25.97 to $35.51	3.40	103,850	$33.08	60,980	$32.02
$38.24 to $73.13	3.69	158,685	52.95	114,380	53.28
	3.58	262,535	$45.09	175,360	$45.88

For the year ended December 31, 2017, compensation expense related to stock options was $0.5 million (2016 - $0.6 million).

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Segmented information

12 Months Ended

Dec. 31, 2017

Operating Segments [Abstract]

Segmented information

Segmented information:

The Company’s operations consist of the production and sale of methanol, which constitutes a single operating segment.

During the years ended December 31, 2017 and 2016, revenues attributed to geographic regions, based on the location of customers, were as follows:

Revenue	China		Europe		United States		South Korea		South America		Canada		Other Asia		TOTAL
2017	$	801,838	$	608,668	$	570,482	$	347,896	$	279,270	$	167,436	$	285,052	$	3,060,642
2016	$	518,499	$	403,879	$	359,476	$	257,658	$	179,287	$	109,706	$	169,924	$	1,998,429

As at December 31, 2017 and 2016, the net book value of property, plant and equipment by country was as follows:

Property, plant and equipment	United States		Egypt		New Zealand		Trinidad		Canada		Chile		Other		TOTAL
2017	$	1,412,394	$	720,397	$	265,153	$	155,525	$	148,420	$	107,495	$	188,942	$	2,998,326
2016	$	1,468,283	$	742,446	$	261,482	$	176,256	$	154,982	$	108,065	$	205,955	$	3,117,469

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Income and other taxes

12 Months Ended

Dec. 31, 2017

Income Taxes [Abstract]

Income and other taxes

Income and other taxes:

a) Income tax expense:

For the years ended December 31	2017			2016
Current tax recovery (expense):
Current period before undernoted items	$	(85,287	)	$	(44,743	)
Impact of Argentina gas settlement	—			(7,800		)
Adjustments to prior years	(217		)	(2,134		)
	(85,504		)	(54,677		)
Deferred tax recovery (expense):
Origination and reversal of temporary differences	23,310			82,838
Impact of Argentina gas settlement	—			(3,575		)
Derecognition of non-capital loss carryforwards	—			(17,861		)
Adjustments to prior years	200			1,667
Change in U.S. tax rate	(36,567		)	—
Change in other jurisdictions tax rates	734			—
Other	2,039			887
	(10,284		)	63,956
Total income tax recovery (expense)	$	(95,788	)	$	9,279

b) Reconciliation of the effective tax rate:

The Company operates in several tax jurisdictions and therefore its income is subject to various rates of taxation. Income tax expense differs from the amounts that would be obtained by applying the Canadian statutory income tax rate to net income (loss) before income taxes as follows:

For the years ended December 31	2017			2016
Income (loss) before income taxes	$	470,885		$	(37,504	)
Deduct earnings of associate	(75,995		)	(19,930		)
	394,890			(57,434		)
Canadian statutory tax rate	26.5		%	26.5		%
Income tax recovery (expense) calculated at Canadian statutory tax rate	(104,646		)	15,220
Increase (decrease) in income tax recovery resulting from:
Impact of income and losses taxed in foreign jurisdictions	30,223			34,857
Derecognition of non-capital loss carryforwards	—			(17,861		)
Unrecognised loss carryforwards and temporary differences	20,468			(6,468		)
Impact of tax rate changes in the U.S.	(36,567		)	—
Impact of tax rate changes in other jurisdictions	734			—
Impact of foreign exchange	3,104			(4,332		)
Other business taxes	(4,105		)	(5,404		)
Adjustments to prior years	(17		)	(467		)
Other	(4,982		)	(6,266		)
Total income tax recovery (expense)	$	(95,788	)	$	9,279

c) Net deferred income tax liabilities:

(i) The tax effect of temporary differences that give rise to deferred income tax liabilities and deferred income tax assets are as follows:

As at				Dec 31 2017									Dec 31 2016
	Net			Deferred tax assets			Deferred tax liabilities			Net			Deferred tax assets			Deferred tax liabilities
Property, plant and equipment	$	(403,705	)	$	(189,368	)	$	(214,337	)	$	(419,982	)	$	(197,931	)	$	(222,051	)
Repatriation taxes	(87,239		)	—			(87,239		)	(85,364		)	—			(85,364		)
Other	(11,670		)	(3,740		)	(7,930		)	(19,956		)	(4,981		)	(14,975		)
	(502,614		)	(193,108		)	(309,506		)	(525,302		)	(202,912		)	(322,390		)
Non-capital loss carryforwards	244,576			244,576			—			280,931			280,931			—
Share-based compensation	19,920			2,946			16,974			8,590			935			7,655
Other	74,027			47,927			26,100			82,142			58,387			23,755
	338,523			295,449			43,074			371,663			340,253			31,410
Net deferred income tax assets (liabilities)	$	(164,091	)	$	102,341		$	(266,432	)	$	(153,639	)	$	137,341		$	(290,980	)

The Company recognizes deferred income tax assets to the extent that it is probable that the benefit of these assets will be realized. As at December 31, 2017, the Company had $110 million (2016 - $153 million) of unrecognized non-capital loss carryforwards in Egypt that expire in 2020 and 2021 and $384 million (2016 - $ 415 million) of deductible temporary differences in the United States that have not been recognized.

(ii) Analysis of the change in deferred income tax assets and liabilities:

							2017									2016
	Net			Deferred tax assets			Deferred tax liabilities			Net			Deferred tax assets			Deferred tax liabilities
Balance, January 1	$	(153,639	)	$	137,341		$	(290,980	)	$	(223,757	)	$	61,881		$	(285,638	)
Deferred income tax recovery (expense) included in net income (loss)	(10,284		)	(34,517		)	24,233			63,956			69,110			(5,154		)
Impact of U.S. tax rate change in other comprehensive income	(8,621		)	(8,621		)	—			—			—			—
Deferred income tax recovery (expense) included in other comprehensive income (loss)	9,295			8,398			897			6,597			6,364			233
Other	(842		)	(260		)	(582		)	(435		)	(14		)	(421		)
Balance, December 31	$	(164,091	)	$	102,341		$	(266,432	)	$	(153,639	)	$	137,341		$	(290,980	)

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Supplemental cash flow information

12 Months Ended

Dec. 31, 2017

Cash Flow Statement [Abstract]

Supplemental cash flow information

Supplemental cash flow information:

a) Changes in non-cash working capital:

Changes in non-cash working capital for the years ended December 31, 2017 and 2016 are as follows:

For the years ended December 31	2017			2016
Changes in non-cash working capital:
Trade and other receivables	$	(37,033	)	$	4,747
Inventories	(23,136		)	(28,094		)
Prepaid expenses	(5,702		)	(1,286		)
Trade, other payables and accrued liabilities, including long-term payables included in other long-term liabilities	103,601			14,577
	37,730			(10,056		)
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid	(89,445		)	(65,850		)
Changes in non-cash working capital	$	(51,715	)	$	(75,906	)
These changes relate to the following activities:
Operating	$	(49,368	)	$	(87,644	)
Financing	—			—
Investing	(2,347		)	11,738
Changes in non-cash working capital	$	(51,715	)	$	(75,906	)

The Company has reclassified the presentation of amounts relating to accrued distributions to non-controlling interests in Changes in non-cash working capital from Operating activities to Financing activities. The reclassification has been reflected in the comparative figures.

b) Reconciliation of movements in liabilities to cash flows arising from financing activities:

	Long term debt (note 8)			Finance lease obligations (note 9)
Balance at December 31, 2016	$	1,556,206		$	201,268
Changes from financing cash flows
Repayment of long-term debt and financing fees	(56,997		)	—
Payment of finance lease liabilities	—			(6,880		)
Total changes from financing cash flows	$	(56,997	)	$	(6,880	)
Liability-related other changes
Finance costs	$	3,062		$	—
New finance leases	—			9,512
Other	—			342
Total liability-related other changes	$	3,062		$	9,854
Balance at December 31, 2017	$	1,502,271		$	204,242

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Capital disclosures

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

Capital disclosures

Capital disclosures:

The Company’s objectives in managing its liquidity and capital are to safeguard the Company’s ability to continue as a going concern, to provide financial capacity and flexibility to meet its strategic objectives, to provide an adequate return to shareholders commensurate with the level of risk and to return excess cash through a combination of dividends and share repurchases.

As at	Dec 31 2017			Dec 31 2016
Liquidity:
Cash and cash equivalents	$	375,479		$	223,890
Undrawn credit facilities	300,000			300,000
Total liquidity	$	675,479		$	523,890
Capitalization:
Unsecured notes	$	1,188,163		$	1,186,424
Limited recourse debt facilities, including current portion	314,108			369,782
Total debt	1,502,271			1,556,206
Non-controlling interests	244,347			208,515
Shareholders’ equity	1,500,764			1,596,835
Total capitalization	$	3,247,382		$	3,361,556
Total debt to capitalization1	46		%	46		%
Net debt to capitalization2	39		%	42		%

¹ Total debt (including 100% of Egypt limited recourse debt facilities) divided by total capitalization.

² Total debt (including 100% of Egypt limited recourse debt facilities) less cash and cash equivalents divided by total capitalization less cash and cash equivalents.

The Company manages its liquidity and capital structure and makes adjustments to it in light of changes to economic conditions, the underlying risks inherent in its operations and capital requirements to maintain and grow its operations. The strategies employed by the Company may include the issue or repayment of general corporate debt, the issue of project debt, the issue of equity, the payment of dividends and the repurchase of shares.

The Company is not subject to any statutory capital requirements and has no commitments to sell or otherwise issue common shares except pursuant to outstanding employee stock options.

During the year, the Company renewed and extended a $300 million revolving credit facility for a five year term to December 2022. The undrawn credit facility is provided by highly rated financial institutions and is subject to certain financial covenants (note 8).

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Financial instruments

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Financial instruments

Financial instruments:

Financial instruments are either measured at amortized cost or fair value.

In the normal course of business, the Company's assets, liabilities and forecasted transactions, as reported in U.S. dollars, are impacted by various market risks including, but not limited to, natural gas prices and currency exchange rates. The time frame and manner in which the Company manages those risks varies for each item based on the Company's assessment of the risk and the available alternatives for mitigating risks.

The Company uses derivatives as part of its risk management program to mitigate variability associated with changing market values. Changes in fair value of derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges, in which case the changes in fair value are recorded in other comprehensive income and are reclassified to profit or loss when the underlying hedged transaction is recognized in earnings. The Company designates as cash flow hedges certain derivative financial instruments to hedge its risk exposure to fluctuations in natural gas prices and to hedge its risk exposure to fluctuations on certain foreign currency denominated transactions.

The following table provides the carrying value of each category of financial assets and liabilities and the related balance sheet item:

As at	Dec 31 2017		Dec 31 2016
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges1	$	—	$	7,024
Financial assets not measured at fair value:
Cash and cash equivalents	375,479		223,890
Trade and other receivables, excluding tax receivable	527,084		479,272
Project financing reserve accounts included in other assets	27,863		35,386
Total financial assets2	$	930,426	$	745,572
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges1	$	91,014	$	68,664
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	528,182		449,213
Long-term debt, including current portion	1,502,271		1,556,206
Total financial liabilities	$	2,121,467	$	2,074,083

¹ The Geismar 2 and Medicine Hat natural gas hedges and euro foreign currency hedges designated as cash flow hedges are measured at fair value based on industry accepted valuation models and inputs obtained from active markets.

² The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods.

As at December 31, 2017, all of the financial instruments were recorded on the consolidated statements of financial position at amortized cost with the exception of derivative financial instruments, which are recorded at fair value unless exempted.

The fair value of derivative instruments is determined based on industry-accepted valuation models using market observable inputs and are classified within Level 2 of the fair value hierarchy. The fair value of all the Company's derivative contracts includes an adjustment for credit risk. The effective portion of the changes in fair value of derivative financial instruments designated as cash flow hedges is recorded in other comprehensive income. The spot element of forward contracts in the hedging relationships is recorded in other comprehensive income as the change in fair value of cash flow hedges. The change in the fair value of the forward element of forward contracts is recorded separately in other comprehensive income as the forward element excluded from hedging relationships.

Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in commodity prices or foreign currency exchange rates.

Natural gas forward contracts

The Company has elected to manage its exposure to changes in natural gas prices for a portion of its North American natural gas requirements by executing a number of fixed price forward contracts. The Company has entered into forward contracts to manage its exposure to changes in natural gas prices for the Geismar 2 facility for 40% of its gas requirements to 2025, which it has designated as cash flow hedges. The Company has also entered into physical forward contracts to manage its exposure to changes in natural gas prices for the Medicine Hat facility over the period 2017 to 2022. The Company has designated contracts for the 2021 and 2022 periods as cash flow hedges for its highly probable forecast natural gas purchases in Medicine Hat. Other costs incurred to transport natural gas from the contracted delivery point, either Henry Hub or AECO, to the relevant production facility represent an insignificant portion of the overall underlying risk and are recognized as incurred outside of the hedging relationship. The Company has elected to designate the spot element of the forward contracts as cash flow hedges. The forward element of the forward contracts are excluded from the designation and only the spot element is considered for the purpose of assessing effectiveness and measuring ineffectiveness. The excluded forward element of the swap contracts will be accounted for as a cost of hedging (transaction cost) to be recognized in profit or loss over the term of the hedging relationships. Ineffectiveness may arise in the hedging relationship due to changes in the timing of the anticipated transactions and/or due to changes in credit risk of the hedging instrument not replicated in the hedged item. No hedge ineffectiveness has been recognized in 2017.

As at December 31, 2017, the Company had outstanding forward contracts designated as cash flow hedges with a notional amount of $473 million (2016 - $484 million) and a net negative fair value of $90.2 million (2016 - $ 61.9 million) included in other long-term liabilities. As at December 31, 2017, the forward contracts for the Geismar 2 facility had an average contract price of $3.74 per mmbtu (2016 - $3.68 per mmbtu) over the remaining eight year term, and for the forward contracts for the Medicine Hat facility has an average contract price of $1.96 per mmbtu.

Forward exchange contracts

The Company also designates as cash flow hedges forward exchange contracts to sell certain foreign currencies at a fixed U.S. dollar exchange rate to hedge its exposure to exchange rate fluctuations on certain foreign currency denominated transactions. The Company has elected to designate the spot element of the forward contracts as cash flow hedges. The forward element of the forward contracts are excluded from the designation and only the spot element is considered for the purpose of assessing effectiveness and measuring ineffectiveness. The excluded forward element of the swap contracts will be accounted for as a cost of hedging (transaction cost) to be recognized in profit or loss over the term of the hedging relationships. Ineffectiveness may arise in the hedging relationship due to changes in the timing of the anticipated transactions and/or due to changes in credit risk of the hedging instrument not replicated in the hedged item. No hedge ineffectiveness has been recognized in 2017.

As at December 31, 2017, the Company had outstanding forward exchange contracts designated as cash flow hedges to sell euros at a fixed U.S. dollar exchange rate with a notional amount of 109 million euros (2016 - 92 million euros) and a negative fair value of $0.8 million included in current liabilities (2016 - positive fair value of $0.3 million included in current assets) .

Fair value liabilities

The table below shows net cash outflows for derivative hedging instruments including natural gas forward contracts and forward exchange contracts, excluding credit risk adjustments, based upon contracted payment dates. The amounts reflect the maturity profile of the fair value liabilities and are subject to change based on the prevailing market rate at each of the future settlement dates. Financial asset derivative positions, if any, are held with investment-grade counterparties and therefore the settlement day risk exposure is considered to be negligible.

As at	Dec 31 2017		Dec 31 2016
Within one year	$	7,114	$	—
1-3 years	17,057		8,481
3-5 years	28,864		18,962
More than 5 years	52,085		56,029
	$	105,120	$	83,472

The fair value of the Company’s derivative financial instruments as disclosed above are determined based on Bloomberg quoted market prices and confirmations received from counterparties, which are adjusted for credit risk.

The Company is exposed to credit-related losses in the event of non-performance by counterparties to derivative financial instruments but does not expect any counterparties to fail to meet their obligations. The Company deals with only highly rated counterparties, normally major financial institutions. The Company is exposed to credit risk when there is a positive fair value of derivative financial instruments at a reporting date. The maximum amount that would be at risk if the counterparties to derivative financial instruments with positive fair values failed completely to perform under the contracts was nil as at December 31, 2017 (2016 - $7.0 million).

The carrying values of the Company’s financial instruments approximate their fair values, except as follows:  

As at	December 31, 2017				December 31, 2016
	Carrying value		Fair value		Carrying value		Fair value
Long-term debt excluding deferred financing fees	$	1,515,544	$	1,561,392	$	1,568,822	$	1,538,543

Long-term debt consists of limited recourse debt facilities and unsecured notes. There is no publicly traded market for the limited recourse debt facilities. The fair value of the limited recourse debt facilities as disclosed on a recurring basis and categorized as Level 2 within the fair value hierarchy is estimated by reference to current market rates as at the reporting date. The fair value of the unsecured notes disclosed on a recurring basis and also categorized as Level 2 within the fair value hierarchy is estimated using quoted prices and yields as at the reporting date. The fair value of the Company’s long term debt will fluctuate until maturity.

