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, 2023    Commission File Number 000-20115

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, 28 Liberty Street, New York, New York 10005

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	Trading Symbol	Name of each exchange on which registered
Common Shares	MEOH	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.

4.25% Senior Notes due December 1, 2024

5.125% Senior Notes due October 15, 2027

5.25% Senior Notes due December 15, 2029

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.

    67,387,492 Common Shares were outstanding as of December 31, 2023

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 every Interactive Data File required to be submitted 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 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.

   ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

   ☑

PCAOB Auditor Firm ID Number:	Auditor Name:	Auditor Location:
85	KPMG LLP	Vancouver, British Columbia, Canada

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

   ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

   ☐

2

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 (the “TSX”) 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, 2023	99.1
Management’s Discussion and Analysis of the Company for the year ended December 31, 2023 (the "2023 MD&A")	99.2
Audited financial statements of the Company for the years ended December 31, 2023 and 2022, including the reports of Independent Registered Public Accounting Firm 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 (“IFRS”), 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.

3

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, 2023, 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 $1.3226. The exchange rate of United States dollars into Canadian dollars, on March 6, 2024, based upon the daily exchange rate as published by the Bank of Canada, was U.S.$1.00=CDN$1.3528.

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 rules and forms of the Securities and Exchange Commission (the “Commission”). 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, 2023, 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, 2023.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate 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 principal executive officer and principal 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.

Internal control over financial reporting has inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements will not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

4

Management’s Assessment and Auditor’s Attestation Report

In connection with the Company’s reporting obligations in Canada and its obligations under Rule 13a-15(c) under the Exchange Act, management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, based on the framework set forth in Internal Control – Integrated Framework, issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on its evaluation under this framework, management concluded that our internal control over financial reporting was effective as at 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, 2023. The attestation report is included on the fourth page of our consolidated financial statements filed as Exhibit 99.3 to this report.

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting that occurred during the year ended December 31, 2023 that has materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 Marketplace 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 Marketplace Rule 5605(a):

Benita Warmbold, Chair

Jim Bertram

Paul Dobson

Maureen Howe

Leslie O’Donoghue

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 Marketplace 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, 2023, 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 Ms. Benita Warmbold 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 Ms. Warmbold as an audit committee financial expert does not make Ms. Warmbold an “expert” for any other purpose (including without limitation for purposes of section 11 of the Securities Act of 1933, as amended), impose any duties, obligations or liability on Ms. Warmbold 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 or the board of directors.

5

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 Marketplace 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 of Ethics were made in 2023.

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 auditors’ 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.

Audit and Non-Audit Fees Billed by the Independent Auditors

KPMG LLP’s global fees relating to the years ended December 31, 2023 and December 31, 2022 are as follows:

US$000s	2023	2022
Audit Fees	2415	2264
Audit-Related Fees	160	168
Tax Fees	165	66
All Other Fees	—	—
Total	2740	2498

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.

6

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, including the review of tax returns; assistance in completing routine tax schedules and calculations; review of transfer pricing and indirect tax items.

Other Fees

There were no other fees in 2023 and 2022.

OFF-BALANCE SHEET ARRANGEMENTS

At December 31, 2023, we did not have any off-balance sheet arrangements, that have, or are reasonably likely to have, a current or future material effect on our results of operations or financial condition.

CONTRACTUAL AND OTHER OBLIGATIONS

The information provided under the heading "Liquidity and Capital Resources" (pages 18-23) contained in the 2023 MD&A, filed as Exhibit 99.2 to this annual report on Form 40-F, is incorporated by reference herein.

NASDAQ CORPORATE GOVERNANCE

The Company is subject to corporate governance requirements prescribed under applicable Canadian securities laws, rules 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 Marketplace 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 Marketplace Rules. A foreign private issuer that follows a home country practice in lieu of one or more provisions of the NASDAQ Marketplace Rules is required to disclose in its annual report filed with the Commission, or on its website, each corporate governance requirement of the NASDAQ Marketplace Rules that it does not follow and describe the home country practice followed by the issuer in lieu of such NASDAQ corporate governance requirements.

A description of the significant ways in which the Company’s governance practices differ from those followed by domestic companies pursuant to NASDAQ standards is as follows:

•Shareholder Meeting Quorum Requirement: NASDAQ Marketplace Rule 5620(c) provides that the minimum quorum requirement for a shareholder meeting is 331/3% of the outstanding shares of common stock. In addition, a company listed on NASDAQ is required to provide for a quorum requirement in its bylaws. The Company’s by-laws provide that at any meeting of 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.

•Distribution of Annual Reports: NASDAQ Marketplace Rule 5250(d) requires a NASDAQ-listed company to make available to shareholders an annual report containing audited financial statements of the company and its subsidiaries (which, for example, may be on 40-F under the Exchange Act) within a reasonable period of time following the filing of the annual report with the Commission. The Company may comply with this requirement either:

7

◦by mailing the report to shareholders (as opposed to electronic or notice-and-access delivery);

◦by satisfying the requirements for furnishing an annual report contained in Rule 14a-16 under the Exchange Act (which rule is not applicable to the Company, as explained in more detail below); or

◦by posting the annual report to shareholders on or through the company's website, along with a prominent undertaking in the English language to provide shareholders, upon request, a hard copy of the annual report free of charge. A company that chooses to satisfy this requirement in this manner must, simultaneously with this posting, issue a press release stating that its annual report has been filed with the Commission. The press release must also state that: (a) the annual report is available on the company's website and include the website address, and (b) shareholders may receive a hard copy free of charge upon request.

The Company is a “foreign private issuer” as defined in Rule 3b-4 under the Exchange Act, and the equity securities of the Company are accordingly exempt from the proxy rules set forth in Sections 14(a), 14(b), 14(c) and 14(f) of the Exchange Act (including Exchange Act Rule 14a-16). The Company solicits proxies in accordance with applicable rules and regulations in Canada.

Pursuant to the provisions of the Canada Business Corporations Act (the “CBCA”), the Company, as a “distributing corporation” under the CBCA, is required to send a copy of the annual audited comparative financial statements to each registered shareholder determined as of a set record date, except to a shareholder who has informed the Company in writing that he or she does not want a copy of these documents.

Section 437 of the TSX Company Manual requires that: (a) every TSX-listed company must forward annually to each shareholder who has requested them its annual financial statements and its MD&A in accordance with NI 51-102; and (b) if a listed company produces an annual report, it must be filed publicly through the System for Electronic Document Analysis and Retrieval (commonly referred to as “SEDAR+”), an electronic database maintained on behalf of the Canadian provincial securities regulators (the “Canadian Securities Administrators”) and available at www.sedarplus.ca.

Pursuant to Canadian National Instrument 51-102 - Continuous Disclosure Obligations (“NI 51-102”), the Company is required to send annually a request form to the registered holders and beneficial owners of its securities, other than debt instruments, that registered holders and beneficial owners may use to request a copy of the Company's annual financial statements and related Management’s Discussion and Analysis (“MD&A”), the interim financial statements and related MD&A, or both. If a registered holder or beneficial owner of securities, other than debt instruments, of the Company requests the Company's annual or interim financial statements, the Company must send a copy of the requested financial statements to the person or company that made the request, without charge, by the later of: (a) 10 days after the filing deadline for the financial statements, or (b) 10 calendar days after the Company receives the request. If the Company sends financial statements it must also send, at the same time, the annual or interim MD&A relating to the financial statements.

The Company has elected to use the notice-and-access (“Notice-and-Access”) provisions adopted by the Canadian Securities Administrators for delivery of proxy materials to its shareholders, as contained in NI 51-102 and National Instrument 54-101 – Communication with Beneficial Owners of Securities of a Reporting Issuer. Pursuant to Notice-and-Access, the Company’s shareholders will receive a notice containing only certain prescribed information in plain language (including the website addresses for SEDAR+ and the non-SEDAR+ websites where the proxy-related materials are posted, as well as a toll-free telephone number for use by shareholders to obtain information about Notice-and-Access and to request paper copies of the proxy materials). Such notice may be sent by the Company by prepaid mail, courier (or the equivalent) or electronically if prior consent has been obtained, along with the applicable voting instruction form.

If a shareholder requests paper copies of an information circular, the Company will be required to send, free of charge, the items requested within three business days for requests received prior to the date of the meeting, and within 10 calendar days for requests received on or after the date of the meeting but within one year of the information circular being filed on SEDAR+. When responding to such requests, the Company will be prohibited

8

from asking for any other information about the requestor, other than the name and address to which the requested materials are to be sent.

Since the foregoing corporate governance practices of the Company are consistent with the laws, customs and practices in Canada, the Company has sought and received relief from the differing NASDAQ standards pursuant to NASDAQ Marketplace Rule 5615(a)(3).

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 Marketplace Rule 5605(d), as currently in force. The Human Resources Committee's responsibilities include administering the Company's Policy for the Recovery of Erroneously Awarded Incentive-Based Compensation (the "Recovery Policy"), which has been adopted by the Board of Directors pursuant to Rule 5608 of the NASDAQ Marketplace Rules. A copy of the Recovery Policy is filed as Exhibit 97 to this Annual Report.

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 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; (c) 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; (d) with respect to the 5.25% Senior Notes due December 15, 2029, was filed with the Commission together with the Form F-10 of the Registrant on August 22, 2019; and (e) with respect to the 5.125% Senior Notes due October 15, 2027, was filed with the Commission together with the Form F-10 of the Registrant on September 9, 2020.

9

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
97	Policy for the Recovery of Erroneously Awarded Incentive-Based Compensation
99.1	Annual Information Form of the Registrant dated March 8, 2024
99.2	Management’s Discussion and Analysis for the Year Ended December 31, 2023
99.3	Audited Consolidated Financial Statements of the Registrant for the years ended December 31, 2023 and December 31, 2022 and the reports of the Independent Registered Public Accounting Firm thereon
101.SCH	Inline XBRL Taxonomy Extension Schema Document
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	Inline XBRL Taxonomy Extension Definitions Linkbase Document
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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 8, 2024

By:     /s/ KEVIN PRICE

Name: Kevin Price

Title: SVP, General Counsel & Corporate Secretary

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors of Methanex Corporation

We consent to the use of:

•our report dated March 8, 2024 on the consolidated financial statements of Methanex Corporation(the “Entity”) which comprise the consolidated statements of financial position as of December 31, 2023 and December 31, 2022, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the years in the two-year period ended December 31, 2023, and the related notes, and

•our report dated March 8, 2024 on the effectiveness of the Entity’s internal control over financial reporting as of December 31, 2023

each of which is included in the Annual Report on Form 40-F of the Entity for the fiscal year ended December 31, 2023.

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. 33-217591) on Form S-8 of the Entity.

/s/ KPMG LLP

Chartered Professional Accountants

March 8, 2024

Vancouver, Canada

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Rich Sumner, 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 the issuer's board of directors (or persons performing the equivalent functions):

a)    all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Date:    March 8, 2024

/s/ RICH SUMNER

Rich Sumner

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Dean Richardson, 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 the issuer's board of directors (or persons performing the equivalent functions):

a)    all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Date:    March 8, 2024

/s/ DEAN RICHARDSON

Dean Richardson

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, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Rich Sumner, 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/ RICH SUMNER

Rich Sumner

President and Chief Executive Officer

March 8, 2024

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, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dean Richardson, 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/ DEAN RICHARDSON

Dean Richardson

Senior Vice President, Finance
and Chief Financial Officer

March 8, 2024

EX-97

MANAGE PEOPLE PROCESSES                             Exhibit 97

RECOUPMENT POLICY

As adopted by the Board of Directors on November 16, 2023

PART 1

GENERAL PROVISIONS

Purpose

1.1    This document sets forth the Methanex Corporation Recoupment Policy as amended and restated effective November 16, 2023. This Recoupment Policy has been adopted by resolution of the Board in accordance with certain listing standards of the Nasdaq Stock Market LLC mandated by Rule 10D-1, to facilitate reasonably prompt recovery by the Company of the amount of any Incentive- Based Compensation that is deemed to have been erroneously awarded in the event that the Company is required to restate its financial statements due to material non-compliance with any financial reporting requirement under relevant Securities Laws.

Definitions

1.2    In this Recoupment Policy, the following terms will have the following meanings:

(a)    “Accounting Restatement” means an accounting restatement due to material noncompliance of the Company with any financial reporting requirement under the Securities Laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period;

(b)    “Board” means the Board of Directors of the Company;

(c)    “Canadian Securities Laws” means all applicable securities laws of each of the provinces of Canada in which the Company is a “reporting issuer”, and the respective rules and regulations made and forms prescribed under such laws, together with all applicable published instruments, policy statements, blanket orders, rulings and notices adopted by the securities regulatory authorities in such provinces;

(d)    “Company” means Methanex Corporation;

(e)    “Human Resources Committee” means the Human Resources Committee of the Board;

(f)    “Effective Date” means the effective date of this Recoupment Policy, being the 16th day of November, 2023;

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 1 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

(g)    “Erroneously Awarded Incentive-Based Compensation” means that portion of any Incentive-Based Compensation that has been paid to an Executive Officer and is recoverable under Section 4.1 of this Recoupment Policy, as such Erroneously Awarded Incentive-Based Compensation is determined under this Recoupment Policy;

(h)    “Exchange Act” means the United States Securities Exchange Act of 1934, as amended;

(i)    “Executive Officer” means any individual deemed to be an “executive officer” of the     Company under Rule 10D-1;

(j)    “Financial Reporting Measures” means any measures that are determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measures derived wholly or in part from such measures whether or not the measure is presented within the financial statements or included in a filing with the SEC. For greater certainty, stock price and TSR are included in the definition of Financial Reporting Measures;

(k)    “Incentive-Based Compensation” means any compensation that is granted, earned or vested based wholly or in part upon the attainment of a Financial Reporting Measure;

(l)    “MJDS” means the United States/Canada multi-jurisdictional disclosure system;

(m)    “Nasdaq” means The Nasdaq Stock Market LLC:

(n)    “Received” means, in the context of Incentive-Based Compensation, the actual or deemed receipt in the Company’s fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period;

(o)    “Recovery Period” has the meaning set forth in Section 4.4;

(p)    “Recoupment Policy” means this policy for the recovery of erroneously awarded executive compensation;

(q)    “Rule 10D-1” means Rule 10D-1 adopted by the SEC under the Exchange Act;

(r)    “SEC” means the United States Securities and Exchange Commission;

(s)    “SEC Final Release” means the final release no. 34-96159 of the SEC entitled “Listing Standards of Recovery of Erroneously Awarded Compensation” in respect of the adoption of Rule 10D-1 pursuant to the requirements of Section 10D of the Exchange Act;

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 2 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

(t)    “Securities Laws” means the Exchange Act and the U.S. Securities Act and, to the extent that the Company has filed any of its financial statements with the SEC under the Exchange Act in reliance on the MJDS, Canadian Securities Laws;

(u)    “TSR” means total shareholder return; and

(v)    “U.S. Securities Act” means the United States Securities Act of 1933, as amended.

PART 2

ADMINISTRATION

Administration

2.1    This Recoupment Policy will be administered by the Human Resources Committee which will be empowered to, with consideration of applicable Securities Laws,

(a)    interpret and administer this Recoupment Policy,

(b)    make determinations as to whether any Incentive-Based Compensation that has been Received by the current and former Executive Officers of the Company constitutes Erroneously Awarded Incentive-Based Compensation in the event of an Accounting Restatement,

(c)    take action to enforce on behalf of the Company any recovery of any Erroneously Awarded Incentive-Based Compensation pursuant to the provisions of this Recoupment Policy,

(d)    make any other determinations that the Human Resources Committee deems necessary or desirable to give effect to the objectives of this Recoupment Policy, and

(e)    periodically review legislative developments that may have an impact on this Recoupment Policy, and report to the Board any recommendations.

Interpretations

2.2    This Recoupment Policy is intended to meet the requirements of Nasdaq Listing Rule 5608 and will be interpreted by the Human Resources Committee consistent with the SEC’s interpretation of Rule 10D-1, including the guidance of the SEC set forth in the SEC Final Release and any other applicable law, regulation, rule or interpretation of the SEC or Nasdaq promulgated or issued in connection therewith. This Recoupment Policy is in addition to the requirements of Section 304 of the Sarbanes-Oxley Act of 2002 that are applicable to the Company’s chief executive officer and chief financial officer.

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 3 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

Compliance

2.3    The Human Resources Committee may require that any employment agreement, offer letter, compensation plan, equity award agreement, or any other agreement entered into on or after the Effective Date require an Executive Officer to agree to abide by the terms of this Recoupment Policy.

PART 3

SCOPE AND INTERPRETATION OF THIS RECOUPMENT POLICY

Effective Period

3.1    This Recoupment Policy will be applied to all Incentive-Based Compensation that is Received by an Executive Officer on or after the Effective Date.

Scope of Executive Officers Subject to Recoupment Policy

3.2    The Human Resources Committee will determine from time-to-time the individuals that are deemed to be subject to the Recoupment Policy by virtue of being considered an Executive Officer.

Scope of Accounting Restatements Subject to Recoupment Policy

3.3    The Accounting Restatements that will trigger the obligation to recover Erroneously Awarded Incentive-Based Compensation will include any restatement of any of the financial statements of the Company filed with the SEC under the Exchange Act to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period. For clarity, Accounting Restatements include for the purposes of this Recoupment Policy both:

(a)    big “R” restatements, being restatements to correct an error material to previously issued financial statements; and

(b)    little “r” restatements, being restatements to correct errors that were not material to those previously issued financial statements but would result in a material misstatement if (i) the errors were left uncorrected in the current report or (ii) the error correction was recognized in the current period.

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 4 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

Determination of When Incentive-Based Compensation is Received

3.4    Incentive-Based Compensation will be deemed Received in the fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award was attained, even if the payment or grant occurs after the end of that period.

PART 4

RECOVERY OF ERRONEOUSLY AWARDED INCENTIVE-BASED COMPENSATION

Recovery

4.1    In that event that the Company is required to prepare an Accounting Restatement, the Company will reasonably promptly take action to recover the amount of any Erroneously Awarded Incentive-Based Compensation that has been Received by each applicable Executive Officer:

(a)    after beginning services as an Executive Officer;

(b)    who served as Executive Officer at any time during the performance period for that Incentive-Based Compensation;

(c)    while the Company has a class of securities listed on Nasdaq (or another national securities exchange in the United States); and

(d)    during the three completed fiscal years immediately preceding the date on which the Company was required to prepare the Accounting Statement, as this three-year period is determined under Section 4.4 below.

4.2    Recovery will be required on a “no fault” basis, without regard to whether an Executive Officer engaged in any misconduct or whether the Executive Officer was responsible for the erroneous financial statements that led to the Accounting Restatement.

Trigger for Recovery of Erroneously Award Compensation

4.3    The date on which the Company is deemed to be required to prepare an Accounting Statement for the purposes of determining the Recovery Period under Section 4.1 will be the earlier to occur of:

(a)        the date that the Board or a committee of the Board concludes, or reasonably should have concluded that the Company, is required to prepare an Accounting Restatement; or

(b)    the date that a court, regulator or other legally authorized body directs the Company to prepare an Accounting Restatement.

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 5 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

Determination of Recovery Period

4.4    The recovery period for the determination of Erroneously Awarded Incentive-Based Compensation (the “Recovery Period”) will be determined as the three completed fiscal years immediately preceding the date that the Company is required to prepare an Accounting Restatement, as that date is determined under Section 4.3. In the event of a change in the financial year of the Company, the Recovery Period will also include any transition period that results from a change in the Company’s fiscal year within or immediately following those three completed fiscal years, provided that a transition period between the last day of the Company’s previous fiscal year end and the first day of its new fiscal year that comprises a period of nine to 12 months would be deemed a completed fiscal year.

Scope of Incentive-Based Compensation Subject to Recovery

4.5    Recovery will be made against each current and former Executive Officer who has Received Incentive-Based Compensation during the three-year Recovery Period to the extent that such Incentive-Based Compensation is determined to be Erroneously Awarded Incentive-Based Compensation. Recovery of Incentive-Based Compensation received while an individual was serving in a non-executive capacity prior to becoming an Executive Officer is not subject to this Recoupment Policy and recovery will not be required. An award of incentive-based compensation granted to an individual before the individual becomes an Executive Officer will be subject to this Recoupment Policy, so long as the Incentive-Based Compensation was received by the individual at any time during the performance period after beginning service as an Executive Officer.

Determination of Amount of Erroneously Awarded Compensation

4.6    The amount of any Erroneously Awarded Incentive-Based Compensation to be recovered under Section 4.1 will be determined as follows for each applicable Executive Officer:

(a)    the amount of Incentive-Based Compensation that has been Received by the Executive Officer during the Recovery Period to which this Recoupment Policy applies, less

(b)    the amount of the Incentive-Based Compensation that would have been received in respect of the Recovery Period had the Incentive-Based Compensation been determined based on the restated amount.

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 6 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

4.7    Erroneously Awarded Incentive-Based Compensation will include any Incentive-Based Compensation that was based on stock price or TSR to the extent that the Incentive-Based Compensation was inaccurate as a result of the Accounting Restatement. For Incentive-Based Compensation based on stock price or TSR, where the amount of Erroneously Awarded Incentive- Based Compensation is not subject to mathematical recalculation directly from the information in the Accounting Restatement:

(a)    the amount must be based on a reasonable estimate of the effect of the Accounting Restatement on the stock price or TSR upon which the Incentive-Based Compensation was received, and

(b)    the amount of the Incentive-Based Compensation that would have been received in respect of the Recovery Period had the Incentive-Based Compensation been determined based on the restated amount.

4.8    The Human Resources Committee shall promptly notify each Executive Officer with a written notice containing the amount of any Erroneously Awarded Compensation and a demand for repayment or return of such compensation.

4.9    The amount of any Erroneously Awarded Incentive-Based Compensation will be computed without regard to any taxes paid by the Executive Officer.

4.10    To the extent that the Executive Officer has already reimbursed the Company for any Erroneously Awarded Compensation Received under any duplicative recovery obligations established by the Company or applicable law, it shall be appropriate for any such reimbursed amount to be credited to the amount of Erroneously Awarded Compensation that is subject to recovery under this Recoupment Policy.

4.11    Notwithstanding anything in this Recoupment Policy, in no event will the Company be required to award any Executive Officer an additional payment or other compensation if the Accounting Restatement would have resulted in the grant, payment or vesting of Incentive-Based Compensation that is greater than the Incentive-Based Compensation actually received by the affected Executive Officer. The recovery of Erroneously Awarded Incentive-Based Compensation is not dependent on if or when the restatement is filed.

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 7 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

PART 5

ENFORCEMENT OF RECOVERY

Requirement to Recover

5.1    Upon a determination by the Human Resources Committee that the Company is obligated to recover Erroneously Awarded Incentive-Based Compensation under Section 4.1, the Company will take steps to recover such Erroneously Awarded Incentive-Based Compensation other than in circumstances where the Human Resources Committee, or a majority of the independent directors of the Board, has made a determination that recovery would be impracticable.

Deferred Payment Plans

5.2    The Human Resources Committee may consider the establishment of a deferred payment where recovery is required from an Executive Officer and where the deferred payment plan allows the Executive Officer to repay the Erroneously Awarded Incentive-Based Compensation as soon as possible without unreasonable economic hardship to the Executive Officer, depending on the facts and circumstances; provided that any such deferred payment plan shall be narrowly tailored to the Erroneously Awarded Incentive-Based Compensation being recovered so as not to constitute a personal loan to the Executive Officer that is prohibited by Section 13(k) of the Exchange Act.

5.3    This Recoupment Policy does not preclude the Company from taking any other action to enforce an Executive Officer’s obligations to the Company or limit any other remedies that the Company may have available to it and any other actions that the Company may take, including termination of employment, institution of civil proceedings, or reporting of any misconduct to appropriate government authorities.

PART 6

PROHIBITION ON INDEMNIFICATION

Prohibition on Indemnification

6.1    The Company shall not be permitted to indemnify or insure any Executive Officer against (i) the loss of any Erroneously Awarded Compensation that is repaid, returned or recovered pursuant to the terms of this Policy, or (ii) any claims relating to the Company’s enforcement of its rights under this Recoupment Policy. Further, the Company shall not enter into any agreement that exempts any Incentive-based Compensation that is granted, paid or awarded to an Executive Officer from the application of this Recoupment Policy or that waives the Company’s right to recovery of any Erroneously Awarded Compensation, and this Recoupment Policy shall supersede any such agreement (whether entered into before, on or after the Effective Date of this Recoupment Policy).

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 8 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

MANAGE PEOPLE PROCESSES

Insurance

6.2    The Company will not purchase or pay or reimburse any Executive Officer for any insurance policy to cover losses incurred by any Executive Officer under this Recoupment Policy.

PART 7

AUTHORITY OF THE HUMAN RESOURCES COMMITTEE

Engagement of Professional Advisors

7.1    In addition to any authority provided under its mandate, the Human Resources Committee will have the authority to engage and retain independent legal counsel, independent accounting advisors and any outside professional advisor that it determines necessary to carry out its duties, at the expense of the Company, without the Board’s approval and at any time, and has the authority to determine any such advisor’s fees and other retention terms.

Oversight

7.2    In the event that the Company is required to recover any Erroneously Awarded Incentive- Based Compensation under this Recoupment Policy, such recovery efforts will be undertaken with the supervision of the office of the General Counsel under oversight of the Human Resources Committee, provided that Human Resources Committee will directly supervise such efforts in the event of that the General Counsel is an Executive Officer who is subject to recovery.

Revision Log

Revision #	BRIEF DESCRIPTION OF CHANGE	Revision Date
2	Published as CG1CP034 under Manage Legal & Compliance	8-Nov-2014
3	Moved to Manage People Processes as PP1GLBL1000; content updated.	14-Dec-2023

Code: PP1GLBL1001	Issue date: 14-Dec-2023	Page 9 of 9
Approved: Kim Campbell, VP, Human Resources		Revision No. 3

Uncontrolled when printed

EX-99.1

Exhibit 99.1

METHANEX CORPORATION

ANNUAL INFORMATION FORM

www.methanex.com

March 8, 2024

TABLE OF CONTENTS	Page
REFERENCE INFORMATION	3
CAUTION REGARDING FORWARD-LOOKING STATEMENTS	4
THE COMPANY	6
BUSINESS OF THE COMPANY	7
DEVELOPMENT OF THE BUSINESS AND CORPORATE STRATEGY	7
Three Year History	7
Our Strategy	9
Leadership	9
Low Cost	9
Operational Excellence	10
Sustainability	10
METHANOL INDUSTRY INFORMATION	11
Demand Factors	11
Supply Factors	13
Methanol Prices	14
PRODUCTION	15
Production Process	15
Operating Data and Other Information	15
MARKETING	15
DISTRIBUTION AND LOGISTICS	16
NATURAL GAS SUPPLY	16
General	16
United States	16
New Zealand	16
Trinidad and Tobago	17
Chile	17
Egypt	17
Canada	17
FOREIGN OPERATIONS	18
RESPONSIBLE CARE & SUSTAINABILITY	18
ENVIRONMENTAL MATTERS	19
GHG Legislation	19
INSURANCE	20
COMPETITION	20
EMPLOYEES	21
RISK FACTORS	21
DIVIDENDS	21
CAPITAL STRUCTURE	21
RATINGS	22
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	26
The Audit Committee Charter	26
Composition of the Audit Committee	26
Relevant Education and Experience	26
Pre-Approval Policies and Procedures	28
Audit and Non-Audit Fees Billed by the Independent Auditors	28
TRANSFER AGENT AND REGISTRAR	29
MATERIAL CONTRACTS	29
CONTROLS AND PROCEDURES	29
CODE OF ETHICS	29
ADDITIONAL INFORMATION	29
APPENDIX "A"	30

2

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 2023 Management’s Discussion and Analysis ("2023 MD&A"), which contains information required to be included in this AIF. The 2023 MD&A is publicly accessible and is filed on the Canadian Securities Administrators’ SEDAR website at www.sedarplus.ca 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 Chemical Market Analytics by OPIS, a Dow Jones company, Tecnon OrbiChem Ltd., Argus, ICIS, S&P Global 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.

3

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," "targets," "plan," "predict" 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, including demand for methanol for energy uses, and its derivatives,

•expected new methanol supply or restart of idled capacity and timing for startup 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 and anticipated timing and rate of return on such 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, cash balances, earnings capability, debt levels and share price,

•availability of committed credit facilities and other financing,

•our ability to meet covenants 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,

•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, including our Geismar 3 project,

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

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

•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,

4

•receipt or issuance of third-party consents or approvals or 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,

•the expected timing and capital cost of our Geismar 3 project,

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

•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,

•our ability to meet timeline and budget targets for the Geismar 3 project, including the impact of any cost

pressures arising from tightening construction labour market conditions,

•competing demand for natural gas, especially with respect to any domestic needs for gas and electricity,

•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 2023 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.

5

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, 2023, 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.

6

BUSINESS OF THE COMPANY

Methanol is a clear liquid commodity chemical that is produced from natural gas and is also produced from coal, particularly in China. Traditional chemical demand, which represents approximately 50% of global 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 wide variety of industrial and consumer products. Demand for energy-related applications, which represents over 30% of global methanol demand, includes several applications including methyl tertiary-butyl ether ("MTBE"), fuel applications (including vehicle fuel, marine fuel and other thermal applications), di-methyl ether ("DME") and biodiesel. Demand into methanol-to-olefins ("MTO") represents over 15% of global methanol demand. MTO plants produce light olefins which have wide applications in packaging, textiles, plastic parts and automotive components.

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 operating capacity, including Methanex's interests in jointly owned plants, is currently 9.3 million tonnes and is located in the United States, New Zealand, Trinidad and Tobago, Chile, Egypt, and Canada. 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 Tobago and in 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 section on page 15 for more information regarding production at our plants.

DEVELOPMENT OF THE BUSINESS AND CORPORATE STRATEGY

Three-Year History

2021

On January 7, 2021, as a result of not being successful in reaching an agreement for an economic longer-term natural gas agreement, the Company announced that it expected its Titan methanol facility in Trinidad to remain idled indefinitely. In order to reduce costs while continuing efforts to secure longer-term gas supply, the Company restructured its Trinidad operations to support a one-plant operation and reduced its Trinidad workforce by approximately 60 positions.

On July 15, 2021, the Company and Mitsui O.S.K. Lines (“MOL”) announced that they had reached agreement on Key Commercial Terms for a strategic partnership involving the Company’s Waterfront Shipping subsidiary, with MOL acquiring a 40 percent minority interest for $145 million.

On July 16, 2021, the Company announced that it was restarting construction on its advantaged Geismar 3 project in October 2021, with commercial operations targeted for the end of 2023 or early 2024. The decision was made as a result of positive methanol industry fundamentals and the completion of certain deleveraging initiatives. Credit facility amendments were also made to further strengthen the Company's balance sheet and enhance its financial flexibility, including repaying the $173 million drawn on the Company’s Geismar 3 construction facility, reducing the facility to $600 million and extending its maturity to 2025. The maturity of the Company’s undrawn $300 million revolving credit facility was also extended to 2026 pursuant to an amended and restated credit agreement. On this date the Company also announced a reset of the quarterly dividend to $0.125 per share from $0.0375 per share.

On September 16, 2021, the Company announced that its Board of Directors approved a normal course issuer bid to commence on September 24, 2021, pursuant to which the Company could purchase up to 3,810,464 common shares, representing 5% of the public float at the time of the announcement.

On October 27, 2021, the Company announced that it had concluded definitive agreements for the Company and MOL to establish a strategic partnership involving the Company’s Waterfront Shipping subsidiary, with MOL acquiring a 40 percent minority interest for $145 million, subject to regulatory approval.

2022

On January 26, 2022, in reporting its fourth quarter 2021 results, the Company announced the restart of its Chile IV plant in early October 2021.

7

On February 1, 2022, the Company and MOL announced the completion of the previously announced strategic partnership involving the Company’s Waterfront Shipping subsidiary, with MOL acquiring a 40 percent minority interest for $145 million.

On April 27, 2022, the Company announced that its Board of Directors approved an amendment to its existing normal course issuer bid originally announced on September 16, 2021, which increased the number of common shares that could be purchased under the bid from 3,810,464 to 6,094,171, representing 10% of the public float at the time of the original announcement.