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Financial risk management

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Financial risk management

Financial risk management:

a) Market risks:

The Company’s operations consist of the production and sale of methanol. Market fluctuations may result in significant cash flow and profit volatility risk for the Company. Its worldwide operating business as well as its investment and financing activities are affected by changes in methanol and natural gas prices and interest and foreign exchange rates. The Company seeks to manage and control these risks primarily through its regular operating and financing activities and uses derivative instruments to hedge these risks when deemed appropriate. This is not an exhaustive list of all risks, nor will the risk management strategies eliminate these risks.

Methanol price risk

The methanol industry is a highly competitive commodity industry and methanol prices fluctuate based on supply and demand fundamentals and other factors. The profitability of the Company is directly related to the market price of methanol. A decline in the market price of methanol could negatively impact the Company's future operations. The Company does not hedge its methanol sales through derivative contracts. The Company manages its methanol price risk, to a certain degree, through natural gas supply contracts that include a variable price component related to methanol prices, as described below.

Natural gas price risk

Natural gas is the primary feedstock for the production of methanol. The Company has entered into multi-year natural gas supply contracts for its production facilities in New Zealand, Trinidad, Egypt and certain contracts in Chile that include base and variable price components to reduce the commodity price risk exposure. The variable price component is adjusted by formulas related to methanol prices above a certain level. The Company also has multi-year fixed price natural gas contracts to supply its production facilities in Geismar, Medicine Hat and Chile and natural gas hedges in Geismar and Medicine Hat to manage its exposure to natural gas price risk.

Interest rate risk

Interest rate risk is the risk that the Company suffers financial loss due to changes in the value of an asset or liability or in the value of future cash flows due to movements in interest rates.

The Company’s interest rate risk exposure is mainly related to long-term debt obligations.

As at	Dec 31 2017		Dec 31 2016
Fixed interest rate debt:
Unsecured notes	$	1,188,163	$	1,186,424
	$	1,188,163	$	1,186,424
Variable interest rate debt:
Egypt limited recourse debt facilities	$	241,190	$	288,515
Other limited recourse debt facilities	72,918		81,267
	$	314,108	$	369,782

For fixed interest rate debt, a 1% change in interest rates would result in a change in the fair value of the debt (disclosed in note 18) of approximately $84.0 million as of December 31, 2017 (2016 - $80.2 million).

The fair value of variable interest rate debt fluctuates primarily with changes in credit spreads.

For the variable interest rate debt, a 1% change in LIBOR would result in a change in annual interest payments of $3.2 million as of December 31, 2017 (2016 - $3.7 million).

Foreign currency risk

The Company’s international operations expose the Company to foreign currency exchange risks in the ordinary course of business. Accordingly, the Company has established a policy that provides a framework for foreign currency management and hedging strategies and defines the approved hedging instruments. The Company reviews all significant exposures to foreign currencies arising from operating and investing activities and hedges exposures if deemed appropriate.

The dominant currency in which the Company conducts business is the United States dollar, which is also the reporting currency.

Methanol is a global commodity chemical that is priced in United States dollars. In certain jurisdictions, however, the transaction price is set either quarterly or monthly in the local currency. Accordingly, a portion of the Company’s revenue is transacted in Canadian dollars, euros, Chinese yuan and, to a lesser extent, other currencies. For the period from when the price is set in local currency to when the amount due is collected, the Company is exposed to declines in the value of these currencies compared to the United States dollar. The Company also purchases varying quantities of methanol for which the transaction currency is the euro, Chinese yuan and, to a lesser extent, other currencies. In addition, some of the Company’s underlying operating costs and capital expenditures are incurred in other currencies. The Company is exposed to increases in the value of these currencies that could have the effect of increasing the United States dollar equivalent of cost of sales and operating expenses and capital expenditures. The Company has elected not to actively manage these exposures at this time except for a portion of the net exposure to euro revenues, which is hedged through forward exchange contracts each quarter when the euro price for methanol is established.

As at December 31, 2017, the Company had a net working capital asset of $85.3 million in non U.S. dollar currencies (2016 - $75.3 million). Each 10% strengthening (weakening) of the U.S. dollar against these currencies would decrease (increase) the value of net working capital and pre-tax cash flows and earnings by approximately $8.5 million (2016 - $7.5 million).

b) Liquidity risks:

Liquidity risk is the risk that the Company will not have sufficient funds to meet its liabilities, such as the settlement of financial debt and lease obligations and payment to its suppliers. The Company maintains liquidity and makes adjustments to it in light of changes to economic conditions, underlying risks inherent in its operations and capital requirements to maintain and grow its operations. As at December 31, 2017, the Company had $375 million of cash and cash equivalents. In addition, the Company has an undrawn credit facility of $300 million provided by highly rated financial institutions that expires in December 2022.

In addition to the above-mentioned sources of liquidity, the Company monitors funding options available in the capital markets, as well as trends in the availability and costs of such funding, with a view to maintaining financial flexibility and limiting refinancing risks.

The expected cash flows of financial liabilities from the date of the balance sheet to the contractual maturity date are as follows:

As at December 31, 2017	Carrying amount		Contractual cash flows		1 year or less		1-3 years		3-5 years		More than 5 years
Trade and other payables1	$	519,352	$	519,352	$	519,352	$	—	$	—	$	—
Finance lease obligations	204,242		397,876		31,447		64,039		65,618		236,772
Long-term debt2	1,502,271		2,178,011		121,689		586,091		471,831		998,400
Cash flow hedges	91,014		105,120		7,114		17,057		28,864		52,085
	$	2,316,879	$	3,200,359	$	679,602	$	667,187	$	566,313	$	1,287,257

¹ Excludes tax and accrued interest.

² Contractual cash flows include contractual interest payments related to debt obligations. Interest rates on variable rate debt are based on prevailing rates as at December 31, 2017.

c) Credit risks:

Counterparty credit risk is the risk that the financial benefits of contracts with a specific counterparty will be lost if a counterparty defaults on its obligations under the contract. This includes any cash amounts owed to the Company by those counterparties, less any amounts owed to the counterparty by the Company where a legal right of offset exists and also includes the fair values of contracts with individual counterparties that are recorded in the financial statements.

Trade credit risk

Trade credit risk is defined as an unexpected loss in cash and earnings if the customer is unable to pay its obligations in due time or if the value of the security provided declines. The Company has implemented a credit policy that includes approvals for new customers, annual credit evaluations of all customers and specific approval for any exposures beyond approved limits. The Company employs a variety of risk-mitigation alternatives, including credit insurance, certain contractual rights in the event of deterioration in customer credit quality and various forms of bank and parent company guarantees and letters of credit to upgrade the credit risk to a credit rating equivalent or better than the stand-alone rating of the counterparty. Trade credit losses have historically been minimal and as at December 31, 2017 substantially all of the trade receivables were classified as current.

Cash and cash equivalents

To manage credit and liquidity risk, the Company’s investment policy specifies eligible types of investments, maximum counterparty exposure and minimum credit ratings. Therefore, the Company invests only in highly rated investment-grade instruments that have maturities of three months or less.

Derivative financial instruments

The Company’s hedging policies specify risk management objectives and strategies for undertaking hedge transactions. The policies also include eligible types of derivatives and required transaction approvals, as well as maximum counterparty exposures and minimum credit ratings. The Company does not use derivative financial instruments for trading or speculative purposes.

To manage credit risk, the Company only enters into derivative financial instruments with highly rated investment-grade counterparties. Hedge transactions are reviewed, approved and appropriately documented in accordance with Company policies.

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Retirement plans

12 Months Ended

Dec. 31, 2017

Employee Benefits [Abstract]

Retirement plans

Retirement plans:

a) Defined benefit pension plans:

The Company has non-contributory defined benefit pension plans covering certain employees. The Company does not provide any significant post-retirement benefits other than pension plan benefits. Information concerning the Company’s defined benefit pension plans, in aggregate, is as follows:

As at	Dec 31 2017			Dec 31 2016
Accrued benefit obligations:
Balance, beginning of year	$	60,771		$	55,966
Current service cost	1,879			1,677
Past service cost	812			—
Interest cost on accrued benefit obligations	2,242			2,269
Benefit payments	(5,280		)	(2,570		)
Settlements	—			—
Actuarial loss	166			2,393
Foreign exchange loss	4,803			1,036
Balance, end of year	65,393			60,771
Fair values of plan assets:
Balance, beginning of year	44,230			40,286
Interest income on assets	1,522			1,553
Contributions	1,970			2,722
Benefit payments	(5,280		)	(2,570		)
Settlements	—			—
Return on plan assets	1,330			2,345
Foreign exchange gain (loss)	3,219			(106		)
Balance, end of year	46,991			44,230
Unfunded status	18,402			16,541
Minimum funding requirement	—			—
Defined benefit obligation, net	$	18,402		$	16,541

The Company has an unfunded retirement obligation of $25.1 million as at December 31, 2017 (2016 - $22.4 million) for its employees in Chile that will be funded at retirement in accordance with Chilean law. The accrued benefit for the unfunded retirement arrangement in Chile is paid when an employee leaves the Company in accordance with plan terms and Chilean regulations. The Company estimates that it may make benefit payments based on actuarial assumptions related to the unfunded retirement obligation in Chile of $5.1 million in 2018. Actual benefit payments in future periods will fluctuate based on employee retirements.

The Company has a net funded retirement asset of $6.6 million as at December 31, 2017 (2016 - $5.7 million) for certain employees and retirees in Canada and a net funded retirement asset of $0.1 million as at December 31, 2017 (2016 - $0.2 million) in Europe. The Company estimates that it will make additional contributions relating to its defined benefit pension plan in Canada of $0.6 million in 2018.

These defined benefit plans expose the Company to actuarial risks, such as longevity risk, currency risk, interest rate risk and market risk on the funded plans. Additionally, as the plans provide benefits to plan members predominantly in Canada and Chile, the plans expose the Company to foreign currency risk for funding requirements. The primary long-term risk is that the Company will not have sufficient plan assets and liquidity to meet obligations when they fall due. The weighted average duration of the net defined benefit obligation is 10 years.

The Company’s net defined benefit pension plan expense charged to the consolidated statements of income for the years ended December 31, 2017 and 2016 is as follows:

For the years ended December 31	2017		2016
Net defined benefit pension plan expense:
Current service cost	$	1,879	$	1,677
Past service cost	812		—
Net interest cost	720		715
Cost of settlement	—		—
	$	3,411	$	2,392

The Company’s current year actuarial gains (losses), recognized in the consolidated statements of comprehensive income (loss) for the years ended December 31, 2017 and 2016, are as follows:

For the years ended December 31	2017		2016
Actuarial gain (loss)	$	564	$	(77	)
Minimum funding requirement	—		—
Actuarial gain (loss), net	$	564	$	(77	)

The Company uses a December 31 measurement date for its defined benefit pension plans. Actuarial reports for the Company’s defined benefit pension plans were prepared by independent actuaries for funding purposes as of December 31, 2016 in Canada. The next actuarial reports for funding purposes for the Company’s Canadian defined benefit pension plans are scheduled to be completed as of December 31, 2019.

The discount rate is the most significant actuarial assumption used in accounting for the defined benefit pension plans. As at December 31, 2017, the weighted average discount rate for the defined benefit obligation was 3.7% (2016 - 3.7%). A decrease of 1% in the weighted average discount rate at the end of the reporting period, while holding all other assumptions constant, would result in an increase to the defined benefit obligation of approximately $6.3 million.

The asset allocation for the defined benefit pension plan assets as at December 31, 2017 and 2016 is as follows:

As at	Dec 31 2017		Dec 31 2016
Equity securities	46	%	49	%
Debt securities	29	%	27	%
Cash and other short-term securities	25	%	24	%
Total	100	%	100	%

The fair values of the above equity and debt instruments are determined based on quoted market prices in active markets whereas the fair values of cash and other short-term securities are not based on quoted market prices in active markets. The plan assets are held separately from those of the Company in funds under the control of trustees.

b) Defined contribution pension plans:

The Company has defined contribution pension plans. The Company’s funding obligations under the defined contribution pension plans are limited to making regular payments to the plans, based on a percentage of employee earnings. Total net pension expense for the defined contribution pension plans charged to operations during the year ended December 31, 2017 was $8.1 million (2016 - $7.6 million).

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Commitments and contingencies

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies [Abstract]

Commitments and contingencies

Commitments and contingencies:

a) Take-or-pay purchase contracts and related commitments:

The Company has commitments under take-or-pay contracts to purchase natural gas, to pay for transportation capacity related to the delivery of natural gas and to purchase oxygen and other feedstock requirements up to 2035. The minimum estimated commitment under these contracts, except as noted below, is as follows:

As at December 31, 2017

2018		2019		2020		2021		2022		Thereafter
$	473,927	$	371,167	$	306,400	$	308,338	$	245,989	$	1,300,609

In the above table, the Company has included natural gas commitments at the contractual volume and prices.

b) Argentina natural gas supply contracts:

Since June 2007, the Company’s natural gas suppliers from Argentina have curtailed all gas supply to the Company’s plants in Chile pursuant to long-term gas supply agreements. The Company has not received natural gas under these long-term agreements since 2007 and therefore potential future purchase obligations have been excluded from the table above.

c) Operating lease commitments:

The Company has future minimum lease payments under operating leases relating primarily to vessel charter, terminal facilities, office space, equipment and other operating lease commitments as follows:

As at December 31, 2017

2018		2019		2020		2021		2022		Thereafter
$	90,820	$	90,035	$	56,973	$	38,982	$	37,858	$	163,822

The minimum lease payments relate to the right of use of the leased asset and exclude non-lease elements such as the reimbursement of operating costs.

For the year ended December 31, 2017, the Company recognized as an expense $181.4 million (2016 - expense of $165.1 million) relating to operating lease payments. The expense recognized includes amounts related to leased assets and the reimbursement of operating costs for time charter vessels.

d) Leased assets not yet in service:

The Company has future minimum lease payments under operating leases related to two time charter agreements for vessels which are currently under construction and expected to be delivered in 2019. The minimum lease payments under these leases have been excluded from the operating lease commitments table above as the contracts contain certain cancellation features which are dependent on the delivery of the vessels. Once delivered, these vessels will have a total minimum commitment of approximately $80 million per vessel over a 15 year life.

e) Purchased methanol:

The Company has marketing rights for 100% of the production from its jointly owned plants (the Atlas plant in Trinidad in which it has a 63.1% interest and the plant in Egypt in which it has a 50% interest), which results in purchase commitments of an additional 1.3 million tonnes per year of methanol offtake supply when these plants operate at capacity. As at December 31, 2017, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2018 and 1.5 million tonnes in aggregate thereafter. The pricing under these purchase commitments is referenced to pricing at the time of purchase or sale, and accordingly, no amounts have been included in the table above.

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Related parties

12 Months Ended

Dec. 31, 2017

Related Party [Abstract]

Related parties

Related parties:

The Company has interests in significant subsidiaries and joint ventures as follows:

Name	Country of incorporation	Principal activities	Interest %
			Dec 31 2017		Dec 31 2016
Significant subsidiaries:
Methanex Asia Pacific Limited	Hong Kong	Marketing & distribution	100	%	100	%
Methanex Europe NV	Belgium	Marketing & distribution	100	%	100	%
Methanex Methanol Company, LLC	United States	Marketing & distribution	100	%	100	%
Egyptian Methanex Methanol Company S.A.E. ("Methanex Egypt")	Egypt	Production	50	%	50	%
Methanex Chile S.A.	Chile	Production	100	%	100	%
Methanex New Zealand Limited	New Zealand	Production	100	%	100	%
Methanex Trinidad (Titan) Unlimited	Trinidad	Production	100	%	100	%
Methanex U.S.A. LLC	United States	Production	100	%	100	%
Methanex Louisiana LLC	United States	Production	100	%	100	%
Waterfront Shipping Company Limited2	Cayman Islands	Shipping	100	%	100	%
Significant joint ventures:
Atlas Methanol Company Unlimited1	Trinidad	Production	63.1	%	63.1	%

¹ Summarized financial information for the group’s investment in Atlas is disclosed in note 6.

² Waterfront Shipping Company Limited has a controlling interest in multiple ocean going vessels owned through less than wholly-owned entities as disclosed in note 23.

Transactions between the Company and Atlas are considered related party transactions and are included within the summarized financial information in note 6. Atlas revenue for the year ended December 31, 2017 of $459 million (2016 - $214 million) is a related party transaction as the Company has marketing rights for 100% of the methanol produced by Atlas. Balances outstanding with Atlas as at December 31, 2017 and provided in the summarized financial information in note 6 include receivables owing from Atlas to the Company of $13 million (2016 - $7 million), and payables to Atlas of $98 million (2016 - $55 million). The Company has total loans outstanding to Atlas as at December 31, 2017 of $76 million (2016 - $76 million) which are unsecured and due at maturity.

Remuneration of non-management directors and senior management, which includes the members of the executive leadership team, is as follows:

For the years ended December 31	2017		2016
Short-term employee benefits	$	5,214	$	5,315
Post-employment benefits	583		650
Other long-term employee benefits	43		47
Share-based compensation expense1	40,668		16,172
Total	$	46,508	$	22,184

¹  Balance includes realized and unrealized gains (losses) from share-based compensation awards granted.

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Non-controlling interests

12 Months Ended

Dec. 31, 2017

Interest In Other Entities [Abstract]

Non-controlling interests

Non-controlling interests:

Set out below is summarized financial information for each of our subsidiaries that have non-controlling interests. The amounts disclosed are before inter-company eliminations.

As at							Dec 31 2017									Dec 31 2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Current assets	$	248,032		$	27,240		$	275,272		$	155,422		$	12,123		$	167,545
Non-current assets	720,356			105,375			825,731			746,202			116,314			862,516
Current liabilities	(231,259		)	(12,489		)	(243,748		)	(177,088		)	(14,622		)	(191,710		)
Non-current liabilities	(293,184		)	(76,090		)	(369,274		)	(339,369		)	(84,540		)	(423,909		)
Net assets	443,945			44,036			487,981			385,167			29,275			414,442
Carrying amount of Methanex non-controlling interests	$	216,599		$	27,748		$	244,347		$	188,099		$	20,416		$	208,515

For the years ended December 31							2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Revenue	$	285,017		$	32,094		$	317,111		$	111,728		$	26,148		$	137,876
Net and total comprehensive income (loss)	65,241			6,981			72,222			(79,963		)	4,781			(75,182		)
Net and total comprehensive income (loss) allocated to Methanex non-controlling interests	55,470			3,492			58,962			(18,069		)	2,389			(15,680		)
Equity contributions by non-controlling interests	$	—		$	8,170		$	8,170		$	—		$	25		$	25
Distributions paid and accrued to non-controlling interests	$	(26,970	)	$	(4,330	)	$	(31,300	)	$	(23,264	)	$	(1,410	)	$	(24,674	)

For the years ended December 31							2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Cash flows from (used in) operating activities	$	131,175		$	19,538		$	150,713		$	(23,992	)	$	17,718		$	(6,274	)
Cash flows from (used in) financing activities	(27,365		)	(3,250		)	(30,615		)	(24,929		)	55,891			30,962
Cash flows from (used in) investing activities	$	(18,839	)	$	(605	)	$	(19,444	)	$	(4,637	)	$	(70,516	)	$	(75,153	)

¹ Other is comprised of multiple ocean going vessels controlled by Waterfront Shipping Company Limited through less than wholly-owned entities.

The Company has reclassified the presentation of amounts relating to accrued distributions to Methanex Egypt in Changes in non-cash working capital from Operating activities to Financing activities. The reclassification has been reflected in the comparative figures.

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Significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

Basis of presentation and consolidation

Basis of presentation and consolidation:

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, less than wholly-owned entities for which it has a controlling interest and its equity-accounted joint venture. Wholly-owned subsidiaries are entities in which the Company has control, directly or indirectly, where control is defined as the power to govern the financial and operating policies of an enterprise so as to obtain benefits from its activities. For less than wholly-owned entities for which the Company has a controlling interest, a non-controlling interest is included in the Company’s consolidated financial statements and represents the non-controlling shareholders’ interest in the net assets of the entity. The Company also consolidates any special purpose entity where the substance of the relationship indicates the Company has control. All significant intercompany transactions and balances have been eliminated.

Use of estimates

Preparation of these consolidated financial statements requires estimates, judgments and assumptions that affect the amounts reported and disclosed in the financial statements and related notes. The areas of estimation and judgment that management considers most significant are property, plant and equipment (note 2(g)), financial instruments (note 2(o)), fair value measurements (note 2(p)) and income taxes (note 2(q)). Actual results could differ from those estimates.

Reporting currency

Reporting currency and foreign currency translation:

Functional currency is the currency of the primary economic environment in which an entity operates. The majority of the Company’s business in all jurisdictions is transacted in United States dollars and, accordingly, these consolidated financial statements have been measured and expressed in that currency. The Company translates foreign currency denominated monetary items at the period-end exchange rates, foreign currency denominated non-monetary items at historic rates and revenues and expenditures at the exchange rates at the dates of the transactions. Foreign exchange gains and losses are included in earnings.

Foreign currency translation

Functional currency is the currency of the primary economic environment in which an entity operates. The majority of the Company’s business in all jurisdictions is transacted in United States dollars and, accordingly, these consolidated financial statements have been measured and expressed in that currency. The Company translates foreign currency denominated monetary items at the period-end exchange rates, foreign currency denominated non-monetary items at historic rates and revenues and expenditures at the exchange rates at the dates of the transactions. Foreign exchange gains and losses are included in earnings.

Cash and cash equivalents

Cash and cash equivalents:

Cash and cash equivalents include securities with maturities of three months or less when purchased.

Receivables

Receivables:

The Company provides credit to its customers in the normal course of business. The Company performs ongoing credit evaluations of its customers and maintains reserves for potential credit losses. The Company records an allowance for doubtful accounts or writes down the receivable to estimated net realizable value if not collectible in full. Credit losses have historically been within the range of management’s expectations.

Inventories

Inventories:

Inventories are valued at the lower of cost and estimated net realizable value. Cost is determined on a first-in, first-out basis and includes direct purchase costs, cost of production, allocation of production overhead and depreciation based on normal operating capacity and transportation.

Property, plant and equipment

Property, plant and equipment:

Initial recognition

Property, plant and equipment are initially recorded at cost. The cost of purchased equipment includes expenditures that are directly attributable to the purchase price, delivery and installation. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to the location and condition for their intended use, the costs of dismantling and removing the items and restoring the site on which they are located, and borrowing costs on self-constructed assets that meet certain criteria. Borrowing costs incurred during construction and commissioning are capitalized until the plant is operating in the manner intended by management.

Subsequent costs

Routine repairs and maintenance costs are expensed as incurred. At regular intervals, the Company conducts a planned shutdown and inspection (turnaround) at its plants to perform major maintenance and replacement of catalysts. Costs associated with these shutdowns are capitalized and amortized over the period until the next planned turnaround and the carrying amounts of replaced components are derecognized and included in earnings.

Depreciation

Depreciation and amortization is generally provided on a straight-line basis at rates calculated to amortize the cost of property, plant and equipment from the commencement of commercial operations over their estimated useful lives to estimated residual value.

The estimated useful lives of the Company’s buildings, plant installations and machinery, excluding costs related to turnarounds, ranges from 10 to 25 years depending on the specific asset component and the production facility to which it is related. The Company determines the estimated useful lives of individual asset components based on the shorter of its physical life or economic life. The physical life of these assets is generally longer than the economic life. The economic life is primarily determined by the nature of the natural gas feedstock available to the various production facilities. Factors that influence the nature of natural gas feedstock availability include the terms of individual natural gas supply contracts, access to natural gas supply through open markets, regional factors influencing the exploration and development of natural gas and the expected price of securing natural gas supply. The Company reviews the factors related to each production facility on an annual basis to determine if changes are required to the estimated useful lives.

Assets under finance lease are depreciated to their estimated residual value based on the shorter of their useful lives and the lease term.

Impairment

The Company reviews the carrying value of long-lived assets for impairment whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. Examples of such events or changes in circumstances include, but are not restricted to: a significant adverse change in the extent or manner in which the asset is being used or in its physical condition; a significant change in the long-term methanol price or in the price or availability of natural gas feedstock required to manufacture methanol; a significant adverse change in legal factors or in the business climate that could affect the asset’s value, including an adverse action or assessment by a foreign government that impacts the use of the asset; or a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the asset’s use.

Recoverability of long-lived assets is measured by comparing the carrying value of an asset or cash-generating unit to the estimated recoverable amount, which is the higher of its estimated fair value less cost to sell or its value in use. Value in use is determined by estimating the pre-tax cash flows expected to be generated from the asset or cash-generating unit over its estimated useful life discounted by a pre-tax discount rate. An impairment writedown is recorded for the difference that the carrying value exceeds the estimated recoverable amount. An impairment writedown recognized in prior periods for an asset or cash-generating unit is reversed if there has been a subsequent recovery in the value of the asset or cash-generating unit due to changes in events and circumstances. For purposes of recognition and measurement of an impairment writedown, the Company groups long-lived assets with other assets and liabilities to form a "cash-generating unit" at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. To the extent that methanol facilities in a particular location are interdependent as a result of common infrastructure and/or feedstock from sources that can be shared within a facility location, the Company groups assets based on site locations for the purpose of determining impairment.

Other assets

Other assets:

Intangible assets are capitalized to other assets and amortized to depreciation and amortization expense on an appropriate basis to charge the cost of the assets against earnings.

Finance costs

Financing fees related to undrawn credit facilities are capitalized to other assets and amortized to finance costs over the term of the credit facility.

Leases

Leases:

Leasing contracts are classified as either finance or operating leases based on the substance of the contractual arrangement at inception date. A lease is classified as a finance lease if it transfers substantially all of the risks and rewards of ownership of the leased asset. Where the contracts are classified as finance leases, upon initial recognition, the asset and liability are recorded at the lower of fair value and the present value of the minimum lease payments, net of executory costs. Finance lease payments are apportioned between interest expense and repayments of the liability. Where the contracts are classified as operating leases, they are not recognized in the Company's consolidated statements of financial position and lease payments are charged to income as they are incurred on a straight line basis over the lease term.

Site restoration costs

Site restoration costs:

The Company recognizes a liability to dismantle and remove assets or to restore a site upon which the assets are located. The Company estimates the present value of the expenditures required to settle the liability by determining the current market cost required to settle the site restoration costs, adjusts for inflation through to the expected date of the expenditures and then discounts this amount back to the date when the obligation was originally incurred. As the liability is initially recorded on a discounted basis, it is increased each period until the estimated date of settlement. The resulting expense is referred to as accretion expense and is included in finance costs. The Company reviews asset retirement obligations and adjusts the liability and corresponding asset as necessary to reflect changes in the estimated future cash flows, timing, inflation and discount rates underlying the measurement of the obligation.

Employee future benefits

Employee future benefits:

The Company has non-contributory defined benefit pension plans covering certain employees and defined contribution pension plans. The Company does not provide any significant post-retirement benefits other than pension plan benefits. For defined benefit pension plans, the net of the present value of the defined benefit obligation and the fair value of plan assets is recorded to the consolidated statements of financial position. The determination of the defined benefit obligation and associated pension cost is based on certain actuarial assumptions including inflation rates, mortality, plan expenses, salary growth and discount rates. The present value of the net defined benefit obligation (asset) is determined by discounting the net estimated future cash flows using current market bond yields that have terms to maturity approximating the terms of the net obligation. Actuarial gains and losses arising from differences between these assumptions and actual results are recognized in other comprehensive income and recorded in retained earnings. The Company recognizes gains and losses on the settlement of a defined benefit plan in income when the settlement occurs. The cost for defined contribution benefit plans is recognized in net income (loss) as earned by the employees.

Share-based compensation

Share-based compensation:

The Company grants share-based awards as an element of compensation. Share-based awards granted by the Company can include stock options, tandem share appreciation rights, share appreciation rights, deferred share units, restricted share units or performance share units.

For stock options granted by the Company, the cost of the service received is measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus. On the exercise of stock options, consideration received, together with the compensation expense previously recorded to contributed surplus, is credited to share capital. The Company uses the Black-Scholes option pricing model to estimate the fair value of each stock option tranche at the date of grant.

Share appreciation rights ("SARs") are units that grant the holder the right to receive a cash payment upon exercise for the difference between the market price of the Company’s common shares and the exercise price that is determined at the date of grant. Tandem share appreciation rights ("TSARs") give the holder the choice between exercising a regular stock option or a SAR. For SARs and TSARs, the cost of the service received is initially measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in liabilities. For SARs and TSARs, the liability is re-measured at each reporting date based on an estimate of the fair value with changes in fair value recognized as compensation expense for the proportion of the service that has been rendered at that date. The Company uses the Black-Scholes option pricing model to estimate the fair value for SARs and TSARs.

Deferred, restricted and performance share units are grants of notional common shares that are redeemable for cash based on the market value of the Company’s common shares and are non-dilutive to shareholders. Performance share units have an additional feature where the ultimate number of units that vest will be determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The number of units that will ultimately vest will be in the range of 50% to 120% of the original grant for grants prior to 2014 and in the range of 25% to 150% for subsequent grants based on the weighted-average closing share price for the 90 calendar days on the NASDAQ Global Select Market immediately preceding the year end date that the performance share units vest. For deferred, restricted and performance share units, the cost of the service received as consideration is initially measured based on the market value of the Company’s common shares at the date of grant. The grant-date fair value is recognized as compensation expense over the vesting period with a corresponding increase in liabilities. Deferred, restricted and performance share units are re-measured at each reporting date based on the market value of the Company’s common shares with changes in fair value recognized as compensation expense for the proportion of the service that has been rendered at that date.

Additional information related to the stock option plan, TSARs, SARs and the deferred, restricted and performance share units is described in note 13.

Net income (loss) per common per share

Net income (loss) per common share:

The Company calculates basic net income (loss) per common share by dividing net income (loss) attributable to Methanex shareholders by the weighted average number of common shares outstanding and calculates diluted net income (loss) per common share under the treasury stock method. Under the treasury stock method, diluted net income (loss) per common share is calculated by considering the potential dilution that would occur if outstanding stock options and, under certain circumstances, TSARs were exercised or converted to common shares. Stock options and TSARs are considered dilutive when the average market price of the Company’s common shares during the period disclosed exceeds the exercise price of the stock option or TSAR.

Outstanding TSARs may be settled in cash or common shares at the holder’s option. For the purposes of calculating diluted net income (loss) per common share, the more dilutive of the cash-settled or equity-settled method is used, regardless of how the plan is accounted for. Accordingly, TSARs that are accounted for using the cash-settled method will require adjustments to the numerator and denominator if the equity-settled method is determined to have a dilutive effect on diluted net income (loss) per common share.

The calculation of basic net income (loss) per common share and a reconciliation to diluted net income (loss) per common share is presented in note 12.

Revenue recognition

Revenue recognition:

Revenue is recognized based on individual contract terms when the risk of loss to the product transfers to the customer, which usually occurs at the time shipment is made. Revenue is recognized at the time of delivery to the customer’s location if the Company retains risk of loss during shipment. For methanol sold on a consignment basis, revenue is recognized when the customer consumes the methanol. For methanol sold on a commission basis, the commission income is included in revenue when earned.

Financial instruments

Financial instruments:

All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Financial instruments are classified into one of three categories and, depending on the category, will either be measured at amortized cost or fair value with fair value changes either recorded through profit or loss or other comprehensive income. All non-derivative financial instruments held by the Company are classified and measured at amortized cost.

The Company enters into derivative financial instruments to manage certain exposures to commodity price and foreign exchange volatility. Under these standards, derivative financial instruments, including embedded derivatives, are classified as fair value through profit or loss and are recorded in the consolidated statements of financial position at fair value unless they are in accordance with the Company’s normal purchase, sale or usage requirements. The valuation of derivative financial instruments is a critical accounting estimate due to the complex nature of these instruments, the degree of judgment required to appropriately value these instruments and the potential impact of such valuation on the Company’s financial statements. The Company records all changes in fair value of derivative financial instruments in profit or loss unless the instruments are designated as cash flow hedges. The Company enters into and designates as cash flow hedges certain forward contracts to hedge its highly probable forecast natural gas purchases and certain forward exchange purchase and sales contracts to hedge foreign exchange exposure on anticipated purchases or sales. The Company assesses at inception and on an ongoing basis whether the hedges are and continue to be effective in offsetting changes in the cash flows of the hedged transactions. The effective portion of changes in the fair value of these hedging instruments is recognized in other comprehensive income. Any gain or loss in fair value relating to the ineffective portion is recognized immediately in profit or loss. Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in commodity prices, foreign currency exchange rates or variable interest rates.

Fair value measurements

Fair value measurements:

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements within the scope of IFRS 13 are categorized into Level 1, 2 or 3 based on the degree to which the inputs are observable and the significance of the inputs to the fair value measurement in its entirety. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can access at the measurement date. Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Financial instruments measured at fair value and categorized within the fair value hierarchy are disclosed in note 18.

Income taxes

Income taxes:

Income tax expense represents current tax and deferred tax. The Company records current tax based on the taxable profits for the period calculated using tax rates that have been enacted or substantively enacted by the reporting date. Income taxes relating to uncertain tax positions are provided for based on the Company’s best estimate. Deferred income taxes are accounted for using the liability method. The liability method requires that income taxes reflect the expected future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their tax bases. Deferred income tax assets and liabilities are determined for each temporary difference based on currently enacted or substantially enacted tax rates that are expected to be in effect when the underlying items are expected to be realized. The effect of a change in tax rates or tax legislation is recognized in the period of substantive enactment. Deferred tax assets, such as non-capital loss carryforwards, are recognized to the extent it is probable that taxable profit will be available against which the asset can be utilized.

The Company accrues for taxes that will be incurred upon distributions from its subsidiaries when it is probable that the earnings will be repatriated.

Provisions

Provisions:

Provisions are recognized where a legal or constructive obligation has been incurred as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation.

Segmented information

Segmented information:

The Company’s operations consist of the production and sale of methanol, which constitutes a single operating segment.

Application of new and revised accounting standards and Anticipated changes to International Financial Reporting Standards

Anticipated changes to International Financial Reporting Standards:

In May 2014, the IASB issued IFRS 15, Revenue from Contracts with Customers ("IFRS 15") establishing a comprehensive framework for revenue recognition. The standard replaces IAS 18, Revenue and IAS 11, Construction Contracts and related interpretations and is effective for annual periods beginning on or after January 1, 2018, with early adoption permitted. The Company has performed its assessment of the impact of the new standard and anticipates no impact on its consolidated financial statements.