On September 15, 2022, the Company announced that its Board of Directors approved a normal course issuer bid to commence on September 26, 2022, pursuant to which the Company may purchase up to 3,506,405 common shares, representing 5% of the public float at the time of the announcement, subject to approval by the Toronto Stock Exchange.

On September 15, 2022, the Board of Directors of the Company announced that John Floren will retire as President and CEO and from the Board as of December 31, 2022, and that, following a comprehensive multi-year succession process, the Board appointed Rich Sumner as President and Chief Executive Officer and member of the Board of Directors, effective January 1, 2023.

On September 21, 2022, the Company announced that the Toronto Stock Exchange approved the Company’s previously announced normal course issuer bid, pursuant to which the Company may purchase for cancellation up to 3,506,405 common shares, representing 5% of the 70,128,109 common shares issued and outstanding as of September 15, 2022.

On December 13, 2022, the Company announced the following appointments to its executive leadership team:

–Dean Richardson, Vice President, Corporate Finance at the time of the announcement, was appointed as Senior Vice President, Finance and Chief Financial Officer as of February 1, 2023. Ian Cameron retired from his role as Senior Vice President, Finance and Chief Financial Officer.

–Kevin Maloney, Vice President, Corporate Development at the time of the announcement, was appointed Senior Vice President, Corporate Development as of January 1, 2023. Vanessa James stepped down from her role as Senior Vice President, Corporate Development and Sustainability.

–Gustavo Parra, Vice President, Manufacturing Strategy and Planning at the time of the announcement, was appointed Senior Vice President, Manufacturing as of January 1, 2023. Kevin Henderson retired as Senior Vice President, Manufacturing.

–Karine Delbarre, Vice President, North America Marketing & Logistics at the time of the announcement, was appointed Senior Vice President, Global Marketing & Logistics as of January 1, 2023, filling the vacancy left by Rich Sumner following his appointment as President and CEO.

–Mark Allard, Vice President of North America Manufacturing at the time of the announcement, was appointed Senior Vice President, Low Carbon Solutions as of January 1, 2023. The newly formed role will be focused on capitalizing on the demand and supply opportunities for low-carbon methanol.

–Kevin Price, General Counsel & Corporate Secretary at the time of the announcement, was appointed as Senior Vice President, General Counsel & Corporate Secretary as of January 1, 2023.

2023

On October 13, 2023, the Company announced that it had signed a two-year natural gas supply agreement with the National Gas Company of Trinidad and Tobago ("NGC") for its Titan methanol plant, which is currently idled, to restart operations in September 2024. Simultaneously, the Company announced its intention to idle its Atlas methanol plant in September 2024, when its legacy 20-year natural gas supply agreement expires.

On October 25, 2023, the Company announced the restart of its Chile I plant in September with increased gas availability from Argentina and an increase in 2023 production guidance for Chile from 0.8-0.9 million tonnes to 0.9-1.0 million tonnes.

On November 22, 2023, the Company announced that its 1.26 million tonne Egypt methanol production facility was impacted by an unplanned outage in mid-October as a result of a mechanical failure in the synthesis gas compressor, The unit was removed from service for repairs on an expedited schedule. Production was expected to resume towards the end of the first quarter of 2024.

8

Our Strategy

Our primary objective is to create value through our leadership in the global production, marketing and delivery of methanol to customers. To achieve this objective we have a simple, clearly defined strategy: leadership, low cost and operational excellence. We pride ourselves in being a leader in Responsible Care (an operating ethic and set of principles for sustainability developed by the Chemistry Industry Association of Canada and recognized by the United Nations) and having a strategic focus on managing risks and proactive plans relating to personnel health and safety, environmental protection, community involvement, social responsibility, sustainability, security and emergency preparedness. 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.

Leadership

Leadership is a key element of our strategy. We are focused on creating value through our position as the leading 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 2023 sales volume of 11.2 million tonnes of methanol represented approximately 12% of global methanol demand. This scale allows us the flexibility to meet customer needs across international markets. Our leadership position has also enabled us to play an important role in the methanol 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. We continue to invest in global distribution and supply infrastructure, which includes the world's largest methanol ocean tanker fleet and terminal capacity in all major international markets, enabling us to enhance value to customers by providing reliable and secure supply.

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.

China and Asia continue to lead global methanol demand growth. We have storage capacity in China, South Korea, Japan and Singapore that allows us to cost-effectively manage supply to customers and we have offices in Shanghai, Beijing, Hong Kong, Tokyo, and Seoul to ensure customer service and industry positioning in the region. This enables us to participate in and improve our knowledge of the evolving and growing methanol markets in China and other Asian countries including the use of methanol as a cleaner burning fuel.

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.

We manage our natural gas costs in two ways: through gas contracts linked to methanol price and through fixed price contracts. Our production facilities outside North America are largely underpinned by natural gas purchase agreements where the natural gas price is linked to methanol prices. This pricing relationship enables these facilities to be competitive throughout the methanol price cycle. In North America, we have fixed price contracts and hedges in place targeting minimum operating rate requirements of approximately 70% in the near term. We purchase our remaining North American gas requirements through the spot market.

Our production facilities are well located to supply global methanol markets and we take a long-term approach to contracting shipping capacity to meet customer needs. Nonetheless, 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 focus on identifying initiatives to reduce these costs, including optimizing the use of our shipping fleet, third-party backhaul arrangements and taking advantage of prevailing conditions in the shipping market by varying the type and

9

term of ocean vessel contracts. We also look for opportunities to leverage our global asset position by entering into geographic product exchanges with other methanol producers to reduce distribution and transportation 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, Responsible Care and financial management.

To differentiate ourselves from competitors, we strive to be the best operator and 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. Our commitment to Responsible Care drives our adherence to the highest principles of health, safety, environmental stewardship, and social responsibility. We believe this commitment helps us achieve an excellent overall environmental and safety record and aligns our community involvement and social investments with our core values.

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, and logistics providers) through direct communication and active participation in local and international industry associations, seminars and conferences and online education initiatives.

In 2023, our strategy of operational excellence in financial management supported the construction of the Geismar 3 project to be funded from our cash balance, while continuing to allocate any excess cash to shareholders through share repurchases and a regular dividend. At December 31, 2023, we remain in a strong liquidity position with $458 million in cash and $300 million of undrawn back-up liquidity through our revolving credit facility, leaving us in position to fund the remaining costs for the Geismar 3 project fully with cash on hand. Our intent remains to repay rather than re-finance the $300 million bond due at the end of 2024. We have no other significant debt maturities in the near term. We actively manage our liquidity and capital structure in light of changes to economic conditions, the underlying risks inherent in our operations and the capital requirements of our business.

Sustainability

We have embedded sustainability into our long-term strategy alongside our commitment to Responsible Care. We prioritize the sustainability topics that are most relevant to our business and stakeholders. In a sustainability context, material topics are those environmental, social or governance topics that can significantly impact our business success and are of interest to our key stakeholders. In 2023, we conducted a materiality assessment with external stakeholder outreach to inform whether we were prioritizing the right topics. Our top material sustainability topics were confirmed as greenhouse gas ("GHG") emissions, transition to a low-carbon economy, employee and contractor safety and process safety.

Our executive leadership team has overall responsibility for ensuring our material sustainability topics are being effectively evaluated and managed. These include climate-related risks and opportunities associated with our GHG emissions and the transition to a low-carbon economy. The Executive Leadership Team incorporates these matters into our strategic and business planning activities to support the long-term sustainability of our business.

We believe that having a diverse team, equitable people practices and an inclusive workplace leads to a better culture, better decisions and a better company. Our Equity, Diversity and Inclusion (EDI) Vision is to have an inclusive culture where diversity is valued, differences are embraced and everyone has the opportunity to contribute, develop and advance. The Global EDI Council, made up of senior leaders from around the globe, supports the development and execution of our EDI strategy and its integration into the business. In 2023, we made significant strides towards achieving our vision, including a global roll-out of our foundational EDI learning module to all team members, the development of a Guide to Equitable Succession Planning, and the launch of an Employee Resource Group (ERG) Toolkit to support team members in forming new ERGs.

In March 2024, we issued our 2023 Sustainability Report, aligned with the Sustainability Accounting Standards Board (SASB) and the Task-Force on Climate-related Financial Disclosures (TCFD). Our 2023 Sustainability Report is available at https://www.methanex.com/sustainability.

10

METHANOL INDUSTRY INFORMATION

Demand Factors

Based on the diversity of end products in which methanol is used, demand for methanol is driven by a number of factors, including: the strength of global and regional economies, industrial production levels, energy prices, pricing of end products, downstream capacity additions and government regulations and policies.

We estimate that global methanol demand increased to approximately 91 million tonnes in 2023 driven primarily by growth in China.

Outside of China, traditional demand decreased slightly due to ongoing macro-economic headwinds and the impact of inflation and the resulting monetary policy actions on the rate of industrial activity. This was offset by growing demand in China from traditional chemical derivatives driven by higher GDP growth as compared to 2022, higher demand from energy-related applications with increased global mobility, and strong operating rates in the second half of the year from the methanol-to-olefins (MTO) sector.

Traditional Chemical Derivative Demand

Traditional chemical demand, which represents approximately 50% of global 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 wide variety of industrial and consumer products. Over the long term, we believe that traditional chemical demand is influenced by the strength of global and regional economies and industrial production levels.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 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 because 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 2023, methanol demand to produce formaldehyde represented approximately 25% 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 2023, methanol used to produce acetic acid represented approximately 10% 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.

Other Chemical Derivative Demand

In 2023, the remaining chemical derivative demand for methanol represented approximately 15% of global methanol and is used 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, poultry feed additives and a variety of health and pharmaceutical products. Other end uses include silicone products, aerosol products, de-icing fluid, windshield washer fluid for automobiles and antifreeze for pipeline dehydration.

Energy Demand

Demand for energy-related applications, which represents over 30% of global methanol demand, includes a number of applications including methyl tertiary-butyl ether ("MTBE"), fuel applications (including vehicle fuel, marine fuel and a fuel for industrial boilers and kilns), di-methyl ether and biodiesel. We believe that demand for energy-related applications will be influenced by energy prices, pricing of end products, and government policies that are playing an increasing role in encouraging

11

new applications for methanol due to its emissions benefits as a fuel. Ongoing regulatory changes as part of the global energy transition along with other factors have led to a growing interest in methanol as a fuel due to its cleaner-burning attributes and potential to reduce greenhouse gas emissions.

Methyl tertiary-butyl (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 market. China is the world’s largest automotive market with growing gasoline demand and has publicly stated its desire to reduce exhaust emissions. In the US, MTBE production continues to increase for export markets (Latin America and Europe mainly) as idled assets have restarted and a new project is under construction. By the end of 2023, approximately 11 million tonnes of methanol, or 12% of global demand, 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 Applications

Methanol can be used as a marine fuel, vehicle fuel and as a fuel for industrial boilers, kilns and for cooking stoves.

There is growing interest in methanol as a marine fuel given its environmental benefits, wide availability, cost competitiveness and ease of use. When made from renewable sources, methanol can be carbon neutral on a life-cycle basis, providing a future-proof pathway to meet the decarbonization goals of the shipping industry. The demand outlook for methanol as marine fuel continues to grow with orders for dual-fueled vessels and retrofits. The current vessels operating coupled with the order book for new builds and retrofits represents over 250 dual-fueled ships. Actual methanol consumption from marine applications will depend on regulations, relative economics versus other fuels, and other factors.

Methanol is also being used as a vehicle fuel in China. Methanol can be blended with gasoline in low quantities and used in existing vehicles and can be used in high-proportion blends such as M85 in flex-fuel vehicles or M100 in dedicated methanol-fueled vehicles. There is significant interest in high-level methanol fuel blends for M100 taxis and trucks (able to run on 100% methanol fuel) in China. There are approximately 30,000 taxis and methanol hybrid passenger cars and 4,000 heavy-duty trucks in China, running on M100 fuel, representing approximately one million tonnes of annual methanol demand. Other countries are in the assessment or near-commercial stage for using methanol as a vehicle fuel.

In China, stricter air quality emissions regulations in several provinces are leading to a phase-out of coal-fueled commercial boilers, kilns, and cooking stoves in favour of cleaner fuels, creating a growing market for methanol as an alternative fuel. We estimate that this demand segment represents approximately seven million tonnes of methanol demand. We continue to support various pilot projects and the development of operational and safety standards to support the commercialization of methanol as a thermal fuel for industrial boilers, kilns and cooking stoves.

Methanol is also used in the production of di-methyl ether (DME) and biodiesel. DME is a clean-burning fuel that can be stored and transported like LPG. It is used for household cooking, heating, and a clean-burning substitute for diesel fuel in transportation, although, this application has not yet entered widespread commercialization. Biodiesel is a renewable biofuel and its primary use is in transportation. In 2023, global methanol demand for use in DME and biodiesel was estimated at eight million tonnes, or over 8% of global demand.

In 2023, global methanol demand for use in all fuel applications mentioned above was estimated at approximately 19 million tonnes, or over 20%.

Methanol-to-Olefins (MTO) Demand

Demand for MTO applications represents over 15% of global methanol demand. The future operating rates and methanol consumption of MTO producers 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, the impact of olefin industry feedstock costs, including naphtha, on relative competitiveness and plant maintenance schedules.

Light olefins (ethylene and propylene) are the basic building blocks used to make many everyday products 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, ethane and methanol. In 2023, over 16 million tonnes of methanol, or over 15% of global demand, in the merchant market was consumed by MTO plants in China (excluding demand

12

from upstream-integrated coal-to-olefins plants). We estimate the current MTO capacity for merchant methanol to be approximately 20 million tonnes per annum excluding the integrated coal-to-methanol (CTO) facilities.

Supply Factors

Methanol industry supply is impacted by the cost of production, methanol industry operating rates and new methanol industry capacity additions.

Methanol is predominantly produced from natural gas and is also produced from coal, particularly in China. The cost of production is influenced by the availability and cost of raw materials, including coal and natural gas, freight costs, other operating and maintenance costs and government policies. An increase in economically competitive methanol supply, all else equal, can displace supply from higher cost producers and have a negative impact on methanol price.

The industry has historically operated below stated capacity on a consistent basis, even in periods of high methanol prices, primarily due to shutdowns for planned or unplanned maintenance and feedstock shortages and/or uneconomical feedstock costs. Methanol industry supply can increase through improving operating rates of existing methanol plants.

Methanol industry capacity can increase through the construction of new methanol plants, by restarting idle methanol plants, or by expanding or debottlenecking existing plants to increase their operating capacity. There is typically a span of four to six years to plan and construct a new world-scale methanol plant.

Typical of most commodity chemicals, periods of high methanol prices encourage high-cost producers to operate at maximum rates and 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 market and deliver methanol cost-effectively and reliably to customers.

In 2023, approximately two to three million tonnes of new production capacity was added in China. In Iran, a new plant was commissioned at the end of 2023 but plant operating rates continue to be uncertain and challenged due to the impact of sanctions, plant technical issues and seasonal natural gas constraints. The methanol industry ran at similar rates in 2023 compared to 2022.

In North America, we expect our new 1.8 million tonne Geismar 3 facility, which will be our third plant in Louisiana, to reach commercial production in 2024. In Malaysia, a 1.8 million tonne plant is under construction with a scheduled start up in 2024. We expect to see increased supply from new capacities to be partially offset by rationalization of existing supply in the market in 2024. With the shut down of Atlas and the restart of Titan in September 2024 the overall production in Trinidad will be lower by approximately 1 million tonnes annually and we continue to monitor other factors that could further impact supply such as the announced gas diversion from methanol to LNG in Equatorial Guinea. In China, there are planned capacity additions over the near-to-medium term which we expect will be somewhat offset by the closure of some small-scale, inefficient and older plants. New capacity built in China is expected to be consumed domestically as China requires methanol imports to meet growing demand.

13

Methanol Prices

The methanol business is a highly competitive commodity industry and future methanol prices will ultimately depend on the strength of global demand and methanol industry supply but can also be impacted by other factors such as global trade disputes and government sanctions.Methanol demand and industry supply are driven by several factors as described above. Methanol prices have historically been, and are expected to continue to be, characterized by cyclicality. We are not able to predict future methanol prices, which are driven by several factors that are beyond our control.

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.

1 In January 2022 Methanex introduced a separate price posting for China (China Posted Contract Price), prior to this the Asian Posted Contract Price (APCP) was used for all Asia Pacific and China customers.

14

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 30 and 45 days. Catalysts generally need to be changed every three to six years depending on technology. 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.

The following table details the annual operating capacity and actual production at our facilities in 2023 and 2022:

	Annual Operating Capacity(1)	2023 Production	2022 Production
	(000 tonnes/year)	(000 tonnes)	(000 tonnes)
USA (Geismar) (2)	2,200	2,142	2,041
New Zealand (3)	2,200	1,381	1,230
Trinidad and Tobago (Methanex interest) (4)	1,960	1,074	981
Chile	1,700	993	888
Egypt (50% interest)	630	504	385
Canada (Medicine Hat)	600	548	593
	9,290	6,642	6,118

(1)The annual operating capacity of our production facilities may be higher or lower than original nameplate capacity as, over time, these figures have been adjusted to reflect ongoing operating efficiencies. 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 availability, feedstock composition, the age of the facility's catalyst, turnarounds and access to CO2 from external suppliers for certain facilities. We review and update the operating capacity of our production facilities on a regular basis based on historical performance.

(2)The operating capacity of USA (Geismar) does not include the incremental capacity from the Geismar 3 plant (1.8 million tonnes) that is starting up in 2024. (refer to the Natural Gas Supply - United States section below).

(3)The operating capacity of New Zealand is made up of the two Motunui facilities and the Waitara Valley facility. The Waitara Valley facility is idled indefinitely due to natural gas constraints.(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 – Trinidadand Tobago section below).

Refer to the Production Summary section of our 2023 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 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.

15

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 reliably meet customer commitments.

DISTRIBUTION AND LOGISTICS

All of our methanol production facilities are located adjacent to deepwater ports, except for Medicine Hat which mainly services the regional market via rail and truck. Methanol is transported from our coastal plants by pipeline to these ports for shipping. We currently own or manage a fleet of approximately 30 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 Pacific. 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.

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 focus on identifying initiatives to reduce costs, including optimizing the use of our shipping fleet, third-party backhaul arrangements and taking advantage of prevailing conditions in the shipping market by varying the type and term of ocean vessel contracts. We also look for opportunities to leverage our global asset position by entering into geographic product exchanges with other methanol producers to reduce distribution and transportation costs. We are continuously investigating opportunities to further improve the efficiency and cost-effectiveness of distributing methanol from our production facilities to customers.

Our production site in Trinidad and Tobago is ideally located to supply customers in all global markets. Our plants in New Zealand primarily supply customers in the Asia Pacific region, but can 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. Our Egypt plant primarily services the domestic Egypt market and our European markets but can also supply the Asia Pacific region. Our Medicine Hat plant serves our customer base in North America and the Geismar plants can serve customers across North America, Europe and the Asia Pacific region.

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.

United States

We expect our new 1.8 million tonne Geismar 3 facility to reach commercial production in 2024. Subsequent to the start-up, we will have three plants in Geismar, Louisiana with an annual operating capacity of 4.0 million tonnes.

We utilize a combination of fixed price financial hedges and fixed price physical gas supply agreements to manage natural gas price risk for our Geismar facilities.In North America, we have fixed price gas supply contracts and hedges in place targeting minimum operating rate requirements of approximately 70% in the near-term, declining over time. The balance of our gas requirements are purchased at spot prices.

New Zealand

We have three plants in New Zealand with a total operating capacity of 2.2 million tonnes of methanol per year. Two plants are located at Motunui and can produce 1.7 million tonnes per year and the third is located at nearby Waitara Valley and can produce 0.5 million tonnes. The Waitara Valley Plant was idled indefinitely in the first quarter of 2021 due to a lack of available gas supply.

16

We have entered into several agreements with various natural gas suppliers with terms that range in length up to 2029. All gas supply 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 linked 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. Certain 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.

Trinidad and Tobago

Natural gas for our Atlas methanol production facility in Trinidad and Tobago, with our share of total production capacity being 1.1 million tonnes per year, is supplied under a take-or-pay contract with the National Gas Company of Trinidad and Tobago Limited ("NGC"), which purchases the natural gas from upstream gas producers. The contract for Atlas has a U.S. dollar base and variable price components, where the variable portion is adjusted by a formula linked to methanol prices above a certain level and expires in September 2024.

In October 2023, Methanex signed a two-year natural gas agreement with NGC for its Titan plant, which has been idled since the first quarter of 2020, to restart operations in September 2024. The natural gas agreement for Titan is a take-or-pay contract with a U.S. dollar base and variable price components, where the variable portion is adjusted by a formula linked to methanol prices. Simultaneously, the Company plans to idle Atlas in September 2024, when its legacy 20-year natural gas agreement expires.

Chile

Natural gas for our two plants in Chile is supplied by various producers in Chile and Argentina. A portion of the contracted gas is subject to deliver-or-pay and take-or-pay provisions. Our current gas agreements and gas export permits from Argentina provide for sufficient gas to allow for a two-plant operation in Chile during the Southern hemisphere summer months.

In 2023, one plant operated throughout the year and a second plant operated for seven months.

Our primary Chilean natural gas supplier is Empresa Nacional del Petróleo ("ENAP"). ENAP has made significant investments over the past several years in the development of natural gas from unconventional reservoirs, which has resulted in stable gas deliveries from ENAP to our facilities. The agreements for natural gas supply with ENAP underpin approximately 25% of the 1.7 million tonnes of annual operating capacity for 2023 through 2025.

In 2023, we received natural gas from Argentina from four different natural gas suppliers pursuant to firm supply agreements from September through December 2023. We also received Argentine natural gas in 2023 from a fifth supplier, YPF S.A., from January until April 2023 and from October through December 2023. We have a gas supply agreement with YPF S.A. that expires at the end of 2025.

The price paid for natural gas for our Chilean facilities from our Chilean and Argentine suppliers is a U.S. dollar base price plus a variable price component that is adjusted by a formula linked to methanol prices above a certain level.

Egypt

We have a 25-year, take-or-pay natural gas supply agreement expiring in 2035 for the 1.3 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 linked 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. 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.

Canada

We have entered into fixed price contracts to supply 80-90% of our natural gas requirements for our Medicine Hat facility through 2031. The balance of our gas requirements is purchased under contracts at spot prices.

17

FOREIGN OPERATIONS

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. We are also subject to potential trade risks associated with geopolitical disputes between countries in which we operate.

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, withholding taxes and transfer pricing), 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.

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 its equity. The DL 600 Contracts provide that they cannot be amended or terminated except by written agreement.

RESPONSIBLE CARE & SUSTAINABILITY

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, China Association of International Chemical Manufacturers, Japan Chemical Industry Association and Gulf Petrochemicals and Chemicals Association, we are committed to the Responsible Care® Ethic and Principles for Sustainability.

Responsible Care, a sustainability initiative recognized by the United Nations, 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, 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.

Methanex’s Responsible Care and Social Responsibility (RC and SR) related policies and programs are based on CIAC’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 extends throughout our organization.

The Board’s Responsible Care Committee provides oversight of the RC and SR program performance and related matters at the policy level. The Responsible Care Committee considers RC ethics, sustainability, safety (personal and process), health, environment, crisis management and communications, physical security, product stewardship, quality assurance management, and social responsibility. The executive leadership team has overall responsibility for establishing Methanex’s RC and SR policies and programs, and ensuring that they align with the Board’s requirements and the Company’s business strategy. These global programs are directed and managed by the Vice President, Responsible Care and the Vice President, Corporate Sustainability, who lead Methanex’s global Responsible Care and global Corporate Sustainability functions, respectively.

18

Methanex evaluates the performance of its RC and 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 re-verification was successfully completed in 2022.

Our overarching RC Ethic & Principles for Sustainability Purpose and Values statement sets out the Company’s commitment to RC and sustainability. 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 and investigate 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 health and occupational safety, environmental and process safety-related risks. When incidents do occur, we have a formal incident investigation process to determine root causes and corrective actions to allow for effective mitigation as well as application of lessons learned throughout our organization.

As a natural extension of our RC ethic, we align our employee engagement and communications, community involvement and social investment strategies with our core values and corporate strategy. In alignment with our Stakeholder Relations Policy, the Company is committed to being accountable and responsive to our stakeholders. We proactively respond to any 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. Furthermore, the Company is committed to positively contributing to and having an open, honest and proactive relationship with the communities where we have a significant presence; to having effective processes to identify and respond to community concerns; and to informing the community of risks associated with our operations.

One of the ways the Company maintains the highest standards of product care is by sharing methanol safe handling knowledge and best practices with key stakeholders involved in the methanol value chain including customers, distributors, logistics providers, emergency responders, industry associations and regulators.

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 and international and jurisdictional waters in which our vessels operate have laws, regulations, treaties and conventions in force 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 with respect to protecting the environment have become more stringent over time 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.

GHG Legislation

We generate GHG emissions, primarily as carbon dioxide ("CO2"), directly and indirectly through the production, distribution and use of its products. GHG emissions are a byproduct of the development and extraction of hydrocarbons, including natural gas used as a feedstock in methanol production, as well as the methanol production process. GHG emissions are also generated when fuel is consumed during the global transport of methanol. The GHG Protocol Corporate Standard classifies a company’s

19

GHG emissions into three ‘scopes’. Scope 1 emissions are direct emissions from owned or controlled sources. Scope 2 emissions are indirect emissions from the generation of purchased energy. Scope 3 emissions are all indirect emissions (not included in Scope 2) that occur in the value chain, including both upstream and downstream emissions.

We monitor and manage our GHG emissions intensity for Scope 1 and Scope 2 emissions, defined as the equivalent quantity of CO2 released per unit of production or transported tonne, relating to both methanol equity production and our owned marine operations. The amount of GHG emissions generated by the methanol production process is highly dependent on a number of factors including the design of the methanol plant, plant reliability and availability of natural gas. Similarly, the distance of trade routes for transported cargo, as well as ship technology and operating efficiency, influence the emissions intensity of our marine operations. Accordingly, GHG emissions may vary from year to year depending on the mix of production assets and vessels in operation.

Under the Paris Agreement within the United Nations Framework Convention on Climate Change, many of the countries we operate in have agreed to put forth substantial efforts and commitments to reduce GHG emissions that they are implementing through GHG regulations that include carbon prices. We are currently subject to GHG regulations in New Zealand, Canada and Chile, while our production in the United States, Trinidad and Tobago, and Egypt is currently not subject to such regulations. These regulations result in additional costs to produce methanol. Many of our competitors produce methanol in countries with no imposed GHG regulations or carbon taxes and as such, further increases in regulations or carbon taxes in the countries in which we operate may negatively impact our competitive position within the methanol industry. In addition, as of January 2024, Waterfront Shipping is subject to the EU’s Emissions Trading System (ETS) for fifty percent of emissions from voyages where the point of origin or the point of destination is within the EU and 100 percent of emissions that occur for voyages between two EU ports and when ships are within EU ports. EU ETS emissions allowances will need to be purchased and surrendered for 40 percent of reported CO2 emissions in 2024, 70 percent in 2025 and 100 percent in 2027.

There are ongoing reviews and potential changes to government GHG regulations in countries where we have operations or conduct business, including potential carbon border adjustment mechanisms that could impact the efficient management of our global supply chain.

We cannot provide assurance that changes in existing or the introduction of new GHG regulations, carbon taxes, or other initiatives related to climate change in jurisdictions where we have operations or conduct business will not have an adverse impact on our results of operations and financial condition.

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, oxygen, or utilities, 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 insurance, including business interruption and construction 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 12% of the global market demand in 2023, 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. Similar to other global commodities, the methanol industry is highly competitive. A supplier’s ability to withstand price competition and volatile market conditions will depend on several 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. We manage our natural gas costs in two ways: through gas contracts linked to methanol price and through fixed price contracts. Our production facilities outside North America are largely underpinned by natural gas purchase agreements where the natural gas price is linked to methanol prices. This pricing relationship enables these facilities to be competitive throughout the methanol price cycle. In North America, we have fixed price contracts and hedges in place targeting minimum operating rate requirements of approximately 70% in the near term. 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

20

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, 2023, we had 1,451 employees.

RISK FACTORS

The risks relating to our business are described under the heading Risk Factors and Risk Management in our 2023 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 to return cash to shareholders while allowing the Company to retain financial flexibility appropriate for the historically cyclical nature of the methanol industry. The following table sets forth the amount of quarterly cash dividends paid by the Company on its Common Shares in 2021, 2022 and 2023:

Record Date	Payment Date	Dividend per Share
December 15, 2023	December 29, 2023	$0.185
September 16, 2023	September 30, 2023	$0.185
June 16, 2023	June 30, 2023	$0.185
March 17, 2023	March 31, 2023	$0.175
December 17, 2022	December 31, 2022	$0.175
September 16, 2022	September 30, 2022	$0.175
June 16, 2022	June 30, 2022	$0.145
March 17, 2022	March 31, 2022	$0.125
December 17, 2021	December 31, 2021	$0.125
September 16, 2021	September 30, 2021	$0.125
June 16, 2021	June 30, 2021	$0.0375
March 17, 2021	March 31, 2021	$0.0375

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 bylaws 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 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.

21

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 negative change in the Company's current rating score and/or rating outlook could adversely affect the Company's future 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.

The following table sets forth the ratings assigned to the Company by S&P Global Ratings ("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)	BB+
Unsecured Notes	BB	Ba1	BB+
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 BB are less vulnerable in the near term relative to other lower-rated obligations, however, they face major ongoing uncertainties in periods of adverse business, financial or economic conditions. 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 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, debt securities rated Ba are judged to have speculative elements and are subject to substantial credit risk. Moody’s applies numerical modifiers 1, 2 and 3 in each major rating category from Aa through Caa in its corporate bond rating system. The modifier 1 indicates that the issue ranks in the higher end of its major 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 major rating category. Moody's rates the Company's debt securities and does not provide an Issuer Credit Rating.

(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 BB indicate an elevated vulnerability to default risk, particularly in the event of adverse changes in business or economic conditions over time; however, business or financial flexibility exists that supports the servicing of financial commitments. 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.

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.

22

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, 2023, through December 31, 2023).

2023 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	63.26	49.71	3,568,630	1,660,145	6,150,989	11,379,764
February	71.46	61.00	3,981,509	2,311,674	7,970,399	14,263,582
March	74.68	59.10	3,959,616	1,783,228	7,094,504	12,837,348
April	64.16	58.41	2,815,417	1,257,176	5,752,883	9,825,476
May	61.66	54.61	2,849,594	1,191,567	5,342,180	9,383,341
June	62.33	50.57	2,984,862	1,533,745	6,512,810	11,031,417
July	60.03	54.24	2,113,503	1,234,997	5,442,543	8,791,043
August	62.30	54.93	1,893,963	1,109,437	5,235,311	8,238,711
September	61.93	54.67	1,984,341	1,264,081	5,256,406	8,504,828
October	62.24	53.00	2,545,595	1,205,419	7,982,103	11,733,117
November	62.60	56.14	1,606,213	938,207	4,286,579	6,830,999
December	64.97	56.98	1,965,722	1,060,110	4,790,014	7,815,846

(1) Source: Bloomberg

NORMAL COURSE ISSUER BID

On September 15, 2022, the Company announced a normal course issuer bid (the "2022 Bid") authorizing the Company to purchase up to 3,506,405 Common Shares, representing 5% of the Common Shares issued and outstanding as of September 15, 2022. Under the 2022 Bid, which commenced on September 26, 2022 and expired on September 25, 2023, the Company repurchased for cancellation 2,787,484 Common Shares on the open market through the facilities of the TSX for US $119 million, an average purchase price of approximately US $43 per share.

DIRECTORS AND EXECUTIVE OFFICERS

As at December 31, 2023, the directors and executive officers of the Company owned, controlled or directed, directly or indirectly, 290,708 Common Shares, representing approximately 0.4% of the outstanding Common Shares as at December 31, 2023.