In January 2016, the IASB issued IFRS 16, Leases ("IFRS 16"), which eliminates the current operating/finance lease dual accounting model for lessees and replaces it with a single, on-balance sheet accounting model, similar to the current finance lease accounting. The standard replaces IAS 17, Leases ("IAS 17") and related interpretations and is effective for annual periods beginning on or after January 1, 2019, with early application permitted. The Company plans to apply this standard at the date it becomes effective.

The Company is currently assessing the impact of the new standard including the optional exemptions available. The recognition of all leases on balance sheet is expected to increase the assets and liabilities on the Consolidated Statement of Financial Position upon adoption. The increase primarily relates to ocean vessels, terminal facilities and other right of use assets currently accounted for as operating leases. In addition, the nature and timing of certain expenses related to leases previously classified as operating and presented in cost of sales and operating expenses will now change and be presented in depreciation and amortization and finance costs. As a result, the Company expects that adoption of IFRS 16 will significantly impact the consolidated financial statements. The Company has not yet decided whether it will use the optional exemptions available under the standard. Refer to note 21, commitments and contingencies, for operating lease commitments as at December 31, 2017 disclosed under IAS 17.

The Company does not expect that any other new or amended standards or interpretations that are effective as of January 1, 2018 will have a significant impact on the Company’s results of operations or financial position.

Application of new and revised accounting standards:

The Company has adopted the amendments to IAS 7, Statement of Cash Flows, which were effective for annual periods beginning on or after January 1, 2017. As a result of applying the amendment, the Company presented new disclosures relating to change in financial liabilities arising from financing activities (note16(b)).

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Trade and other receivables (Tables)

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

Schedule of trade and other receivables

As at	Dec 31 2017		Dec 31 2016
Trade	$	429,582	$	335,606
Value-added and other tax receivables	36,584		63,738
Egypt gas contract recoveries(a)	24,466		41,578
Other	46,004		58,681
	$	536,636	$	499,603

a) Egypt gas contract recoveries:

The natural gas supply agreement in Egypt has a mechanism whereby the Company is partially compensated when gas delivery shortfalls exceed a certain threshold. The receivable is secured by a combination of funds held in escrow and a bank guarantee.

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Property, plant and equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, plant and equipment [abstract]

Schedule of property, plant and equipment

	Buildings, plant installations and machinery			Finance leases		Other			TOTAL
Cost at January 1, 2017	$	4,549,816		$	206,260	$	272,878		$	5,028,954
Additions	98,780			7,667		5,001			111,448
Disposals and other	328			1,846		(2,386		)	(212		)
Cost at December 31, 2017	4,648,924			215,773		275,493			5,140,190
Accumulated depreciation at January 1, 2017	1,752,540			18,557		140,388			1,911,485
Disposals and other	(2,066		)	—		(673		)	(2,739		)
Depreciation	205,843			15,370		11,905			233,118
Accumulated depreciation at December 31, 2017	1,956,317			33,927		151,620			2,141,864
Net book value at December 31, 2017	$	2,692,607		$	181,846	$	123,873		$	2,998,326

	Buildings, plant installations and machinery			Finance leases			Other			TOTAL
Cost at January 1, 2016	$	4,521,835		$	121,849		$	204,483		$	4,848,167
Additions	35,644			87,800			74,303			197,747
Disposals and other	(7,663		)	(3,389		)	(5,908		)	(16,960		)
Cost at December 31, 2016	4,549,816			206,260			272,878			5,028,954
Accumulated depreciation at January 1, 2016	1,545,834			6,853			136,698			1,689,385
Disposals and other	(945		)	—			(5,908		)	(6,853		)
Depreciation	207,651			11,704			9,598			228,953
Accumulated depreciation at December 31, 2016	1,752,540			18,557			140,388			1,911,485
Net book value at December 31, 2016	$	2,797,276		$	187,703		$	132,490		$	3,117,469

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Investment in associate (Tables)

12 Months Ended

Dec. 31, 2017

Interests In Other Entities [Abstract]

Summarized financial information in associate

Summarized financial information of Atlas (100% basis) is as follows:

Consolidated statements of financial position as at	Dec 31 2017			Dec 31 2016
Cash and cash equivalents	$	8,361		$	15,530
Other current assets1	79,738			45,219
Non-current assets	289,671			324,297
Current liabilities1	(41,388		)	(24,783		)
Other long-term liabilities, including current maturities	(157,935		)	(168,253		)
Net assets at 100%	178,447			192,010
Net assets at 63.1%	112,600			121,158
Long-term receivable from Atlas1	76,322			76,244
Investment in associate	$	188,922		$	197,402

Consolidated statements of income for the years ended December 31	2017			2016
Revenue1	$	459,367		$	213,533
Cost of sales and depreciation and amortization	(261,121		)	(145,126		)
Operating income	198,246			68,407
Finance costs, finance income and other expenses	(11,170		)	(12,771		)
Income tax expense	(66,640		)	(24,052		)
Net earnings at 100%	120,436			31,584
Earnings of associate at 63.1%	75,995			19,930
Dividends received from associate	$	84,553		$	47,325

¹ Includes related party transactions between Atlas and the Company (see note 22).

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Other assets (Tables)

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

Schedule of other assets

As at	Dec 31 2017		Dec 31 2016
Restricted cash	$	27,863	$	35,386
Chile VAT receivable	25,456		23,406
Investment in Carbon Recycling International	4,502		4,502
Defined benefit pension plans (note 20)	6,650		5,862
Other	13,555		9,628
	$	78,026	$	78,784

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Long-term debt (Tables)

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Schedule of long-term debt

As at	Dec 31 2017			Dec 31 2016
Unsecured notes
(i) 3.25% due December 15, 2019	$	348,060		$	347,126
(ii) 5.25% due March 1, 2022	248,072			247,685
(iii) 4.25% due December 1, 2024	296,873			296,529
(iv) 5.65% due December 1, 2044	295,158			295,084
	1,188,163			1,186,424
Egypt limited recourse debt facilities	241,190			288,515
Other limited recourse debt facilities	72,918			81,267
Total long-term debt1	1,502,271			1,556,206
Less current maturities1	(55,905		)	(53,997		)
	$	1,446,366		$	1,502,209

¹ Long-term debt and current maturities are presented net of discounts and deferred financing fees of $17.8 million as at December 31, 2017 (2016 - $17.8 million).

Schedule of minimum principal payments for long-term debt

The minimum principal payments for long-term debt in aggregate and for each of the five succeeding years are as follows:

	Limited recourse debt facilities		Unsecured notes		Total
2018	$	57,072	$	—	$	57,072
2019	60,100		350,000		410,100
2020	62,115		—		62,115
2021	109,462		—		109,462
2022	31,279		250,000		281,279
Thereafter	—		600,000		600,000
	$	320,028	$	1,200,000	$	1,520,028

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Other long-term liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Subclassifications of assets, liabilities and equities [abstract]

Composition of other liabilities

As at	Dec 31 2017			Dec 31 2016
Site restoration costs(a)	$	33,975		$	30,512
Finance lease obligations(b)	204,242			201,268
Share-based compensation liability (note 13)	111,405			53,725
Cash flow hedges (note 18)	90,199			68,664
Defined benefit pension plans (note 20)	25,076			22,403
Other	5,214			4,339
	470,111			380,911
Less current maturities	(65,226		)	(29,720		)
	$	404,885		$	351,191

Provision for site restoration costs

The movement in the provision during the year is explained as follows:

	2017		2016
Balance at January 1	$	30,512	$	29,892
New or revised provisions	2,823		51
Accretion expense	640		569
Balance at December 31	$	33,975	$	30,512

Finance lease obligations payable

Finance lease obligations are payable as follows:

	Lease payments		Interest component		Finance lease obligations
2018	$	31,447	$	23,549	$	7,898
2019	31,826		22,727		9,099
2020	32,213		21,756		10,457
2021	32,608		20,612		11,996
2022	33,010		19,271		13,739
Thereafter	236,772		85,719		151,053
	$	397,876	$	193,634	$	204,242

The Company has future minimum lease payments under operating leases relating primarily to vessel charter, terminal facilities, office space, equipment and other operating lease commitments as follows:

As at December 31, 2017

2018		2019		2020		2021		2022		Thereafter
$	90,820	$	90,035	$	56,973	$	38,982	$	37,858	$	163,822

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Expenses (Tables)

12 Months Ended

Dec. 31, 2017

Analysis of income and expense [abstract]

Schedule of expenses

For the years ended December 31	2017		2016
Cost of sales	$	2,035,545	$	1,533,915
Selling and distribution	449,593		408,893
Administrative expenses	99,036		59,675
Total expenses by function	$	2,584,174	$	2,002,483
Cost of raw materials and purchased methanol	$	1,637,085	$	1,140,551
Ocean freight and other logistics	374,717		351,609
Employee expenses, including share-based compensation	243,707		204,762
Other expenses	96,440		77,507
Cost of sales and operating expenses	2,351,949		1,774,429
Depreciation and amortization	232,225		228,054
Total expenses by nature	$	2,584,174	$	2,002,483

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Net income (loss) per common share (Tables)

12 Months Ended

Dec. 31, 2017

Earnings per share [abstract]

Earnings per share reconciliation

A reconciliation of the denominator used for the purposes of calculating basic and diluted net income (loss) per common share is as follows:

For the years ended December 31	2017	2016
Denominator for basic net income (loss) per common share	86,768,589	89,783,883
Effect of dilutive stock options	56,359	—
Denominator for diluted net income (loss) per common share	86,824,948	89,783,883

For the years ended December 31, 2017 and 2016, basic and diluted net income (loss) per common share attributable to Methanex shareholders were as follows:

For the years ended December 31	2017		2016
Basic net income (loss) per common share	$	3.64	$	(0.14	)
Diluted net income (loss) per common share	$	3.64	$	(0.14	)

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Share-based compensation (Tables)

12 Months Ended

Dec. 31, 2017

Share-Based Payment Arrangements [Abstract]

Changes in number and exercise prices of other equity instruments

All SARs and TSARs granted have a maximum term of seven years with one-third vesting each year after the date of grant. SARs and TSARs units outstanding at December 31, 2017 are as follows:

	SARs				TSARs
	Number of units		Exercise price USD		Number of units		Exercise price USD
Outstanding at December 31, 2015	1,259,208		$	44.48	2,108,965		$	42.73
Granted	375,500		34.59		574,600		34.59
Exercised	(73,291	)	27.43		(212,505	)	25.38
Cancelled	(49,932	)	49.77		(54,949	)	52.55
Outstanding at December 31, 2016	1,511,485		$	42.68	2,416,111		$	42.10
Granted	167,600		50.15		340,200		50.17
Exercised	(213,207	)	32.03		(710,616	)	32.98
Cancelled	(10,801	)	50.18		(2,200	)	34.59
Expired	(5,000	)	25.22		—		—
Outstanding at December 31, 2017	1,450,077		$	45.11	2,043,495		$	46.62

Deferred, restricted and performance share units outstanding as at December 31, 2017 are as follows:

	Number of deferred share units		Number of restricted share units		Number of performance share units
Outstanding at December 31, 2015	285,816		13,864		610,578
Granted	8,269		11,500		261,760
Granted performance factor1	—		—		55,592
Granted in lieu of dividends	8,430		773		18,082
Redeemed	(51,498	)	(7,488	)	(355,415	)
Cancelled	—		—		(18,325	)
Outstanding at December 31, 2016	251,017		18,649		572,272
Granted	10,452		8,100		163,500
Performance factor impact on redemption1	—		—		(102,557	)
Granted in lieu of dividends	5,669		613		14,383
Redeemed	(42,292	)	(6,907	)	(34,186	)
Cancelled	—		—		(8,517	)
Outstanding at December 31, 2017	224,846		20,455		604,895

¹ Performance share units have a feature where the ultimate number of units that vest are adjusted by a performance factor of the original grant as determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The performance factor is measured based on the weighted-average closing share price for the 90 calendar days on the NASDAQ Global Select Market immediately preceding the year end date that the performance share units vest.

Number and weighted average remaining contractual life of SARs and TSARs outstanding and exercisable

Information regarding the SARs and TSARs outstanding as at December 31, 2017 is as follows:

	Units outstanding at December 31, 2017				Units exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)	Number of units outstanding	Weighted average exercise price		Number of units exercisable	Weighted average exercise price
SARs
$25.97 to $35.51	3.36	585,317	$	32.94	345,629	$	31.79
$38.24 to $73.13	3.77	864,760	53.35		609,687	53.94
	3.61	1,450,077	$	45.11	955,316	$	45.93
TSARs
$25.97 to $35.51	3.94	779,194	$	33.67	401,049	$	32.80
$38.24 to $73.13	4.09	1,264,301	54.60		794,658	56.33
	4.03	2,043,495	$	46.62	1,195,707	$	48.44

SARs and TSARs outstanding and exercisable by range of exercise prices

Information regarding the SARs and TSARs outstanding as at December 31, 2017 is as follows:

	Units outstanding at December 31, 2017				Units exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)	Number of units outstanding	Weighted average exercise price		Number of units exercisable	Weighted average exercise price
SARs
$25.97 to $35.51	3.36	585,317	$	32.94	345,629	$	31.79
$38.24 to $73.13	3.77	864,760	53.35		609,687	53.94
	3.61	1,450,077	$	45.11	955,316	$	45.93
TSARs
$25.97 to $35.51	3.94	779,194	$	33.67	401,049	$	32.80
$38.24 to $73.13	4.09	1,264,301	54.60		794,658	56.33
	4.03	2,043,495	$	46.62	1,195,707	$	48.44

Weighted average assumptions of outstanding SARs and TSARs

The fair value of each outstanding SARs and TSARs grant was estimated on December 31, 2017 using the Black-Scholes option pricing model with the following weighted average assumptions:

	2017			2016
Risk-free interest rate	1.8		%	1.0		%
Expected dividend yield	2.0		%	2.5		%
Expected life of SARs and TSARs (years)	1.2			1.4
Expected volatility	31		%	41		%
Expected forfeitures	0.2		%	0.2		%
Weighted average fair value (USD per share)	$	19.02		$	10.19

Changes in stock options issued

Common shares reserved for outstanding incentive stock options as at December 31, 2017 and 2016 are as follows:

	Number of stock options		Weighted average exercise price
Outstanding at December 31, 2015	448,507		$30.52
Granted	75,500		34.59
Exercised	(153,140	)	9.80
Cancelled	(14,100	)	44.04
Expired	(12,000	)	6.33
Outstanding at December 31, 2016	344,767		$40.91
Granted	31,400		50.17
Exercised	(98,274	)	30.90
Cancelled	(15,358	)	52.43
Outstanding at December 31, 2017	262,535		$45.09

Stock options outstanding and exercisable by range of exercise prices

Information regarding the stock options outstanding as at December 31, 2017 is as follows:  

	Options outstanding at December 31, 2017			Options exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)	Number of stock options outstanding	Weighted average exercise price	Number of stock options exercisable	Weighted average exercise price
Options
$25.97 to $35.51	3.40	103,850	$33.08	60,980	$32.02
$38.24 to $73.13	3.69	158,685	52.95	114,380	53.28
	3.58	262,535	$45.09	175,360	$45.88

Number and weighted average remaining contractual life of stock options outstanding and exercisable

Information regarding the stock options outstanding as at December 31, 2017 is as follows:  

	Options outstanding at December 31, 2017			Options exercisable at December 31, 2017
Range of exercise prices	Weighted average remaining contractual life (years)	Number of stock options outstanding	Weighted average exercise price	Number of stock options exercisable	Weighted average exercise price
Options
$25.97 to $35.51	3.40	103,850	$33.08	60,980	$32.02
$38.24 to $73.13	3.69	158,685	52.95	114,380	53.28
	3.58	262,535	$45.09	175,360	$45.88

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Segmented information (Tables)

12 Months Ended

Dec. 31, 2017

Operating Segments [Abstract]

Revenue attributed to geographic regions

During the years ended December 31, 2017 and 2016, revenues attributed to geographic regions, based on the location of customers, were as follows:

Revenue	China		Europe		United States		South Korea		South America		Canada		Other Asia		TOTAL
2017	$	801,838	$	608,668	$	570,482	$	347,896	$	279,270	$	167,436	$	285,052	$	3,060,642
2016	$	518,499	$	403,879	$	359,476	$	257,658	$	179,287	$	109,706	$	169,924	$	1,998,429

As at December 31, 2017 and 2016, the net book value of property, plant and equipment by country was as follows:

Property, plant and equipment	United States		Egypt		New Zealand		Trinidad		Canada		Chile		Other		TOTAL
2017	$	1,412,394	$	720,397	$	265,153	$	155,525	$	148,420	$	107,495	$	188,942	$	2,998,326
2016	$	1,468,283	$	742,446	$	261,482	$	176,256	$	154,982	$	108,065	$	205,955	$	3,117,469

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Income and other taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Taxes [Abstract]

Components of income tax expense

Income tax expense:

For the years ended December 31	2017			2016
Current tax recovery (expense):
Current period before undernoted items	$	(85,287	)	$	(44,743	)
Impact of Argentina gas settlement	—			(7,800		)
Adjustments to prior years	(217		)	(2,134		)
	(85,504		)	(54,677		)
Deferred tax recovery (expense):
Origination and reversal of temporary differences	23,310			82,838
Impact of Argentina gas settlement	—			(3,575		)
Derecognition of non-capital loss carryforwards	—			(17,861		)
Adjustments to prior years	200			1,667
Change in U.S. tax rate	(36,567		)	—
Change in other jurisdictions tax rates	734			—
Other	2,039			887
	(10,284		)	63,956
Total income tax recovery (expense)	$	(95,788	)	$	9,279