23

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: 

Name and Municipality of Residence	Office	Principal Occupations and Positions During the Last Five Years	Director Since(16)
ARNELL, DOUG West Vancouver British Columbia Canada	Director and Chair of the Board	Chief Executive Officer of Cedar LNG LLC(5) since June 2021 and President and Chief Executive Officer of Helm Energy Advisors Inc.(6) since March 2015.	October 2016
BERTRAM, JIM(1)(3) Calgary, Alberta Canada	Director	Corporate Director.	October 2018
DOBSON, PAUL(1)(4) Naples, Florida USA	Director	Senior Vice President and Chief Financial Officer of Ballard Power Systems(7) since March 2021. Prior thereto Acting President and Chief Executive Officer of Hydro One Limited(8) from July 2018 to May 2019; prior thereto Chief Financial Officer of Hydro One Limited from May 2018; prior thereto Chief Financial Officer of Direct Energy Ltd.(9) from January 2016 to February 2018.	April 2019
HOWE, MAUREEN(1)(2) Vancouver, British Columbia Canada	Director	Corporate Director.	June 2018
KOSTELNIK, ROBERT(3)(4) Fulshear, Texas USA	Director	Corporate Director. Principal of GlenRock Recovery Partners, LLC(10) since February 2012.	September 2008
O'DONOGHUE, LESLIE(1)(4) Calgary, Alberta Canada	Director	Corporate Director. Executive Vice President and Adviser to the Chief Executive Officer of Nutrien Ltd.(11) from June 2019 to December 2019; prior thereto Executive Vice President, Chief Strategy and Business Development Officer of Nutrien Ltd. from January 2018 to June 2019.	April 2020
RODGERS, KEVIN(2)(3) London UK	Director	Corporate Director.	July 2019
SAMPSON, JOHN(4) Midland, Michigan USA	Director	Senior Vice President, Operations, Manufacturing and Engineering of Dow Inc.(12) since 2020; prior thereto Executive Vice President, Business Operations of Olin Corporation(13) from 2019 to 2020; prior thereto Vice President, Operations of Olin Corporation from 2015 to 2019.	October 2023
SUMNER, RICH North Vancouver British Columbia Canada	Director, President and Chief Executive Officer	President and Chief Executive Officer of the Company since January 2023. Prior thereto Senior Vice President, Global Marketing and Logistics of the Company since October 2021; prior thereto Regional President, Marketing and Logistics, Asia Pacific of the Company since February 2019; prior thereto Vice President, Marketing and Logistics, North America of the Company since March 2015.	January 2023
WALKER, MARGARET(3)(4) Austin, Texas USA	Director	Corporate Director. Owner of MLRW Group, LLC(14) since 2011.	April 2015
WARMBOLD, BENITA(1)(2) Toronto, Ontario Canada	Director	Corporate Director.	February 2016
YANG, XIAOPING(2)(4) Henderson, Nevada USA	Director	Corporate Director. President and Chair of BP China(15) from November 2016 to September 2020.	January 2022

(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 Responsible Care Committee.

(5)Cedar LNG LLC is developing an LNG export terminal in Northeastern British Columbia.

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

(7)Ballard Power Systems is a global provider of innovative clean energy and fuel cell solutions.

(8)Hydro One Limited is a major transmission and distribution provider in Ontario, Canada.

(9)Direct Energy Ltd. is a North American retailer of energy and energy services.

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

(11)Nutrien Ltd. is a Canadian fertilizer company, and is the world's largest provider of crop inputs, services and solutions.

(12)Dow Inc. is a producer and supplier of raw materials for products in a wide variety of industries.

(13)Olin Corporation is a global manufacturer and distributor of chemical products.

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

24

(15)BP is a multinational energy company.

(16)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.

Name and Municipality of Residence	Office	Principal Occupations and Positions During the Last Five Years
ALLARD, MARK West Vancouver, British Columbia Canada	Senior Vice President, Low Carbon Solutions	Senior Vice President, Low Carbon Solutions of the Company since January 2023; prior thereto Vice President, North America of the Company since January 2019; prior thereto Vice President, Corporate Development of the Company since November 2012.
BOYD, BRAD West Vancouver, British Columbia Canada	Senior Vice President,  Corporate Resources	Senior Vice President, Corporate Resources of the Company since January 2018.
DELBARRE, KARINE West Vancouver, British Columbia Canada	Senior Vice President, Global Marketing and Logistics	Senior Vice President, Global Marketing and Logistics of the Company since January 2023; prior thereto Vice President, Marketing and Logistics, North America of the Company since February 2019; prior thereto Director, Operations (NA) of the Company from April 2014.
MALONEY, Kevin West Vancouver, British Columbia Canada	Senior Vice President, Corporate Development	Senior Vice President, Corporate Development of the Company since January 2023; prior thereto Vice President, Corporate Development of the Company since April 2018; prior thereto Managing Director, New Zealand of the Company since April 2015.
PARRA, GUSTAVO Santiago Chile	Senior Vice President, Manufacturing	Senior Vice President, Manufacturing of the Company since January 2023; prior thereto Vice President, Manufacturing Strategy and Planning of the Company since September 2019; prior thereto Managing Director and President, Trinidad and Tobago of the Company since January 2017.
PRICE, KEVIN Vancouver, British Columbia Canada	Senior Vice President, General Counsel & Corporate Secretary	Senior Vice President, General Counsel and Corporate Secretary of the Company since January 2023; prior thereto General Counsel and Corporate Secretary of the Company since March 2016.
RICHARDSON, DEAN Vancouver, British Columbia Canada	Senior Vice President, Finance and Chief Financial Officer	Senior Vice President, Finance and Chief Financial Officer of the Company since February 2023; prior thereto Vice President, Corporate Finance of the Company since January 2022; prior thereto Managing Director, New Zealand of the Company since April 2018; prior thereto Vice President, Treasury and Investor Relations of the Company since August 2017.

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

Our Independent Registered Public Accounting Firm is KPMG LLP (“KPMG”), who prepared the Report of the Independent Registered Public Accounting Firm dated March 8, 2024 with respect to the Company’s consolidated financial statements as at December 31, 2023 and 2022, and for the years ended December 31, 2023 and 2022, and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023. KPMG has 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 regulations and also 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 audited and issued assessments against our 63.1% owned joint venture, Atlas, in respect of the 2005 to 2017 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 with affiliates that commenced in 2005 and continued with affiliates through 2014 and with an unrelated third party through 2019. The long-term fixed-price sales contracts with affiliates were established as part of the formation of Atlas and management believes these were reflective of market considerations at that time.

During the periods under assessment and continuing through 2014, approximately 50% of Atlas-produced methanol was sold under these fixed-price contracts. From late 2014 through 2019 fixed-prices sales to an unrelated third party represented approximately 10% of Atlas-produced methanol. Atlas had partial relief from corporation income tax until late July 2014.

25

The Company believes it is impractical to disclose a reasonable estimate of the potential contingent liability due to the wide range of assumptions and interpretations implicit in the assessments.

The Company has lodged objections to the assessments. No deposits have been required to lodge objections. Although there can be no assurance that these tax assessments will not have a material adverse impact, based on the merits of the case and advice from legal counsel, we believe our position should be sustained, that Atlas has filed its tax returns and paid applicable taxes in compliance with Trinidadian tax law, and as such has not accrued for any amounts relating to these assessments. Contingencies inherently involve the exercise of significant judgment, and as such the outcomes of these assessments and the financial impact to the Company could be material.

We anticipate the resolution of this matter through the court systems to be lengthy and, at this time, cannot predict a date as to when we expect this matter to be ultimately resolved.

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 accounting and financial controls; the professional qualifications and independence of the Company's external auditors; the performance of the internal and external auditors; risk management processes; financing 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".

Composition of the Audit Committee

The Audit Committee is comprised of five directors: Benita Warmbold (Chair), Jim Bertram, Paul Dobson, Maureen Howe and Leslie O'Donoghue. Each Audit Committee member is "independent" and "financially literate" as determined in accordance with Canadian National Instrument 52-110 - Audit Committees. Ms. Warmbold is currently designated as the "audit committee financial expert" (as that term is defined by U.S. securities regulations). 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 or the Board.

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.

Ms. Benita Warmbold

Ms. Warmbold is a corporate director and former Senior Managing Director and Chief Financial Officer of the Canada Pension Plan Investment Board ("CPPIB"). CPPIB is a professional investment management organization responsible for investing funds on behalf of the Canada Pension Plan. Over her nine years at CPPIB, Ms. Warmbold was responsible for finance, risk, tax, internal audit, legal, technology, data and investment operations. Prior to joining CPPIB, Ms. Warmbold held leadership positions with Northwater Capital Management Inc., Canada Development Investment Corporation and KPMG LLP.

Ms. Warmbold holds a bachelor of commerce (honours) degree from Queen’s University, is a chartered professional accountant and is a Fellow of the Institute of Chartered Accountants of Ontario. She is also a Fellow of the Institute of Corporate Directors and has been granted their ICD.D .

Ms. Warmbold serves on the board of the Bank of Nova Scotia and chairs their Audit and Conduct Review Committee and is a designated financial expert. She is also a director of AtkinsRéalis (legally known as SNC-Lavalin Group Inc.) and is a former Chair of their Audit and Risk Committee. Ms. Warmbold is also Chair of the Canadian Public Accountability Board.

26

Ms. Warmbold has served on the Audit Committee since February 2016 and has been Chair of the Audit Committee since April 2018.

Mr. Jim Bertram

Mr. Bertram is a corporate director. From its inception in 1998 until his retirement in December 2014, he was Chief Executive Officer of Keyera Corporation ("Keyera"), a publicly traded midstream oil and gas operator.

Mr. Bertram holds a bachelor of commerce from the University of Calgary and has been granted the ICD.D designation by the Institute of Corporate Directors.

Mr. Bertram has served on the board of Keyera since 2003, and was appointed Chair of the Board in 2016. Mr. Bertram attends all Keyera Audit Committee meetings in his current capacity as Chair of the Board and also did so during his tenure as Chief Executive Officer.

Mr. Bertram also serves on the board of Emera Inc.

Mr. Bertram has served on the Audit Committee since October 2020.

Mr. Paul Dobson

Mr. Dobson has been Senior Vice President, Chief Financial Officer of Ballard Power Systems ("Ballard") since March 2021. Ballard is a global provider of innovative clean energy and fuel cell solutions. From July 2018 to May 2019 Mr. Dobson was Acting President and Chief Executive Officer of Hydro One Limited, a major transmission and distribution provider in Ontario, Canada, and prior to that was Chief Financial Officer of Hydro One Limited from March 2018. Mr. Dobson also served as Chief Financial Officer of Direct Energy Ltd. in Houston, Texas, and held senior leadership positions in finance across the Centrica Group, the parent company of Direct Energy.

Mr. Dobson holds a bachelor of arts in management accounting (honours) from the University of Waterloo as well as an MBA from the University of Western Ontario. He is a chartered professional accountant and a certified management accountant.

Mr. Dobson has served on the Audit Committee since April 2019.

Ms. Maureen Howe

Ms. Howe is a corporate director. From 1996 to 2008 she was Managing Director of RBC Capital Markets specializing in the area of energy infrastructure, which included power generation, transmission and distribution, oil and gas transmission and distribution, gas processing and alternative energy. Prior to joining RBC Capital Markets, Ms. Howe held finance positions in the utility industry, investment banking and portfolio management.

Ms. Howe holds a bachelor of commerce (honours) from the University of Manitoba and a Ph.D. in Finance from the University of British Columbia.

Ms. Howe is a director and Audit Committee chair of both Pembina Pipeline Corporation and Freehold Royalties Ltd.

Ms. Howe has served on the Audit Committee since June 2018.

Ms. Leslie O'Donoghue

Ms. O'Donoghue is a corporate director. She was Executive Vice President and Advisor to the Chief Executive Officer of Nutrien Ltd. ("Nutrien") from June 2019 until her retirement in December 2019. Nutrien is a Canadian fertilizer company and is the wold's largest provider of crop inputs, services and solutions. Ms. O'Donoghue was the Executive Vice President, Chief Strategy and Business Development Officer of Nutrien from January 2018 to June 2019, and prior to this she was Executive Vice President, Corporate Development and Strategy and Chief Risk Officer of Agrium Inc. (Nutrien's predecessor company) from 2012 to 2017.

Through Ms. O’Donoghue’s experience at Nutrien and from serving on other audit committees, she has gained an understanding of accounting and financial reporting, including internal controls and procedures for financial reporting.

Ms. O'Donoghue holds a bachelor of arts (economics) degree from the University of Calgary and a LLB, from Queen's University.

27

Ms. O'Donoghue is a director of Pembina Pipeline Corporation and serves on their Audit Committee. She is also a director of Dye & Durham Limited.

Ms. O'Donoghue has served on the Audit Committee since April 2021.

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 non-audit services proposed to be performed by KPMG LLP are pre-approved in order to mitigate the risk of non-audit services impacting the auditor’s independence. 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 of the Company 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, 2023 and December 31, 2022 are as follows:

US$000s	2023	2022
Audit Fees	2,415	2,264
Audit-Related Fees	160	168
Tax Fees	165	66
All Other Fees	—	—
Total	2,740	2,498

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.

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, including the review of tax returns; assistance in completing routine tax schedules and calculations; review of transfer pricing and indirect tax items.

Other Fees

There were no other fees in 2023 and 2022.

28

TRANSFER AGENT AND REGISTRAR

Our principal transfer agent for our Common Shares is TSX Trust Company at its offices in Vancouver, British Columbia. Our co-transfer agent in the United States for our Common Shares is Equiniti Trust Company, LLC at its offices in New Jersey.

MATERIAL CONTRACTS

Other than those contracts entered into during the normal course of business, the only material contract that was entered into before December 31, 2023 and after January 1, 2002, that is still in effect, and which is required to be filed with Canadian securities regulatory authorities pursuant to applicable securities laws, is the amended and restated credit agreement (2021) dated for reference June 16, 2021, between the Company, as borrower, Royal Bank of Canada, as agent bank, and the financial institutions party thereto, as lenders (the "Credit Agreement"). The Credit Agreement is described above in "Three-Year History - 2021".

CONTROLS AND PROCEDURES

Our disclosure controls and procedures are described under the heading Controls and Procedures in our 2023 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 9, 2024, relating to our Annual General Meeting that will be held on April 25, 2024.

Additional financial information about the Company is provided in the Company’s financial statements for the year ended December 31, 2023, and in our 2023 MD&A.

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

Methanex Corporation

Kevin Price

Senior Vice President, 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.sedarplus.ca, on the United States Securities and Exchange Commission’s EDGAR website at www.sec.gov and on our website at www.methanex.com.

29

APPENDIX "A"

METHANEX CORPORATION

AUDIT, FINANCE AND RISK COMMITTEE MANDATE

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

A.PURPOSE

The Committee is appointed by the Board of Directors (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 accounting and financial controls; the professional qualifications and independence of the Corporation’s external auditor; the performance of the external and internal auditors; risk management processes; financing 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 applicable 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 their business judgment, shall be entitled to rely on the integrity of those persons and organizations within and outside the Corporation from whom they receive 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.

B.    STRUCTURE

1.    The Committee shall be composed of a minimum of three directors.

2.    The members of the Committee shall 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 shall continue to be a Committee member until a successor is appointed, unless they resign or are removed by the Board or cease 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.

3.    Each member of the Committee shall meet the independence and financial literacy requirements of the Corporation’s Corporate Governance Principles and the applicable rules and regulations of the stock exchanges on which the Corporation is listed, the U.S. Securities and Exchange Commission (the “SEC”) and the Canadian Securities Administrators (collectively, the “Applicable Rules”), and at least one member of the Committee shall qualify as an “audit committee financial expert” in accordance with the rules of the SEC.

4.    The Board shall appoint a Chair from among the Committee members and the Chair shall set the agendas for Committee meetings. If the Chair of the Committee is not present at any meeting of the Committee, the Chair of the meeting shall be chosen by the Committee from among the members present. The Chair presiding at any meeting of the Committee has a deciding vote in the case of deadlock. The Committee shall also appoint a Secretary who need not be a director.

C.    MEETINGS

1.The Committee shall meet at least quarterly. The time and place of Committee meetings and the procedure at such meetings shall be determined from time to time by Committee members, provided that:

a.a quorum for meetings shall be a majority of the members of the Committee, present in person or by tele- or video-conference that permits all persons participating in the meeting to communicate with each other;

b.notice of the time and place of every meeting shall be given in writing, by electronic transmission or otherwise, to each member of the Committee and the external auditor of the Corporation at least 24 hours prior to the time fixed for such meeting, provided, however, that a member may in any manner waive notice of a meeting, and attendance of a member 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;

30

c.the Committee shall, at least annually, meet with the Chief Financial Officer without other members of management present;

d.each regular meeting of the Committee shall conclude with a session without any members of management present;

e.the external auditor shall be entitled to attend each meeting at the Corporation’s expense;

f.a meeting of the Committee may be called by the Secretary of the Committee on the direction of the Chair or any other member of the Committee, the Chief Executive Officer of the Corporation or the external auditor; and

g.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.

2.    The Committee shall report to the Board following each meeting with respect to its activities and such recommendations as the Committee deems appropriate. The report may take the form of an oral report by the Chair or any other member of the Committee designated by the Committee to make such report.

3.    The Committee shall maintain minutes or other records of its meetings and activities.

D.    RESPONSIBILITIES AND DUTIES

The following functions shall be the common recurring responsibilities of the Committee. The Committee may carry out additional functions as may be appropriate in light of changing business, legislative and other conditions. The Committee shall also carry out any other responsibilities delegated to it by the Board from time to time.

The Committee, in carrying out its duties and discharging its oversight role, shall have the sole authority to retain independent legal, accounting or other experts as it determines necessary, including the authority to set and pay the fees payable to such experts at the Corporation’s expense. The Board shall be kept apprised of both the selection of the experts and the experts’ findings through the Committee’s regular reports to the Board.

Financial Statements and Disclosure

1.    Review and discuss with management and the external auditor, and recommend to the Board for approval prior to public disclosure, the Corporation’s Annual Report, Annual Information Form, audited Consolidated Financial Statements and related Management’s Discussion and Analysis, Management Information Circular and any reports on adequacy of internal controls.

2.    Review and discuss with management, and recommend to the Board for approval prior to public disclosure, prospectuses and other offering documents.

3.    Review and discuss with management and the external auditor, and approve prior to public disclosure, the Corporation’s interim reports, including the unaudited Condensed Consolidated Interim Financial Statements and related Management’s Discussion and Analysis.

4.    Review and discuss with management and the external auditor, and approve prior to public disclosure, press releases on quarterly and year-end financial results and any other disclosure documents not identified above that are required to be filed with regulators and contain significant financial information respecting the Corporation.

5.    Review and discuss with management and the external auditor significant accounting policies and critical accounting estimates that would have a significant effect on the Corporation’s financial statements, and any changes to such policies. This review shall include a discussion with management and the external auditor concerning:

a.any areas of management judgment and estimates that may have a significant effect on the financial statements;

b.the appropriateness, acceptability and quality of the Corporation’s accounting policies; and

c.any material written communication between the external auditor and management.

6.    Discuss with management the use of ‘‘pro forma’’ or ‘‘non-GAAP information’’ in the Corporation’s disclosure documents.

31

7.    Discuss with management and the external auditor the effect of regulatory and accounting initiatives as well as the use of off-balance sheet arrangements on the Corporation’s financial statements.

8.    Discuss with the Corporation’s General Counsel (and with external legal counsel if necessary) and other members of management, as applicable, 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

1.    Review and discuss with management the financing plans and objectives of the Corporation.

Risk Management and Internal Controls

1.    Review and discuss with management at least annually:

a.the Corporation’s risk management framework, including the Corporation’s processes and controls to identify, monitor, evaluate and manage enterprise-wide risks and the Corporation's policies and practices relating to enterprise risk management. The Committee shall recommend to the Board for approval any changes considered advisable to such policies and practices;

b.the Corporation’s financial and taxation risks, shipping risk and IT-related risks (including cybersecurity and data privacy) and steps management has taken to monitor, evaluate and manage such risks; and

c.the insurance coverage maintained by the Corporation.

2.    Review such other risk management matters from time to time as the Committee may consider appropriate or the Board may specifically direct.

3.    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 shall include a review of:

a.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

b.internal control recommendations of the external auditor 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.

External Auditors

1.    Review the selection, evaluation, reappointment or, where appropriate, replacement of the external auditor and recommend to the Board the nomination and remuneration of the external auditor to be appointed by the Corporation’s shareholders.

2.    Resolve any disagreements between management and the external auditor regarding financial reporting.

3.    Receive reports directly from, and communicate directly with, the external auditor.

4.    Review a formal written statement obtained at least annually from the external auditor describing:

a.the external auditor’s internal quality control procedures;

b.any material issues raised by the most recent internal quality control review, peer review of the external auditor 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 external auditor;

c.any steps taken to deal with any such issues; and

d.all relationships between the external auditor and the Corporation.

32

As part of such review, the Committee shall discuss with the external auditor whether the external auditor’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 also conduct a comprehensive review of the external auditor at least every five years.

5.    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 external auditor for strengthening internal controls shall be reviewed.

6.    Monitor the rotation of senior audit personnel who have primary responsibility for the audit work, as required by law.

7.    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 Standard, which is to be annually reviewed and approved by the Committee.

8.    Review the establishment of policies relating to the Corporation’s hiring of present and former employees of the external auditor, if such individuals have participated in the audit of the Corporation, as required by law.

9.    Prior to filing the Corporation’s Condensed Consolidated Interim Financial Statements and the Consolidated Financial Statements, receive a report from the external auditor on the results of their review or audit.

10.    Meet with (a) the external auditor without management present and discuss any issues related to performance of the audit work, any restrictions and any significant disagreement with management and (b) separately with management to discuss the same matters as those discussed with the external auditor.

Internal Audit

1.    Review the scope of responsibilities of the Corporation’s Internal Audit function, including its reporting relationships, activities, organizational structure and resources and whether there are any unjustified or inappropriate restrictions or limitations on the functioning of Internal Audit.

2.    Discuss the appointment and performance of the head of the Corporation’s Internal Audit function.

3.    Review and approve the annual Internal Audit Plan and objectives.

4.    Review the responses and actions taken by management to address any control weaknesses or deficiencies identified in internal audit reports issued to management.

5.    Meet, without management present, with the Corporation’s Internal Auditor and/or representatives of any external firm that executed the annual Internal Audit Plan. The Committee shall also meet, without management and the external auditor present, with the Corporation’s Internal Auditor to discuss any matters that the Committee or the Internal Auditor believes should be discussed privately.

Ethics and Compliance

1.    Review annually the Corporation’s compliance with the Code of Business Conduct and make recommendations to the Board regarding any requests by directors or officers for waivers of the Code of Business Conduct.

2.    Review the processes and procedures established by the Corporation for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters or non-compliance with the Code of Business Conduct, including procedures for the confidential, anonymous submission of such complaints from employees.

3.    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 or that could have a material effect on the Corporation’s financial statements.

4.    Review annually the Corporation’s Corporate Disclosure Policy and recommend to the Board for approval any changes thereto.

5.    Review and approve all related party transactions between the Corporation (or any of its subsidiaries) and its officers or directors (or any affiliates of such officers or directors), other than those disclosed in the Corporation’s financial statements.

33

E.    ANNUAL PERFORMANCE EVALUATION

1.    The Committee shall review and evaluate, at least annually, the performance of the Committee and its members, including the compliance of the Committee with its mandate.

2.    The Committee shall annually review and assess the adequacy of its mandate and recommend to the Board for approval any improvements to the mandate that the Committee considers necessary or desirable.

34

EX-99.2

Management’s Discussion and Analysis                      

Exhibit 99.2

Index

6	Overview of the Business	34	Critical Accounting Estimates
8	Our Strategy	37	Adoption of New Accounting Standards
10	Financial Highlights	37	Anticipated Changes to International Financial Reporting Standards
10	Production Summary	37	Non-GAAP Measures
12	How We Analyze Our Business	39	Quarterly Financial Data (Unaudited)
12	Financial Results	39	Selected Annual Information
18	Liquidity and Capital Resources	40	Controls and Procedures
24	Risk Factors and Risk Management	41	Forward-Looking Statements

This Management’s Discussion and Analysis ("MD&A") is dated March 8, 2024, and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2023. 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.

Throughout this document we use non-GAAP measures and ratios 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 Non-GAAP Measures section on page 37 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures.

Some of the historical price data and supply and demand statistics for methanol and certain other industry data contained in this MD&A 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 Chemical Market Analytics by OPIS, a Dow Jones company, Tecnon OrbiChem Ltd., Argus, ICIS, S&P Global 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.

As at March 7, 2024 we had 67,387,492 common shares issued and outstanding and stock options exercisable for 1,478,353 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.sedarplus.ca 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 produced from natural gas and is also produced from coal, particularly in China. Traditional chemical demand, which represents approximately 50% of global 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 wide variety of industrial and consumer products. Demand for energy-related applications, which represents over 30% of global methanol demand, includes several applications including methyl tertiary-butyl ether ("MTBE"), fuel applications (including vehicle fuel, marine fuel and other thermal applications), di-methyl ether and biodiesel. Demand into methanol-to-olefins ("MTO") represents over 15% of global methanol demand. MTO plants produce light olefins which have wide applications in packaging, textiles, plastic parts and automotive components.

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 operating capacity, including Methanex's interests in jointly owned plants, is currently 9.3 million tonnes and is located in the United States, New Zealand, Trinidad and Tobago, Chile, Egypt, and Canada. 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 Tobago and in 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 10 for more information.

2023 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. Based on the diversity of end products in which methanol is used, demand for methanol is driven by a number of factors, including: the strength of global and regional economies, industrial production levels, energy prices, pricing of end products, downstream capacity additions and government regulations and policies. Methanol industry supply is impacted by the cost of production, methanol industry operating rates and new methanol industry capacity additions.

Demand

We estimate that global methanol demand increased to approximately 91 million tonnes in 2023 driven primarily by growth in China. Outside of China, traditional demand decreased slightly due to ongoing macro-economic headwinds and the impact of inflation and the resulting monetary policy actions on the rate of industrial activity. This was offset by growing demand in China from traditional chemical derivatives driven by higher GDP growth as compared to 2022, higher demand from energy-related applications with increased global mobility, and strong operating rates in the second half of the year from the methanol-to-olefins (MTO) sector.

Over the long term, we believe that traditional chemical demand is influenced by the strength of global and regional economies and industrial production levels. We believe that demand for energy-related applications will be influenced by energy prices, pricing of end products, and government policies that are playing an increasing role in encouraging new applications for methanol due to its emissions benefits as a fuel. The future operating rates and methanol consumption of MTO producers 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, the impact of olefin industry feedstock costs, including naphtha, on relative competitiveness and plant maintenance schedules.

Ongoing regulatory changes as part of the global energy transition along with other factors have led to a growing interest in methanol as a fuel due to its cleaner-burning attributes and potential to reduce greenhouse gas emissions.

There is growing interest in methanol as a marine fuel given its environmental benefits, wide availability, cost competitiveness and ease of use. When made from renewable sources, methanol can be carbon neutral on a life-cycle basis, providing a future-proof pathway to meet the decarbonization goals of the shipping industry. The demand outlook for methanol as marine fuel continues to grow with orders for dual-fueled vessels and retrofits. The current vessels operating coupled with the order book for new builds and retrofits represents over 250 dual-fueled ships. Actual methanol consumption from marine applications will depend on regulations, relative economics versus other fuels, and other factors.

Methanol is also being used as a vehicle fuel in China. Methanol can be blended with gasoline in low quantities and used in existing vehicles and can be used in high-proportion blends such as M85 in flex-fuel vehicles or M100 in dedicated methanol-fueled vehicles. There is significant interest in high-level methanol fuel blends for M100 taxis and trucks (able to run on 100% methanol fuel) in China. There are approximately 30,000 taxis and methanol hybrid passenger cars and 4,000 heavy-duty trucks in China, running on M100 fuel, representing approximately one million tonnes of annual methanol demand. Other countries are in the assessment or near-commercial stage for using methanol as a vehicle fuel.

In China, stricter air quality emissions regulations in several provinces are leading to a phase-out of coal-fueled commercial boilers, kilns, and cooking stoves in favour of cleaner fuels, creating a growing market for methanol as an alternative fuel. We estimate that this demand segment represents approximately seven million tonnes of methanol demand. We continue to support various pilot projects and the development of operational and safety standards to support the commercialization of methanol as a thermal fuel for industrial boilers, kilns and cooking stoves.

Supply

Methanol is predominantly produced from natural gas and is also produced from coal, particularly in China. The cost of production is influenced by the availability and cost of raw materials, including coal and natural gas, freight costs, other operating and maintenance costs and government policies. An increase in economically competitive methanol supply, all else equal, can displace supply from higher cost producers and have a negative impact on methanol price.

In 2023, approximately two to three million tonnes of new production capacity was added in China. In Iran, a new plant was commissioned at the end of 2023 but plant operating rates continue to be uncertain and challenged due to the impact of sanctions, plant technical issues and seasonal natural gas constraints. The methanol industry ran at similar rates in 2023 compared to 2022.

In North America, we expect our new 1.8 million tonne Geismar 3 facility, which will be our third plant in Louisiana, to reach commercial production in 2024. In Malaysia, a 1.8 million tonne plant is under construction with a scheduled start up in 2024. We expect to see increased supply from new capacities to be partially offset by rationalization of existing supply in the market in 2024.

With the shut down of Atlas and the restart of Titan in September 2024 the overall production in Trinidad will be lower by approximately 1 million tonnes annually and we continue to monitor other factors that could further impact supply such as the announced gas diversion from methanol to LNG in Equatorial Guinea. In China, there are planned capacity additions over the near-to-medium term which we expect will be somewhat offset by the closure of some small-scale, inefficient and older plants. New capacity built in China is expected to be consumed domestically as China requires methanol imports to meet growing demand.

Price

The methanol business is a highly competitive commodity industry and future methanol prices will ultimately depend on the strength of global demand and methanol industry supply. Methanol demand and industry supply are driven by several factors as described above. Methanol prices have historically been, and are expected to continue to be, characterized by cyclicality.

Methanex’s average realized price in 2023 was $333 per tonne compared to $397 per tonne in 2022.

OUR STRATEGY

Our primary objective is to create value through our leadership in the global production, marketing and delivery of methanol to customers. To achieve this objective we have a simple, clearly defined strategy: leadership, low cost and operational excellence. We pride ourselves in being a leader in Responsible Care (an operating ethic and set of principles for sustainability developed by the Chemistry Industry Association of Canada and recognized by the United Nations) and having a strategic focus on managing risks and proactive plans relating to personnel health and safety, environmental protection, community involvement, social responsibility, sustainability, security and emergency preparedness. 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.

Leadership

Leadership is a key element of our strategy. We are focused on creating value through our position as the leading 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 2023 sales volume of 11.2 million tonnes of methanol represented approximately 12% of global methanol demand. This scale allows us the flexibility to meet customer needs across international markets. Our leadership position has also enabled us to play an important role in the methanol 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.We continue to invest in global distribution and supply infrastructure, which includes the world's largest methanol ocean tanker fleet and terminal capacity in all major international markets, enabling us to enhance value to customers by providing reliable and secure supply.

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.

China and Asia continue to lead global methanol demand growth. We have storage capacity in China, South Korea, Japan and Singapore that allows us to cost-effectively manage supply to customers and we have offices in Shanghai, Beijing, Hong Kong, Tokyo, and Seoul to ensure customer service and industry positioning in the region. This enables us to participate in and improve our knowledge of the evolving and growing methanol markets in China and other Asian countries including the use of methanol as a cleaner burning fuel.

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.

We manage our natural gas costs in two ways: through gas contracts linked to methanol price and through fixed price contracts. Our production facilities outside North America are largely underpinned by natural gas purchase agreements where the natural gas price is linked to methanol prices. This pricing relationship enables these facilities to be competitive throughout the methanol price cycle. In

North America, we have fixed price contracts and hedges in place targeting minimum operating rate requirements of approximately 70% in the near term. We purchase our remaining North American gas requirements through the spot market.

Our production facilities are well located to supply global methanol markets and we take a long-term approach to contracting shipping capacity to meet customer needs. Nonetheless, 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 focus on identifying initiatives to reduce these costs, including optimizing the use of our shipping fleet, third-party backhaul arrangements and taking advantage of prevailing conditions in the shipping market by varying the type and term of ocean vessel contracts. We also look for opportunities to leverage our global asset position by entering into geographic product exchanges with other methanol producers to reduce distribution and transportation costs.

OperationalExcellence

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, Responsible Care and financial management.

To differentiate ourselves from competitors, we strive to be the best operator and 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. Our commitment to Responsible Care drives our adherence to the highest principles of health, safety, environmental stewardship, and social responsibility. We believe this commitment helps us achieve an excellent overall environmental and safety record and aligns our community involvement and social investments with our core values.

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, and logistics providers) through direct communication and active participation in local and international industry associations, seminars and conferences and online education initiatives.

In 2023, our strategy of operational excellence in financial management supported the construction of the Geismar 3 project to be funded from our cash balance, while continuing to allocate any excess cash to shareholders through share repurchases and a regular dividend. At December 31, 2023, we remain in a strong liquidity position with $458 million in cash and $300 million of undrawn back-up liquidity through our revolving credit facility, leaving us in position to fund the remaining costs for the Geismar 3 project fully with cash on hand. Our intent remains to repay rather than re-finance the $300 million bond due at the end of 2024. We have no other significant debt maturities in the near term. We actively manage our liquidity and capital structure in light of changes to economic conditions, the underlying risks inherent in our operations and the capital requirements of our business.

Sustainability

We have embedded sustainability into our long-term strategy alongside our commitment to Responsible Care. We prioritize the sustainability topics that are most relevant to our business and stakeholders. In a sustainability context, material topics are those environmental, social or governance topics that can significantly impact our business success and are of interest to our key stakeholders. In 2023, we conducted a materiality assessment with external stakeholder outreach to inform whether we were prioritizing the right topics. Our top material sustainability topics were confirmed as greenhouse gas ("GHG") emissions, transition to a low-carbon economy, employee and contractor safety and process safety.

Our executive leadership team has overall responsibility for ensuring our material sustainability topics are being effectively evaluated and managed. These include climate-related risks and opportunities associated with our GHG emissions and the transition to a low-carbon economy. The Executive Leadership Team incorporates these matters into our strategic and business planning activities to support the long-term sustainability of our business.

We believe that having a diverse team, equitable people practices and an inclusive workplace leads to a better culture, better decisions and a better company. Our Equity, Diversity and Inclusion (EDI) Vision is to have an inclusive culture where diversity is valued, differences are embraced and everyone has the opportunity to contribute, develop and advance. The Global EDI Council, made up of senior leaders from around the globe, supports the development and execution of our EDI strategy and its integration into the business. In 2023, we made significant strides towards achieving our vision, including a global roll-out of our foundational EDI learning module to all team members, the development of a Guide to Equitable Succession Planning, and the launch of an Employee Resource Group (ERG) Toolkit to support team members in forming new ERGs.

In March 2024, we issued our 2023 Sustainability Report, aligned with the Sustainability Accounting Standards Board (SASB) and the Task-Force on Climate-related Financial Disclosures (TCFD). Our 2023 Sustainability Report is available at https://www.methanex.com/sustainability.

FINANCIAL HIGHLIGHTS

($ Millions, except as noted)	2023	2022
Production (thousands of tonnes) (attributable to Methanex shareholders)	6,642	6,118
Sales volume (thousands of tonnes)
Methanex-produced methanol	6,455	6,141
Purchased methanol	3,527	3,688
Commission sales	1,187	945
Total sales volume 1	11,169	10,774
Methanex average non-discounted posted price ($ per tonne) 2	434	503
Average realized price ($ per tonne) 3 4	333	397
Revenue	3,723	4,311
Net income (attributable to Methanex shareholders)	174	354
Adjusted net income 4	153	343
Adjusted EBITDA 4	622	932
Cash flows from operating activities	660	987
Basic net income per common share ($ per share)	2.57	4.95
Diluted net income per common share ($ per share)	2.57	4.86
Adjusted net income per common share ($ per share) 4	2.25	4.79
Common share information (millions of shares)
Weighted average number of common shares	68	71
Diluted weighted average number of common shares	68	72
Number of common shares outstanding, end of year	67	69

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.

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

3     The Company has used Average realized price ("ARP") throughout this document. ARP is calculated as revenue divided by the total sales volume. It is used by management to assess the realized price per unit of methanol sold, and is relevant in a cyclical commodity environment where revenue can fluctuate widely in response to market prices.

4     The Company has used the terms Adjusted net income, Adjusted net income per common share, and Adjusted EBITDA throughout this document. These items are non-GAAP measures and ratios 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 Non-GAAP Measures section on page 37 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures.

PRODUCTION SUMMARY

The following table details the annual operating capacity and actual production at our facilities in 2023 and 2022:

(Thousands of tonnes)	Annual operating capacity 1	2023 Production	2022 Production
USA (Geismar) 2	2,200	2,142	2,041
New Zealand 3	2,200	1,381	1,230
Trinidad (Methanex interest) 4	1,960	1,074	981
Chile	1,700	993	888
Egypt (50% interest)	630	504	385
Canada (Medicine Hat)	600	548	593
	9,290	6,642	6,118

1 The annual operating capacity of our production facilities may be higher or lower than original nameplate capacity as, over time, these figures have been adjusted to reflect ongoing operating efficiencies. 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 availability, feedstock composition, the age of the facility's catalyst, turnarounds and access to CO2 from external suppliers for certain facilities. We review and update the operating capacity of our production facilities on a regular basis based on historical performance.

2    The operating capacity of USA (Geismar) does not include the incremental capacity from the Geismar 3 plant (1.8 million tonnes) that is starting up in 2024.

3    The operating capacity of New Zealand is made up of the two Motunui facilities and the Waitara Valley facility. The Waitara Valley facility is idled indefinitely due to natural gas constraints.(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 and Tobago section below.)

United States

Our Geismar plants in Louisiana produced 2.1 million tonnes of methanol in 2023, compared with 2.0 million in 2022. Production at the Geismar site was higher in 2023 due an unplanned outage in late 2022 as the utilities supplier for the Geismar site experienced a loss of power due to a failed transformer. Refer to the Risk Factors and Risk Management – United States section on page 28 for more information.

New Zealand

In New Zealand, we produced 1.4 million tonnes of methanol in 2023 compared with 1.2 million tonnes in 2022. Production for 2023 was higher than 2022 due to higher gas deliveries in 2023. We operate the two Motunui plants in New Zealand with our smaller Waitara Valley plant idled indefinitely since the beginning of 2021 due to natural gas constraints.

We estimate production for 2024 to be between 1.0 - 1.1 million tonnes. 2024 natural gas supply is expected to be impacted by a combination of our suppliers' planned natural gas infrastructure maintenance outages as well as lower than expected output from existing wells. While upstream investment has been made by our gas suppliers in New Zealand over the past two years, recent gas production results have been lower than originally expected which has contributed to the revised forecast for lower production in 2024 as compared to 2023. Refer to the Risk Factors and Risk Management – New Zealand section on page 28 for more information.

Trinidad and Tobago

We operate our fully-owned Titan facility, which is currently idled, and the Atlas facility, in which we have a 63.1% economic interest and marketing rights for 100% of the production. Together, the two facilities represent 2.0 million tonnes of annual operating capacity. The Atlas facility produced 1.1 million tonnes of methanol (Methanex share) in 2023, compared with 1.0 million tonnes in 2022. Production in Trinidad was higher in 2023 due to unplanned outages in the fourth quarter of 2022. In October, Methanex signed a two-year natural gas supply agreement with the National Gas Company of Trinidad and Tobago (NGC) for its currently idled, wholly owned, Titan methanol plant (875,000 tonnes per year capacity) to restart operations in September 2024. Simultaneously, the Atlas plant (Methanex interest 63.1% or 1,085,000 tonnes per year capacity) will be idled in September 2024, when its legacy 20-year natural gas supply agreement expires. Refer to the Risk Factors and Risk Management – Trinidad and Tobago section on page 28 for more information.

Chile

The Chile facilities produced 1.0 million tonnes of methanol in 2023 compared with 0.9 million tonnes in 2022. Production in Chile was higher in 2023 due to higher gas availability from Argentina. Both plants are expected to run at full rates from the end of September 2023 through April 2024, the Southern hemisphere summer months. We estimate production for 2024 will be between 1.1 - 1.2 million tonnes. This production is underpinned by year-round natural gas supply from Chile for about 30 – 35% of our requirements with the remaining 65 – 70% from Argentina during the non-winter period allowing us to operate both plants at full rates. Natural gas development and related infrastructure investments in Argentina continue to progress and we are working with our Argentine natural gas suppliers on extending the period of full gas availability to our plants. Refer to the Risk Factors and Risk Management – Chile section on page 28 for more information.

Egypt

We operate the 1.3 million tonne per year methanol facility in Egypt, in which we have a 50% economic interest and marketing rights for 100% of the production. We produced 1.0 million tonnes of methanol (Methanex share of 0.5 million) in Egypt in 2023 compared to 0.8 million tonnes (Methanex share of 0.4 million) in 2022. We had lower levels of production from Egypt in 2022 as we completed an extended planned turnaround. 2023 production in Egypt was impacted by an unplanned outage in mid-October caused by a mechanical failure in the synthesis gas compressor. The unit was removed from service and repaired on an expedited schedule at the manufacturer overseas. The repairs were completed and the plant restarted in February 2024. Refer to the Risk Factors and Risk Management – Egypt section on page 29 for more information.

Canada

Medicine Hat produced 0.5 million tonnes of methanol in 2023 compared with 0.6 million tonnes in 2022. Production was lower in 2023 compared to 2022 due to unplanned outages in 2023. Refer to the Risk Factors and Risk Management – Canada section on page 29 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, finance costs, finance income and other, and income taxes.

The Company has used the terms Adjusted net income, Adjusted net income per common share, and Adjusted EBITDA throughout this document. These items are non-GAAP measures and ratios 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 Non-GAAP Measures section on page 37 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures.

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.
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 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, 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, both of which we recognize as revenue on a gross basis. 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, respectively. For the purpose of analyzing our business, Adjusted EBITDA, Adjusted net income and Adjusted net income per common share include an amount representing our 63.1% equity share in Atlas. Our analysis of depreciation and amortization, finance costs, finance income and other, and income taxes is consistent with the presentation of our consolidated statements of income and excludes amounts related to Atlas.

We own 50% of the Egypt methanol facility and market the remaining 50% of its production through a commission offtake agreement. We own 60% of Waterfront Shipping, which provides service to Methanex for the ocean freight component of our distribution and logistics costs. We consolidate both Egypt and Waterfront Shipping, which results in 100% of the financial results being included in our financial statements. 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 Waterfront Shipping. For the purpose of analyzing our business, Adjusted EBITDA, Adjusted net income and Adjusted net income per common share exclude the amounts associated with non-controlling interests.

FINANCIAL RESULTS

For the year ended December 31, 2023, we reported a net income attributable to Methanex shareholders of $174 million ($2.57 net income per common share on a diluted basis), compared with a net income attributable to Methanex shareholders of $354 million ($4.86 net income per common share on a diluted basis) for the year ended December 31, 2022. Net income attributable to Methanex shareholders for the year ended December 31, 2023 is lower compared to the year ended December 31, 2022, primarily due to a lower average realized price and the non-recurring Egypt gas redirection and sale proceeds which occurred in 2022, partially offset by higher sales of Methanex-produced methanol and proceeds from a gas contract settlement that occurred in 2023.

For the year ended December 31, 2023, we reported Adjusted EBITDA of $622 million and Adjusted net income of $153 million ($2.25 Adjusted net income per common share), compared with Adjusted EBITDA of $932 million and Adjusted net income of $343 million ($4.79 Adjusted net income per common share) for the year ended December 31, 2022.

We calculate Adjusted EBITDA and Adjusted net income 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, the impact of the Egypt gas contract revaluation included in finance income and other and the impact of certain items associated with specific identified events. For 2023, the settlement of a historical dispute under an existing gas contract was excluded from Adjusted EBITDA and Adjusted net income due to the one-time nature of the settlement and to better reflect the operating performance of the Company's business. For 2022, there were no specifically identified events impacting Adjusted EBITDA or Adjusted net income.

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

($ Millions, except number of shares and per share amounts)	2023		2022
Net income attributable to Methanex shareholders	$	174	$	354
Mark-to-market impact of share-based compensation, net of tax	13		(6)
Gas contract settlement, net of tax	(31)		—
Impact of Egypt gas contract revaluation, net of tax	(3)		(5)
Adjusted net income	$	153	$	343
Diluted weighted average shares outstanding (millions)	68		72
Adjusted net income per common share	$	2.25	$	4.79

A summary of our consolidated statements of income for 2023 and 2022 is as follows:

($ Millions)	2023		2022
Consolidated statements of income:
Revenue	$	3,723	$	4,311
Cost of sales and operating expenses	(3,068)		(3,446)
Egypt gas redirection and sale proceeds	—		118
Mark-to-market impact of share-based compensation	16		(7)
Adjusted EBITDA attributable to associate	135		151
Amounts excluded from Adjusted EBITDA attributable to non-controlling interests	(184)		(195)
Adjusted EBITDA	622		932
Mark-to-market impact of share-based compensation	(16)		7
Depreciation and amortization	(392)		(372)
Gas contract settlement, net of tax	31		—
Finance costs	(117)		(131)
Finance income and other	40		25
Income tax expense	(1)		(120)
Earnings of associate adjustment 1	(67)		(74)
Non-controlling interests adjustment 1	74		87
Net income attributable to Methanex shareholders	$	174	$	354
Net income	$	284	$	462

1     These adjustments represent depreciation and amortization, finance costs, finance income and other 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. The methanol business is a global commodity industry affected by supply and demand fundamentals. Based on the diversity of end products in which methanol is used, demand for methanol is driven by a number of factors, including: strength of global and regional economies, industrial production levels, energy prices, pricing of end products and government regulations and policies. Revenue was $3.7 billion in 2023 compared to $4.3 billion in 2022. The lower revenue reflects a lower average realized price, partially offset by higher sales volume in 2023 compared to 2022.

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 2023 was $434 per tonne compared with $503 per tonne in 2022. Our average realized price in 2023 was $333 per tonne compared to $397 per tonne in 2022.

Distribution of Revenue

The geographic distribution of revenue by customer location for 2023 was comparable to 2022. Details are as follows:

($ Millions, except where noted)	2023			2022
China	$	1,043	28%	$	1,106	26%
Europe	722		19%	830		19%
United States	575		15%	657		15%
South America	429		12%	459		11%
South Korea	392		11%	543		13%
Other Asia	387		10%	519		12%
Canada	175		5%	197		4%
	$	3,723	100%	$	4,311	100%

Adjusted EBITDA (Attributable to Methanex Shareholders)

2023 Adjusted EBITDA was $622 million compared with 2022 Adjusted EBITDA of $932 million, a decrease of $310 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)	2023 vs. 2022
Average realized price	$	(657)
Sales volume	16
Total cash costs	331
Decrease in Adjusted EBITDA	$	(310)

Average Realized Price

Our average realized price for the year ended December 31, 2023, was $333 per tonne compared to $397 per tonne for 2022, and this decreased Adjusted EBITDA by $657 million (refer to the Financial Results – Revenue section on page 13 for more information).

Sales Volume

Methanol sales volume, excluding commission sales volume, for the year ended December 31, 2023, increased to 10.0 million tonnes from 9.8 million tonnes in 2022, and this increased Adjusted EBITDA by $16 million. Including commission sales volume from the Atlas and Egypt facilities, our total methanol sales volume was 11.2 million tonnes in 2023 compared with 10.8 million tonnes in 2022. Sales volume may vary year to year depending on customer requirements and inventory levels as well as the available commission sales volume.

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 in major global markets.

We apply 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.

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 2023 compared with 2022 were due to the following:

($ Millions)	2023 vs. 2022
Methanex-produced methanol costs	$	199
Proportion of Methanex-produced methanol sales	18
Purchased methanol costs	207
Logistics costs	(18)
Egypt gas redirection and sale proceeds	(58)
Other, net	(17)
Increase in Adjusted EBITDA due to changes in total cash costs	$	331

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. Through 2023, we purchased 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 methanol price to reduce our commodity price risk exposure. The variable price component of each gas contract is adjusted by a formula linked to methanol sales prices above a certain level. We also purchase natural gas in North America and are exposed to natural gas spot price fluctuations for the unhedged portion of our gas needs in the region. Methanex-produced methanol costs were lower in 2023 compared with 2022 by $199 million, primarily due to the impact of changes in realized methanol prices on the variable portion of our natural gas cost, changes in spot gas prices which impact the unhedged portion of our North American operations, timing of inventory flows 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 21.

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, while a decrease in the proportion of Methanex-produced methanol will increase our cost structure. The proportion of Methanex-produced methanol sales increased in 2023 due to higher production and this decreased costs and increased Adjusted EBITDA by $18 million for 2023 compared with 2022.

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. Lower methanol prices in 2023 and the timing of inventory flows and purchases decreased the cost of purchased methanol per tonne and this increased Adjusted EBITDA by $207 million compared with 2022.

Logistics Costs

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 methanol supply. Additionally we carry third-party backhaul cargoes, when available, to optimize supply chain costs overall. Logistics costs can also vary from period to period primarily depending on the levels of production from each of our production facilities, the resulting impact on our supply chain, and variability in bunker fuel costs. Higher logistics costs in 2023 decreased Adjusted EBITDA by $18 million compared to 2022. Logistics costs increased in 2023 compared to 2022 primarily due to the mix of production from various plants and the impact of longer supply routes, with the outage in Egypt and preparation for Geismar 3 causing increased costs in the fourth quarter of 2023.

Egypt Gas Redirection and Sale Proceeds

In the third quarter of 2022, we entered into an agreement to redirect and sell the Egypt plant's contracted natural gas during an extended turnaround for a three-month period. Adjusted EBITDA for the year ended December 31, 2022 includes $58 million (attributable to Methanex) from this transaction which did not recur in 2023.

Other, Net

Other, net relates to unabsorbed fixed costs, selling, general and administrative expenses and other operational items. For the year ended December 31, 2023 compared with the same period in 2022, other costs were higher by $17 million mainly due to the organization build-up of costs relating to the start-up of Geismar 3 plant.

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 fair value of the share-based awards primarily driven by the Company’s share price. The grant date value amount is included in Adjusted EBITDA and Adjusted net income. 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 and is analyzed separately.

($ Millions, except share price)	2023		2022
Methanex Corporation share price 1	$	47.36	$	37.86
Grant date fair value expense included in Adjusted EBITDA and Adjusted net income	19		22
Mark-to-market impact 2	16		(7)
Total share-based compensation expense, before tax	$	35	$	15

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.

2 For the periods presented, the mark-to-market impact on share-based compensation is primarily due to changes in the Methanex Corporation share price.

For stock options, the cost is measured based on an estimate of the fair value at the grant date 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 to fair value.

Share appreciation rights ("SARs") are non-dilutive 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 grant date. Tandem share appreciation rights ("TSARs") give the holder the choice between exercising a regular stock option or a SAR. The fair value 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 granted annually reflect a long-term incentive plan where units are redeemable for cash based on the market value of the Company's common shares and are non-dilutive to shareholders. Units vest over three years and include two performance factors: (i) relative total shareholder return of Methanex shares versus a specific market index, and (ii) the three-year average return on capital employed. The relative total shareholder performance factor is measured by the Company at the grant date and each reporting date using a Monte-Carlo simulation model to determine fair value. The three-year average return on capital employed performance factor reflects the actual return on capital employed for historical periods and management's best estimate for forecast periods to determine the expected number of units to 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.

The price of the Company’s common shares as quoted on the NASDAQ Global Select Market Composite increased from $37.86 per share at December 31, 2022, to $47.36 per share at December 31, 2023. 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 $16 million mark-to-market expense related to share-based compensation during 2023.

Depreciation and Amortization

Depreciation and amortization was $392 million for the year ended December 31, 2023, and is higher than $372 million for the year ended December, 31 2022 due to the higher cost base of depreciable property, plant and equipment driven by additional capitalized maintenance costs and ocean going vessel additions.

Finance Costs

($ Millions)	2023		2022
Finance costs before capitalized interest	$	173	$	167
Less capitalized interest	(55)		(36)
Finance costs	$	117	$	131

Finance costs are primarily comprised of interest on borrowings and lease obligations and were $117 million for the year ended December 31, 2023, compared to $131 million for the year ended December 31, 2022. Finance costs are lower primarily due to higher capitalized interest. Capitalized interest relates to interest costs capitalized for the Geismar 3 project. Refer to the Liquidity and Capital Resources section of page 18 for more information.

Finance Income and Other

Finance income and other were $40 million for the year ended December 31, 2023, compared to $25 million for the year ended December 31, 2022. Finance income and other were higher during the year ended December 31, 2023 compared to the same period in 2022 primarily due to higher interest income.

Income Taxes

A summary of our income taxes for 2023 compared with 2022 is as follows:

($ Millions, except where noted)	2023				2022
	Per consolidated statement of income		Adjusted 1 2 3 4		Per consolidated statement of income		Adjusted 1 2 3 4
Net income before income tax	$	286	$	199	$	582	$	482
Income tax expense	(2)		(46)		(120)		(139)
Net income after income tax	$	284	$	153	$	462	$	343
Effective tax rate	1%		23%		21%		29%

1 Adjusted net income before income tax reflects amounts required for the inclusion of 63.1% of Atlas income, 50% of Egypt and 60% of Waterfront Shipping, as well as amounts required to exclude the mark-to-market impact of share-based-compensation expense or recovery, the impact of the Egypt gas contract revaluation, and the impact of the settlement of a historical dispute under an existing gas contract. The most directly comparable measure in the financial statements is net income before tax.

2 Adjusted income tax expense reflects amounts required for the inclusion of 63.1% of Atlas income, 50% of Egypt and 60% of Waterfront Shipping, as well as amounts required to exclude the tax impact of mark-to-market impact of share-based-compensation expense or recovery, the impact of the Egypt gas contract revaluation, and the impact of the settlement of a historical dispute under an existing gas contract calculated at the appropriate applicable tax rate for their respective jurisdictions. The most directly comparable measure in the financial statements is income tax expense.

3 Adjusted effective tax rate is a non-GAAP ratio and is calculated as adjusted income tax expense or recovery, divided by adjusted net income before tax.

4 Adjusted net income before income tax and Adjusted income tax (expense) recovery are non-GAAP measures. Adjusted effective tax rate is a non-GAAP ratio. These do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Management uses these to assess the effective tax rate. These measures and ratios are useful as they are a better measure of our underlying tax rate across the jurisdictions in which we operate.

We earn the majority of our income in the United States, New Zealand, Trinidad and Tobago, Chile, Egypt and Canada. Including applicable withholding taxes, the statutory tax rate applicable to Methanex in the United States is 23%, New Zealand is 28%, Trinidad and Tobago is 38%, Chile is 35%, Egypt is 30% and Canada is 24.5%. We accrue for taxes that will be incurred upon distributions from our subsidiaries when it is probable that the earnings will be repatriated. 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.

The effective tax rate based on Adjusted net income was an expense of 23% for the year ended December 31, 2023, compared to 29% for the year ended December 31, 2022. Adjusted net income 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 (losses) and the impact of foreign exchange fluctuations against the United States dollar on our tax balances. In periods with low income levels or losses, 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.

The following table shows a reconciliation of Net income to Adjusted net income before tax, and of Income tax expense to Adjusted income tax expense:

($ Millions, except where noted)	2023		2022
Net income	$	284	$	462
Adjusted for:
Income tax expense	1		120
Earnings from associate	(99)		(77)
Share of associate's income before tax	152		120
Net income before tax of non-controlling interests	(103)		(130)
Mark-to-market impact of share-based compensation	16		(7)
Gas contract settlement	(47)		—
Impact of Egypt gas contract revaluation	(5)		(6)
Adjusted net income before tax	$	199	$	482
Income tax expense	$	(1)	$	(120)
Adjusted for:
Inclusion of our share of associate's adjusted tax expense	(37)		(43)
Removal of non-controlling interest's share of tax (recovery) expense	(7)		22
Tax (recovery) expense on mark-to-market impact of share-based compensation	(3)		1
Tax on impact of Egypt gas contract revaluation	2		1
Adjusted income tax expense	$	(46)	$	(139)

For additional information regarding income taxes, refer to note 16 of our 2023 consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

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

($ Millions)	2023		2022
Cash flows from/(used in) operating activities:
Cash flows from operating activities before changes in non-cash working capital	$	719	$	933
Changes in non-cash working capital related to operating activities	(59)		54
	660		987
Cash flows from/(used in) financing activities:
Payments for the repurchase of shares	(86)		(253)
Dividend payments to Methanex Corporation shareholders	(49)		(44)
Interest paid	(169)		(162)
Repayment of long-term debt and financing fees	(12)		(9)
Repayment of lease obligations	(118)		(106)
Distributions to non-controlling interests	(185)		(85)
Proceeds on issue of shares on exercise of stock options	1		1
Restricted cash for debt service accounts	(1)		(1)
Sale of partial interest in subsidiary	—		149
Changes in non-cash working capital relating to financing activities	69		2
	(551)		(508)
Cash flows from/(used in) investing activities:
Property, plant and equipment	(178)		(146)
Geismar plant under construction	(270)		(432)
Changes in non-cash working capital relating to investing activities	(60)		24
	(509)		(553)
Decrease in cash and cash equivalents	(400)		(74)
Cash and cash equivalents, end of year	$	458	$	858

Cash Flow Highlights

Cash Flows from Operating Activities

Cash flows from operating activities for the year ended December 31, 2023 were $660 million compared with $987 million for the year ended December 31, 2022. The decrease in cash flows from operating activities is primarily due to lower earnings and differences in non-cash working capital changes, offset by lower tax payments and higher dividends received from the Atlas joint venture.

The following table provides a summary of these items for 2023 and 2022:

($ Millions)	2023		2022
Net income	$	284	$	462
Deduct earnings of associate	(99)		(77)
Add dividends received from associate	112		97
Add (deduct) non-cash items:
Depreciation and amortization	392		372
Income tax expense	1		120
Share-based compensation expense	35		15
Finance costs	117		131
Interest received	22		10
Income taxes paid	(82)		(164)
Other	(63)		(33)
Cash flows from operating activities before changes in non-cash working capital	719		933
Changes in non-cash working capital:
Trade and other receivables	(33)		38
Inventories	16		33
Prepaid expenses	(19)		(3)
Accounts payable and accrued liabilities	(23)		(14)
	(59)		54
Cash flows from operating activities	$	660	$	987

For a discussion of the changes in net income, depreciation and amortization, income tax expense, share-based compensation expense (recovery) and finance costs, refer to the Financial Results section on page 12.

Changes in non-cash working capital decreased cash flows from operating activities by $59 million for the year ended December 31, 2023, compared with an increase of $54 million for the year ended December 31, 2022. Trade and other receivables increased in 2023 and this decreased cash flows from operating activities by $33 million, primarily due to timing of invoices and payments by customers by the end of 2023 compared to 2022. Inventories decreased primarily due to the lower cost of production in the fourth quarter of 2023 compared to the fourth quarter of 2022 driven by the impact of lower methanol prices on our natural gas costs, which increased cash flows from operating activities by $16 million. Accounts payable and accrued liabilities decreased in 2023 compared to 2022 due to the impact of lower gas costs and lower methanol prices on purchased methanol at the end of 2023 compared to at the end of 2022, which decreased cash flows from operating activities by $23 million.

Cash Flows from Financing Activities

In 2023, we repurchased 1,894,711 common shares under a normal course issuer bid for approximately $86 million, compared to 5,551,751 common shares repurchased in 2022 for approximately $253 million.

Total dividend payments in 2023 were $49 million compared with $44 million in 2022 as a result of an increase in quarterly dividends in 2023. Our quarterly dividend was increased from $0.175 per share to $0.185 per share in April of 2023.

Total interest payments increased from $162 million in 2022 to $169 million in 2023 as a result of an increase in leases held in 2023. The Company has no debt maturities until December 2024, other than normal course obligations for principal repayments related to our other limited recourse debt facilities.

Distributions to non-controlling interests, including the 50% ownership of the Egypt entity and the 40% ownership of Waterfront Shipping not attributable to Methanex, were $185 million in 2023 compared to $85 million in 2022 and include amounts accrued but unpaid during 2023. The higher distributions to non-controlling interests for 2023 compared to 2022 were primarily due to the timing of distribution accruals and changes in earnings of Egypt and Waterfront Shipping.

In 2022, the Company completed the sale of a 40% equity interest in Waterfront Shipping Limited for cash proceeds of $145 million, excluding final purchase price adjustments.

Cash Flows from Investing Activities

During 2023, we incurred cash outflows on capital expenditures relating to our consolidated operations of $178 million (2022 - $146 million) primarily related to planned turnarounds in Geismar, New Zealand and Chile. The 2022 capital expenditures were primarily related to planned turnarounds in New Zealand and Egypt as well as refurbishment work in Chile. In addition, we incurred cash outflows on capital expenditures of $270 million (2022 - $432 million) related to the construction of the Geismar 3 project.

Liquidity and Capitalization

Our objective in 2023 in managing liquidity and capital was to provide financial capacity and flexibility to meet our strategic objectives, with a focus on cash preservation and liquidity. Our intent remains to repay rather than re-finance the $300 million bond due at the end of 2024 and under current market conditions and pricing levels we will be prioritizing excess cash towards this repayment.

The following table provides information on our liquidity and capitalization position as at December 31, 2023, and December 31, 2022:

($ Millions, except where noted)	2023		2022
Liquidity:
Cash and cash equivalents	$	458	$	858
Undrawn credit facility	300		300
Undrawn G3 construction facility	—		300
Total liquidity 1	$	758	$	1,458
Capitalization:
Unsecured notes, including current portion	1,986		1,983
Other limited recourse debt facilities, including current portion	156		168
Total debt	2,142		2,151
Non-controlling interests	242		317
Shareholders’ equity	1,931		2,112
Total capitalization	$	4,315	$	4,580
Total debt to capitalization 2	50%		47%
Net debt to capitalization 3	44%		35%

1     Total liquidity consists of cash and cash equivalents, as well as any undrawn amounts from facilities. Total liquidity is a non-GAAP capital management measure, see Non-GAAP Measures on page 37 for more information.

2     Defined as total debt (including other limited recourse debt facilities) divided by total capitalization.

3 Net debt to capitalization is defined as total debt (including other limited recourse debt facilities) less cash and cash equivalents divided by total capitalization less cash and cash equivalents. Net debt to capitalization is a non-GAAP capital management measure. See Non-GAAP Measures on page 37 for more information.

We manage our liquidity and capital structure in light of changes to economic conditions, the underlying risks inherent in our operations and the capital requirements for the business. Total liquidity is useful because it illustrates the extent to which management has immediate access to cash for operational and construction purposes, and is indicative of our flexibility should uses for these facilities immediately arise. Net debt to capitalization is useful because it illustrates the relative risk of our financing structure to potential lenders and investors. The strategies we have employed in managing our liquidity and capital structure 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.

We operate in a highly competitive commodity industry and believe that it is appropriate to maintain a strong balance sheet and maintain financial flexibility. As at December 31, 2023, we had a cash balance of $458 million, including $79 million of cash related to Egypt and $46 million of cash related to Waterfront Shipping entities consolidated on a 100% basis. 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.

As at December 31, 2023, we have access to a $300 million committed revolving credit facility expiring in July 2026. The facility is with a syndicate of highly rated financial institutions. During the year ended December 31, 2023, we cancelled the non-revolving construction facility for the Geismar 3 project. At the time of cancellation, the construction facility was undrawn.

We have covenant and default provisions under our long-term debt obligations and we also have certain covenants that could restrict access to our credit facilities. The covenants governing the unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding the Egypt entity and the Atlas joint venture 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 or equal to 2:1 calculated on a four-quarter trailing basis and a debt to capitalization ratio of less than or equal to 60%, both 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 credit facility is secured by certain assets of the Company, and also includes other customary covenants including restrictions on the incurrence of additional indebtedness.

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. 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.

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, 2023, management believes the Company was in compliance with all covenants related to its long-term debt obligations.

Capital Projects

The Geismar 3 project is a 1.8 million tonne methanol plant, in Geismar, Louisiana adjacent to our Geismar 1 and Geismar 2 plants with significant capital and operating cost advantages. We expect the plant to start up in 2024 with total capital costs expected to not significantly exceed the upper end of the capital cost guidance of $1.3 billion.