Reconciliation of accounting profit multiplied by applicable tax rates

Income tax expense differs from the amounts that would be obtained by applying the Canadian statutory income tax rate to net income (loss) before income taxes as follows:

For the years ended December 31	2017			2016
Income (loss) before income taxes	$	470,885		$	(37,504	)
Deduct earnings of associate	(75,995		)	(19,930		)
	394,890			(57,434		)
Canadian statutory tax rate	26.5		%	26.5		%
Income tax recovery (expense) calculated at Canadian statutory tax rate	(104,646		)	15,220
Increase (decrease) in income tax recovery resulting from:
Impact of income and losses taxed in foreign jurisdictions	30,223			34,857
Derecognition of non-capital loss carryforwards	—			(17,861		)
Unrecognised loss carryforwards and temporary differences	20,468			(6,468		)
Impact of tax rate changes in the U.S.	(36,567		)	—
Impact of tax rate changes in other jurisdictions	734			—
Impact of foreign exchange	3,104			(4,332		)
Other business taxes	(4,105		)	(5,404		)
Adjustments to prior years	(17		)	(467		)
Other	(4,982		)	(6,266		)
Total income tax recovery (expense)	$	(95,788	)	$	9,279

Effect of temporary difference, unused tax losses and unused tax credits and analysis of change in deferred income tax liabilities

The tax effect of temporary differences that give rise to deferred income tax liabilities and deferred income tax assets are as follows:

As at				Dec 31 2017									Dec 31 2016
	Net			Deferred tax assets			Deferred tax liabilities			Net			Deferred tax assets			Deferred tax liabilities
Property, plant and equipment	$	(403,705	)	$	(189,368	)	$	(214,337	)	$	(419,982	)	$	(197,931	)	$	(222,051	)
Repatriation taxes	(87,239		)	—			(87,239		)	(85,364		)	—			(85,364		)
Other	(11,670		)	(3,740		)	(7,930		)	(19,956		)	(4,981		)	(14,975		)
	(502,614		)	(193,108		)	(309,506		)	(525,302		)	(202,912		)	(322,390		)
Non-capital loss carryforwards	244,576			244,576			—			280,931			280,931			—
Share-based compensation	19,920			2,946			16,974			8,590			935			7,655
Other	74,027			47,927			26,100			82,142			58,387			23,755
	338,523			295,449			43,074			371,663			340,253			31,410
Net deferred income tax assets (liabilities)	$	(164,091	)	$	102,341		$	(266,432	)	$	(153,639	)	$	137,341		$	(290,980	)

Analysis of the change in deferred income tax assets and liabilities:

							2017									2016
	Net			Deferred tax assets			Deferred tax liabilities			Net			Deferred tax assets			Deferred tax liabilities
Balance, January 1	$	(153,639	)	$	137,341		$	(290,980	)	$	(223,757	)	$	61,881		$	(285,638	)
Deferred income tax recovery (expense) included in net income (loss)	(10,284		)	(34,517		)	24,233			63,956			69,110			(5,154		)
Impact of U.S. tax rate change in other comprehensive income	(8,621		)	(8,621		)	—			—			—			—
Deferred income tax recovery (expense) included in other comprehensive income (loss)	9,295			8,398			897			6,597			6,364			233
Other	(842		)	(260		)	(582		)	(435		)	(14		)	(421		)
Balance, December 31	$	(164,091	)	$	102,341		$	(266,432	)	$	(153,639	)	$	137,341		$	(290,980	)

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Supplemental cash flow information (Tables)

12 Months Ended

Dec. 31, 2017

Cash Flow Statement [Abstract]

Changes in non-cash working capital

Changes in non-cash working capital for the years ended December 31, 2017 and 2016 are as follows:

For the years ended December 31	2017			2016
Changes in non-cash working capital:
Trade and other receivables	$	(37,033	)	$	4,747
Inventories	(23,136		)	(28,094		)
Prepaid expenses	(5,702		)	(1,286		)
Trade, other payables and accrued liabilities, including long-term payables included in other long-term liabilities	103,601			14,577
	37,730			(10,056		)
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid	(89,445		)	(65,850		)
Changes in non-cash working capital	$	(51,715	)	$	(75,906	)
These changes relate to the following activities:
Operating	$	(49,368	)	$	(87,644	)
Financing	—			—
Investing	(2,347		)	11,738
Changes in non-cash working capital	$	(51,715	)	$	(75,906	)

Reconciliation of liabilities arising from financing activities

Reconciliation of movements in liabilities to cash flows arising from financing activities:

	Long term debt (note 8)			Finance lease obligations (note 9)
Balance at December 31, 2016	$	1,556,206		$	201,268
Changes from financing cash flows
Repayment of long-term debt and financing fees	(56,997		)	—
Payment of finance lease liabilities	—			(6,880		)
Total changes from financing cash flows	$	(56,997	)	$	(6,880	)
Liability-related other changes
Finance costs	$	3,062		$	—
New finance leases	—			9,512
Other	—			342
Total liability-related other changes	$	3,062		$	9,854
Balance at December 31, 2017	$	1,502,271		$	204,242

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Capital disclosures (Tables)

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement Of IFRS Compliance [Abstract]

Schedule of liquidity and capitalization

As at	Dec 31 2017			Dec 31 2016
Liquidity:
Cash and cash equivalents	$	375,479		$	223,890
Undrawn credit facilities	300,000			300,000
Total liquidity	$	675,479		$	523,890
Capitalization:
Unsecured notes	$	1,188,163		$	1,186,424
Limited recourse debt facilities, including current portion	314,108			369,782
Total debt	1,502,271			1,556,206
Non-controlling interests	244,347			208,515
Shareholders’ equity	1,500,764			1,596,835
Total capitalization	$	3,247,382		$	3,361,556
Total debt to capitalization1	46		%	46		%
Net debt to capitalization2	39		%	42		%

¹ Total debt (including 100% of Egypt limited recourse debt facilities) divided by total capitalization.

² Total debt (including 100% of Egypt limited recourse debt facilities) less cash and cash equivalents divided by total capitalization less cash and cash equivalents.

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Financial instruments (Tables)

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Fair value measurement of assets

The following table provides the carrying value of each category of financial assets and liabilities and the related balance sheet item:

As at	Dec 31 2017		Dec 31 2016
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges1	$	—	$	7,024
Financial assets not measured at fair value:
Cash and cash equivalents	375,479		223,890
Trade and other receivables, excluding tax receivable	527,084		479,272
Project financing reserve accounts included in other assets	27,863		35,386
Total financial assets2	$	930,426	$	745,572
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges1	$	91,014	$	68,664
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	528,182		449,213
Long-term debt, including current portion	1,502,271		1,556,206
Total financial liabilities	$	2,121,467	$	2,074,083

¹ The Geismar 2 and Medicine Hat natural gas hedges and euro foreign currency hedges designated as cash flow hedges are measured at fair value based on industry accepted valuation models and inputs obtained from active markets.

² The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods.

Fair value measurement of liabilities

The carrying values of the Company’s financial instruments approximate their fair values, except as follows:  

As at	December 31, 2017				December 31, 2016
	Carrying value		Fair value		Carrying value		Fair value
Long-term debt excluding deferred financing fees	$	1,515,544	$	1,561,392	$	1,568,822	$	1,538,543

The following table provides the carrying value of each category of financial assets and liabilities and the related balance sheet item:

As at	Dec 31 2017		Dec 31 2016
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges1	$	—	$	7,024
Financial assets not measured at fair value:
Cash and cash equivalents	375,479		223,890
Trade and other receivables, excluding tax receivable	527,084		479,272
Project financing reserve accounts included in other assets	27,863		35,386
Total financial assets2	$	930,426	$	745,572
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges1	$	91,014	$	68,664
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	528,182		449,213
Long-term debt, including current portion	1,502,271		1,556,206
Total financial liabilities	$	2,121,467	$	2,074,083

¹ The Geismar 2 and Medicine Hat natural gas hedges and euro foreign currency hedges designated as cash flow hedges are measured at fair value based on industry accepted valuation models and inputs obtained from active markets.

² The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods.

Maturity profile of fair value liabilities

The table below shows net cash outflows for derivative hedging instruments including natural gas forward contracts and forward exchange contracts, excluding credit risk adjustments, based upon contracted payment dates. The amounts reflect the maturity profile of the fair value liabilities and are subject to change based on the prevailing market rate at each of the future settlement dates. Financial asset derivative positions, if any, are held with investment-grade counterparties and therefore the settlement day risk exposure is considered to be negligible.

As at	Dec 31 2017		Dec 31 2016
Within one year	$	7,114	$	—
1-3 years	17,057		8,481
3-5 years	28,864		18,962
More than 5 years	52,085		56,029
	$	105,120	$	83,472

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Financial risk management (Tables)

12 Months Ended

Dec. 31, 2017

Financial Instruments [Abstract]

Schedule of interest rate risk exposure

The Company’s interest rate risk exposure is mainly related to long-term debt obligations.

As at	Dec 31 2017		Dec 31 2016
Fixed interest rate debt:
Unsecured notes	$	1,188,163	$	1,186,424
	$	1,188,163	$	1,186,424
Variable interest rate debt:
Egypt limited recourse debt facilities	$	241,190	$	288,515
Other limited recourse debt facilities	72,918		81,267
	$	314,108	$	369,782

Expected cash flows of financial liabilities by maturity date

The expected cash flows of financial liabilities from the date of the balance sheet to the contractual maturity date are as follows:

As at December 31, 2017	Carrying amount		Contractual cash flows		1 year or less		1-3 years		3-5 years		More than 5 years
Trade and other payables1	$	519,352	$	519,352	$	519,352	$	—	$	—	$	—
Finance lease obligations	204,242		397,876		31,447		64,039		65,618		236,772
Long-term debt2	1,502,271		2,178,011		121,689		586,091		471,831		998,400
Cash flow hedges	91,014		105,120		7,114		17,057		28,864		52,085
	$	2,316,879	$	3,200,359	$	679,602	$	667,187	$	566,313	$	1,287,257

¹ Excludes tax and accrued interest.

² Contractual cash flows include contractual interest payments related to debt obligations. Interest rates on variable rate debt are based on prevailing rates as at December 31, 2017.

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Retirement plans (Tables)

12 Months Ended

Dec. 31, 2017

Employee Benefits [Abstract]

Disclosure of net defined benefit liability (asset)

Information concerning the Company’s defined benefit pension plans, in aggregate, is as follows:

As at	Dec 31 2017			Dec 31 2016
Accrued benefit obligations:
Balance, beginning of year	$	60,771		$	55,966
Current service cost	1,879			1,677
Past service cost	812			—
Interest cost on accrued benefit obligations	2,242			2,269
Benefit payments	(5,280		)	(2,570		)
Settlements	—			—
Actuarial loss	166			2,393
Foreign exchange loss	4,803			1,036
Balance, end of year	65,393			60,771
Fair values of plan assets:
Balance, beginning of year	44,230			40,286
Interest income on assets	1,522			1,553
Contributions	1,970			2,722
Benefit payments	(5,280		)	(2,570		)
Settlements	—			—
Return on plan assets	1,330			2,345
Foreign exchange gain (loss)	3,219			(106		)
Balance, end of year	46,991			44,230
Unfunded status	18,402			16,541
Minimum funding requirement	—			—
Defined benefit obligation, net	$	18,402		$	16,541

Expense recognized in the income statement

The Company’s net defined benefit pension plan expense charged to the consolidated statements of income for the years ended December 31, 2017 and 2016 is as follows:

For the years ended December 31	2017		2016
Net defined benefit pension plan expense:
Current service cost	$	1,879	$	1,677
Past service cost	812		—
Net interest cost	720		715
Cost of settlement	—		—
	$	3,411	$	2,392

Expense recognized in other comprehensive income

The Company’s current year actuarial gains (losses), recognized in the consolidated statements of comprehensive income (loss) for the years ended December 31, 2017 and 2016, are as follows:

For the years ended December 31	2017		2016
Actuarial gain (loss)	$	564	$	(77	)
Minimum funding requirement	—		—
Actuarial gain (loss), net	$	564	$	(77	)

Disclosure of fair value of plan assets

The asset allocation for the defined benefit pension plan assets as at December 31, 2017 and 2016 is as follows:

As at	Dec 31 2017		Dec 31 2016
Equity securities	46	%	49	%
Debt securities	29	%	27	%
Cash and other short-term securities	25	%	24	%
Total	100	%	100	%

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Commitments and contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies [Abstract]

Schedule of minimum estimated commitment under purchase contracts

The minimum estimated commitment under these contracts, except as noted below, is as follows:

As at December 31, 2017

2018		2019		2020		2021		2022		Thereafter
$	473,927	$	371,167	$	306,400	$	308,338	$	245,989	$	1,300,609

Schedule of minimum lease payments

Finance lease obligations are payable as follows:

	Lease payments		Interest component		Finance lease obligations
2018	$	31,447	$	23,549	$	7,898
2019	31,826		22,727		9,099
2020	32,213		21,756		10,457
2021	32,608		20,612		11,996
2022	33,010		19,271		13,739
Thereafter	236,772		85,719		151,053
	$	397,876	$	193,634	$	204,242

The Company has future minimum lease payments under operating leases relating primarily to vessel charter, terminal facilities, office space, equipment and other operating lease commitments as follows:

As at December 31, 2017

2018		2019		2020		2021		2022		Thereafter
$	90,820	$	90,035	$	56,973	$	38,982	$	37,858	$	163,822

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Related parties (Tables)

12 Months Ended

Dec. 31, 2017

Related Party [Abstract]

Disclosure of interests in subsidiaries

The Company has interests in significant subsidiaries and joint ventures as follows:

Name	Country of incorporation	Principal activities	Interest %
			Dec 31 2017		Dec 31 2016
Significant subsidiaries:
Methanex Asia Pacific Limited	Hong Kong	Marketing & distribution	100	%	100	%
Methanex Europe NV	Belgium	Marketing & distribution	100	%	100	%
Methanex Methanol Company, LLC	United States	Marketing & distribution	100	%	100	%
Egyptian Methanex Methanol Company S.A.E. ("Methanex Egypt")	Egypt	Production	50	%	50	%
Methanex Chile S.A.	Chile	Production	100	%	100	%
Methanex New Zealand Limited	New Zealand	Production	100	%	100	%
Methanex Trinidad (Titan) Unlimited	Trinidad	Production	100	%	100	%
Methanex U.S.A. LLC	United States	Production	100	%	100	%
Methanex Louisiana LLC	United States	Production	100	%	100	%
Waterfront Shipping Company Limited2	Cayman Islands	Shipping	100	%	100	%
Significant joint ventures:
Atlas Methanol Company Unlimited1	Trinidad	Production	63.1	%	63.1	%

¹ Summarized financial information for the group’s investment in Atlas is disclosed in note 6.

² Waterfront Shipping Company Limited has a controlling interest in multiple ocean going vessels owned through less than wholly-owned entities as disclosed in note 23.

Set out below is summarized financial information for each of our subsidiaries that have non-controlling interests. The amounts disclosed are before inter-company eliminations.

As at							Dec 31 2017									Dec 31 2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Current assets	$	248,032		$	27,240		$	275,272		$	155,422		$	12,123		$	167,545
Non-current assets	720,356			105,375			825,731			746,202			116,314			862,516
Current liabilities	(231,259		)	(12,489		)	(243,748		)	(177,088		)	(14,622		)	(191,710		)
Non-current liabilities	(293,184		)	(76,090		)	(369,274		)	(339,369		)	(84,540		)	(423,909		)
Net assets	443,945			44,036			487,981			385,167			29,275			414,442
Carrying amount of Methanex non-controlling interests	$	216,599		$	27,748		$	244,347		$	188,099		$	20,416		$	208,515

For the years ended December 31							2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Revenue	$	285,017		$	32,094		$	317,111		$	111,728		$	26,148		$	137,876
Net and total comprehensive income (loss)	65,241			6,981			72,222			(79,963		)	4,781			(75,182		)
Net and total comprehensive income (loss) allocated to Methanex non-controlling interests	55,470			3,492			58,962			(18,069		)	2,389			(15,680		)
Equity contributions by non-controlling interests	$	—		$	8,170		$	8,170		$	—		$	25		$	25
Distributions paid and accrued to non-controlling interests	$	(26,970	)	$	(4,330	)	$	(31,300	)	$	(23,264	)	$	(1,410	)	$	(24,674	)

For the years ended December 31							2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Cash flows from (used in) operating activities	$	131,175		$	19,538		$	150,713		$	(23,992	)	$	17,718		$	(6,274	)
Cash flows from (used in) financing activities	(27,365		)	(3,250		)	(30,615		)	(24,929		)	55,891			30,962
Cash flows from (used in) investing activities	$	(18,839	)	$	(605	)	$	(19,444	)	$	(4,637	)	$	(70,516	)	$	(75,153	)

¹ Other is comprised of multiple ocean going vessels controlled by Waterfront Shipping Company Limited through less than wholly-owned entities.

Disclosure of transactions between related parties

Remuneration of non-management directors and senior management, which includes the members of the executive leadership team, is as follows:

For the years ended December 31	2017		2016
Short-term employee benefits	$	5,214	$	5,315
Post-employment benefits	583		650
Other long-term employee benefits	43		47
Share-based compensation expense1	40,668		16,172
Total	$	46,508	$	22,184

¹  Balance includes realized and unrealized gains (losses) from share-based compensation awards granted.