We have capitalized $1,205 million on the project, before capitalized interest and finance charges. Assuming a total capital cost of $1.3 billion, we estimate that as of December 31, 2023, there is approximately $110 million of remaining capital expenditure, including approximately $20 million of spending accrued in accounts payable, which is fully funded with cash on hand.

Geismar 3 is expected to significantly enhance our cash generation capability and help us meet our commitment to reduce our greenhouse gas emissions intensity.

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, 2023, is as follows:

($ Millions)	2024		2025-2026		2027-2028		After 2028		Total
Long-term debt repayments	$	315	$	27	$	731	$	1,085	$	2,158
Long-term debt interest obligations	111		194		148		322		775
Lease obligations	172		266		221		515		1,174
Repayments of other long-term liabilities	96		56		14		83		249
Natural gas and other	438		842		470		923		2,673
Other commitments	95		6		1		1		103
	$	1,227	$	1,391	$	1,585	$	2,929	$	7,132

Long-Term Debt Repayments and Long-Term Debt Interest Obligations

We have $300 million of unsecured notes that mature in December 2024, $700 million of unsecured notes that mature in 2027, $700 million of unsecured notes that mature in 2029, 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. For additional information, refer to note 8 of our 2023 consolidated financial statements.

Lease obligations

Lease obligations represent contractual payment dates and amounts for right-of-use assets recognized on balance sheet. The majority of lease obligations are for ocean-going vessels.

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 for our operating plants and Geismar 3 project. 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 Tobago, Egypt and certain contracts in Chile are take-or-pay contracts denominated in United States dollars and include base and variable price components to manage our commodity price risk exposure. The variable price component of each natural gas contract is adjusted by a formula linked to methanol prices. 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 representative of the minimum take-or-pay commitment.

We also have multi-year fixed price natural gas contracts and hedges to manage exposure to natural gas price risk and supply our production facilities in Geismar and Medicine Hat. We believe that the fixed price contracts, hedges and long-term natural gas dynamics in North America support the long-term operation of these facilities. In the above table, we have included natural gas commitments, not accounted for as financial instruments, in North America for Geismar and Medicine Hat at the contractual volume and fixed prices.

We have marketing rights for 100% of the production from our jointly owned Atlas and Egypt plants that results in purchase commitments of up to an additional 0.6 million tonnes per year of methanol offtake supply when Egypt operates at capacity and 0.6 million tonnes per year of methanol offtake supply for Atlas. The offtake commitment for Atlas for 2024 will be reduced to 0.4 million tonnes of supply due to the facility running only until September 2024, when the legacy gas supply agreement expires. As at December 31, 2023, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2024. 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.

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

Other Commitments

We have future minimum lease payments under leases relating primarily to vessel charter, terminal facilities, office space and equipment that are outside the scope of IFRS 16. For additional information, refer to note 22 of our 2023 consolidated financial statements.

Off-Balance Sheet Arrangements

As at December 31, 2023, 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 the 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

or accumulated other comprehensive income when the underlying hedged transaction is recognized in earnings or inventory. 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 Level 2 derivative financial instruments will fluctuate based on changes in commodity prices or foreign currency exchange rates and the fair value of Level 3 derivative financial instruments will fluctuate based on changes in the observable and unobservable valuation model inputs.

The following table shows the carrying value of each of our categories of financial assets and liabilities and the related balance sheet items as at December 31, 2023 and December 31, 2022:

($ Millions)	2023		2022
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	121	$	323
Fair value of Egypt gas supply contract derivative 2	20		11
Financial assets not measured at fair value:
Cash and cash equivalents	458		858
Trade and other receivables, excluding tax receivable	515		488
Restricted cash included in other assets	16		14
Total financial assets 3	$	1,130	$	1,694
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	92	$	8
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	672		656
Lease obligations, including current portion	872		870
Long-term debt, including current portion	2,142		2,152
Land mortgage	28		29
Total financial liabilities	$	3,806	$	3,715

1     Geismar 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 Egypt natural gas supply contract is measured at fair value using a Monte-Carlo model classified within Level 3 of the fair value hierarchy.

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

As at December 31, 2023, 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 were 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 and those using significant unobservable inputs classified as Level 3. The fair value of all of the Company's derivative contracts as presented in the consolidated statements of financial position are determined based on present values and the discount rates used are adjusted 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 in other comprehensive income as the forward element excluded from the hedging relationships. Once a commodity hedge settles, the amount realized during the period and not recognized immediately in the statement of income is reclassified from accumulated other comprehensive income (equity) to inventory and ultimately through cost of goods sold. Foreign currency hedges settled, are realized during the period directly to the statement of income reclassified from the statement of other comprehensive income.

The Company has entered into forward contracts designated as cash flow hedges to manage its exposure to changes in natural gas prices for Geismar. Natural gas is fungible across the Geismar plants.

The Company manages its foreign currency exposure to euro denominated sales by executing a number of forward contracts which it has designated as cash flow hedges for its highly probable forecast euro collections.

Related Party Transactions

We own 63.1% of the Atlas methanol facility and a contractual agreement with our partners establishes joint control which results in our accounting for Atlas as an equity investment. As our equity investee, Atlas is our most significant related party. Refer to note 23 to the 2023 consolidated financial statements for information on our related party 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 34, to be among the most important for understanding the issues that face our business and our approach to risk management. Our strategic risk management process drives the identification, measurement, prioritization and management of our principal strategic risks. The Audit, Finance and Risk Committee of the Board provides oversight to the Company's risk management process.

Methanol Market Fundamentals

Methanol Price

The methanol business is a highly competitive commodity industry and future methanol prices will ultimately depend on the strength of global demand and methanol industry supply but can also be impacted by other factors such as global trade disputes and government sanctions. Methanol demand and industry supply are driven by several factors as described below. Methanol prices have historically been, and are expected to continue to be, characterized by cyclicality. We are not able to predict future methanol prices, which are driven by several factors that are 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

Based on the diversity of end products in which methanol is used, demand for methanol is driven by a number of factors, including: the strength of global and regional economies, industrial production levels, energy prices, pricing of end products, downstream capacity additions and government regulations and policies. In addition, increasing focus on climate change and the timing and pace of the transition to a lower-carbon economy could impact the demand for methanol that is manufactured in a manner that produces GHG emissions. Changes in methanol demand based on availability of substitute products, consumer preference (including preference for low-or-zero-carbon emission products), government regulation, or other factors may have a significant negative effect on our results of operations and financial condition irrespective of energy prices or economic growth rates. We cannot provide assurance that methanol demand will not be negatively impacted and this could have an adverse effect on our results of operations and financial condition.

Energy Prices

Demand for energy-related applications, which represents over 30% of global methanol demand, includes several applications including methyl tertiary-butyl ether ("MTBE"), fuel applications (including vehicle fuel, marine fuel and other thermal applications), di-methyl ether and biodiesel. Demand into methanol-to-olefins ("MTO") represents over 15% of global methanol demand. MTO plants produce light olefins which have wide applications in packaging, textiles, plastic parts and automotive components.

Methanol is an alternative feedstock for the production of light olefins in the methanol-to-olefins application. MTO competes with olefins made from ethane, propane and naptha, which are typically derived from natural gas and oil-based feedstocks. The price of methanol relative to the price of ethane, propane and naptha can impact the competitiveness of methanol in this application. The price of olefins and downstream derivative products are also affected by their industry supply and demand fundamentals. In a low olefin product price environment, methanol could be a less competitive feedstock in the production of olefins, which could reduce demand for methanol or contribute to negative pressure on methanol prices.

Methanol can also be used to produce MTBE (an oxygenate blended into gasoline to improve air quality), blended directly with gasoline and used to produce di-methyl ether which 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, which could have an adverse effect on our results of operations and financial condition.

Global Economic Growth Rates

Traditional chemical demand, which represents approximately 50% of global 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 wide variety of industrial and consumer products. Over the long term, we believe that traditional chemical demand is influenced by the strength of global and regional economies and industrial production levels. Any slowdown in the global or regional economies, specifically manufacturing and industrial economies, can negatively impact demand for methanol and have a detrimental impact on methanol prices.

Methanol Supply

Methanol industry supply is impacted by the cost of production, methanol industry operating rates and new methanol industry capacity additions. Methanol is predominantly produced from natural gas and is also produced from coal, particularly in China. The cost of production is influenced by the availability and cost of raw materials, including coal and natural gas, freight costs, other operating and maintenance costs and government policies. An increase in economically competitive methanol supply, all else equal, can displace supply from higher cost producers and have a negative impact on methanol price. The industry has historically operated below stated capacity on a consistent basis, even in periods of high methanol prices, primarily due to shutdowns for planned or unplanned maintenance and feedstock shortages and/or uneconomical feedstock costs. Methanol industry supply can increase through improving operating rates of existing methanol plants. Methanol industry capacity can increase through the construction of new methanol plants, by restarting idle methanol plants, or by expanding or debottlenecking existing plants to increase their operating capacity. There is typically a span of four to six years to plan and construct a new world-scale methanol plant. Typical of most commodity chemicals, periods of high methanol prices encourage high-cost producers to operate at maximum rates and 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 market and deliver methanol cost-effectively and reliably to customers.

In 2023, approximately two to three million tonnes of new production capacity was added in China. In Iran, a new plant was commissioned at the end of 2023 but plant operating rates continue to be uncertain and challenged due to the impact of sanctions, plant technical issues and seasonal natural gas constraints. The methanol industry ran at similar rates in 2023 compared to 2022.

In North America, we expect our new 1.8 million tonne Geismar 3 facility, which will be our third plant in Louisiana, to reach commercial production in 2024. In Malaysia, a 1.8 million tonne plant is under construction with a scheduled start up in 2024. We expect to see increased supply from new capacities to be partially offset by rationalization of existing supply in the market in 2024. With the shut down of Atlas and the restart of Titan in September 2024 the overall production in Trinidad will be lower by approximately 1 million tonnes annually and we continue to monitor other factors that could further impact supply such as the announced gas diversion from methanol to LNG in Equatorial Guinea. In China, there are planned capacity additions over the near-to-medium term which we expect will be somewhat offset by the closure of some small-scale, inefficient and older plants. New capacity built in China is expected to be consumed domestically as China requires methanol imports to meet growing demand.

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

Macroeconomic Risks

Pandemic Risk

Should a pandemic arise, measures introduced in response by governments and health authorities could lead to greater uncertainty in our business, commodity industries, energy markets and the broader global economy. Pandemic responses could lead to substantial reduction in global manufacturing and general economic activity, which in turn leads to supply constraints and supply chain disruptions, impacting the supply-demand balance and inventory levels across many industries.

A pandemic may increase our exposure to, and the magnitude of, each of the risks identified, whether they be methanol specific, macroeconomic, financial, or operational. The magnitude of the impact will depend on future developments that cannot be predicted and therefore we cannot provide assurance that a deterioration in economic conditions related to a pandemic will not have an adverse impact on our results of operations and 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 also result in changes in capital markets. A deterioration in economic conditions could have a negative impact on supply or demand for methanol, our investments, diminish our ability to access existing or future credit, and it could increase the risk of defaults by customers, suppliers, insurers and other counterparties. Also, inflationary pressures associated with buoyant economic activity, supply chain challenges or geopolitical events such as war or international trade relations, could have a negative impact on our cost structure or access to feedstock or logistics services. Considering these potential impacts, we cannot provide assurance that a deterioration in economic conditions or inflationary pressures associated with buoyant economic activity will not have an adverse impact on our results of operations and financial condition.

Global Operations

Our operations and investments are primarily located in North America, New Zealand, Trinidad and Tobago, Egypt, Chile, Europe and Asia. We are subject to risks inherent in global operations which are more significant in certain jurisdictions, 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, social activism, 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, including lack of certainty with respect to foreign legal systems, corruption and other factors inconsistent with the rule of law. Many of the foregoing risks related to foreign operations may also exist for our domestic operations in North America. We are also subject to potential risks associated with geopolitical disputes including: (i) those between countries in which we operate, buy, sell or transport methanol, (ii) those that border such countries such as over rights to water flowing across political boundaries including the Nile river which supplies water to our Egypt plant, and (iii) significant geopolitical disputes including wars, such as the invasion of Ukraine by Russia or the Israel-Palestinian conflict where the globalized nature of our operations and the commodity we sell could be negatively impacted by the actions of multiple countries and stakeholders.

The Company is committed to doing business in accordance with all applicable laws and its code of business conduct, but there is a risk that it, its subsidiaries or affiliated entities or their respective officers, directors, employees or agents could act in violation of its codes and applicable laws. Any such violation could severely damage our reputation and could result in substantial civil and criminal fines or penalties. Such damage to our reputation and fines and penalties could materially affect the Company's business and have an adverse impact on our results of operations and financial condition.

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.

Global Trade

Methanol is a globally traded commodity produced at facilities located around the world. Trade in methanol is subject to duty in a number of jurisdictions. Methanol sold in certain markets from the countries in which we produce methanol is currently subject to import duties ranging from 0% to 6%. As well, there is currently an additional 25% duty on methanol imported from the US to China. Over the past number of years, methanol demand has grown faster in China compared to other markets. This growth has resulted in China currently representing approximately 60% of total methanol demand, which is supplied by both local and imported methanol. This concentration of industry demand creates a risk of market access from any production source as China may increase duties, restrict imports or take other measures to prevent or limit the import of methanol from a particular producing country. There can be no assurance that the countries where we produce methanol will continue to have access to all markets, including China, that 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.

Some producers and marketers of methanol 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"). Methanol produced in sanctioned countries may sell at a lower price to methanol produced in non-sanctioned countries creating competitive price pressure for the methanol we produce. 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.

Financial Risks

Taxation Risk

The Company is subject to taxes, duties, levies, governmental royalties and other government-imposed compliance costs in numerous jurisdictions. New taxes and/or increases to the rates at which these amounts are determined could have an adverse impact on our results of operations and financial condition.

We have organized our foreign operations in part based on certain assumptions about various tax laws (including capital gains, withholding taxes and transfer pricing), 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. The results of audit of prior tax filings and the final determination of these events may have a material impact on the Company. Refer to Litigation Risk and Legal Proceedings on page 33 for more information related to current legal matters. Further, if such foreign jurisdictions were to change or modify such laws, we could suffer adverse tax and financial consequences.

Liquidity Risk

As at December 31, 2023, we had a cash balance of $458 million, as well as an undrawn $300 million revolving credit facility with a syndicate of highly rated financial institutions expiring in July 2026. 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 are calculated in accordance with definitions in the credit agreement that include adjustments related to the Company's limited recourse subsidiaries.

As at December 31, 2023, our long-term debt obligations include $1,986 million in unsecured notes and $156 million related to other limited recourse debt for ocean-going vessels (100% basis).

The covenants governing the unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding the Egypt entity and the Atlas joint venture 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.

For additional information regarding long-term debt, refer to note 8 of our 2023 consolidated financial statements.

We cannot provide assurance that we will have sufficient liquidity to fund future capital projects without incurring additional debt. Additionally, we cannot provide assurance that we will be able to access capital in the future on commercially acceptable terms or at all, or that the financial institutions providing the credit facilities 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.

Foreign Currency Risk

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, the Chinese yuan and Korean won. 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 Chinese yuan, euros, Canadian dollars and, to a lesser extent, other currencies. 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.

Customer Credit Risk

Our customers are large global or regional petrochemical manufacturers or distributors and a number are highly leveraged, though we have not experienced significant credit losses in the past. 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.

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.

Operational Risks

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.

United States

We expect our new 1.8 million tonne Geismar 3 facility to reach commercial production in 2024. Subsequent to the start-up, we will have three plants in Geismar, Louisiana with an annual operating capacity of 4.0 million tonnes.

We utilize a combination of fixed price financial hedges and fixed price physical gas supply agreements to manage natural gas price risk for our Geismar facilities. In North America, we have fixed price gas supply contracts and hedges in place targeting minimum operating rate requirements of approximately 70% in the near-term, declining over time. The balance of our gas requirements are purchased at spot prices.

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.

New Zealand

We have three plants in New Zealand with a total operating capacity of 2.2 million tonnes of methanol per year. Two plants are located at Motunui and can produce 1.7 million tonnes per year and the third is located at nearby Waitara Valley and can produce 0.5 million tonnes. The Waitara Valley Plant was idled indefinitely in the first quarter of 2021 due to a lack of available gas supply. We have entered into several agreements with various natural gas suppliers with terms that range in length up to 2029. All gas supply 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 linked 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. Certain 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.

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 exploration and development activities in New Zealand will be successful to enable us to operate at capacity or at all. We cannot provide assurance that we will be able to secure additional natural gas on commercially acceptable terms. These factors could have an adverse impact on our results of operations and financial condition.

Trinidad and Tobago

We have two plants in Trinidad and Tobago, Atlas (Methanex interest 63.1%) and Titan, with Methanex's interest in Trinidad and Tobago representing an operating capacity of 2.0 million tonnes per year. Natural gas for our Atlas methanol production facility in Trinidad and Tobago, with our share of total production capacity being 1.1 million tonnes per year, is supplied under a take-or-pay contract with the National Gas Company of Trinidad and Tobago Limited ("NGC"), which purchases the natural gas from upstream gas producers. The contract for Atlas has a U.S. dollar base and variable price components, where the variable portion is adjusted by a formula linked to methanol prices above a certain level and expires in September 2024.

In October 2023, Methanex signed a two-year natural gas agreement with NGC for its Titan plant, which has been idled since the first quarter of 2020, to restart operations in September 2024. The natural gas agreement for Titan is a take-or-pay contract with a U.S. dollar base and variable price components, where the variable portion is adjusted by a formula linked to methanol prices. Simultaneously, the Company plans to idle Atlas in September 2024, when its legacy 20-year natural gas agreement expires.

We cannot provide assurance that our contracted supplier will be able to meet their commitments, that we will be able to secure additional natural gas on commercially acceptable terms or that exploration and development activities in Trinidad and Tobago will be successful to enable us to operate at capacity or at all. These factors could have an adverse impact on our results of operations and financial condition.

Chile

Natural gas for our two plants in Chile is supplied by various producers in Chile and Argentina. A portion of the contracted gas is subject to deliver-or-pay and take-or-pay provisions. Our current gas agreements and gas export permits from Argentina provide for sufficient gas to allow for a two-plant operation in Chile during the Southern hemisphere summer months. In 2023, one plant operated throughout the year and a second plant operated for seven months.

Our primary Chilean natural gas supplier is Empresa Nacional del Petróleo ("ENAP"). ENAP has made significant investments over the past several years in the development of natural gas from unconventional reservoirs, which has resulted in stable gas deliveries from ENAP to our facilities. The agreements for natural gas supply with ENAP underpin approximately 25% of the 1.7 million tonnes of annual operating capacity for 2023 through 2025.

In 2023, we received natural gas from Argentina from four different natural gas suppliers pursuant to firm supply agreements from September through December 2023. We also received Argentine natural gas in 2023 from a fifth supplier, YPF S.A., from January until

April 2023 and from October through December 2023. We have a gas supply agreement with YPF S.A. that expires at the end of 2025. The price paid for natural gas for our Chilean facilities from our Chilean and Argentine suppliers is a U.S. dollar base price plus a variable price component that is adjusted by a formula linked to methanol prices above a certain level.

While we continue to work with gas suppliers in Chile and Argentina to secure sufficient natural gas to sustain our Chile operations, we cannot provide assurance that our contracted suppliers will be able to meet their commitments, that we will be able to secure additional natural gas on commercially acceptable terms, that Argentina will grant future export permits for natural gas to be delivered to Chile or that exploration and development activities in Chile and Argentina will be successful to enable us to operate at capacity or at all. These factors could have an adverse impact on our results of operations or financial condition.

Egypt

We have a 25-year, take-or-pay natural gas supply agreement expiring in 2035 for the 1.3 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 linked 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. 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.

Our Egypt facility has experienced gas restrictions in the past during periods of significant social unrest and government transition and we believe this contributed to past constraints in the development of natural gas reserves. More recently, domestic gas needs in periods of extreme weather have also contributed to potential gas shortage. The restrictions experienced in past years may occur in the future. We cannot provide assurance that our contracted supplier will be able to meet its commitments or that exploration and development activities in Egypt will be successful to enable us to operate at capacity or at all. These factors could have an adverse impact on our results of operations and financial condition.

Canada

We have entered into fixed price contracts to supply 80-90% of our natural gas requirements for our Medicine Hat facility through 2031. The balance of our gas requirements is purchased under contracts at spot prices.

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 for our Medicine Hat facility on commercially acceptable terms and this could have an adverse impact on our results of operations and financial condition.

Production Risks

Most of our earnings are derived from the sale of methanol produced at our plants. Many of our methanol plants have been in operation for multiple decades and with appropriate maintenance they are still capable of operating efficiently and cost-effectively today. Our business is subject to the risks of operating methanol production facilities, such as a process safety event, equipment breakdowns, interruptions in the supply of natural gas and other feedstocks, including oxygen and utilities such as water and steam, 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 produce and 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.

Capital Projects

Our ability to effectively allocate capital, including successfully identifying, developing, and completing 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 startup of large complex industrial projects. Further risks include the impact of evolving government regulation relating to carbon intensive industries and evaluating the technological feasibility and anticipated operation of new plant designs such as those with lower carbon intensity.

We cannot provide assurance that we will be able to effectively allocate capital to identify or develop methanol projects or that any changes to the targeted timing of completion or estimated cost or ability to complete capital projects or future ability to operate at production capacity, due to a number of factors, which could have an adverse impact on our results of operations and financial condition.

Technological Risks

New technologies for natural-gas-based methanol production have been primarily incremental rather than transformational. Alternative feedstocks and methods for methanol production, including producing methanol from renewable resources exist today, but are not currently economically competitive at scale. The adoption of new technologies for methanol production or methanol derivatives, including those that reduce the GHG emissions intensity, may make our plants less competitive or obsolete over time. In addition, implementing technologies to reduce GHG emissions, including carbon capture and storage, could result in significant capital expenditures.

As a result, we cannot provide assurance that new technologies in methanol production will not have an adverse effect on our results of operations and financial condition.

Joint Arrangement Risk

Certain Methanex assets are jointly held and are governed by partnership and shareholder agreements. As a result, certain decisions regarding these assets require a simple majority, while others require 100 percent approval of the owners. In addition, certain of these assets (ocean-going vessels) are operated by unrelated third-party entities. The operating results of these assets is to some extent dependent on the effectiveness of the business relationship and decision making among Methanex and the other joint owner(s) and the expertise and ability of these third-party operators to successfully operate and maintain the assets. While Methanex believes that there are prudent governance and contractual rights in place, there can be no assurance that Methanex will not encounter disputes with partners. Such events could impact operations or cash flows of these assets which, in turn, 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.

Supply Chain Risks

Our production is transported through various pipelines, terminals, marine, rail and road networks making up our integrated supply chain. These networks, and ultimately our supply chain, may be interrupted by means outside of our control or have operational constraints or restrictions that could prohibit the safe and timely transportation and distribution of methanol to our customers and prolonged disruptions could have an adverse effect on our results of operations, financial condition and leadership position.

Shipping Capacity 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.

Talent Attraction and Retention Risks

The safe and reliable operation of our methanol plants, logistics and supporting functions rely on a skilled and experienced workforce. We compete for skilled employees in various locations globally where labour market conditions can be highly competitive. If we are unable to attract, develop, and retain a skilled and experienced workforce or effectively manage succession in key roles, this may be an impediment to the operations of our methanol plants, the optimization of logistics and impact our daily operations which could have an adverse impact on our results of operations and financial condition.

Cybersecurity Risks

Our business processes rely on Information Technology ("IT") systems that are interconnected with external networks and increasingly hosted by third parties in the cloud. The interconnection of external networks increases the threat of cyberattack and the importance of cybersecurity. In particular, if a cyberattack was targeted at our production facilities, our supply chain or other key infrastructure networks, the result could harm our plants, customers, environment, 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, including attempts to divert financial assets or introduce ransomware to extract

payment 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 in place to protect our assets, detect malicious activity and respond in the event of a cybersecurity incident. This includes: cyber education for our staff; risk-prioritized controls to protect against known and emerging threats; segregating core operating systems from our corporate systems; tools to provide automated monitoring and alerting; incident response planning and testing to ensure an agile response and backup and recovery procedures 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 cyberattacks. The Audit, Finance and Risk Committee is responsible for overseeing our cybersecurity mitigation efforts and the program is reviewed periodically by an independent third party.

As the cyberthreat landscape continues to evolve, we pivot to adjust or add to our existing controls to protect the organization. We collect, use and store sensitive data in the normal course of business, including intellectual property, proprietary business information and personal information of our employees and third parties. Despite our security measures in place, our IT systems may be vulnerable to cyberattacks 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 our reputation, which could have an adverse impact 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, GHG emissions, employment, health or safety, or process safety matters), whether true or not. There is a risk of increasing stakeholder expectations around climate change and transition to a lower-carbon economy. Further risks arise from these changing stakeholder perceptions related to the way in which we are viewed as contributing to (or hindering) a transition to a low-carbon economy and responding to climate change. In March 2024, we issued our 2023 Sustainability Report, aligned with the Sustainability Accounting Standards Board (SASB) and the Task-Force on Climate-related Financial Disclosures (TCFD). Our 2023 Sustainability Report is available at https://www.methanex.com/sustainability. Our reputation could be impacted by evolving perceptions of carbon-intensive industries, petrochemical industries and, most specifically, the methanol industry and its associated downstream derivatives. 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 access to capital and insurance coverage, decreased investor confidence, challenges with employee retention and talent attraction, an impediment to our overall ability to advance our projects, difficulty in obtaining permits, or increased challenges in maintaining our social license to operate, which could have an adverse impact on our results of operations and financial condition.

Climate Related Risks

Transition Risks - Regulatory

GHG Legislation

We generate GHG emissions, primarily as carbon dioxide ("CO2"), directly and indirectly through the production, distribution and use of its products. GHG emissions are a byproduct of the development and extraction of hydrocarbons, including natural gas used as a feedstock in methanol production, as well as the methanol production process. GHG emissions are also generated when fuel is consumed during the global transport of methanol. The GHG Protocol Corporate Standard classifies a company’s GHG emissions into three ‘scopes’. Scope 1 emissions are direct emissions from owned or controlled sources. Scope 2 emissions are indirect emissions from the generation of purchased energy. Scope 3 emissions are all indirect emissions (not included in Scope 2) that occur in the value chain, including both upstream and downstream emissions.

We monitor and manage our GHG emissions intensity for Scope 1 and Scope 2 emissions, defined as the equivalent quantity of CO2 released per unit of production or transported tonne, relating to both methanol equity production and our owned marine operations. The amount of GHG emissions generated by the methanol production process is highly dependent on a number of factors including the design of the methanol plant, plant reliability and availability of natural gas. Similarly, the distance of trade routes for transported cargo, as well as ship technology and operating efficiency, influence the emissions intensity of our marine operations. Accordingly, GHG emissions may vary from year to year depending on the mix of production assets and vessels in operation.

Public attitudes around climate change and the transition to a lower-carbon economy continue to evolve. Under the Paris Agreement within the United Nations Framework Convention on Climate Change, many of the countries we operate in have agreed to put forth substantial efforts and commitments to reduce GHG emissions that they are implementing through GHG regulations that include

carbon prices. We are currently subject to GHG regulations in New Zealand, Canada and Chile, while our production in the United States, Trinidad and Tobago, and Egypt is currently not subject to such regulations. These regulations result in additional costs to produce methanol. Many of our competitors produce methanol in countries with no imposed GHG regulations or carbon taxes and as such, further increases in regulations or carbon taxes in the countries in which we operate may negatively impact our competitive position within the methanol industry. In addition, as of January 2024, Waterfront Shipping is subject to the EU’s Emissions Trading System (ETS) for fifty percent of emissions from voyages where the point of origin or the point of destination is within the EU and 100 percent of emissions that occur for voyages between two EU ports and when ships are within EU ports. EU ETS emissions allowances will need to be purchased and surrendered for 40 percent of reported CO2 emissions in 2024, 70 percent in 2025 and 100 percent in 2027. There are ongoing reviews and potential changes to government GHG regulations in countries where we have operations or conduct business, including potential carbon border adjustment mechanisms that could impact the efficient management of our global supply chain.

We cannot provide assurance that changes in existing or the introduction of new GHG regulations, carbon taxes, or other initiatives related to climate change in jurisdictions where we have operations or conduct business will not have an adverse impact on our results of operations and financial condition.

Marine Demand

Europe and the International Maritime Organization (IMO) have moved to measuring GHG emissions impact of marine fuels to on a lifecycle basis, which includes upstream feedstock production. They have also set decarbonization targets that require decreasing emissions intensity over time, which come into effect in 2025 and 2027, respectively. Low-carbon methanol is one of several potential fuels that could be used to comply with these regulations. We cannot provide assurance that low-carbon methanol will be the preferred fuel for demand under shipping or clean fuel regulations.

Physical Impacts

Climate change poses a number of potential risks and impacts to Methanex that may increase over time. The prospective impact of climate change may have an adverse impact on our operations, our suppliers or customers. The physical impacts of climate change may include water scarcity, changing sea or river levels, changing storm patterns and intensities, and changing temperature levels, and the impact of any of these changes could be severe.

The New Zealand, Geismar, Medicine Hat and Egypt facilities rely on access to fresh water in the methanol production process. Potential shortages or constraints in fresh water supply could impact methanol production at these sites and may impact considerations of future growth locations. Our other two sites, Trinidad and Chile, rely on ocean water and have equipment to desalinate water for the methanol production process.

Our transport of methanol relies primarily on vessels to ship methanol from our production sites to customers around the world. We have, at times, experienced logistics delays in our supply chain due to high and low river or canal levels in exporting methanol from a production site or delivering methanol by vessel or barge to customers. High or low river levels impacting our production assets and supply chain, more severe and frequent storms and weather events could have a material adverse impact on our operating capacity and supply chain. We cannot predict, at this time, the prospective impact of climate change on our operations, suppliers or customers, which could have an adverse impact on our results of operations and financial condition.

Regulatory and Compliance Risks

Environmental Regulation

The countries in which we operate and international and jurisdictional waters in which our vessels operate have laws, regulations, treaties and conventions in force 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 with respect to protecting the environment have become more stringent over time 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.

Although we have formal and proactive compliance management systems in place, 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.

Government Regulations and Policies – Methanol

Changes in environmental, health and safety laws, regulations or requirements in any country where methanol is produced or consumed could impact methanol demand. Methanol is subject to the chemical control laws of the countries in which they are located. These laws include the regulation of chemical substances and inventories under the Toxic Substances Control Act (“TSCA”) in the U.S. and the Registration, Evaluation and Authorization of Chemicals (“REACH”) and the Classification, Labeling and Packaging of substances and mixtures (“CLP”) regulations in Europe.

Above certain inhalation and ingestion levels, methanol is toxic to humans. In past years, the United States Environmental Protection Agency ("EPA") had assessed methanol for carcinogenicity and issued levels of maximum ingestion and inhalation that it claims will not result in adverse health impacts. While methanol is not currently on the priority list of chemicals to be evaluated under the Toxic Substances Control Act, we are unable to determine whether the current classifications relating to the carcinogenicity of methanol will be maintained or if other government agencies will take actions related to methanol. Any further action or reclassification of methanol could reduce future methanol demand, which could have an adverse effect on our results of operations and financial condition.

Government Regulations and Policies – Methanol-Derived Products

Similar to methanol, methanol-derived chemical products are subject to the chemical control laws of the countries in which they are located. These laws include the regulation of chemical substances and inventories under the Toxic Substances Control Act (“TSCA”) in the U.S. and the Registration, Evaluation and Authorization of Chemicals (“REACH”) and the Classification, Labeling and Packaging of substances and mixtures (“CLP”) regulations in Europe. Analogous regimes exist in other parts of the world, including China, South Korea, and Taiwan. In addition, a number of countries where our customers operate, including the U.K., have adopted rules to conform chemical labeling in accordance with the globally harmonized system. Many of these foreign regulatory regimes are in the process of a multi-year implementation period for these rules.

In the US, changes to the US Environmental Protection Agency's risk evaluation process under the TSCA could also result in additional restrictions or bans of methanol-derived products, such as formaldehyde which is currently being reassessed by the EPA.

In 2023, global methanol demand for the production of formaldehyde represented approximately 25% of global methanol demand and is the largest demand segment. 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.

Assessments under TSCA may result in heightened concerns about methanol-derived products and may result in additional requirements or bans being placed on the production, handling, labeling or use of those chemicals. Any such actions could reduce future methanol demand for use in producing methanol-derived products and could have an adverse effect on our results of operations and financial condition

Litigation and Legal Proceedings

The Company is subject, from time to time, to litigation and may be involved in disputes with other parties in the future, which may result in litigation and claims under such litigation may be material. Various types of claims may be raised in these proceedings, including, but not limited to breach of contract, product liability, tax, employment matters and in relation to an attack, breach or unauthorized access to Methanex's information technology and infrastructure, environmental damage, climate change and the impact thereof, antitrust, bribery, and other forms of corruption. The Company cannot predict the outcome of any litigation. Defense and settlement costs may be substantial, even with respect to claims that have no merit. If the Company cannot resolve these disputes favourably, its business, financial condition, results of operations and future prospects may be materially adversely affected.

Trinidad and Tobago

The Board of Inland Revenue of Trinidad and Tobago has audited and issued assessments against our 63.1% owned joint venture, Atlas, in respect of the 2005 to 2017 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 with affiliates that commenced in 2005 and continued with affiliates through 2014 and with an unrelated third party through 2019. The long-term fixed-price sales contracts with affiliates were established as part of the formation of Atlas and management believes these were reflective of market considerations at that time.

During the periods under assessment and continuing through 2014, approximately 50% of Atlas-produced methanol was sold under these fixed-price contracts. From late 2014 through 2019 fixed-prices sales to an unrelated third party represented approximately 10% of Atlas-produced methanol. Atlas had partial relief from corporation income tax until late July 2014.

The Company believes it is impractical to disclose a reasonable estimate of the potential contingent liability due to the wide range of assumptions and interpretations implicit in the assessments.

The Company has lodged objections to the assessments. No deposits have been required to lodge objections. Although there can be no assurance that these tax assessments will not have a material adverse impact, based on the merits of the case and advice from legal counsel, we believe our position should be sustained, that Atlas has filed its tax returns and paid applicable taxes in compliance with Trinidadian tax law, and as such has not accrued for any amounts relating to these assessments. Contingencies inherently involve the exercise of significant judgment, and as such the outcomes of these assessments and the financial impact to the Company could be material.

We anticipate the resolution of this matter through the court systems to be lengthy and, at this time, cannot predict a date as to when we expect this matter to be ultimately resolved.

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, leases, income taxes and fair value measurement of financial instruments require us to make assumptions relating to operations and 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 27. See note 2 to our 2023 consolidated financial statements for our material 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, 2023, the net book value of our property, plant and equipment was $4.4 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, 2023, we had accrued $33 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 at installation, excluding costs related to turnarounds, initially range up 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. The estimated useful life of production facilities may be adjusted from time-to-time based on turnarounds, plant refurbishments and gas availability. 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.

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 the asset or idle

the asset for a significant period of time; 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. Fair value less costs of disposal is determined by ascertaining the price that would be received to sell an asset in an orderly transaction between market participants under current market conditions, less incremental costs directly attributable to the disposal, excluding finance costs and income tax expense. 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.

When impairment indicators exist, 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, incorporating third-party assumptions, forecasts and market-observable prices when appropriate. 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 when testing for impairment 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. In relation to previous impairment charges, we do not believe that there are significant changes in events or circumstances that would support their reversal.

In Trinidad we announced our intention to idle the Atlas plant when its 20-year legacy natural gas supply arrangement expires in September 2024. The expected idling of the Atlas plant has been identified as an impairment indicator for the Atlas cash generating unit ("Atlas CGU"). The impairment test performed on the Atlas CGU resulted in no impairment provision recognized as the estimated recoverable value, determined on a fair value less costs of disposal methodology, exceeded the carrying value. The estimated recoverable value was based on an assumed restart date and an operating period for Atlas aligned to natural gas reserves estimates in Trinidad and Tobago with no terminal value, discounted at an after-tax rate of 16%.

The following table indicates the percentages by which key assumptions would need to change individually for the estimated Atlas CGU recoverable value to be equal to the carrying value:

Key Assumptions	Change Required for Carrying Value to Equal Recoverable Value
Long-term average realized methanol price	10 percent decrease
Production volumes	15 percent decrease
Gas price	10 percent increase
Discount rate (after-tax)	800 basis points increase

The sensitivity above has been prepared considering each variable independently. Historically, our natural gas contracts in Trinidad and Tobago have included terms whereby a change in methanol price results in a change in natural gas price, protecting margins should revenue decrease.

Leases

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

In determining the lease term, the Company considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed upon a trigger by an event or a significant change in circumstances. 

Certain leases contain non-lease components, excluded from the right-of-use asset and lease liability, related to operating charges for ocean vessels and terminal facilities. Judgment is applied in the determination of the stand-alone price of the lease and non-lease components. All related operating charges are classified as variable payments and all such costs are accounted for as a non-lease component charged to the consolidated statement of operations as incurred.

The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Company’s estimate of the amount expected to be payable under a residual value guarantee or if the Company changes its assessment of whether it will exercise a purchase, extension or termination option. In measuring lease liabilities, the Company discounts lease payments using the incremental borrowing rate applicable at lease inception. The incremental borrowing rate is determined using a credit rating specific to the entity, location, asset security and term of the lease.

Income Taxes

We calculate current and deferred tax provisions for each of the jurisdictions in which we operate. Actual amounts of income tax expense or recoveries are not final until tax returns are filed and accepted by the relevant tax authorities and as a result, the ultimate amount of taxes the Company may owe could differ from the amounts recognized in the consolidated financial statements. The filing of annual tax returns primarily occurs subsequent to the issuance 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. Uncertain tax positions derive from the complexity of tax law and its interpretation by tax authorities and ultimately the judicial system in place in each jurisdiction. Uncertain tax positions, including interest and penalties, are recognized and measured applying management estimates. Given the complexity, management engages third-party experts as required, for the interpretation of tax law, transfer pricing regulations and determination of the ultimate resolution of its tax positions. The Company is subject to various taxation authorities who may interpret tax legislation differently, and resolve matters over longer periods of time. The differences in judgement in assessing uncertain tax positions may result in material differences in the final amount or timing of the payment of taxes or settlement of tax assessments.

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. 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, 2023, we had recognized deferred tax assets of $152 million primarily relating to non-capital loss carryforwards and other temporary differences in the United States and Trinidad and Tobago. As at December 31, 2023, the Company had $201 million of unrecognized deductible temporary differences in the United States. 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 Measured at Fair Value

The Company uses derivatives as part of its risk management program to mitigate variability associated with changing market values. Changes in the 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 or accumulated other comprehensive income when the underlying hedged transaction is recognized in earnings or inventory. 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, determination of whether contracts contain embedded derivatives to be separated, 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 their complex nature and the potential impact on our financial statements.

The Company holds a long-term natural gas supply contract expiring in 2035 with the Egyptian Natural Gas Holding Company, a State-Owned enterprise in Egypt. The natural gas supply contract includes a base fixed price plus a premium based on the realized price of methanol for the full volume of natural gas to supply the plant for the remainder of its useful life. As a result of the amendment in 2022, the contract is being treated as a derivative measured at fair value.

There is no observable, liquid spot market or forward curve for natural gas in Egypt. In addition, there are limited observable prices for natural gas in Egypt as all natural gas purchases and sales are controlled by the government and the observed prices differ based on the produced output or usage.

Due to the absence of an observable market price for an equivalent or similar contract to measure fair value, the contract's fair value is estimated using a Monte-Carlo model. We consider market participant assumptions in establishing the model inputs and determining fair value, including adjusting the base fixed price and methanol based premium at the valuation date to consider estimates of inflation since contract inception.

Refer to note 19 to our 2023 consolidated financial statements for more information.

ADOPTION OF NEW ACCOUNTING STANDARDS

The Company has adopted the amendments to IAS 1 Presentation of Financial Statements as well as IAS 8 Changes in Accounting Estimates and Errors regarding the disclosure of accounting policies and accounting estimates, and IAS 12, Income Taxes ("IAS 12") regarding deferred tax related to assets and liabilities arising from a single transaction, which were effective for annual periods beginning on January 1, 2023. The amendments did not have a material impact on the Company's consolidated financial statements.

In May 2023, the IASB issued a further amendment to IAS 12, establishing a mandatory exception for recognition and disclosure of deferred taxes related to the Pillar Two model rules published by the Organization for Economic Co-operation and Development (“Pillar Two rules”). The Pillar Two rules establish a global minimum fifteen percent top-up tax regime and are expected to apply to Methanex beginning in 2024. The Company has applied this mandatory exception in the current period. Refer to note 16 to our 2023 consolidated financial statements for further disclosure on the expected impact of Pillar Two rules.

ANTICIPATED CHANGES TO INTERNATIONAL FINANCIAL REPORTING STANDARDS

The following new or amended standards or interpretations that are effective for annual periods beginning on or after January 1, 2024 are being reviewed to determine the potential impact: amendments to IAS 1, Presentation of Financial Statements regarding the classification of liabilities as current or non-current, IFRS 16, Leases regarding sale-and-leaseback transactions and IAS 7, Statement of Cash Flows regarding supplier finance arrangements.

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 or ratios). These are Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share, Adjusted net income (loss) before income tax, Adjusted income tax expense, and Adjusted effective tax rate. These non-GAAP financial measures and ratios reflect our 63.1% economic interest in the Atlas facility, 50% economic interest in the Egypt facility and our 60% economic interest in Waterfront Shipping, and are useful as they are a better measure of our underlying performance and assist in assessing the operating performance of the Company’s business. These measures, at our economic share, are a better measure of our underlying performance, as we fully run the operations on our partners' behalf, despite having less than full share of the economic interest. Adjusted EBITDA is also frequently used by securities analysts and investors when comparing our results with those of other companies.

In addition, the Company also presents non-GAAP capital management measures, specifically, Net debt to capitalization and Total liquidity, which are useful in assessing the liquidity of the Company’s ongoing business. Total liquidity is useful because it illustrates the extent to which management has immediate access to cash for operational and construction purposes, and is indicative of our flexibility should uses for these facilities immediately arise. Net debt to capitalization is useful because it illustrates the relative risk of our financing structure to potential lenders and investors.These measures and ratios do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other companies.

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

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure and differs from the most comparable GAAP measure, net income attributable to Methanex shareholders, because it excludes finance costs, finance income and other, income tax expense, depreciation and amortization and mark-to-market impact of share-based compensation. 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 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 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 may differ from the total settlement cost.

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

($ Millions)	2023		2022
Net income attributable to Methanex shareholders	$	174	$	354
Mark-to-market impact of share-based compensation	16		(7)
Gas contract settlement, net of tax	(31)		—
Depreciation and amortization	392		372
Finance costs	117		131
Finance income and other	(40)		(25)
Income tax expense	1		120
Earnings of associate adjustment 1	67		74
Non-controlling interests adjustment 1	(74)		(87)
Adjusted EBITDA (attributable to Methanex shareholders)	$	622	$	932

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

Adjusted Net Income and Adjusted Net Income per Common Share

Adjusted net income and Adjusted net income per common share are a non-GAAP measure and ratio, respectively, because they exclude the mark-to-market impact of share-based compensation, the impact of the Egypt gas contract revaluation included in finance income and other and the impact of certain items associated with specific identified events. The following table shows a reconciliation from net income attributable to Methanex shareholders to Adjusted net income and the calculation of Adjusted diluted net income per common share:

($ Millions, except number of shares and per share amounts)	2023		2022
Net income attributable to Methanex shareholders	$	174	$	354
Mark-to-market impact of share-based compensation, net of tax	13		(6)
Gas contract settlement, net of tax	(31)		—
Impact of Egypt gas contract revaluation, net of tax	(3)		(5)
Adjusted net income	$	153	$	343
Diluted weighted average shares outstanding (millions)	68		72
Adjusted net income per common share	$	2.25	$	4.79

Management uses these measures to analyze net income and net income per common share after adjusting for our economic interest in the Atlas and Egypt facilities and Waterfront Shipping, for reasons as described above. The exclusion of the mark-to-market portion of the impact of shared-based compensation is due to these amounts not being seen as indicative of the operational performance and can fluctuate in the intervening periods until settlement. The exclusion of the impact of the Egypt gas contract revaluation is due to the change in the derivative being unrealized with the fair value of the derivative expected to fluctuate in the intervening periods until settlement.

QUARTERLY FINANCIAL DATA (UNAUDITED)

Our operations consist of a single operating segment – the production and sale of methanol. Quarterly results vary due to the average realized price of methanol, sales volume and total cash costs.

A summary of selected financial information is as follows:

	Three months ended
($ Millions, except per share amounts)	Dec 31		Sep 30		Jun 30		Mar 31
2023
Revenue	$	922	$	823	$	939	$	1,038
Cost of sales and operating expenses	(772)		(730)		(724)		(841)
Net income (attributable to Methanex shareholders)	33		24		57		60
Basic net income per common share	0.50		0.36		0.84		0.87
Diluted net income per common share	0.50		0.36		0.73		0.87
Adjusted EBITDA 1	148		105		160		209
Adjusted net income 1	35		1		41		76
Adjusted net income per common share 1	0.52		0.02		0.60		1.11
2022
Revenue	$	986	$	1,012	$	1,137	$	1,176
Cost of sales and operating expenses	(841)		(861)		(852)		(892)
Net income (attributable to Methanex shareholders)	41		69		125		119
Basic net income per common share	0.59		0.99		1.74		1.60
Diluted net income per common share	0.59		0.87		1.41		1.60
Adjusted EBITDA 1	160		192		243		337
Adjusted net income 1	51		49		84		159
Adjusted net income per common share 1	0.73		0.69		1.16		2.16

1 The Company has used the terms Adjusted EBITDA, Adjusted net income, and Adjusted net income per common share, throughout this document. These items are non-GAAP measures and ratios 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 Non-GAAP Measures section on page 37 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures.

A discussion and analysis of our results for the fourth quarter of 2023 is set out in our fourth quarter of 2023 Management’s Discussion and Analysis filed with the Canadian Securities Administrators on SEDAR+ at www.sedarplus.ca 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)	2023		2022		2021
Total assets	$	6,427	$	6,631	$	6,090
Total long-term liabilities (excluding deferred income tax)	2,733		3,032		2,959
Revenue	3,723		4,311		4,415
Net income (attributable to Methanex shareholders)	174		354		482
Adjusted net income 1	153		343		460
Adjusted EBITDA 1	622		932		1,108
Basic net income per common share	2.57		4.95		6.34
Diluted net income per common share	2.57		4.86		6.13
Adjusted net income per common share 1	2.25		4.79		6.03
Cash dividends declared per common share	0.730		0.620		0.325

1 The Company has used the terms Adjusted EBITDA, Adjusted net income, and Adjusted net income per common share,throughout this document. These items are non-GAAP measures and ratios 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 Non-GAAP Measures section on page 37 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")), and NI 52-109, 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, 2023, 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 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. 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.

Internal control over financial reporting has inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements will not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

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, 2023, based on the framework set forth in Internal Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (the "COSO framework"). 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, 2023. The attestation report is included in our consolidated financial statements on page 46.

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting that occurred during the most recent interim period and year ended December 31, 2023, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

FORWARD-LOOKING STATEMENTS

This 2023 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," "targets," "plan," "predict" 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, including demand for methanol for energy uses, and its derivatives,

▪expected new methanol supply or restart of idled capacity and timing for startup 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 and anticipated timing and rate of return of such 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, cash balances, earnings capability, debt levels and share price,

▪availability of committed credit facilities and other financing,

▪our ability to meet covenants associated with our long-term debt obligations,

▪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, including our Geismar 3 project,

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

▪expected global or regional economic activity (including industrial production levels) and GDP growth,

▪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 or 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,

▪the expected timing and capital cost of our Geismar 3 project,

▪global and regional economic activity (including industrial production levels) and GDP growth,

▪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,

▪our ability to meet timeline and budget targets for the Geismar 3 project, including the impact of any cost pressures arising from tightening construction labour market conditions,

▪competing demand for natural gas, especially with respect to any domestic needs for gas and electricity,

▪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 2023 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.

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 as issued by the International Accounting Standards Board 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, 2023.

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 five 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; the financial reporting process; the systems of accounting and financial controls; the professional qualifications and independence of the external auditor; the performance of the external and internal auditors; risk management processes; financing 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 LLP has full and unrestricted access to the Committee. KPMG LLP audited the consolidated financial statements and the effectiveness of internal controls over financial reporting. Their opinions are included in the annual report.

Benita Warmbold Chair of the Audit, Finance and Risk Committee March 8, 2024	Rich Sumner President and  Chief Executive Officer	Dean Richardson Senior Vice President, Finance and Chief Financial Officer

43

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Methanex Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statements of financial position of Methanex Corporation (the Company) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and its financial performance and its cash flows for each of the years then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 8, 2024 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. 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.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 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 consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Recognition and Measurement of Uncertain Tax Positions

As discussed in Notes 6(c) and 16 to the consolidated financial statements, the Company has identified and, in certain cases, recognized uncertain tax positions (tax positions) including associated interest and penalties. As discussed in Note 2(q) to the consolidated financial statements, uncertain tax positions derive from the complexity of tax law and its interpretation by tax authorities and ultimately the judicial system in place in each jurisdiction. Given the complexity, the Company engages third-party experts as required, for the interpretation of tax law, transfer pricing regulations and determination of the ultimate resolution of its tax positions. The Company is subject to various taxation authorities who may interpret tax legislation differently, and resolve matters over longer-periods of time.

We identified the assessment of the recognition and measurement of uncertain tax positions as a critical audit matter. Complex auditor judgment was required to evaluate the Company’s interpretation of tax law and its identification and determination of the ultimate resolution of its tax positions. Additionally, the evaluation of the recognition and measurement of the Company's uncertain tax positions required specialized skills and knowledge.

44

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company's process for recognizing uncertain tax positions. This included controls related to the interpretation of tax law and identification of tax positions, the determination of the probability that the tax authorities would accept the Company's tax positions, and the estimation of reserves recorded for tax positions. We involved domestic and international tax professionals with specialized skills and knowledge, who assisted in assessing the Company's tax positions by:

–inspecting tax rulings and correspondence between the Company and the applicable taxation authorities;

–inspecting transfer pricing studies and information obtained from external tax specialists and legal counsel; and

–comparing our understanding and interpretation of tax laws to the Company's evaluation.

/s/ KPMG LLP

Chartered Professional Accountants

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

Vancouver, Canada

March 8, 2024

45

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Methanex Corporation:

Opinion on Internal Control Over Financial Reporting

We have audited Methanex Corporation's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, Methanex Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with 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, 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements), and our report dated March 8, 2024 expressed an unqualified opinion on those consolidated 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 under the heading ”Management’s Annual Report on Internal Control Over Financial Reporting” in Management's Discussion and Analysis for the year ended December 31, 2023. 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.

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

Definition and Limitations of Internal Control Over Financial Reporting

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

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

/s/ KPMG LLP

Chartered Professional Accountants

Vancouver, Canada

March 8, 2024

46

Consolidated Statements of Financial Position

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

As at	Dec 31 2023		Dec 31 2022
ASSETS
Current assets:
Cash and cash equivalents	$	458,015	$	857,747
Trade and other receivables (note 3)	533,615		500,925
Inventories (note 4)	426,774		439,771
Prepaid expenses	58,024		38,585
Other assets (note 7)	3,893		39,346
	1,480,321		1,876,374
Non-current assets:
Property, plant and equipment (note 5)	4,411,768		4,155,283
Investment in associate (note 6)	184,249		197,083
Deferred income tax assets (note 16)	152,250		46,353
Other assets (note 7)	197,967		356,387
	4,946,234		4,755,106
	$	6,426,555	$	6,631,480
LIABILITIES AND EQUITY
Current liabilities:
Trade, other payables and accrued liabilities	$	771,867	$	789,200
Current maturities on long-term debt (note 8)	314,716		15,133
Current maturities on lease obligations (note 9)	120,731		108,736
Current maturities on other long-term liabilities (note 10)	94,992		29,548
	1,302,306		942,617
Non-current liabilities:
Long-term debt (note 8)	1,827,085		2,136,380
Lease obligations (note 9)	751,389		761,427
Other long-term liabilities (note 10)	154,918		134,603
Deferred income tax liabilities (note 16)	217,840		226,996
	2,951,232		3,259,406
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, 2023 were 67,387,492 (2022 - 69,239,136)	391,924		401,295
Contributed surplus	1,838		1,904
Retained earnings	1,514,264		1,466,872
Accumulated other comprehensive income	22,901		241,942
Shareholders’ equity	1,930,927		2,112,013
Non-controlling interests	242,090		317,444
Total equity	2,173,017		2,429,457
	$	6,426,555	$	6,631,480

Commitments and contingencies (note 22)

See accompanying notes to consolidated financial statements.

Approved by the Board:

Benita Warmbold (Director)	Rich Sumner (Director)

47

Consolidated Statements of Income

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

For the years ended December 31	2023		2022
Revenue	$	3,723,475	$	4,311,188
Cost of sales and operating expenses (note 11)	(3,068,072)		(3,446,101)
Depreciation and amortization (note 11)	(391,830)		(372,420)
Egypt gas redirection and sale proceeds (note 26)	—		117,946
Operating income	263,573		610,613
Earnings of associate (note 6)	99,466		76,938
Finance costs (note 12)	(117,366)		(130,752)
Finance income and other	39,938		25,348
Income before income taxes	285,611		582,147
Income tax (expense) recovery (note 16):
Current	(49,924)		(127,578)
Deferred	48,435		7,719
	(1,489)		(119,859)
Net income	$	284,122	$	462,288
Attributable to:
Methanex Corporation shareholders	$	174,140	$	353,830
Non-controlling interests (note 24)	109,982		108,458
	$	284,122	$	462,288
Income per common share for the year attributable to Methanex Corporation shareholders:
Basic net income per common share (note 13)	$	2.57	$	4.95
Diluted net income per common share (note 13)	$	2.57	$	4.86
Weighted average number of common shares outstanding (note 13)	67,805,220		71,422,360
Diluted weighted average number of common shares outstanding (note 13)	67,811,615		71,677,484

See accompanying notes to consolidated financial statements.

48

Consolidated Statements of Comprehensive Income

(thousands of U.S. dollars)

For the years ended December 31	2023		2022
Net income	$	284,122	$	462,288
Other comprehensive income:
Items that may be reclassified to income:
Change in cash flow hedges and excluded forward element (note 19)	(310,456)		378,287
Realized losses (gains) on foreign exchange hedges reclassified to revenue	3,105		(5,674)
Items that will not be reclassified to income:
Actuarial loss on defined benefit pension plans (note 21(a))	(2,827)		(726)
Taxes on above items	66,636		(72,440)
	(243,542)		299,447
Comprehensive income	$	40,580	$	761,735
Attributable to:
Methanex Corporation shareholders	$	(69,402)	$	653,277
Non-controlling interests (note 24)	109,982		108,458
	$	40,580	$	761,735

See accompanying notes to consolidated financial statements.

49

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 income (loss)	Shareholders’ equity	Non-controlling interests	Total equity
Balance, December 31, 2021	74,774,087	$432,728	$1,928	$1,251,640	($2,720)	$1,683,576	$271,155	$1,954,731
Net income	—	—	—	353,830	—	353,830	108,458	462,288
Other comprehensive income (loss)	—	—	—	(252)	299,699	299,447	—	299,447
Compensation expense recorded for stock options	—	—	110	—	—	110	—	110
Issue of shares on exercise of stock options	16,800	582	—	—	—	582	—	582
Reclassification of grant date fair value on exercise of stock options	—	134	(134)	—	—	—	—	—
Sale of partial interest in subsidiary (note 25)	—	—	—	126,445	—	126,445	22,545	148,990
Payments for repurchase of shares	(5,551,751)	(32,149)	—	(220,836)	—	(252,985)	—	(252,985)
Dividend payments to Methanex Corporation shareholders ($0.620 per common share)	—	—	—	(43,955)	—	(43,955)	—	(43,955)
Distributions made and accrued to non-controlling interests	—	—	—	—	—	—	(84,714)	(84,714)
Realized hedge gains recognized in cash flow hedges	—	—	—	—	(55,037)	(55,037)	—	(55,037)
Balance, December 31, 2022	69,239,136	$401,295	$1,904	$1,466,872	$241,942	$2,112,013	$317,444	$2,429,457
Net income	—	—	—	174,140	—	174,140	109,982	284,122
Other comprehensive loss	—	—	—	(1,976)	(241,566)	(243,542)	—	(243,542)
Compensation expense recorded for stock options	—	—	124	—	—	124	—	124
Issue of shares on exercise of stock options	43,067	1,437	—	—	—	1,437	—	1,437
Reclassification of grant date fair value on exercise of stock options	—	190	(190)	—	—	—	—	—
Payments for repurchase of shares	(1,894,711)	(10,998)	—	(75,394)	—	(86,392)	—	(86,392)
Dividend payments to Methanex Corporation shareholders ($0.730 per common share)	—	—	—	(49,378)	—	(49,378)	—	(49,378)
Distributions made and accrued to non-controlling interests	—	—	—	—	—	—	(185,336)	(185,336)
Realized hedge losses recognized in cash flow hedges	—	—	—	—	22,525	22,525	—	22,525
Balance, December 31, 2023	67,387,492	$391,924	$1,838	$1,514,264	$22,901	$1,930,927	$242,090	$2,173,017

See accompanying notes to consolidated financial statements.

50

Consolidated Statements of Cash Flows

(thousands of U.S. dollars)

For the years ended December 31	2023		2022
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net income	$	284,122	$	462,288
Deduct earnings of associate	(99,466)		(76,938)
Dividends received from associate	112,318		97,174
Add (deduct) non-cash items:
Depreciation and amortization	391,830		372,420
Income tax expense	1,489		119,859
Share-based compensation expense	34,502		15,398
Finance costs	117,366		130,752
Other	(24,651)		(12,985)
Interest received	21,633		9,590
Income taxes paid	(81,922)		(163,828)
Other cash payments, including share-based compensation	(37,894)		(20,503)
Cash flows from operating activities before undernoted	719,327		933,227
Changes in non-cash working capital (note 17(a))	(59,058)		54,122
	660,269		987,349
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Payments for repurchase of shares	(86,392)		(252,985)
Dividend payments to Methanex Corporation shareholders	(49,378)		(43,955)
Interest paid	(168,636)		(161,816)
Repayment of long-term debt and financing fees (note 8)	(12,280)		(9,151)
Repayment of lease obligations	(118,159)		(105,863)
Distributions to non-controlling interests	(185,336)		(84,713)
Proceeds on issue of shares on exercise of stock options	1,437		582
Restricted cash for debt service accounts	(1,424)		(1,394)
Sale of partial interest in subsidiary (note 25)	—		148,990
Changes in non-cash working capital related to financing activities (note 17(a))	68,750		1,771
	(551,418)		(508,534)
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Property, plant and equipment	(178,464)		(145,701)
Geismar plant under construction	(269,989)		(431,680)
Changes in non-cash working capital related to investing activities (note 17(a))	(60,130)		24,244
	(508,583)		(553,137)
Decrease in cash and cash equivalents	(399,732)		(74,322)
Cash and cash equivalents, beginning of year	857,747		932,069
Cash and cash equivalents, end of year	$	458,015	$	857,747

See accompanying notes to consolidated financial statements.

51

Notes to Consolidated Financial Statements

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

Year ended December 31, 2023

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. Material 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 7, 2024.

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 controlled by the Company. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. 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. 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)), leases (note 2(i)), 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 records provisions for expected credit losses for receivables measured at amortized cost. The Company records an allowance for doubtful accounts or writes down the receivable to estimated net realizable value, if not collectible in full, based on expected credit losses. Expected credit losses are based on historic and forward looking customer specific factors including historic credit losses incurred.

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 ocean freight costs for the shipment of product.

52

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 at installation, excluding costs related to turnarounds, initially range up to 25 years depending on the specific asset component and the production facility to which it is related. Right-of-use (leased) assets are depreciated from the lease commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. 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. The estimated useful life of production facilities may be adjusted from time-to-time based on turnarounds, plant refurbishments and gas availability. 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.

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 may 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 the asset or idle the asset for a significant period of time; 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. Fair value less costs of disposal is determined by estimating the price that would be received to sell an asset in an orderly transaction between market participants under current market conditions, less incremental costs directly attributable to the disposal, excluding finance costs and income tax expense. 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.

When impairment indicators exist, 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

53

long-term supply and demand, incorporating third-party assumptions, forecasts and market observable prices when appropriate. 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 when testing for impairment 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. In relation to previous impairment charges, we do not believe that there are significant changes in events or circumstances that would support their reversal.

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:

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether:

•the contract involves the use of an identified asset - this may be specified explicitly or implicitly and should be physically distinct or represent substantially all of the capacity of a physically distinct asset. If the supplier has a substantive substitution right, then the asset is not identified;

•the Company has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use; and

•the Company has the right to direct the use of the asset. The Company has the right when it has the decision-making rights that are most relevant to changing how and for what purpose the asset is used.

For contracts that contain a lease, the Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. The estimated useful lives of right-of-use assets are determined on the same basis as those of property, plant and equipment. In addition, the right-of-use asset is assessed for impairment losses, should a trigger be identified and adjusted for impairment if required. Lease terms range up to 20 years for vessels, terminals, equipment, and other items.

The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Company’s estimate of the amount expected to be payable under a residual value guarantee or if the Company changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed upon a trigger by an event or a significant change in circumstances.

Certain leases contain non-lease components, excluded from the right-of-use asset and lease liability, related to operating charges for ocean vessels, terminal facilities and rail transport contracts. Judgment is applied in the determination of the stand-alone price of the lease and non-lease components.

54

The Company has elected not to recognize right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less and leases of low-value assets, except for terminal and vessel leases. The Company recognizes the lease payments associated with these leases as an expense 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 transferred to 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 ("PSUs") granted from 2019 onwards are redeemable for cash based on the market value of the Company's common shares and are non-dilutive to shareholders. PSUs vest over three years and include two performance factors: (i) relative total shareholder return of Methanex shares versus a specific market index (the market performance factor) and (ii) three year average Return on Capital Employed ("ROCE") (the non-market performance factor). The market performance factor is measured by the Company at the grant date and reporting date using a Monte-Carlo simulation model to determine fair value. The non-market performance factor reflects management's best estimate of ROCE over the performance period (using actual ROCE as applicable) to determine the expected number of units to vest. Based on these performance factors the performance share unit payout will range between 0% to 200%.

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-

55

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 14.

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 13.

n) Revenue recognition:

Revenue is recognized based on individual contract terms at the point in time when control of 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 contractual performance obligation has not been met during shipment. For methanol sold on a consignment basis, revenue is recognized at the point in time the customer draws down the consigned methanol. Revenue is measured and recorded at the most likely amount of consideration the Company expects to receive.

By contract, the Company sells all the methanol produced by the Atlas Joint Venture and earns a commission on the sale of the methanol. As the Company obtains title and control of the methanol from the Atlas facility and directs the sale of the methanol to the Company's customers, the Company recognizes the revenue on these sales to customers at the gross amount receivable from the customers based on the Company's revenue recognition policy noted above. Cost of sales is recognized for these sales as the amount due to the Atlas Joint Venture which is the gross amount receivable less the commission earned by the Company.

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.

Assessment of contracts as derivative instruments, applicability of the own use exemption, determination of whether hybrid instruments contain embedded derivatives to be separated, the valuation of financial instruments and derivatives and hedge effectiveness assessments require a high degree of judgment and are considered critical accounting judgements and estimates due to the complex nature of these products and the potential impact on our financial statements.

56

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 19.

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.