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Non-controlling interests (Tables)

12 Months Ended

Dec. 31, 2017

Interest In Other Entities [Abstract]

Summary of financial information for each subsidiary with non-controlling interests

The Company has interests in significant subsidiaries and joint ventures as follows:

Name	Country of incorporation	Principal activities	Interest %
			Dec 31 2017		Dec 31 2016
Significant subsidiaries:
Methanex Asia Pacific Limited	Hong Kong	Marketing & distribution	100	%	100	%
Methanex Europe NV	Belgium	Marketing & distribution	100	%	100	%
Methanex Methanol Company, LLC	United States	Marketing & distribution	100	%	100	%
Egyptian Methanex Methanol Company S.A.E. ("Methanex Egypt")	Egypt	Production	50	%	50	%
Methanex Chile S.A.	Chile	Production	100	%	100	%
Methanex New Zealand Limited	New Zealand	Production	100	%	100	%
Methanex Trinidad (Titan) Unlimited	Trinidad	Production	100	%	100	%
Methanex U.S.A. LLC	United States	Production	100	%	100	%
Methanex Louisiana LLC	United States	Production	100	%	100	%
Waterfront Shipping Company Limited2	Cayman Islands	Shipping	100	%	100	%
Significant joint ventures:
Atlas Methanol Company Unlimited1	Trinidad	Production	63.1	%	63.1	%

¹ Summarized financial information for the group’s investment in Atlas is disclosed in note 6.

² Waterfront Shipping Company Limited has a controlling interest in multiple ocean going vessels owned through less than wholly-owned entities as disclosed in note 23.

Set out below is summarized financial information for each of our subsidiaries that have non-controlling interests. The amounts disclosed are before inter-company eliminations.

As at							Dec 31 2017									Dec 31 2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Current assets	$	248,032		$	27,240		$	275,272		$	155,422		$	12,123		$	167,545
Non-current assets	720,356			105,375			825,731			746,202			116,314			862,516
Current liabilities	(231,259		)	(12,489		)	(243,748		)	(177,088		)	(14,622		)	(191,710		)
Non-current liabilities	(293,184		)	(76,090		)	(369,274		)	(339,369		)	(84,540		)	(423,909		)
Net assets	443,945			44,036			487,981			385,167			29,275			414,442
Carrying amount of Methanex non-controlling interests	$	216,599		$	27,748		$	244,347		$	188,099		$	20,416		$	208,515

For the years ended December 31							2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Revenue	$	285,017		$	32,094		$	317,111		$	111,728		$	26,148		$	137,876
Net and total comprehensive income (loss)	65,241			6,981			72,222			(79,963		)	4,781			(75,182		)
Net and total comprehensive income (loss) allocated to Methanex non-controlling interests	55,470			3,492			58,962			(18,069		)	2,389			(15,680		)
Equity contributions by non-controlling interests	$	—		$	8,170		$	8,170		$	—		$	25		$	25
Distributions paid and accrued to non-controlling interests	$	(26,970	)	$	(4,330	)	$	(31,300	)	$	(23,264	)	$	(1,410	)	$	(24,674	)

For the years ended December 31							2017									2016
	Methanex Egypt			Other1			Total			Methanex Egypt			Other1			Total
Cash flows from (used in) operating activities	$	131,175		$	19,538		$	150,713		$	(23,992	)	$	17,718		$	(6,274	)
Cash flows from (used in) financing activities	(27,365		)	(3,250		)	(30,615		)	(24,929		)	55,891			30,962
Cash flows from (used in) investing activities	$	(18,839	)	$	(605	)	$	(19,444	)	$	(4,637	)	$	(70,516	)	$	(75,153	)

¹ Other is comprised of multiple ocean going vessels controlled by Waterfront Shipping Company Limited through less than wholly-owned entities.

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Significant accounting policies - Property plant and equipment (Details)	12 Months Ended
	Dec. 31, 2017
Bottom of range
Disclosure of detailed information about property, plant and equipment [line items]
Estimated useful lives	10 years
Top of range
Disclosure of detailed information about property, plant and equipment [line items]
Estimated useful lives	25 years

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Significant accounting policies - Share-based compensation (Details) - Performance shares	12 Months Ended
	Dec. 31, 2017
Grants prior to 2014 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	50.00%
Grants prior to 2014 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	120.00%
Grants subsequent to 2014 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	25.00%
Grants subsequent to 2014 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	150.00%

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Significant accounting policies - Segment reporting (Details)	12 Months Ended
	Dec. 31, 2017 segment
Corporate Information And Statement Of IFRS Compliance [Abstract]
Number of operating segments	1

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Trade and other receivables (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Subclassifications of assets, liabilities and equities [abstract]
Trade	$ 429,582	$ 335,606
Value-added and other tax receivables	36,584	63,738
Egypt gas contract recoveries	24,466	41,578
Other	46,004	58,681
Trade and other receivables	$ 536,636	$ 499,603

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Inventories (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Inventories [Abstract]
Cost of inventories recognized as expense	$ 2,219	$ 1,704

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Property, plant and equipment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) vessel	Dec. 31, 2016 USD ($)
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	$ 3,117,469
Value at end of period	$ 2,998,326	$ 3,117,469
Number of finance lease vessels | vessel	2
Buildings, plant installations and machinery
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	$ 2,797,276
Value at end of period	2,692,607	2,797,276
Finance leases
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	187,703
Value at end of period	181,846	187,703
Other
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	132,490
Value at end of period	$ 123,873	132,490
Ocean going vessels
Reconciliation of changes in property, plant and equipment [abstract]
Number of finance lease vessels | vessel	2
Cost
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	$ 5,028,954	4,848,167
Additions	111,448	197,747
Disposals and other	212	16,960
Value at end of period	5,140,190	5,028,954
Cost | Buildings, plant installations and machinery
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	4,549,816	4,521,835
Additions	98,780	35,644
Disposals and other	(328)	7,663
Value at end of period	4,648,924	4,549,816
Cost | Finance leases
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	206,260	121,849
Additions	7,667	87,800
Disposals and other	(1,846)	3,389
Value at end of period	215,773	206,260
Cost | Other
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	272,878	204,483
Additions	5,001	74,303
Disposals and other	2,386	5,908
Value at end of period	275,493	272,878
Accumulated depreciation
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(1,911,485)	(1,689,385)
Disposals and other	(2,739)	(6,853)
Depreciation	233,118	228,953
Value at end of period	(2,141,864)	(1,911,485)
Accumulated depreciation | Buildings, plant installations and machinery
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(1,752,540)	(1,545,834)
Disposals and other	(2,066)	(945)
Depreciation	205,843	207,651
Value at end of period	(1,956,317)	(1,752,540)
Accumulated depreciation | Finance leases
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(18,557)	(6,853)
Disposals and other	0	0
Depreciation	15,370	11,704
Value at end of period	(33,927)	(18,557)
Accumulated depreciation | Other
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(140,388)	(136,698)
Disposals and other	(673)	(5,908)
Depreciation	11,905	9,598
Value at end of period	$ (151,620)	$ (140,388)

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Investment in associate - Additional information (Details) - t t in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Annual methanol production facility owned (in tonnes)	1.8
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Percentage of ownership interest in associates	63.10%	63.10%

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Investment in associate - Statements of financial position (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of associates [line items]
Cash and cash equivalents	$ 375,479	$ 223,890	$ 254,934
Non-current assets	3,367,615	3,530,996
Current liabilities	(747,948)	(606,933)
Investment in associate	188,922	197,402
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Net assets	112,600	121,158
Long-term receivable from Atlas	76,322	76,244
Investment in associate	$ 188,922	$ 197,402
Percentage of ownership interest in associates	63.10%	63.10%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Cash and cash equivalents	$ 8,361	$ 15,530
Other current assets	79,738	45,219
Non-current assets	289,671	324,297
Current liabilities	(41,388)	(24,783)
Other long-term liabilities, including current maturities	(157,935)	(168,253)
Net assets	$ 178,447	$ 192,010

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Investment in associate - Statements of income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of associates [line items]
Revenue	$ 3,060,642	$ 1,998,429
Operating income	476,468	28,446
Income tax expense	(95,788)	9,279
Net income (loss)	375,097	(28,225)
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Net income (loss)	75,995	19,930
Dividends received from associate	$ 84,553	$ 47,325
Percentage of ownership interest in associates	63.10%	63.10%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Revenue	$ 459,367	$ 213,533
Cost of sales and depreciation and amortization	(261,121)	(145,126)
Operating income	198,246	68,407
Finance costs, finance income and other expenses	(11,170)	(12,771)
Income tax expense	(66,640)	(24,052)
Net income (loss)	$ 120,436	$ 31,584

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Other assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Subclassifications of assets, liabilities and equities [abstract]
Restricted cash	$ 27,863	$ 35,386
Chile VAT receivable	25,456	23,406
Investment in Carbon Recycling International	4,502	4,502
Defined benefit pension plans (note 20)	6,650	5,862
Other	13,555	9,628
Other assets	$ 78,026	$ 78,784

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Long-term debt - Schedule (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 1,502,271	$ 1,556,206
Less current maturities	(55,905)	(53,997)
Non-current portion of long-term debt	1,446,366	1,502,209
Debt discounts and deferred financing fees	17,800	17,800
Unsecured notes
Disclosure of detailed information about borrowings [line items]
Total long-term debt	1,188,163	1,186,424
3.25% due December 15, 2019
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 348,060	347,126
3.25% due December 15, 2019 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Unsecured notes, interest rate	3.25%
5.25% due March 1, 2022
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 248,072	247,685
5.25% due March 1, 2022 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Unsecured notes, interest rate	5.25%
4.25% due December 1, 2024
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 296,873	296,529
4.25% due December 1, 2024 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Unsecured notes, interest rate	4.25%
5.65% due December 1, 2044
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 295,158	295,084
5.65% due December 1, 2044 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Unsecured notes, interest rate	5.65%
Egypt limited recourse debt facilities
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 241,190	288,515
Other limited recourse debt facilities
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 72,918	$ 81,267

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Long-term debt - Narrative (Details)	2 Months Ended	12 Months Ended
	Mar. 06, 2018 USD ($) vessel	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Disclosure of detailed information about borrowings [line items]
Net proceeds on issue of long-term debt		$ 0	$ 65,700,000
Accretion of deferred financing costs		3,100,000	3,000,000
Cash balance		375,479,000	$ 223,890,000	$ 254,934,000
Egypt entity
Disclosure of detailed information about borrowings [line items]
Cash balance		$ 131,000,000
Egypt entity
Disclosure of detailed information about borrowings [line items]
Ownership basis, percent		100.00%
Egypt limited recourse debt facilities
Disclosure of detailed information about borrowings [line items]
Facilities term		12 years
Egypt limited recourse debt facilities | Egypt entity
Disclosure of detailed information about borrowings [line items]
Percentage of gas requirements (greater than)		70.00%
Shareholder distributions subject to restriction		$ 100,000,000
Principal repayments to be matched with shareholder distributions		$ 100,000,000
Egypt limited recourse debt facilities | Minimum | LIBOR
Disclosure of detailed information about borrowings [line items]
Basis spread, percent		0.90%
Egypt limited recourse debt facilities | Maximum | LIBOR
Disclosure of detailed information about borrowings [line items]
Basis spread, percent		1.60%
Other limited recourse debt facilities | Issuance of debt
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 43,000,000
Number of vessels to be acquired | vessel	2
Other limited recourse debt facilities | Fixed interest rate | Issuance of debt
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	5.35%
Other limited recourse debt facilities | 50% owned subsidiary | Issuance of debt
Disclosure of detailed information about borrowings [line items]
Interest %	50.00%
Notional amount	$ 86,000,000
Other limited recourse debt facilities | Minimum
Disclosure of detailed information about borrowings [line items]
Basis spread, percent		0.75%
Facilities term		2 years
Other limited recourse debt facilities | Maximum
Disclosure of detailed information about borrowings [line items]
Basis spread, percent		2.50%
Facilities term		4 years
Revolving credit facility
Disclosure of detailed information about borrowings [line items]
Facilities term		5 years
Notional amount		$ 300,000,000
Debt covenant, EBITDA to interest coverage ratio		2
Debt covenant, debt to capitalization ratio (less than or equal)		55.00%
Default payment accelerated by a creditor, amount of indebtedness (or more)		$ 50,000,000
Default that permits a creditor to demand repayment, amount of indebtedness (or more)		$ 50,000,000

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Long-term debt - Maturity (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	$ 1,502,271	$ 1,556,206
Limited recourse debt facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	314,108	369,782
Unsecured notes
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	1,188,163	$ 1,186,424
Carrying amount
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	1,520,028
Carrying amount | 2018
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	57,072
Carrying amount | 2019
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	410,100
Carrying amount | 2020
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	62,115
Carrying amount | 2021
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	109,462
Carrying amount | 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	281,279
Carrying amount | Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	600,000
Carrying amount | Limited recourse debt facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	320,028
Carrying amount | Limited recourse debt facilities | 2018
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	57,072
Carrying amount | Limited recourse debt facilities | 2019
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	60,100
Carrying amount | Limited recourse debt facilities | 2020
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	62,115
Carrying amount | Limited recourse debt facilities | 2021
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	109,462
Carrying amount | Limited recourse debt facilities | 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	31,279
Carrying amount | Limited recourse debt facilities | Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	0
Carrying amount | Unsecured notes
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	1,200,000
Carrying amount | Unsecured notes | 2018
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	0
Carrying amount | Unsecured notes | 2019
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	350,000
Carrying amount | Unsecured notes | 2020
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	0
Carrying amount | Unsecured notes | 2021
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	0
Carrying amount | Unsecured notes | 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	250,000
Carrying amount | Unsecured notes | Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	$ 600,000

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- Other long-term liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Subclassifications of assets, liabilities and equities [abstract]
Site restoration costs	$ 33,975	$ 30,512
Finance lease liabilities	204,242	201,268
Share-based compensation liability (note 13)	111,405	53,725
Cash flow hedges (note 18)	90,199	68,664
Defined benefit pension plans (note 20)	25,076	22,403
Other	5,214	4,339
Other long-term liabilities, total	470,111	380,911
Less current maturities	(65,226)	(29,720)
Other non-current liabilities	$ 404,885	$ 351,191

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Other long-term liabilities - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) vessel	Dec. 31, 2016 USD ($)
Subclassifications of assets, liabilities and equities [abstract]
Undiscounted amount of estimated cash flows required to settle liabilities	$ 44.9	$ 41.1
Number of vessels delivered | vessel	2
Total finance lease payments	$ 30.6
Interest expense on finance leases	$ 23.7

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Other long-term liabilities - Provision for site restoration costs (Details) - Provision for site restoration costs - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of changes in other provisions [abstract]
Balance at beginning of period	$ 30,512	$ 29,892
New or revised provisions	2,823	51
Accretion expense	640	569
Balance at end of period	$ 33,975	$ 30,512

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Other long-term liabilities - Finance lease obligations (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Disclosure of finance lease and operating lease by lessee [line items]
Lease payments	$ 397,876
Interest component	193,634
Finance lease obligations	204,242
2018
Disclosure of finance lease and operating lease by lessee [line items]
Lease payments	31,447
Interest component	23,549
Finance lease obligations	7,898
2019
Disclosure of finance lease and operating lease by lessee [line items]
Lease payments	31,826
Interest component	22,727
Finance lease obligations	9,099
2020
Disclosure of finance lease and operating lease by lessee [line items]
Lease payments	32,213
Interest component	21,756
Finance lease obligations	10,457
2021
Disclosure of finance lease and operating lease by lessee [line items]
Lease payments	32,608
Interest component	20,612
Finance lease obligations	11,996
2022
Disclosure of finance lease and operating lease by lessee [line items]
Lease payments	33,010
Interest component	19,271
Finance lease obligations	13,739
Thereafter
Disclosure of finance lease and operating lease by lessee [line items]
Lease payments	236,772
Interest component	85,719
Finance lease obligations	$ 151,053

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Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Analysis of income and expense [abstract]
Cost of sales	$ 2,035,545	$ 1,533,915
Selling and distribution	449,593	408,893
Administrative expenses	99,036	59,675
Total expenses by function	2,584,174	2,002,483
Cost of raw materials and purchased methanol	1,637,085	1,140,551
Ocean freight and other logistics	374,717	351,609
Employee expenses, including share-based compensation	243,707	204,762
Other expenses	96,440	77,507
Cost of sales and operating expenses	2,351,949	1,774,429
Depreciation and amortization	232,225	228,054
Total expenses by nature	2,584,174	2,002,483
Adjustments for share-based payments	$ 78,821	$ 33,493

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Finance costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Borrowing costs [abstract]
Finance costs	$ 94,955	$ 90,060

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Net income (loss) per common share - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Earnings per share [abstract]
Basic and diluted net income (loss)	$ 316,135	$ (12,545)

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Net income (loss) per common share - Reconciliation of denominator used for calculation of basic and diluted net income (loss) per common share (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Earnings per share [abstract]
Denominator for basic net income (loss) per common share	86,768,589	89,783,883
Effect of dilutive stock options	56,359	0
Denominator for diluted net income (loss) per common share	86,824,948	89,783,883

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Net income (loss) per common share - Basic and diluted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Earnings per share [abstract]
Basic net income (loss) per common share (in usd per share)	$ 3.64	$ (0.14)
Diluted net income (loss) per common share (in usd per share)	$ 3.64	$ (0.14)