Uncertain tax positions derive from the complexity of tax law and its interpretation by tax authorities and ultimately the judicial system in place in each jurisdiction. Uncertain tax positions, including interest and penalties, are recognized and measured applying management estimates. Given the complexity, management engages third-party experts as required, for the interpretation of tax law, transfer pricing regulations and determination of the ultimate resolution of its tax positions. The Company is subject to various taxation authorities who may interpret tax legislation differently, and resolve matters over longer-periods of time. The differences in judgement in assessing uncertain tax positions may result in material differences in the final amount or timing of the payment of taxes or settlement of tax assessments.

r) Segmented information:

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

s) Application of new and revised accounting standards:

The Company has adopted the amendments to IAS 1 Presentation of Financial Statements as well as IAS 8 Changes in Accounting Estimates and Errors regarding the disclosure of accounting policies and accounting estimates, and IAS 12, Income Taxes ("IAS 12") regarding deferred tax related to assets and liabilities arising from a single transaction, which were effective for annual periods beginning on January 1, 2023. The amendments did not have a material impact on the Company's consolidated financial statements.

In May 2023, the IASB issued a further amendment to IAS 12, establishing a mandatory exception for recognition and disclosure of deferred taxes related to the Pillar Two model rules published by the Organization for Economic Co-operation and Development (“Pillar Two rules”). The Pillar Two rules establish a global minimum fifteen percent top-up tax regime and are expected to apply to Methanex beginning in 2024. The Company has applied this mandatory exception in the current period. Refer to note 16 for further disclosure on the expected impact of Pillar Two rules.

t) Anticipated changes to International Financial Reporting Standards:

The following new or amended standards or interpretations that are effective for annual periods beginning on or after January 1, 2024 are being reviewed to determine the potential impact: amendments to IAS 1, Presentation of Financial Statements regarding the classification of liabilities as current or non-current, IFRS 16, Leases regarding sale-and-leaseback transactions and IAS 7, Statement of Cash Flows regarding supplier finance arrangements.

57

3. Trade and other receivables: 

As at	Dec 31 2023		Dec 31 2022
Trade	$	431,602	$	407,733
Value-added and other tax receivables	22,292		14,986
Other	79,721		78,206
	$	533,615	$	500,925

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, 2023 is $2,860 million (2022 - $3,157 million).

5. Property, plant and equipment:

	Owned Assets (a)		Right-of-use assets (b)		Total
Net book value at December 31, 2023	$	3,654,475	$	757,293	$	4,411,768
Net book value at December 31, 2022	$	3,398,805	$	756,478	$	4,155,283

a) Owned assets:

	Buildings, plant installations and machinery		Plants Under Construction1		Ocean vessels		Other		TOTAL
Cost at January 1, 2023	$	5,000,999	$	1,001,888	$	240,867	$	140,081	$	6,383,835
Additions	174,058		353,609		253		4,153		532,073
Disposals and other	(294,850)		—		(397)		(15,571)		(310,818)
Cost at December 31, 2023	4,880,207		1,355,497		240,723		128,663		6,605,090
Accumulated depreciation at January 1, 2023	2,827,870		—		49,310		107,850		2,985,030
Depreciation	248,783		—		12,080		2,153		263,016
Disposals and other	(281,951)		—		—		(15,480)		(297,431)
Accumulated depreciation at December 31, 2023	2,794,702		—		61,390		94,523		2,950,615
Net book value at December 31, 2023	$	2,085,505	$	1,355,497	$	179,333	$	34,140	$	3,654,475

1    The Company is constructing a 1.8 million tonne methanol plant in Geismar, Louisiana adjacent to its Geismar 1 and Geismar 2 facilities. Included in cost of Plants Under Construction are $150 million (2022: $94 million) of capitalized interest and finance charges.

	Buildings, plant installations and machinery		Plants under construction		Ocean vessels		Other		TOTAL
Cost at January 1, 2022	$	4,908,492	$	561,860	$	240,525	$	138,378	$	5,849,255
Additions	140,326		440,028		342		1,703		582,399
Disposals and other	(47,819)		—		—		—		(47,819)
Cost at December 31, 2022	5,000,999		1,001,888		240,867		140,081		6,383,835
Accumulated depreciation at January 1, 2022	2,631,268		—		37,271		105,518		2,774,057
Depreciation	248,032		—		12,039		2,332		262,403
Disposals and other	(51,430)		—		—		—		(51,430)
Accumulated depreciation at December 31, 2022	2,827,870		—		49,310		107,850		2,985,030
Net book value at December 31, 2022	$	2,173,129	$	1,001,888	$	191,557	$	32,231	$	3,398,805

58

b) Right-of-use (leased) assets:

	Ocean vessels		Terminals and tanks		Other		TOTAL
Cost at January 1, 2023	$	846,977	$	286,036	$	68,701	$	1,201,714
Additions	83,333		52,909		5,951		142,193
Disposals and other	(19,589)		(6,504)		(16,031)		(42,124)
Cost at December 31, 2023	910,721		332,441		58,621		1,301,783
Accumulated depreciation at January 1, 2023	245,873		160,163		39,200		445,236
Depreciation	88,040		36,140		6,583		130,763
Disposals and other	(19,589)		—		(11,920)		(31,509)
Accumulated depreciation at December 31, 2023	314,324		196,303		33,863		544,490
Net book value at December 31, 2023	$	596,397	$	136,138	$	24,758	$	757,293

	Ocean vessels		Terminals and tanks		Other		TOTAL
Cost at January 1, 2022	$	657,774	$	258,743	$	64,700	$	981,217
Additions	232,536		27,293		4,001		263,830
Disposals and other	(43,333)		—		—		(43,333)
Cost at December 31, 2022	846,977		286,036		68,701		1,201,714
Accumulated depreciation at January 1, 2022	214,004		125,494		30,768		370,266
Depreciation	75,586		34,669		8,432		118,687
Disposals and other	(43,717)		—		—		(43,717)
Accumulated depreciation at December 31, 2022	245,873		160,163		39,200		445,236
Net book value at December 31, 2022	$	601,104	$	125,873	$	29,501	$	756,478

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 and Tobago. 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 2023		Dec 31 2022
Cash and cash equivalents	$	126,392	$	24,420
Other current assets1	189,062		182,103
Non-current assets	149,354		184,373
Current liabilities1	(157,835)		(92,108)
Other long-term liabilities, including current maturities	(135,940)		(107,416)
Net assets at 100%	$	171,033	$	191,372
Net assets at 63.1%	$	107,921	$	120,755
Long-term receivable from Atlas1	76,328		76,328
Investment in associate	$	184,249	$	197,083

Consolidated statements of income for the years ended December 31	2023		2022
Revenue1	$	466,312	$	532,456
Cost of sales and depreciation and amortization	(289,705)		(332,999)
Gas contract settlement (b)	75,000		—
Operating income	251,607		199,457
Finance costs, finance income and other	(10,316)		(9,433)
Income tax expense	(83,659)		(68,093)
Net earnings at 100%	$	157,632	$	121,931
Earnings of associate at 63.1%	$	99,466	$	76,938
Dividends received from associate	$	112,318	$	97,174

1     Includes related party transactions between Atlas and the Company (see note 23).

59

b) Gas contract settlement:

Atlas stand-alone financial results for the year ended December 31, 2023 include a $75 million settlement (Methanex share, $47 million, net of tax, $31 million) related to a historical dispute under an existing gas contract. The amount was received in cash in the fourth quarter of 2023.

c) Atlas tax assessments:

The Board of Inland Revenue of Trinidad and Tobago ("the BIR") has audited and issued assessments against Atlas in respect of the 2005 to 2017 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 that commenced in 2005 and continued with affiliates through 2014 and with an unrelated third party through 2019.

The long-term fixed-price sales contracts with affiliates were established as part of the formation of Atlas and management believes these were reflective of market considerations at that time.

During the periods under assessment and continuing through 2014, approximately 50% of Atlas-produced methanol was sold under these fixed-price contracts. From late 2014 through 2019 fixed-price sales to an unrelated third party represented approximately 10% of Atlas produced methanol. Atlas had partial relief from corporation income tax until late July 2014.

The Company believes it is impractical to disclose a reasonable estimate of the potential contingent liability due to the wide range of assumptions and interpretations implicit in the assessments.

The Company has lodged objections to the assessments. No deposits have been required to lodge objections. Based on the merits of the cases and advice from legal counsel, the Company believes its position should be sustained, that Atlas has filed its tax returns and paid applicable taxes in compliance with Trinidadian tax law, and as such has not accrued for any amounts relating to these assessments. Contingencies inherently involve the exercise of significant judgment, and as such the outcomes of these assessments and the financial impact to the Company could be material.

The Company anticipates the resolution of this matter through the court systems to be lengthy and, at this time, cannot predict a date as to when this matter is expected to be ultimately resolved.

d) Impairment testing:

In Trinidad we announced our intention to idle the Atlas plant when its 20-year legacy natural gas supply arrangement expires in September 2024. The expected idling of the Atlas plant has been identified as an impairment indicator for the Atlas cash generating unit ("Atlas CGU"). The impairment test performed on the Atlas CGU resulted in no impairment provision recognized as the estimated recoverable value, determined on a fair value less costs of disposal methodology, exceeded the carrying value. The estimated recoverable value was based on an assumed restart date and an operating period for Atlas aligned to natural gas reserves estimates in Trinidad and Tobago with no terminal value, discounted at an after-tax rate of 16%.

The following table indicates the percentages by which key assumptions would need to change individually for the estimated Atlas CGU recoverable value to be equal to the carrying value:

Key Assumptions	Change Required for Carrying Value to Equal Recoverable Value
Long-term average realized methanol price	10 percent decrease
Production volumes	15 percent decrease
Gas price	10 percent increase
Discount rate (after-tax)	800 basis points increase

The sensitivity above has been prepared considering each variable independently. Historically, our natural gas contracts in Trinidad and Tobago have included terms whereby a change in methanol price results in a change in natural gas price, protecting margins should revenue decrease.

60

7. Other assets:

As at	Dec 31 2023		Dec 31 2022
Cash flow hedges (note 19)	$	121,108	$	322,748
Chile VAT receivable	17,824		18,343
Restricted cash for debt service and major maintenance of vessels (a)	15,772		14,349
Fair value of Egypt gas supply contract derivative (note 19)	20,402		11,220
Investment in Carbon Recycling International	5,620		5,620
Defined benefit pension plans (note 21)	5,718		3,977
Other	15,416		19,476
Total other assets	201,860		395,733
Less current portion (b)	(3,893)		(39,346)
	197,967		$	356,387

a) Restricted cash

The Company holds $15.8 million (2022 - $14.3 million) of restricted cash for the funding of debt service and major maintenance accounts.

b) Current portion of other assets

Other assets presented as current assets as at December 31, 2023 includes $0.5 million for the current portion of the cash flow hedge (see note 19), and $3.4 million of restricted cash for major maintenance, in particular the anticipated major maintenance costs of four vessels.

8. Long-term debt:

As at	Dec 31 2023		Dec 31 2022
Unsecured notes
(i) $300 million at 4.25% due December 1, 2024	$	299,283	$	298,836
(ii) $700 million at 5.125% due October 15, 2027	694,844		693,649
(iii) $700 million at 5.25% due December 15, 2029	695,824		695,283
(iv) $300 million at 5.65% due December 1, 2044	295,709		295,606
	1,985,660		1,983,374
Other limited recourse debt facilities
(i) 5.58% due through June 30, 2031	56,637		61,978
(ii) 5.35% due through September 30, 2033	65,300		70,312
(iii) 5.21% due through September 15, 2036	34,204		35,849
	156,141		168,139
Total long-term debt1	2,141,801		2,151,513
Less current maturities1	(314,716)		(15,133)
	$	1,827,085	$	2,136,380

1  Long-term debt and current maturities are presented net of discounts and deferred financing fees of $16.8 million as at December 31, 2023 (2022 - $19.4 million).

For the year ended December 31, 2023, non-cash accretion, on an effective interest basis, of deferred financing costs included in finance costs was $2.6 million (2022 - $2.2 million).

61

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

	Other limited recourse debt facilities		Unsecured notes		Total
2024	$	15,367	$	300,000	$	315,367
2025	13,660		—		13,660
2026	13,796		—		13,796
2027	15,173		700,000		715,173
2028	16,026		—		16,026
Thereafter	84,574		1,000,000		1,084,574
	$	158,596	$	2,000,000	$	2,158,596

The Company has access to a $300 million committed revolving credit facility from a syndicate of highly rated financial institutions expiring in July 2026.

The revolving credit facility is subject to the following significant covenants and default provisions:

i)    the obligation to maintain a minimum EBITDA to interest coverage ratio of greater than or equal to 2:1 calculated on a four-quarter trailing basis and a debt to capitalization ratio of less than or equal to 60%, both calculated in accordance with definitions in the credit agreement that include adjustments to 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 revolving credit facility is secured by certain assets of the Company, and also includes other customary covenants including restrictions on the incurrence of additional indebtedness.

During the year, the Company cancelled the $300 million non-revolving construction facility for the Geismar 3 project. At the time of cancellation, the construction facility was undrawn.

Other limited recourse debt facilities relate to financing for certain of our ocean vessels which we own through less than wholly-owned entities under the Company's control. 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 covenants governing the Company’s unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding the Egypt entity and the Atlas joint venture 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 the Company’s assets. The indenture also contains customary default provisions.

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, 2023, management believes the Company was in compliance with all covenants related to its long-term debt obligations.

9. Lease obligations:

	2023		2022
Opening lease obligations	$	870,163	$	717,101
Additions, net of disposals	123,187		262,470
Interest expense	53,418		48,039
Lease payments	(171,577)		(153,901)
Effect of movements in exchange rates and other	(3,071)		(3,546)
Lease obligations at December 31	872,120		870,163
Less: current portion	(120,731)		(108,736)
Lease obligations - non current portion	$	751,389	$	761,427

62

The Company incurs lease payments related to ocean vessels, terminal facilities, rail cars, vehicles and equipment, and office facilities. Leases are entered into and exited in coordination with specific business requirements which includes the assessment of the appropriate durations for the related leased assets.

The following table presents the contractual undiscounted cash flows for lease obligations as at December 31, 2023:

	Lease payments		Interest component		Lease obligations
2024	$	172,197	$	51,466	$	120,731
2025	142,761		45,617		97,144
2026	123,738		39,998		83,740
2027	112,397		34,419		77,978
2028	108,284		28,547		79,737
Thereafter	514,969		102,179		412,790
	$	1,174,346	$	302,226	$	872,120

Variable lease payments and short-term and low value leases

Certain leases contain non-lease components, excluded from the right-of-use asset and lease liability, related to operating charges for ocean vessels and terminal facilities. The total expense recognized in cost of sales relating to operating charges for 2023 was $83.8 million (2022 - $81.9 million). Short-term leases are leases with a lease term of twelve months or less while low-value leases are comprised of information technology and miscellaneous equipment. Such items recognized within cost of sales in 2023 were $0.2 million (2022 - $0.2 million).

Extension options

Some leases contain extension options exercisable by the Company. Where practicable, the Company seeks to include extension options in new leases to provide operational flexibility. The extension options held are exercisable only by the Company and not by the lessors. The Company assesses, at lease commencement, whether it is reasonably certain to exercise the extension options. The Company reassesses whether it is reasonably certain to exercise the options if there is a significant event or significant change in circumstances within its control. Total potential future lease payments not included in the lease liabilities should the Company exercise these extension options totals $51.8 million (2022 - $53.5 million).

	Lease liabilities recognized (discounted)		Potential future lease payments not included in lease liabilities (undiscounted)
Ocean-going vessels	$	662,903	$	1,512
Terminals and tanks	174,019			38,987
Other	35,198			11,279
Total	$	872,120	$	51,778

Leases not yet commenced

As at December 31, 2023, the Company has entered into lease agreements for which the leases have not yet commenced. Total exposure to undiscounted future cash outflows not reflected in lease liabilities is $68.7 million (2022 - $132.6 million). The leases not yet commenced as at December 31, 2023 related to terminal agreements, railcar agreements, storage tank agreements and the addition of 1 new ocean vessel in 2024 with a 5-year term, replacing an existing ocean vessel lease. The leases not yet commenced as at December 31, 2022 related to terminal agreements, storage tank agreements and 1 ocean vessel lease that commenced in 2023.

63

10. Other long-term liabilities:

As at	Dec 31 2023		Dec 31 2022
Share-based compensation liability (note 14)	$	74,107	$	70,569
Site restoration costs	32,596		36,581
Land mortgage	28,014		28,514
Defined benefit pension plans (note 21)	22,691		19,216
Cash flow hedges (note 19)	91,183		6,739
Other	1,319		2,532
	249,910		164,151
Less current maturities	(94,992)		(29,548)
	$	154,918	$	134,603

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, 2023, the total undiscounted amount of estimated cash flows required to settle the liabilities was $50.6 million (2022 - $52.1 million). The movement in the provision during the year is explained as follows:

	2023		2022
Balance at January 1	$	36,581	$	29,355
New or revised provisions	(5,573)		6,915
Accretion expense	1,588		311
Balance at December 31	$	32,596	$	36,581

11. Expenses:

For the years ended December 31	2023		2022
Cost of sales	$	2,797,794	$	3,238,312
Selling and distribution	552,693		498,552
Administrative expenses	109,415		81,657
Total expenses by function	$	3,459,902	$	3,818,521
Cost of raw materials and purchased methanol	2,329,856		2,789,921
Ocean freight and other logistics	357,495		325,893
Employee expenses, including share-based compensation	243,542		219,012
Other expenses	137,179		111,275
Cost of sales and operating expenses	3,068,072		3,446,101
Depreciation and amortization	391,830		372,420
Total expenses by nature	$	3,459,902	$	3,818,521

For the year ended December 31, 2023 we recorded a share-based compensation expense of $34.5 million (2022 - expense of $15.4 million), the majority of which is included in administrative expenses for the total expenses by function presentation above.

Included in cost of sales is $466.3 million (2022 - $532.5 million) of cost of sales which are recognized as sales to Methanex in our Atlas equity investee’s statements of income.

64

12. Finance costs:

For the years ended December 31	2023		2022
Finance costs before capitalized interest	$	172,814	$	167,066
Less capitalized interest related to Geismar plant under construction	(55,448)		(36,314)
Finance costs	$	117,366	$	130,752

Finance costs are primarily comprised of interest on the unsecured notes, limited recourse debt facilities, finance lease obligations, amortization of deferred financing fees, and accretion expense associated with site restoration costs. Interest during construction projects is capitalized until the plant is substantially completed and ready for productive use.

13. Net income per common share:

Diluted net income 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 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 per common share as compared to the cash-settled method. The cash-settled method was more dilutive for the year ended December 31, 2023, and no adjustment was required for the numerator or the denominator. The equity-settled method was more dilutive for the year ended December 31, 2022, and an adjustment was required for both the numerator and denominator.

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 TSARs. For the year ended December 31, 2023 and 2022, stock options were dilutive, resulting in an adjustment to the denominator. For the year ended December 31, 2023, TSARs were not dilutive, resulting in no adjustment to the denominator. For the year ended December 31, 2022, TSARs were dilutive, resulting in an adjustment to the denominator.

A reconciliation of the numerator used for the purposes of calculating diluted net income per common share is as follows:

For the years ended December 31	2023		2022
Numerator for basic net income per common share	$	174,140	$	353,830
Adjustment for the effect of TSARs:
Cash-settled recovery included in net income	—		(316)
Equity-settled expense	—		(5,503)
Numerator for diluted net income per common share	$	174,140	$	348,011

A reconciliation of the denominator used for the purposes of calculating diluted net income per common share is as follows:

For the years ended December 31	2023	2022
Denominator for basic net income per common share	67,805,220	71,422,360
Effect of dilutive stock options	6,395	10,108
Effect of dilutive TSARS	—	245,016
Denominator for diluted net income per common share	67,811,615	71,677,484

For the years ended December 31, 2023 and 2022, basic and diluted net income per common share attributable to Methanex shareholders were as follows:

For the years ended December 31	2023		2022
Basic net income per common share	$	2.57	$	4.95
Diluted net income per common share	$	2.57	$	4.86

65

14. 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, 2023, the Company had 4,010,076 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 from the date of grant. SARs and TSARs units outstanding at December 31, 2023 and 2022 are as follows:

	SARs			TSARs
	Number of units	Exercise price USD		Number of units	Exercise price USD
Outstanding at December 31, 2021	666,256	$	45.70	2,380,237	$	42.05
Granted	32,730	48.49		266,090	48.49
Exercised	(129,162)	37.17		(290,577)	35.94
Cancelled	(12,900)	55.70		(21,922)	46.45
Expired	(149,237)	55.66		(145,469)	55.82
Outstanding at December 31, 2022	407,687	$	44.67	2,188,359	$	42.68
Granted	51,160	50.49		169,190	50.49
Exercised	(50,715)	33.85		(336,535)	31.88
Cancelled	(5,600)	53.69		(13,544)	51.36
Outstanding at December 31, 2023	402,532	$	46.65	2,007,470	$	45.10

Information regarding the SARs and TSARs outstanding as at December 31, 2023 is as follows:

	Units outstanding at December 31, 2023				Units exercisable at December 31, 2023
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
$29.27 to $38.79	3.52	112,962	$	32.60	99,800	$	31.78
$45.40 to $50.49	2.93	171,010	49.93		98,029	49.96
$54.65 to $78.59	1.39	118,560	55.30		118,560	55.30
	2.64	402,532	$	46.65	316,389	$	46.23
TSARs
$29.27 to $38.79	3.57	776,194	$	33.05	666,922	$	32.11
$45.40 to $50.49	3.65	673,316	49.55		330,265	49.62
$54.65 to $78.59	1.66	557,960	56.48		557,960	56.48
	3.07	2,007,470	$	45.10	1,555,147	$	44.57

The fair value of each outstanding SARs and TSARs grant was estimated on December 31, 2023 and 2022 using the Black-Scholes option pricing model with the following weighted average assumptions:

	2023		2022
Risk-free interest rate	4.5%		4.4%
Expected dividend yield	1.6%		1.9%
Expected life of SARs and TSARs (years)	1.4		1.8
Expected volatility	38%		51%
Expected forfeitures	0%		0%
Weighted average fair value (USD per unit)	$	10.75	$	8.72

Compensation expense for SARs and TSARs is measured based on their fair value and is recognized over the vesting period. Changes in fair value each period are recognized in net income for the proportion of the service that has been rendered at each reporting date. The fair value as at December 31, 2023 was $26.7 million compared with the recorded liability of $25 million. The

66

difference between the fair value and the recorded liability of $1.7 million will be recognized over the weighted average remaining vesting period of approximately 1.4 years.

For the year ended December 31, 2023, compensation expense related to SARs and TSARs included an expense in cost of sales and operating expenses of $10.5 million (2022 - expense of $1.8 million). This included an expense of $6.6 million (2022 - recovery of $3.7 million) related to the effect of the change in the Company’s share price.

b) Deferred, restricted and performance share units (old plan and new plan):

Deferred, restricted and performance share units (old plan and new plan) outstanding as at December 31, 2023 and 2022 are as follows:

	Number of deferred share units	Number of restricted share units	Number of performance share units (new plan)
Outstanding at December 31, 2021	133,418	332,385	689,688
Granted	19,909	104,810	199,430
Performance factor impact on redemption1	—	—	(14,796)
Granted in lieu of dividends	2,434	5,561	11,764
Redeemed	—	(82,039)	(119,714)
Cancelled	—	(19,788)	(21,485)
Outstanding at December 31, 2022	155,761	340,929	744,887
Granted	18,417	104,980	179,340
Performance factor impact on redemption1	—	—	143,065
Granted in lieu of dividends	2,484	5,267	10,411
Redeemed	(18,962)	(131,398)	(435,035)
Cancelled	—	(8,924)	(11,546)
Outstanding at December 31, 2023	157,700	310,854	631,122

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. These units relate to performance share units redeemed in the quarter ended March 31, 2023 and the quarter ended March 31, 2022.

Performance share units are redeemable for cash based on the market value of the Company's common shares and are non-dilutive to shareholders. Units vest over three years and include two equally weighted performance factors: (i) relative total shareholder return of Methanex shares versus a specific market index (the market performance factor) and (ii) three year average Return on Capital Employed (the non-market performance factor). The market performance factor is measured by the Company at the grant date and reporting date using a Monte-Carlo simulation model to determine fair value. The non-market performance factor reflects management's best estimate to determine the expected number of units to vest. Based on these performance factors the performance share unit payout will range between 0% to 200%.

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 for the proportion of the service that has been rendered at each reporting date. The fair value of deferred, restricted and performance share units at December 31, 2023 was $58.6 million compared with the recorded liability of $48.9 million. The difference between the fair value and the recorded liability of $9.7 million will be recognized over the weighted average remaining vesting period of approximately 1.7 years.

For the year ended December 31, 2023, compensation expense related to deferred, restricted and performance share units included in cost of sales and operating expenses was an expense of $23.9 million (2022 - expense of $13.5 million). This included an expense of $8.8 million (2022 - recovery of $3.4 million) related to the effect of the change in the Company’s share price.

67

15. 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, 2023 and 2022, revenues attributed to geographic regions, based on the location of customers, were as follows:

Revenue	China			Europe			United States			South America			South Korea			Other Asia			Canada			TOTAL
2023	$	1,042,723		$	722,578		$	574,951		$	428,617		$	391,821		$	387,373		$	175,412		$	3,723,475
	28		%	19		%	15		%	12		%	11		%	10		%	5		%	100		%
2022	$	1,105,610		$	830,507		$	657,495		$	458,989		$	542,646		$	518,901		$	197,040		$	4,311,188
	26		%	19		%	15		%	11		%	13		%	12		%	4		%	100		%

As at December 31, 2023 and 2022, the net book value of property, plant and equipment by geographic region, and the Company's shipping business, was as follows:

Property, plant and equipment 1	United States		Egypt		New Zealand		Canada		Chile		Trinidad		Waterfront Shipping		Other		TOTAL
December 31, 2023	$	2,537,515	$	520,497	$	232,831	$	157,483	$	113,789	$	43,835	$	775,729	$	30,089	$	4,411,768
December 31, 2022	$	2,211,333	$	564,454	$	211,544	$	165,783	$	102,467	$	70,432	$	792,016	$	37,254	$	4,155,283

1 Includes right-of-use (leased) assets.

16. Income and other taxes:

a) Income tax (expense) recovery:

For the years ended December 31	2023		2022
Current tax (expense) recovery:
Current period before undernoted items	$	(64,679)	$	(127,254)
Adjustments to prior years including resolution for certain outstanding audits	14,755		(324)
	(49,924)		(127,578)
Deferred tax recovery (expense):
Origination and reversal of temporary differences	46,982		9,589
Adjustments to prior years including resolution for certain outstanding audits	6,904		(400)
Changes in tax rates	(5,828)		(23)
Impact of foreign exchange and other	377		(1,447)
	48,435		7,719
Total income tax expense	$	(1,489)	$	(119,859)

68

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 before income taxes as follows:

For the years ended December 31	2023			2022
Income before income taxes	$	285,611		$	582,147
Deduct earnings of associate	(99,466)			(76,938)
	186,145			505,209
Canadian statutory tax rate	24.5		%	24.5		%
Income tax expense calculated at Canadian statutory tax rate	(45,606)			(123,776)
Decrease (increase) in income tax expense resulting from:
Impact of income and losses taxed in foreign jurisdictions	27,260			1,346
Utilization of unrecognized loss carryforwards and temporary differences	7,381			7,077
Impact of tax rate changes	(5,828)			(23)
Impact of foreign exchange	5,287			3,783
Other business taxes	(13,943)			(11,065)
Impact of items not taxable for tax purposes	2,373			3,624
Adjustments to prior years including resolution for certain outstanding audits	21,658			(724)
Other	(71)			(101)
Total income tax expense	$	(1,489)		$	(119,859)

c) Net deferred income tax assets and liabilities:

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

As at			Dec 31, 2023						Dec 31, 2022
	Net		Deferred tax assets		Deferred tax liabilities		Net		Deferred tax assets		Deferred tax liabilities
Property, plant and equipment (owned)	$	(363,644)	$	(189,646)	$	(173,998)	$	(403,505)	$	(230,756)	$	(172,749)
Right-of-use assets	(35,883)		(28,299)		(7,584)		(33,477)		(26,486)		(6,991)
Repatriation taxes	(109,186)		(7)		(109,179)		(106,989)		—		(106,989)
Other	(31,630)		(9,259)		(22,371)		(78,305)		(60,850)		(17,455)
	(540,343)		(227,212)		(313,131)		(622,276)		(318,092)		(304,184)
Non-capital loss carryforwards	358,774		321,602		37,172		353,986		322,608		31,378
Lease obligations	48,633		37,854		10,779		46,438		35,957		10,481
Share-based compensation	16,391		651		15,740		17,068		2,096		14,972
Other	50,955		19,355		31,600		24,141		3,784		20,357
	474,753		379,462		95,291		441,633		364,445		77,188
Net deferred income tax assets (liabilities)	$	(65,590)	$	152,250	$	(217,840)	$	(180,643)	$	46,353	$	(226,996)

69

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in the United States. These loss carryforwards expire as follows:

	Dec 31 2023
	Gross amount		Tax effect
Expire
Losses generated in 2015 (expires 2035)	$	282,437	$	62,136
Losses generated in 2016 (expires 2036)	432,581		95,168
Losses generated in 2017 (expires 2037)	234,941		51,687
	949,959		208,991
No expiry
Losses generated in 2019	255,244		56,154
Losses generated in 2020	121,321		26,691
Losses generated in 2023	29,235		6,432
Total non-capital loss carryforwards	$	1,355,760	$	298,267

Losses generated in the United States on or after January 1, 2018 may be carried forward indefinitely against future taxable income. Tax losses generated before December 31, 2017 may be carried forward for a 20 year period.

As at December 31, 2023 the Company had $201 million (2022 - $231 million) of deductible temporary differences in the United States that have not been recognized.

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in Trinidad. The loss carryforwards total $82 million (2022 - $70 million), which result in a deferred income tax asset of $29 million (2022 - $24 million). The losses generated in Trinidad may be carried forward indefinitely against future taxable income.

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in New Zealand. The loss carryforwards total $25 million (2022 - $7 million), which result in a deferred income tax asset of $7 million (2022 - $2 million). The losses generated in New Zealand may be carried forward indefinitely against future taxable income.

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in Canada. The loss carryforwards total $123 million (2022 - $121 million), which result in a deferred income tax asset of $30 million (2022 - $30 million). The losses were generated in 2020 and can be carried forward 20 years against future taxable income.

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

			2023						2022
	Net		Deferred tax assets		Deferred tax liabilities		Net		Deferred tax assets		Deferred tax liabilities
Balance, January 1	$	(180,643)	$	46,353	$	(226,996)	$	(114,536)	$	98,169	$	(212,705)
Deferred income tax recovery (expense) included in net income	48,435		40,159		8,276		7,719		22,578		(14,859)
Deferred income tax recovery (expense) included in other comprehensive income	66,636		65,738		898		(72,440)		(74,394)		1,954
Other	(17)		—		(17)		(1,386)		—		(1,386)
Balance, December 31	$	(65,590)	$	152,250	$	(217,840)	$	(180,643)	$	46,353	$	(226,996)

International Tax Reform — Pillar Two Rules

Pillar Two rules were published by the Organization for Economic Co-operation and Development and establish a global minimum fifteen percent top-up tax regime. Under currently proposed legislation, Pillar Two rules are expected to be implemented in Canada and be effective for tax years beginning January 1, 2024. The Company is in scope of the proposed legislation and has performed a preliminary assessment of the potential exposure to to-up taxes that would apply based on our historical financial results in the jurisdictions in which we operate. Based on the assessment, we do not expect to have a material exposure to Pillar Two top-up taxes.

70

17. Supplemental cash flow information:

a) Changes in non-cash working capital:

Changes in non-cash working capital for the years ended December 31, 2023 and 2022 were as follows:

For the years ended December 31	2023		2022
Changes in non-cash working capital:
Trade and other receivables	$	(32,690)	$	50,442
Inventories	12,997		19,785
Prepaid expenses	(19,439)		(2,622)
Trade, other payables and accrued liabilities	(17,333)		(46,751)
	(56,465)		20,854
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid and interest received	6,027		59,283
Changes in non-cash working capital having a cash effect	$	(50,438)	$	80,137
These changes relate to the following activities:
Operating	$	(59,058)	$	54,122
Financing	68,750		1,771
Investing	(60,130)		24,244
Changes in non-cash working capital	$	(50,438)	$	80,137

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

	Long term debt (note 8)		Lease obligations (note 9)
Balance at December 31, 2022	$	2,151,513	$	870,163
Changes from financing cash flows
Repayment of long-term debt and financing fees	(12,280)		—
Payment of lease obligations	—		(118,159)
Total changes from financing cash flows	(12,280)		(118,159)
Liability-related other changes
Finance costs	2,568		—
New lease obligations	—		123,187
Other	—		(3,071)
Total liability-related other changes	2,568		120,116
Balance at December 31, 2023	$	2,141,801	$	872,120

71

18. Capital disclosures:

The Company’s objective in managing liquidity and capital is to safeguard the Company’s ability to continue as a going concern and to provide financial capacity and flexibility to meet its strategic objectives, with a focus on cash preservation and liquidity.