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Share-based compensation - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of shares reserved for future grants of stock options and share appreciation rights	3,953,471
Liabilities from share-based payment transactions	$ 111,405	$ 53,725
SARs and TSARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Maximum term	7 years
Share-based compensation arrangement vesting rights, percentage	33.33%
Fair value of share-based payment transactions	$ 69,800
Liabilities from share-based payment transactions	65,200
Intrinsic value of liabilities from share-based payment transactions	$ 4,600
Weighted average remaining vesting period	1 year 6 months
Expense from share-based payment transactions with employees	$ 45,100	26,900
Expense from share-based payment transactions with employees, effect of change in share price	37,800	20,000
Deferred, Restricted and Performance Share Units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Fair value of share-based payment transactions	55,900
Liabilities from share-based payment transactions	46,100
Intrinsic value of liabilities from share-based payment transactions	$ 9,800
Weighted average remaining vesting period	1 year 6 months
Expense from share-based payment transactions with employees	$ 33,000	6,000
Expense from share-based payment transactions with employees, effect of change in share price	$ 29,900	2,800
Stock Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Maximum term	7 years
Share-based compensation arrangement vesting rights, percentage	33.33%
Expense from share-based payment transactions with employees	$ 500	$ 600

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Share-based compensation - Changes in SARs and TSARs (Details)	12 Months Ended
	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares
SARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period | shares	1,511,485	1,259,208
Number of outstanding units granted | shares	167,600	375,500
Number of outstanding units exercised | shares	(213,207)	(73,291)
Number of outstanding units cancelled | shares	(10,801)	(49,932)
Number of outstanding units expired | shares	(5,000)
Number of outstanding units, end of period | shares	1,450,077	1,511,485
Exercise price of outstanding units, beginning of period (in usd per unit) | $	$ 42.68	$ 44.48
Exercise price of outstanding units granted (in usd per unit) | $	50.15	34.59
Exercise price of outstanding units exercised (in usd per unit) | $	32.03	27.43
Exercise price of outstanding units cancelled (in usd per unit) | $	50.18	49.77
Exercise price of outstanding units expired (in usd per unit) | $	25.22
Exercise price of outstanding units, end of period (in usd per unit) | $	$ 45.11	$ 42.68
TSARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period | shares	2,416,111	2,108,965
Number of outstanding units granted | shares	340,200	574,600
Number of outstanding units exercised | shares	(710,616)	(212,505)
Number of outstanding units cancelled | shares	(2,200)	(54,949)
Number of outstanding units expired | shares	0
Number of outstanding units, end of period | shares	2,043,495	2,416,111
Exercise price of outstanding units, beginning of period (in usd per unit) | $	$ 42.10	$ 42.73
Exercise price of outstanding units granted (in usd per unit) | $	50.17	34.59
Exercise price of outstanding units exercised (in usd per unit) | $	32.98	25.38
Exercise price of outstanding units cancelled (in usd per unit) | $	34.59	52.55
Exercise price of outstanding units expired (in usd per unit) | $	0.00
Exercise price of outstanding units, end of period (in usd per unit) | $	$ 46.62	$ 42.10

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Share-based compensation - Range of exercise prices in SARs and TSARs (Details)	Dec. 31, 2017 USD ($) year shares	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($) shares
SARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years) | year	3.61
Number of units outstanding | shares	1,450,077	1,511,485	1,259,208
Weighted average exercise price of units outstanding (in usd per unit)	$ 45.11	$ 42.68	$ 44.48
Number of units exercisable | shares	955,316
Weighted average exercise price of units exercisable (in usd per unit)	$ 45.93
SARs | $25.97 to $35.51
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years) | year	3.36
Number of units outstanding | shares	585,317
Weighted average exercise price of units outstanding (in usd per unit)	$ 32.94
Number of units exercisable | shares	345,629
Weighted average exercise price of units exercisable (in usd per unit)	$ 31.79
SARs | $25.97 to $35.51 | Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	25.97
SARs | $25.97 to $35.51 | Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 35.51
SARs | $38.24 to $73.13
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years) | year	3.77
Number of units outstanding | shares	864,760
Weighted average exercise price of units outstanding (in usd per unit)	$ 53.35
Number of units exercisable | shares	609,687
Weighted average exercise price of units exercisable (in usd per unit)	$ 53.94
SARs | $38.24 to $73.13 | Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	38.24
SARs | $38.24 to $73.13 | Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 73.13
TSARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years) | year	4.03
Number of units outstanding | shares	2,043,495	2,416,111	2,108,965
Weighted average exercise price of units outstanding (in usd per unit)	$ 46.62	$ 42.10	$ 42.73
Number of units exercisable | shares	1,195,707
Weighted average exercise price of units exercisable (in usd per unit)	$ 48.44
TSARs | $25.97 to $35.51
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years) | year	3.94
Number of units outstanding | shares	779,194
Weighted average exercise price of units outstanding (in usd per unit)	$ 33.67
Number of units exercisable | shares	401,049
Weighted average exercise price of units exercisable (in usd per unit)	$ 32.80
TSARs | $25.97 to $35.51 | Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	25.97
TSARs | $25.97 to $35.51 | Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 35.51
TSARs | $38.24 to $73.13
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years) | year	4.09
Number of units outstanding | shares	1,264,301
Weighted average exercise price of units outstanding (in usd per unit)	$ 54.60
Number of units exercisable | shares	794,658
Weighted average exercise price of units exercisable (in usd per unit)	$ 56.33
TSARs | $38.24 to $73.13 | Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	38.24
TSARs | $38.24 to $73.13 | Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 73.13

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Share-based compensation - Weighted average assumptions (Details) - SARs and TSARs	12 Months Ended
	Dec. 31, 2017 USD ($) year	Dec. 31, 2016 USD ($) year
Disclosure of terms and conditions of share-based payment arrangement [line items]
Risk-free interest rate	1.80%	1.00%
Expected dividend yield	2.00%	2.50%
Expected life of SARs and TSARs (years) | year	1.2	1.4
Expected volatility	31.00%	41.00%
Expected forfeitures	0.20%	0.20%
Weighted average fair value (USD per share) | $	$ 19.02	$ 10.19

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Share-based compensation - Changes in other equity instruments (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Deferred share units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period	251,017	285,816
Number of outstanding units granted	10,452	8,269
Number of outstanding units granted in lieu of dividends	5,669	8,430
Number of outstanding units redeemed	(42,292)	(51,498)
Number of outstanding units cancelled	0	0
Number of outstanding units, end of period	224,846	251,017
Restricted share units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period	18,649	13,864
Number of outstanding units granted	8,100	11,500
Number of outstanding units granted in lieu of dividends	613	773
Number of outstanding units redeemed	(6,907)	(7,488)
Number of outstanding units cancelled	0	0
Number of outstanding units, end of period	20,455	18,649
Performance share units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period	572,272	610,578
Number of outstanding units granted	163,500	261,760
Number of outstanding units granted performance factor		55,592
Number of outstanding units performance factor impact on redemption	(102,557)
Number of outstanding units granted in lieu of dividends	14,383	18,082
Number of outstanding units redeemed	(34,186)	(355,415)
Number of outstanding units cancelled	(8,517)	(18,325)
Number of outstanding units, end of period	604,895	572,272

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Share-based compensation - Changes in stock options (Details)	12 Months Ended
	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares
Share-Based Payment Arrangements [Abstract]
Number of stock options outstanding, beginning of period | shares	344,767	448,507
Number of stock options granted | shares	31,400	75,500
Number of stock options exercised | shares	(98,274)	(153,140)
Number of stock options cancelled | shares	(15,358)	(14,100)
Number of stock options expired | shares		(12,000)
Number of stock options outstanding, end of period | shares	262,535	344,767
Weighted average exercise price of stock options outstanding, beginning of period (in usd per option) | $	$ 40.91	$ 30.52
Weighted average exercise price of stock options granted (in usd per option) | $	50.17	34.59
Weighted average exercise price of stock options exercised (in usd per option) | $	30.90	9.80
Weighted average exercise price of stock options cancelled (in usd per option) | $	52.43	44.04
Weighted average exercise price of stock options expired (in usd per option) | $		6.33
Weighted average exercise price of stock options outstanding, end of period (in usd per option) | $	$ 45.09	$ 40.91

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Share-based compensation - Range of exercise prices in stock options (Details)	Dec. 31, 2017 USD ($) year shares	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($) shares
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Weighted average remaining contractual life (years) | year	3.58
Number of stock options outstanding | shares	262,535	344,767	448,507
Weighted average exercise price (in usd per option)	$ 45.09	$ 40.91	$ 30.52
Number of stock options exercisable | shares	175,360
Weighted average exercise price (in usd per option)	$ 45.88
$25.97 to $35.51
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Weighted average remaining contractual life (years) | year	3.40
Number of stock options outstanding | shares	103,850
Weighted average exercise price (in usd per option)	$ 33.08
Number of stock options exercisable | shares	60,980
Weighted average exercise price (in usd per option)	$ 32.02
$25.97 to $35.51 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options	25.97
$25.97 to $35.51 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options	$ 35.51
$38.24 to $73.13
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Weighted average remaining contractual life (years) | year	3.69
Number of stock options outstanding | shares	158,685
Weighted average exercise price (in usd per option)	$ 52.95
Number of stock options exercisable | shares	114,380
Weighted average exercise price (in usd per option)	$ 53.28
$38.24 to $73.13 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options	38.24
$38.24 to $73.13 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options	$ 73.13

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Segmented information - Revenue attributed to geographic location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of geographical areas [line items]
Revenue	$ 3,060,642	$ 1,998,429
China
Disclosure of geographical areas [line items]
Revenue	801,838	518,499
Europe
Disclosure of geographical areas [line items]
Revenue	608,668	403,879
United States
Disclosure of geographical areas [line items]
Revenue	570,482	359,476
South Korea
Disclosure of geographical areas [line items]
Revenue	347,896	257,658
South America
Disclosure of geographical areas [line items]
Revenue	279,270	179,287
Canada
Disclosure of geographical areas [line items]
Revenue	167,436	109,706
Other Asia
Disclosure of geographical areas [line items]
Revenue	$ 285,052	$ 169,924

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Segmented information - Property, plant and equipment, net (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of geographical areas [line items]
Property, plant and equipment	$ 2,998,326	$ 3,117,469
United States
Disclosure of geographical areas [line items]
Property, plant and equipment	1,412,394	1,468,283
Egypt
Disclosure of geographical areas [line items]
Property, plant and equipment	720,397	742,446
New Zealand
Disclosure of geographical areas [line items]
Property, plant and equipment	265,153	261,482
Trinidad
Disclosure of geographical areas [line items]
Property, plant and equipment	155,525	176,256
Canada
Disclosure of geographical areas [line items]
Property, plant and equipment	148,420	154,982
Chile
Disclosure of geographical areas [line items]
Property, plant and equipment	107,495	108,065
Other
Disclosure of geographical areas [line items]
Property, plant and equipment	$ 188,942	$ 205,955

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Income and other taxes - Income tax expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Current tax recovery (expense):
Current period before undernoted items	$ (85,287)	$ (44,743)
Impact of Argentina gas settlement	0	(7,800)
Adjustments to prior years	(217)	(2,134)
Current tax recovery (expense)	(85,504)	(54,677)
Deferred tax recovery (expense):
Origination and reversal of temporary differences	23,310	82,838
Impact of Argentina gas settlement	0	(3,575)
Derecognition of non-capital loss carryforwards	0	(17,861)
Adjustments to prior years	200	1,667
Change in U.S. tax rate	(36,567)	0
Change in other jurisdictions tax rates	734	0
Other	2,039	887
Deferred tax recovery (expense)	(10,284)	63,956
Tax expense (income), continuing operations	$ (95,788)	$ 9,279

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Income and other taxes - Reconciliation of effective tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Abstract]
Income (loss) before income taxes	$ 470,885	$ (37,504)
Deduct earnings of associate	(75,995)	(19,930)
Income (loss) before income taxes after deduction of earnings of associate	$ 394,890	$ (57,434)
Canadian statutory tax rate	26.50%	26.50%
Income tax recovery (expense) calculated at Canadian statutory tax rate	$ (104,646)	$ 15,220
Increase (decrease) in income tax recovery resulting from:
Impact of income and losses taxed in foreign jurisdictions	30,223	34,857
Derecognition of non-capital loss carryforwards	0	(17,861)
Unrecognised loss carryforwards and temporary differences	20,468	(6,468)
Impact of tax rate changes in the U.S.	(36,567)	0
Impact of tax rate changes in other jurisdictions	734	0
Impact of foreign exchange	3,104	(4,332)
Other business taxes	(4,105)	(5,404)
Adjustments to prior years	(17)	(467)
Other	(4,982)	(6,266)
Tax expense (income), continuing operations	$ (95,788)	$ 9,279

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Income and other taxes - Net deferred income tax liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	$ (164,091)	$ (153,639)	$ (223,757)
Deferred tax assets	102,341	137,341	61,881
Deferred tax liabilities	(266,432)	(290,980)	$ (285,638)
Property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(403,705)	(419,982)
Deferred tax assets	(189,368)	(197,931)
Deferred tax liabilities	(214,337)	(222,051)
Repatriation taxes
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(87,239)	(85,364)
Deferred tax assets	0	0
Deferred tax liabilities	(87,239)	(85,364)
Other
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(11,670)	(19,956)
Deferred tax assets	(3,740)	(4,981)
Deferred tax liabilities	(7,930)	(14,975)
Temporary differences including temporary differences with liability balances
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(502,614)	(525,302)
Deferred tax assets	(193,108)	(202,912)
Deferred tax liabilities	(309,506)	(322,390)
Non-capital loss carryforwards
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	244,576	280,931
Deferred tax assets	244,576	280,931
Deferred tax liabilities	0	0
Share-based compensation
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	19,920	8,590
Deferred tax assets	2,946	935
Deferred tax liabilities	16,974	7,655
Other
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	74,027	82,142
Deferred tax assets	47,927	58,387
Deferred tax liabilities	26,100	23,755
Temporary differences including temporary differences with asset balances
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	338,523	371,663
Deferred tax assets	295,449	340,253
Deferred tax liabilities	$ 43,074	$ 31,410

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Income and other taxes - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Egypt
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Non-capital loss carryforwards	$ 110	$ 153
United States
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deductible temporary differences for which no deferred tax asset is recognised	$ 384	$ 415

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Income and other taxes - Change in deferred income tax liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Net
Net, beginning of period	$ (153,639)	$ (223,757)
Deferred income tax recovery (expense) included in net income (loss)	(10,284)	63,956
Impact of U.S. tax rate change in other comprehensive income	(8,621)	0
Deferred income tax recovery (expense) included in other comprehensive income (loss)	9,295	6,597
Other	(842)	(435)
Net, end of period	(164,091)	(153,639)
Deferred tax assets
Deferred tax assets, beginning of period	137,341	61,881
Deferred income tax recovery (expense) included in net income (loss)	(34,517)	69,110
Impact of U.S. tax rate change in other comprehensive income	(8,621)	0
Deferred income tax recovery (expense) included in other comprehensive income (loss)	8,398	6,364
Other	(260)	(14)
Deferred tax assets, end of period	102,341	137,341
Deferred tax liabilities
Deferred tax liabilities, beginning of period	(290,980)	(285,638)
Deferred income tax recovery (expense) included in net income (loss)	24,233	(5,154)
Impact of U.S. tax rate change in other comprehensive income	0	0
Deferred income tax recovery (expense) included in other comprehensive income (loss)	897	233
Other	(582)	(421)
Deferred tax liabilities, end of period	$ (266,432)	$ (290,980)

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Supplemental cash flow information - Changes in Non-cash Working Capital (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes in non-cash working capital:
Trade and other receivables	$ (37,033)	$ 4,747
Inventories	(23,136)	(28,094)
Prepaid expenses	(5,702)	(1,286)
Trade, other payables and accrued liabilities, including long-term payables included in other long-term liabilities	103,601	14,577
Decrease (increase) in non-cash working capital	37,730	(10,056)
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid	(89,445)	(65,850)
These changes relate to the following activities:
Operating	(49,368)	(87,644)
Financing	0	0
Investing	(2,347)	11,738
Changes in non-cash working capital	$ (51,715)	$ (75,906)

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Supplemental cash flow information - Reconciliation of Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes from financing cash flows
Repayment of long-term debt and financing fees	$ (56,997)	$ (48,417)
Payment of finance lease liabilities	(6,880)	(5,144)
Long term debt (note 8)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Outstanding at beginning of period	1,556,206
Changes from financing cash flows
Repayment of long-term debt and financing fees	(56,997)
Payment of finance lease liabilities	0
Total changes from financing cash flows	(56,997)
Liability-related other changes
Finance costs	3,062
New finance leases	0
Other	0
Total liability-related other changes	3,062
Outstanding at end of period	1,502,271	1,556,206
Finance lease obligations (note 9)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Outstanding at beginning of period	201,268
Changes from financing cash flows
Repayment of long-term debt and financing fees	0
Payment of finance lease liabilities	(6,880)
Total changes from financing cash flows	(6,880)
Liability-related other changes
Finance costs	0
New finance leases	9,512
Other	342
Total liability-related other changes	9,854
Outstanding at end of period	$ 204,242	$ 201,268

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Capital disclosures (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of liquidity and capitalization [Line Items]
Cash and cash equivalents	$ 375,479,000	$ 223,890,000	$ 254,934,000
Undrawn credit facilities	300,000,000	300,000,000
Total liquidity	675,479,000	523,890,000
Total debt	1,502,271,000	1,556,206,000
Non-controlling interests	244,347,000	208,515,000
Shareholders’ equity	1,500,764,000	1,596,835,000
Total capitalization	$ 3,247,382,000	$ 3,361,556,000
Total debt to capitalization (as a percent)	46.00%	46.00%
Net debt to capitalization (as a percent)	39.00%	42.00%
Unsecured notes
Disclosure of liquidity and capitalization [Line Items]
Total debt	$ 1,188,163,000	$ 1,186,424,000
Limited recourse debt facilities, including current portion
Disclosure of liquidity and capitalization [Line Items]
Total debt	314,108,000	$ 369,782,000
Revolving credit facility
Disclosure of liquidity and capitalization [Line Items]
Notional amount	$ 300,000,000
Facilities term	5 years

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Financial instruments - Fair value measurement (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	$ 930,426,000	$ 745,572,000
Financial liabilities	2,121,467,000	2,074,083,000
Trade, other payables and accrued liabilities, excluding tax payable | Financial liabilities at amortised cost, category
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	528,182,000	449,213,000
Long-term debt, including current portion | Financial liabilities at amortised cost, category
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	1,502,271,000	1,556,206,000
Cash flow hedges | Derivative instruments | Financial liabilities at fair value through other comprehensive income, category
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	91,014,000	68,664,000
Derivative instruments | Financial assets measured at fair value | Cash flow hedges
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	0	7,024,000
Cash and cash equivalents | Financial assets not measured at fair value
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	375,479,000	223,890,000
Trade and other receivables, excluding tax receivable | Financial assets not measured at fair value
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	527,084,000	479,272,000
Project financing reserve accounts included in other assets | Financial assets not measured at fair value
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	$ 27,863,000	$ 35,386,000

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Financial instruments - Natural gas forward contracts (Details) - Natural gas forward contract	12 Months Ended
	Dec. 31, 2017 USD ($) $ / MMBTU	Dec. 31, 2016 USD ($) $ / MMBTU
Disclosure of financial assets [line items]
Hedge ineffectiveness	$ 0
Cash flow hedges
Disclosure of financial assets [line items]
Notional amount	473,000,000	$ 484,000,000
Negative fair value	$ 90,200,000	$ 61,900,000
Cash flow hedges | Geismar 2 Facility
Disclosure of financial assets [line items]
Percentage of gas requirement for forward contracts that will be managed for changes in prices	40.00%
Average contract price (in usd per mmbtu) | $ / MMBTU	3.74	3.68
Remaining term	8 years
Cash flow hedges | Medicine Hat Facility
Disclosure of financial assets [line items]
Average contract price (in usd per mmbtu) | $ / MMBTU	1.96

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Financial instruments - Forward exchange contracts (Details) - Forward exchange contract € in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2017 EUR (€)	Dec. 31, 2016 USD ($)	Dec. 31, 2016 EUR (€)
Disclosure of financial assets [line items]
Hedge ineffectiveness	$ 0
Cash flow hedges
Disclosure of financial assets [line items]
Notional amount | €		€ 109		€ 92
Negative fair value	$ 800,000
Positive fair value			$ 300,000

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Financial instruments - Fair value liabilities, Narrative (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Disclosure of financial assets [line items]
Financial assets	$ 930,426,000	$ 745,572,000
Financial assets measured at fair value | Derivative instruments | Cash flow hedges
Disclosure of financial assets [line items]
Financial assets	$ 0	$ 7,024,000

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Financial instruments - Maturity of derivative liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	$ 105,120	$ 83,472
Within one year
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	7,114	0
1-3 years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	17,057	8,481
3-5 years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	28,864	18,962
More than 5 years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	$ 52,085	$ 56,029

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Financial instruments - Carrying values of financial instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of fair value measurement of liabilities [line items]
Carrying value	$ 2,121,467	$ 2,074,083
Long-term debt excluding deferred financing fees | Level 2
Disclosure of fair value measurement of liabilities [line items]
Carrying value	1,515,544	1,568,822
Fair value	$ 1,561,392	$ 1,538,543

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Financial risk management - Interest rate risk (Details) - Interest rate risk - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fixed interest rate
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	$ 1,188,163	$ 1,186,424
Reasonably possible change in risk variable, percent	1.00%
Reasonably possible change in risk variable, impact on debt	$ 84,000	80,200
Variable interest rate
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	$ 314,108	369,782
Reasonably possible change in risk variable, percent	1.00%
Reasonably possible change in risk variable, impact on pre-tax earnings	$ 3,200	3,700
Unsecured notes | Fixed interest rate
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	1,188,163	1,186,424
Egypt limited recourse debt facilities | Variable interest rate
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	241,190	288,515
Other limited recourse debt facilities | Variable interest rate
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	$ 72,918	$ 81,267

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Financial risk management - Foreign currency risk (Details) - Currency risk - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of financial instruments by type of interest rate [line items]
Net working capital asset	$ 85.3	$ 75.3
Reasonably possible change in risk variable, percent	10.00%
Impact on value of net working capital	$ 8.5	$ 7.5

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Financial risk management - Liquidity risks (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial Instruments [Abstract]
Cash and cash equivalents	$ 375,479	$ 223,890	$ 254,934
Undrawn credit facilities	300,000	300,000
Carrying amount
Finance lease obligations	204,242	201,268
Long-term debt	1,502,271	1,556,206
Cash flow hedges	90,199	68,664
Financial liabilities	2,121,467	2,074,083
Contractual cash flows
Finance lease obligations	397,876
Cash flow hedges	105,120	83,472
1 year or less
Contractual cash flows
Finance lease obligations	31,447
Cash flow hedges	7,114	0
1-3 years
Contractual cash flows
Cash flow hedges	17,057	8,481
3-5 years
Contractual cash flows
Cash flow hedges	28,864	18,962
More than 5 years
Contractual cash flows
Finance lease obligations	236,772
Cash flow hedges	52,085	$ 56,029
Liquidity risk
Carrying amount
Trade and other payables	519,352
Finance lease obligations	204,242
Long-term debt	1,502,271
Cash flow hedges	91,014
Financial liabilities	2,316,879
Contractual cash flows
Trade and other payables	519,352
Finance lease obligations	397,876
Long-term debt	2,178,011
Cash flow hedges	105,120
Financial liabilities	3,200,359
Liquidity risk | 1 year or less
Contractual cash flows
Trade and other payables	519,352
Finance lease obligations	31,447
Long-term debt	121,689
Cash flow hedges	7,114
Financial liabilities	679,602
Liquidity risk | 1-3 years
Contractual cash flows
Trade and other payables	0
Finance lease obligations	64,039
Long-term debt	586,091
Cash flow hedges	17,057
Financial liabilities	667,187
Liquidity risk | 3-5 years
Contractual cash flows
Trade and other payables	0
Finance lease obligations	65,618
Long-term debt	471,831
Cash flow hedges	28,864
Financial liabilities	566,313
Liquidity risk | More than 5 years
Contractual cash flows
Trade and other payables	0
Finance lease obligations	236,772
Long-term debt	998,400
Cash flow hedges	52,085
Financial liabilities	$ 1,287,257

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Retirement plans - Defined benefit pension plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	$ 16,541
Current service cost	1,879	$ 1,677
Past service cost	812	0
Interest cost on accrued benefit obligations / (income) on assets	720	715
Settlements	0	0
Balance, end of year	18,402	16,541
Unfunded status	18,402	16,541
Minimum funding requirement	0	0
Accrued benefit obligations
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	60,771	55,966
Current service cost	1,879	1,677
Past service cost	812	0
Interest cost on accrued benefit obligations / (income) on assets	2,242	2,269
Benefit payments	(5,280)	(2,570)
Settlements	0	0
Actuarial loss	166	2,393
Foreign exchange gain (loss)	4,803	1,036
Balance, end of year	65,393	60,771
Fair values of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	(44,230)	(40,286)
Interest cost on accrued benefit obligations / (income) on assets	(1,522)	(1,553)
Contributions	1,970	2,722
Benefit payments	5,280	2,570
Settlements	0	0
Return on plan assets	1,330	2,345
Foreign exchange gain (loss)	(3,219)	106
Balance, end of year	$ (46,991)	$ (44,230)

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Retirement plans - Additional information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) year	Dec. 31, 2016 USD ($)
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	$ 18,402	$ 16,541
Weighted average duration of defined benefit obligation | year	10
Unfunded | Foreign | Chile
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	$ 25,100	22,400
Estimate of contributions expected to be paid to plan for 2018	5,100
Funded | Domestic
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	(6,600)	(5,700)
Estimate of contributions expected to be paid to plan for 2018	600
Funded | Foreign | Europe
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	$ (100)	$ (200)

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Retirement plans - Expense recognized in income statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Net defined benefit pension plan expense:
Current service cost	$ 1,879	$ 1,677
Past service cost	812	0
Net interest cost	720	715
Cost of settlement	0	0
Net defined benefit pension plan expense	$ 3,411	$ 2,392

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Retirement plans - Expense recognized in other comprehensive income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Employee Benefits [Abstract]
Actuarial gain (loss)	$ 564	$ (77)
Minimum funding requirement	0	0
Actuarial gain (loss), net	$ 564	$ (77)

XML

Retirement plans - Actuarial assumptions and sensitivity analysis (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Discount rates	3.70%	3.70%
Discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible decrease in actuarial assumption	1.00%
Increase (decrease) in defined benefit obligation due to reasonably possible decrease in actuarial assumption	$ 6.3

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Retirement plans - Asset allocation (Details)	Dec. 31, 2017	Dec. 31, 2016
Employee Benefits [Abstract]
Equity securities	46.00%	49.00%
Debt securities	29.00%	27.00%
Cash and other short-term securities	25.00%	24.00%
Total	100.00%	100.00%

XML

Retirement plans - Defined contribution pension plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Employee Benefits [Abstract]
Defined contribution pension plans	$ 8.1	$ 7.6

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Commitments and contingencies - Minimum purchase contract commitment (Details) - Take-or-pay purchase contracts $ in Thousands	Dec. 31, 2017 USD ($)
2018
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	$ 473,927
2019
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	371,167
2020
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	306,400
2021
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	308,338
2022
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	245,989
Thereafter
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	$ 1,300,609

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Commitments and contingencies - Operating lease payments (Details) $ in Thousands	Dec. 31, 2017 USD ($)
2018
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	$ 90,820
2019
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	90,035
2020
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	56,973
2021
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	38,982
2022
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	37,858
Thereafter
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	$ 163,822

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Commitments and contingencies - Narrative (Details) $ in Thousands, t in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) agreement t	Dec. 31, 2016 USD ($)
Commitments And Contingencies [Abstract]
Operating lease payments recognized as expense | $	$ 181,400	$ 165,100
Delivery of vessels currently under construction
Disclosure of associates [line items]
Number of time charter agreements | agreement	2
Future minimum lease payments | $	$ 80,000
Lease term	15 years
Within one year
Disclosure of associates [line items]
Future minimum lease payments | $	$ 90,820
Purchase commitment of methanol supply | Within one year
Disclosure of associates [line items]
Purchase commitments (in tonnes) | t	0.8
Purchase commitment of methanol supply | Thereafter
Disclosure of associates [line items]
Purchase commitments (in tonnes) | t	1.5
Atlas Joint Venture
Disclosure of associates [line items]
Percentage of marketing rights in production	100.00%
Percentage of ownership interest in associates	63.10%	63.10%
Atlas Joint Venture | Purchase commitment of methanol supply
Disclosure of associates [line items]
Purchase commitments (in tonnes) | t	1.3
Atlas Joint Venture | Trinidad
Disclosure of associates [line items]
Percentage of ownership interest in associates	63.10%
Atlas Joint Venture | Egypt
Disclosure of associates [line items]
Percentage of ownership interest in associates	50.00%

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Related parties - Subsidiaries and joint ventures (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Methanex Asia Pacific Limited
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Methanex Europe NV
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Methanex Methanol Company, LLC
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Egyptian Methanex Methanol Company S.A.E. (Methanex Egypt)
Disclosure of subsidiaries [line items]
Interest %	50.00%	50.00%
Methanex Chile S.A.
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Methanex New Zealand Limited
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Methanex Trinidad (Titan) Unlimited
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Methanex U.S.A. LLC
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Methanex Louisiana LLC
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Waterfront Shipping Company Limited
Disclosure of subsidiaries [line items]
Interest %	100.00%	100.00%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Interest %	63.10%	63.10%

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Related parties - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of associates [line items]
Revenue	$ 3,060,642	$ 1,998,429
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Percentage of marketing rights in production	100.00%
Loans outstanding from related party transactions	$ 76,322	76,244
Associates | Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Revenue	459,000	214,000
Receivables from related party transactions	13,000	7,000
Payables from related party transactions	98,000	55,000
Loans outstanding from related party transactions	$ 76,000	$ 76,000

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Related parties - Remuneration (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party [Abstract]
Short-term employee benefits	$ 5,214	$ 5,315
Post-employment benefits	583	650
Other long-term employee benefits	43	47
Share-based compensation expense	40,668	16,172
Total	$ 46,508	$ 22,184

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Non-controlling interests - Financial position (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of subsidiaries [line items]
Current assets	$ 1,243,127	$ 1,025,667
Non-current assets	3,367,615	3,530,996
Current liabilities	(747,948)	(606,933)
Non-current liabilities	(2,117,683)	(2,144,380)
Carrying amount of Methanex non-controlling interests	244,347	208,515
Total
Disclosure of subsidiaries [line items]
Current assets	275,272	167,545
Non-current assets	825,731	862,516
Current liabilities	(243,748)	(191,710)
Non-current liabilities	(369,274)	(423,909)
Net assets	487,981	414,442
Carrying amount of Methanex non-controlling interests	244,347	208,515
Methanex Egypt
Disclosure of subsidiaries [line items]
Current assets	248,032	155,422
Non-current assets	720,356	746,202
Current liabilities	(231,259)	(177,088)
Non-current liabilities	(293,184)	(339,369)
Net assets	443,945	385,167
Carrying amount of Methanex non-controlling interests	216,599	188,099
Other
Disclosure of subsidiaries [line items]
Current assets	27,240	12,123
Non-current assets	105,375	116,314
Current liabilities	(12,489)	(14,622)
Non-current liabilities	(76,090)	(84,540)
Net assets	44,036	29,275
Carrying amount of Methanex non-controlling interests	$ 27,748	$ 20,416

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Non-controlling interests - Income statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of subsidiaries [line items]
Revenue	$ 3,060,642	$ 1,998,429
Net income (loss)	375,097	(28,225)
Total comprehensive income (loss)	346,961	(41,920)
Net income (loss) allocated to Methanex non-controlling interests	58,962	(15,680)
Equity contributions by non-controlling interests	8,170	25
Distributions paid and accrued to non-controlling interests	(4,330)	(1,410)
Methanex Egypt
Disclosure of subsidiaries [line items]
Revenue	285,017	111,728
Net income (loss)	65,241	(79,963)
Total comprehensive income (loss)	65,241	(79,963)
Net income (loss) allocated to Methanex non-controlling interests	55,470	(18,069)
Total comprehensive income (loss) allocated to Methanex non-controlling interests	55,470	(18,069)
Equity contributions by non-controlling interests	0	0
Distributions paid and accrued to non-controlling interests	(26,970)	(23,264)
Other
Disclosure of subsidiaries [line items]
Revenue	32,094	26,148
Net income (loss)	6,981	4,781
Total comprehensive income (loss)	6,981	4,781
Net income (loss) allocated to Methanex non-controlling interests	3,492	2,389
Total comprehensive income (loss) allocated to Methanex non-controlling interests	3,492	2,389
Equity contributions by non-controlling interests	8,170	25
Distributions paid and accrued to non-controlling interests	(4,330)	(1,410)
Total
Disclosure of subsidiaries [line items]
Revenue	317,111	137,876
Net income (loss)	72,222	(75,182)
Total comprehensive income (loss)	72,222	(75,182)
Net income (loss) allocated to Methanex non-controlling interests	58,962	(15,680)
Total comprehensive income (loss) allocated to Methanex non-controlling interests	58,962	(15,680)
Equity contributions by non-controlling interests	8,170	25
Distributions paid and accrued to non-controlling interests	$ (31,300)	$ (24,674)

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Non-controlling interests - Cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of subsidiaries [line items]
Cash flows from (used in) operating activities	$ 787,742	$ 226,667
Cash flows from (used in) financing activities	(530,636)	(169,502)
Cash flows from (used in) investing activities	(105,517)	(88,209)
Methanex Egypt
Disclosure of subsidiaries [line items]
Cash flows from (used in) operating activities	131,175	(23,992)
Cash flows from (used in) financing activities	(27,365)	(24,929)
Cash flows from (used in) investing activities	(18,839)	(4,637)
Other
Disclosure of subsidiaries [line items]
Cash flows from (used in) operating activities	19,538	17,718
Cash flows from (used in) financing activities	(3,250)	55,891
Cash flows from (used in) investing activities	(605)	(70,516)
Total
Disclosure of subsidiaries [line items]
Cash flows from (used in) operating activities	150,713	(6,274)
Cash flows from (used in) financing activities	(30,615)	30,962
Cash flows from (used in) investing activities	$ (19,444)	$ (75,153)