As at	Dec 31 2023		Dec 31 2022
Liquidity:
Cash and cash equivalents	$	458,015	$	857,747
Undrawn credit facility	300,000		300,000
Undrawn G3 construction facility	—		300,000
Total liquidity	$	758,015	$	1,457,747
Capitalization:
Unsecured notes, including current portion	1,985,660		1,983,374
Other limited recourse debt facilities, including current portion	156,141		168,139
Total debt	2,141,801		2,151,513
Non-controlling interests	242,090		317,444
Shareholders’ equity	1,930,927		2,112,013
Total capitalization	$	4,314,818	$	4,580,970
Total debt to capitalization 1	50%		47%
Net debt to capitalization 2	44%		35%

1     Total debt (including Other limited recourse debt facilities) divided by total capitalization.

2     Total debt (including Other 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, private placements by limited recourse subsidiaries, 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.

The Company has access to a $300 million committed revolving credit facility with a syndicate of highly rated financial institutions expiring in July 2026. The credit facility is subject to certain financial covenants (note 8). During the year ended December 31, 2023, the Company cancelled the $300 million non-revolving construction facility for the Geismar 3 plant.

19. 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 the 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 or accumulated other comprehensive income when the underlying hedged transaction is recognized in earnings or inventory. 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.

72

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 2023		Dec 31 2022
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	121,108	$	322,748
Fair value of Egypt gas supply contract derivative 2	20,402		11,220
Financial assets not measured at fair value:
Cash and cash equivalents	458,015		857,747
Trade and other receivables, excluding tax receivable	514,739		488,184
Restricted cash included in other assets	15,772		14,349
Total financial assets 3	$	1,130,036	$	1,694,248
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	91,653	$	8,466
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	672,237		656,010
Lease obligations, including current portion	872,120		870,163
Long-term debt, including current portion	2,141,801		2,151,513
Land mortgage	28,014		28,514
Total financial liabilities	$	3,805,825	$	3,714,666

1     The Geismar 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 Egypt natural gas supply contract is measured at fair value using a Monte-Carlo model classified within Level 3 of the fair value hierarchy.

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

As at December 31, 2023, 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 were 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 and those using significant unobservable inputs classified as Level 3. The fair value of all of the Company's derivative contracts as presented in the consolidated statements of financial position are determined based on present values and the discount rates used are adjusted 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 in other comprehensive income as the forward element excluded from the hedging relationships. Once a commodity hedge settles, the amount realized during the period and not recognized immediately in the statement of income is reclassified from accumulated other comprehensive income (equity) to inventory and ultimately through cost of goods sold. Foreign currency hedges settled, are realized during the period directly to the statement of income reclassified from the statement of other comprehensive income.

Until settled, the fair value of Level 2 derivative financial instruments will fluctuate based on changes in commodity prices or foreign currency exchange rates and the fair value of Level 3 derivative financial instruments will fluctuate based on changes in the observable and unobservable valuation model inputs.

North American natural gas forward contracts

The Company manages 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: both financial and physical.

The Company has entered into forward contracts designated as cash flow hedges to manage its exposure to changes in natural gas prices for Geismar. Natural gas is fungible across the Geismar plants. Other costs incurred to transport natural gas from the contracted delivery point, Henry Hub, to the relevant production facility represent an insignificant portion of the overall underlying risk and are recognized as incurred outside of the hedging relationship. No hedge ineffectiveness has been recognized in 2023 or 2022.

73

As at	Dec 31 2023		Dec 31 2022
Maturities	2024-2032		2023-2032
Notional quantity 1	347,190		307,900
Notional quantity per day, annualized 1	50 - 170		50 - 150
Notional amount	$	1,183,319	$	1,014,264
Net fair value	$	29,925	$	316,008

1    In thousands of Million British Thermal Units (MMBtu)

Information regarding the gross amounts of the Company's natural gas forward contracts designated as cash flow hedges in the audited consolidated statements of financial position is as follows:

As at	Dec 31 2023		Dec 31 2022
Other current assets	$	470	$	32,768
Other non-current assets	120,638		289,979
Other current liabilities	(60,532)		(317)
Other long-term liabilities	(30,651)		(6,422)
Net fair value	$	29,925	$	316,008

For the year ended December 31, 2023, the Company reclassified a loss of $22.5 million (2022 - gain of $55.0 million) for natural gas hedge settlements from accumulated other comprehensive income. Realized gains and losses related to settlements of natural gas hedges are presented separately within the Consolidated Statement of Changes in Equity.

Euro forward exchange contracts

The Company manages its foreign currency exposure to euro denominated sales by executing a number of forward contracts which it has designated as cash flow hedges for its highly probable forecast euro collections. 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 2023 or 2022.

As at December 31, 2023, the Company had outstanding forward exchange contracts designated as cash flow hedges to sell a notional amount of 12.2 million euros (2022 - 21.1 million euros). The euro contracts had a negative fair value of $0.5 million included in current liabilities (2022 - negative fair value of $1.7 million included in current liabilities).

For the year ended December 31, 2023, the Company reclassified a loss of $3.1 million (2022 - gain of $5.7 million) for foreign currency hedge settlements from other comprehensive income.

Changes in cash flow hedges and excluded forward element

Information regarding the impact of changes in cash flow hedges and cost of hedging reserve in the consolidated statement of comprehensive income is as follows:

For the years ended December 31	2023		2022
Change in fair value of cash flow hedges	$	(276,619)	$	(27,742)
Forward element excluded from hedging relationships	(33,837)		406,029
	$	(310,456)	$	378,287

Fair value - Level 2 instruments

The table below shows the nominal cash outflows for derivative hedging instruments including natural gas forward contracts and forward exchange contracts, excluding credit risk adjustments, based upon contracted settlement dates. The amounts reflect the maturity profile of the hedging instruments 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.

74

As at	Dec 31 2023		Dec 31 2022
Within one year	$	65,034	$	2,050
1-3 years	17,771		7,132
3-5 years	5,537		—
More than 5 years	11,378		—
	$	99,720	$	9,182

The fair value of the Company’s derivative financial instruments as disclosed above are determined based on Bloomberg quoted market prices, 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 investment-grade counterparties. 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 $121.1 million as at December 31, 2023 (2022 - $322.7 million).

The carrying values of the Company’s financial instruments approximate their fair values, except as follows:

As at	December 31, 2023				December 31, 2022
	Carrying value		Fair value		Carrying value		Fair value
Long-term debt excluding deferred financing fees	$	2,156,534	$	2,063,661	$	2,168,585	$	1,953,932

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.

Fair value - Level 3 instrument

The Company holds a long-term natural gas supply contract expiring in 2035 with the Egyptian Natural Gas Holding Company ("EGAS"), a State-Owned enterprise in Egypt. The natural gas supply contract includes a base fixed price plus a premium based on the realized price of methanol for the full volume of natural gas to supply the plant through 2035. As a result of the amendment in 2022, the contract is being treated as a derivative measured at fair value.

There is no observable, liquid spot market or forward curve for natural gas in Egypt. In addition, there are limited observable prices for natural gas in Egypt as all natural gas purchases and sales are controlled by the government and the observed prices differ based on the produced output or usage.

Due to the absence of an observable market price for an equivalent or similar contract to measure fair value, the contract's fair value is estimated using a Monte-Carlo model. The Monte-Carlo model includes significant unobservable inputs and as a result is classified within Level 3 of the fair value hierarchy. We consider market participant assumptions in establishing the model inputs and determining fair value, including adjusting the base fixed price and methanol based premium at the valuation date to consider estimates of inflation since contract inception.

At December 31, 2023 the fair value of the derivative associated with the remaining term of the natural gas supply contract is $20.4 million (2022 - $11.2 million) recorded in Other assets. Changes in fair value of the contract are recognized in Finance income and other.

The table presents the Level 3 inputs and the sensitivities of the Monte-Carlo model valuation to changes in these inputs:

	Sensitivities
Valuation input	Input value or range	Change in input	Resulting change in valuation
Methanol price volatility (before impact of mean reversion)	35%	+/- 5%	$+/-7 million
Methanol price forecast	$300 - $415 per MT	+/- $25 per MT	$-5/+7 million
Discount rate	7.6%	+/- 1%	$-/+1 million

It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

75

20. 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 linked 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 and Tobago, 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 financial hedges in Geismar 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 the undrawn credit facility.

As at	Dec 31 2023		Dec 31 2022
Fixed interest rate debt:
Unsecured notes	$	1,985,660	$	1,983,374
Other limited recourse debt facilities	156,141		168,139
	$	2,141,801	$	2,151,513

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 19) of approximately $100.5 million as of December 31, 2023 (2022 - $104.8 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 Chinese yuan, euros, 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.

76

As at December 31, 2023, the Company had a net working capital asset of $74.4 million in non U.S. dollar currencies (2022 - $69.9 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 $7.4 million (2022 - $7.0 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, 2023, the Company had a strong liquidity position including a cash and cash equivalents balance of $458 million. In addition, the Company has access to a $300 million committed undrawn revolving credit facility.

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, 2023	Carrying amount		Contractual cash flows		1 year or less		1-3 years		3-5 years		More than 5 years
Trade and other payables 1	$	659,723	$	659,723	$	659,723	$	—	$	—	$	—
Lease obligations 2	872,120		1,174,346		172,197		266,499		220,681		514,969
Other long-term liabilities2	28,014		53,348		2,200		4,400		4,400		42,348
Long-term debt 2	2,141,801		2,932,911		425,953		220,901		879,530		1,406,527
Cash flow hedges 3	91,653		99,720		65,034		17,771		5,537		11,378
	$	3,793,311	$	4,920,048	$	1,325,107	$	509,571	$	1,110,148	$	1,975,222

1     Excludes tax, accrued interest and euro foreign currency hedges.

2     Contractual cash flows include contractual interest payments related to debt obligations and lease obligations.

3 The expected cash flows of hedges are based on current valuations of the expected settlement amounts, which will fluctuate at settlement dependent on the market prices at the future settlement dates

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, 2023 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.

77

21. 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 2023		Dec 31 2022
Accrued benefit obligations:
Balance, beginning of year	$	53,586	$	62,208
Current service cost	2,246		2,329
Past service cost	2,479		—
Interest cost on accrued benefit obligations	2,549		2,007
Benefit payments	(4,280)		(5,760)
Settlements	(3,738)		—
Actuarial (gain) loss	2,074		(4,047)
Foreign exchange (gain) loss	265		(3,151)
Balance, end of year	55,181		53,586
Fair values of plan assets:
Balance, beginning of year	38,347		46,608
Interest income on assets	1,901		1,221
Contributions	5,687		4,457
Benefit payments	(4,280)		(5,760)
Settlements	(3,680)		—
Return on plan assets	(705)		(5,173)
Foreign exchange gain (loss)	938		(3,006)
Balance, end of year	38,208		38,347
Unfunded status	16,973		15,239
Minimum funding requirement	—		—
Defined benefit obligation, net	$	16,973	$	15,239

The net defined benefit obligation above is comprised of unfunded retirement obligations and funded retirement net assets from defined benefit pension plans, as follows:

The Company has an unfunded retirement obligation of $20.2 million as at December 31, 2023 (2022 - obligation of $19.2 million) for its employees in Chile that will be funded in accordance with Chilean law. The Company also has an unfunded retirement obligation of $2.5 million as at December 31, 2023 (2022 - nil) for its employees in Egypt. The accrued benefits for the unfunded retirement arrangement in Chile and Egypt are paid when an employee leaves the Company in accordance with the plan terms and country regulations.The Company estimates that it may make benefit payments based on actuarial assumptions related to the unfunded retirement obligation of $11.3 million in Chile and $0.1 million in Egypt for 2024. Actual benefit payments in future periods will fluctuate based on employee retirements.

The Company has a net funded retirement asset of $5.3 million as at December 31, 2023 (2022 - $3.6 million) for certain employees and retirees in Canada and a net funded retirement asset of $0.4 million as at December 31, 2023 (2022 - asset of $0.4 million) in Europe. The Company estimates that it will make no additional contributions relating to its defined benefit pension plan in Canada and that it will make additional contributions relating to its defined benefit pension plan in Europe of $0.5 million in 2024.

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 7 years.

78

The Company’s net defined benefit pension plan expense charged to the consolidated statements of income for the years ended December 31, 2023 and 2022 is as follows:

For the years ended December 31	2023		2022
Net defined benefit pension plan expense:
Current service cost	$	2,246	$	2,329
Past service cost	2,479		—
Net interest cost	648		786
Cost of settlement	(58)		—
Total net defined benefit pension plan expense	$	5,315	$	3,115

The Company’s current year actuarial losses, recognized in the consolidated statements of comprehensive income for the years ended December 31, 2023 and 2022, are as follows:

For the years ended December 31	2023		2022
Actuarial loss	$	(2,827)	$	(726)

The Company had no minimum funding requirement for the years ended December 31, 2023 and 2022.

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, 2022 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, 2025.

The discount rate is the most significant actuarial assumption used in accounting for the defined benefit pension plans. As at December 31, 2023, the weighted average discount rate for the defined benefit obligation was 5.3% (2022 - 5.1%). A change of 1% in the weighted average discount rate at the end of the reporting period, while holding all other assumptions constant, would result in a change to the defined benefit obligation of approximately $3.6 million.

The asset allocation for the defined benefit pension plan assets as at December 31, 2023 and 2022 is as follows:

As at	Dec 31 2023	Dec 31 2022
Equity securities	15%	20%
Debt securities	52%	49%
Cash and other short-term securities	33%	31%
Total	100%	100%

The fair value of the above equity and debt instruments are determined based on quoted market prices in active markets whereas the fair value 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, 2023 was $11.0 million (2022 - $9.7 million).

79

22. 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 for our operating plants and Geismar 3 project up to 2044. The minimum estimated commitment under these contracts, except as noted below, is as follows:

As at December 31, 2023

2024		2025		2026		2027		2028		Thereafter
$	438,284	$	517,793	$	324,251	$	254,155	$	215,417	$	923,105

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 Tobago, Egypt and certain contracts in Chile are take-or-pay contracts denominated in United States dollars and include base and variable price components to manage our commodity price risk exposure. The variable price component of each natural gas contract is adjusted by a formula linked to methanol prices. 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 representative of the minimum take-or-pay commitment.

b) Other commitments:

The Company has future minimum payments relating primarily to short-term vessel charters, terminal facilities, and other commitments that are not leases, as follows:

As at December 31, 2023

2024		2025		2026		2027		2028		Thereafter
$	94,534	$	4,665	$	1,314	$	560	$	358	$	1,183

Refer to note 9 for a summary of lease commitments.

c) 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 0.6 million tonnes per year of methanol offtake supply when Egypt operates at capacity and 0.6 million tonnes per year of methanol offtake supply for Atlas. The offtake commitment for Atlas for 2024 will be reduced to 0.4 million tonnes of supply due to the facility running only until September 2024, when the legacy gas supply agreement expires. As at December 31, 2023, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2024. 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.

80

23. Related parties:

The Company has interests in significant subsidiaries and joint ventures as follows:

Name	Country of incorporation	Principal activities	Interest %
			Dec 31 2023	Dec 31 2022
Significant subsidiaries:
Methanex Asia Pacific Limited	Hong Kong	Marketing & distribution	100%	100%
Methanex Services (Shanghai) Co., Ltd.	China	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 SpA	Chile	Production	100%	100%
Methanex New Zealand Limited	New Zealand	Production	100%	100%
Methanex Trinidad (Titan) Unlimited	Trinidad and Tobago	Production	100%	100%
Methanex USA LLC	United States	Production	100%	100%
Methanex Louisiana LLC	United States	Production	100%	100%
Methanex Geismar III LLC	United States	Geismar 3 project development	100%	100%
Waterfront Shipping Limited 1	Canada	Shipping	60%	60%
Significant joint ventures:
Atlas Methanol Company Unlimited 2	Trinidad and Tobago	Production	63.1%	63.1%

1     On February 1, 2022, we closed the shipping partnership with Mitsui O.S.K. Lines, Ltd. ("MOL") whereby MOL acquired a 40% minority interest in Waterfront Shipping Limited.

2     Summarized financial information for the investment in Atlas is disclosed in note 6.

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, 2023 of $466 million (2022 - $532 million) is a related party transaction included in cost of sales of the Company as Methanex has marketing rights for 100% of the methanol produced by Atlas. Balances outstanding with Atlas as at December 31, 2023 and provided in the summarized financial information in note 6 include receivables owing from Atlas to the Company of $74 million (2022 - $73 million), and payables to Atlas of $172 million (2022 - $198 million). The Company has total loans outstanding to Atlas as at December 31, 2023 of $76 million (2022 - $76 million) which are unsecured and due at maturity.

Remuneration to non-management directors and senior management, which includes the members of the executive leadership team, is as follows:

For the years ended December 31	2023		2022
Short-term employee benefits	$	9,034	$	11,760
Post-employment benefits	681		656
Other long-term employee benefits	59		52
Share-based compensation expense 1	10,046		6,142
Total	$	19,820	$	18,610

1  Balance includes realized and unrealized expenses and recoveries from share-based compensation awards granted.

81

 24. 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, 2023						Dec 31, 2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Current assets	$	129,320	$	154,308	$	283,628	$	133,499	$	180,227	$	313,726
Non-current assets	521,708		791,512		1,313,220		557,484		806,079		1,363,563
Current liabilities	(123,969)		(185,459)		(309,428)		(56,689)		(112,085)		(168,774)
Non-current liabilities	(101,810)		(718,915)		(820,725)		(104,101)		(744,936)		(849,037)
Net assets	425,249		41,446		466,695		530,193		129,285		659,478
Carrying amount of Methanex non-controlling interests	$	214,568	$	27,522	$	242,090	$	251,949	$	65,495	$	317,444

For the years ended December 31			2023						2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Revenue	$	258,782	$	670,834	$	929,616	$	212,339	$	576,810	$	789,149
Net and total comprehensive income	55,428		129,411		184,839		107,375		67,670		175,045
Net and total comprehensive income attributable to Methanex non-controlling interests	56,310		53,672		109,982		77,133		31,325		108,458
Sale of partial interest in non-controlling interests and equity contributions by non-controlling interest	$	—	$	—	$	—	$	—	$	22,545	$	22,545
Distributions made and accrued to non-controlling interests	$	(93,696)	$	(91,640)	$	(185,336)	$	(75,996)	$	(8,718)	$	(84,714)

For the years ended December 31			2023						2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Cash flows from operating activities	$	131,667	$	251,290	$	382,957	$	226,647	$	94,355	$	321,002
Cash flows from (used in) financing activities	(99,490)		(300,824)		(400,314)		(152,806)		(52,796)		(205,602)
Cash flows from (used in) investing activities	$	(5,560)	$	2,686	$	(2,874)	$	(35,110)	$	215	$	(34,895)

1    On February 1, 2022, we closed the shipping partnership with Mitsui O.S.K. Lines, Ltd. ("MOL") whereby MOL acquired a minority interest in Waterfront Shipping Limited.

25. Sale of interest in subsidiary:

In 2022, the Company completed the sale of a 40% equity interest in Waterfront Shipping Limited ("WFS") for cash proceeds of approximately $149 million. The sale reduces the Company's interest in WFS to 60% while retaining control of the consolidated WFS group of companies. The sale has been accounted for as a transaction between equity holders as Methanex controls WFS before and after the transaction and the $126 million gain on sale has been reflected as an increase in shareholders' equity.

26. Egypt gas redirection and sale proceeds:

In 2022, the Company entered into an agreement to redirect and sell the Egypt plant's contracted natural gas during an extended turnaround for a three-month period.

The Company has recognized $118 million ($59 million - attributable to Methanex) for the year ended December 31, 2022 to redirect and sell the contracted natural gas during the diversion period.

82

XML

Cover	12 Months Ended
	Dec. 31, 2023 shares
Entity Addresses [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Entity File Number	000-20115
Entity Registrant Name	METHANEX CORPORATION
Entity Incorporation, State or Country Code	Z4
Entity Primary SIC Number	2860
Entity Address, Address Line One	1800 Waterfront Centre
Entity Address, Address Line Two	200 Burrard Street
Entity Address, City or Town	Vancouver
Entity Address, State or Province	BC
Entity Address, Country	CA
Entity Address, Postal Zip Code	V6C 3M1
City Area Code	604
Local Phone Number	661-2600
Title of 12(b) Security	Common Shares
Trading Symbol	MEOH
Security Exchange Name	NASDAQ
Security Reporting Obligation	15(d)
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	67,387,492
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Central Index Key	0000886977
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false
Agent for service in United States
Entity Addresses [Line Items]
Contact Personnel Name	CT Corporation System
Entity Address, Address Line One	28 Liberty Street
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10005
City Area Code	212
Local Phone Number	894-8940

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Firm ID	85
Auditor Name	KPMG LLP
Auditor Location	Vancouver, British Columbia, Canada

XML

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 458,015	$ 857,747
Trade and other receivables (note 3)	533,615	500,925
Inventories (note 4)	426,774	439,771
Prepaid expenses	58,024	38,585
Other assets (note 7)	3,893	39,346
Current assets	1,480,321	1,876,374
Non-current assets:
Property, plant and equipment (note 5)	4,411,768	4,155,283
Investment in associate (note 6)	184,249	197,083
Deferred income tax assets (note 16)	152,250	46,353
Other assets (note 7)	197,967	356,387
Non-current assets	4,946,234	4,755,106
Assets	6,426,555	6,631,480
Current liabilities:
Trade, other payables and accrued liabilities	771,867	789,200
Current maturities on long-term debt (note 8)	314,716	15,133
Current maturities on lease obligations (note 9)	120,731	108,736
Current maturities on other long-term liabilities (note 10)	94,992	29,548
Current liabilities	1,302,306	942,617
Non-current liabilities:
Long-term debt (note 8)	1,827,085	2,136,380
Lease obligations (note 9)	751,389	761,427
Other long-term liabilities (note 10)	154,918	134,603
Deferred income tax liabilities (note 16)	217,840	226,996
Non-current liabilities	2,951,232	3,259,406
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, 2023 were 67,387,492 (2022 - 69,239,136)	391,924	401,295
Contributed surplus	1,838	1,904
Retained earnings	1,514,264	1,466,872
Accumulated other comprehensive income	22,901	241,942
Shareholders’ equity	1,930,927	2,112,013
Non-controlling interests	242,090	317,444
Total equity	2,173,017	2,429,457
Equity and liabilities	$ 6,426,555	$ 6,631,480

XML

Consolidated Statements of Financial Position (Parenthetical) - shares	Dec. 31, 2023	Dec. 31, 2022
Preferred shares
Statement [Line Items]
Number of shares authorised (in shares)	25,000,000	25,000,000
Common shares | Capital stock
Statement [Line Items]
Number of shares issued (in shares)	67,387,492	69,239,136
Number of shares outstanding (in shares)	67,387,492	69,239,136

XML

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Profit or loss [abstract]
Revenue	$ 3,723,475	$ 4,311,188
Cost of sales and operating expenses (note 11)	(3,068,072)	(3,446,101)
Depreciation and amortization (note 11)	(391,830)	(372,420)
Egypt gas redirection and sale proceeds (note 26)	0	117,946
Operating income	263,573	610,613
Earnings of associate (note 6)	99,466	76,938
Finance costs (note 12)	(117,366)	(130,752)
Finance income and other	39,938	25,348
Income before income taxes	285,611	582,147
Income tax (expense) recovery (note 16):
Current	(49,924)	(127,578)
Deferred	48,435	7,719
Total income tax expense	(1,489)	(119,859)
Net income	284,122	462,288
Attributable to:
Methanex Corporation shareholders	174,140	353,830
Non-controlling interests (note 24)	109,982	108,458
Net income	$ 284,122	$ 462,288
Income per common share for the year attributable to Methanex Corporation shareholders:
Basic net income per common share (note 13) (in usd per share)	$ 2.57	$ 4.95
Diluted net income per common share (note 13) (in usd per share)	$ 2.57	$ 4.86
Weighted average number of common shares outstanding (note 13) (in shares)	67,805,220	71,422,360
Diluted weighted average number of common shares outstanding (note 13) (in shares)	67,811,615	71,677,484

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of comprehensive income [abstract]
Net income	$ 284,122	$ 462,288
Items that may be reclassified to income:
Change in cash flow hedges and excluded forward element (note 19)	(310,456)	378,287
Realized losses (gains) on foreign exchange hedges reclassified to revenue	3,105	(5,674)
Items that will not be reclassified to income:
Actuarial loss on defined benefit pension plans (note 21(a))	(2,827)	(726)
Taxes on above items	66,636	(72,440)
Other comprehensive income (loss)	(243,542)	299,447
Comprehensive income	40,580	761,735
Attributable to:
Methanex Corporation shareholders	(69,402)	653,277
Non-controlling interests (note 24)	$ 109,982	$ 108,458

XML

Consolidated Statements of Changes in Equity $ in Thousands	USD ($)	Capital stock USD ($)	Capital stock Common shares shares	Contributed surplus USD ($)	Retained earnings USD ($)	Accumulated other comprehensive income (loss) USD ($)	Shareholders’ equity USD ($)	Non-controlling interests USD ($)
Balance, beginning of period (in shares) at Dec. 31, 2021 | shares			74,774,087
Balance, beginning of period at Dec. 31, 2021	$ 1,954,731	$ 432,728		$ 1,928	$ 1,251,640	$ (2,720)	$ 1,683,576	$ 271,155
Net income	462,288				353,830		353,830	108,458
Other comprehensive income (loss)	299,447				(252)	299,699	299,447
Compensation expense recorded for stock options	110			110			110
Issue of shares on exercise of stock options (in shares) | shares			16,800
Issue of shares on exercise of stock options	582	582					582
Reclassification of grant date fair value on exercise of stock options	0	134		(134)
Sale of partial interest in subsidiary (note 25)	148,990				126,445		126,445	22,545
Payments for repurchase of shares (in shares) | shares			(5,551,751)
Payments for repurchase of shares	(252,985)	(32,149)			(220,836)		(252,985)
Dividend payments to Methanex Corporation shareholders	(43,955)				(43,955)		(43,955)
Distributions made and accrued to non-controlling interests	(84,714)							(84,714)
Realized hedge loss (gains) recognized in cash flow hedges	(55,037)					(55,037)	(55,037)
Balance, end of period (in shares) at Dec. 31, 2022 | shares			69,239,136
Balance, end of period at Dec. 31, 2022	2,429,457	401,295		1,904	1,466,872	241,942	2,112,013	317,444
Net income	284,122				174,140		174,140	109,982
Other comprehensive income (loss)	(243,542)				(1,976)	(241,566)	(243,542)
Compensation expense recorded for stock options	124			124			124
Issue of shares on exercise of stock options (in shares) | shares			43,067
Issue of shares on exercise of stock options	1,437	1,437					1,437
Reclassification of grant date fair value on exercise of stock options	0	190		(190)
Payments for repurchase of shares (in shares) | shares			(1,894,711)
Payments for repurchase of shares	(86,392)	(10,998)			(75,394)		(86,392)
Dividend payments to Methanex Corporation shareholders	(49,378)				(49,378)		(49,378)
Distributions made and accrued to non-controlling interests	(185,336)							(185,336)
Realized hedge loss (gains) recognized in cash flow hedges	22,525					22,525	22,525
Balance, end of period (in shares) at Dec. 31, 2023 | shares			67,387,492
Balance, end of period at Dec. 31, 2023	$ 2,173,017	$ 391,924		$ 1,838	$ 1,514,264	$ 22,901	$ 1,930,927	$ 242,090

XML

Consolidated Statements of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of changes in equity [abstract]
Dividend payments to Methanex Corporation shareholders (in usd per share)	$ 0.730	$ 0.620

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net income	$ 284,122	$ 462,288
Deduct earnings of associate	(99,466)	(76,938)
Dividends received from associate	112,318	97,174
Add (deduct) non-cash items:
Depreciation and amortization	391,830	372,420
Income tax expense	1,489	119,859
Share-based compensation expense	34,502	15,398
Finance costs	117,366	130,752
Other	(24,651)	(12,985)
Interest received	21,633	9,590
Income taxes paid	(81,922)	(163,828)
Other cash payments, including share-based compensation	(37,894)	(20,503)
Cash flows from operating activities before undernoted	719,327	933,227
Changes in non-cash working capital (note 17(a))	(59,058)	54,122
Cash flows from/(used in) operating activities	660,269	987,349
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Payments for repurchase of shares	(86,392)	(252,985)
Dividend payments to Methanex Corporation shareholders	(49,378)	(43,955)
Interest paid	(168,636)	(161,816)
Repayment of long-term debt and financing fees (note 8)	(12,280)	(9,151)
Repayment of lease obligations	(118,159)	(105,863)
Distributions to non-controlling interests	(185,336)	(84,713)
Proceeds on issue of shares on exercise of stock options	1,437	582
Restricted cash for debt service accounts	(1,424)	(1,394)
Sale of partial interest in subsidiary (note 25)	0	148,990
Changes in non-cash working capital related to financing activities (note 17(a))	68,750	1,771
Cash flows from (used in) financing activities	(551,418)	(508,534)
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Property, plant and equipment	(178,464)	(145,701)
Geismar plant under construction	(269,989)	(431,680)
Changes in non-cash working capital related to investing activities (note 17(a))	(60,130)	24,244
Cash flows from (used in) investing activities	(508,583)	(553,137)
Decrease in cash and cash equivalents	(399,732)	(74,322)
Cash and cash equivalents, beginning of year	857,747	932,069
Cash and cash equivalents, end of year	$ 458,015	$ 857,747

XML

Nature of operations	12 Months Ended
	Dec. 31, 2023
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.

XML

Material accounting policies

12 Months Ended

Dec. 31, 2023

Corporate information and statement of IFRS compliance [abstract]

Material accounting policies

Material 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 7, 2024.

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 controlled by the Company. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. 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. 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)), leases (note 2(i)), 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 records provisions for expected credit losses for receivables measured at amortized cost. The Company records an allowance for doubtful accounts or writes down the receivable to estimated net realizable value, if not collectible in full, based on expected credit losses. Expected credit losses are based on historic and forward looking customer specific factors including historic credit losses incurred.

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 ocean freight costs for the shipment of product.

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 at installation, excluding costs related to turnarounds, initially range up to 25 years depending on the specific asset component and the production facility to which it is related. Right-of-use (leased) assets are depreciated from the lease commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. 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. The estimated useful life of production facilities may be adjusted from time-to-time based on turnarounds, plant refurbishments and gas availability. 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.

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 may 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 the asset or idle the asset for a significant period of time; 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. Fair value less costs of disposal is determined by estimating the price that would be received to sell an asset in an orderly transaction between market participants under current market conditions, less incremental costs directly attributable to the disposal, excluding finance costs and income tax expense. 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.

When impairment indicators exist, 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, incorporating third-party assumptions, forecasts and market observable prices when appropriate. 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 when testing for impairment 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. In relation to previous impairment charges, we do not believe that there are significant changes in events or circumstances that would support their reversal.

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:

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether:

•the contract involves the use of an identified asset - this may be specified explicitly or implicitly and should be physically distinct or represent substantially all of the capacity of a physically distinct asset. If the supplier has a substantive substitution right, then the asset is not identified;

•the Company has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use; and

•the Company has the right to direct the use of the asset. The Company has the right when it has the decision-making rights that are most relevant to changing how and for what purpose the asset is used.

For contracts that contain a lease, the Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. The estimated useful lives of right-of-use assets are determined on the same basis as those of property, plant and equipment. In addition, the right-of-use asset is assessed for impairment losses, should a trigger be identified and adjusted for impairment if required. Lease terms range up to 20 years for vessels, terminals, equipment, and other items.

The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Company’s estimate of the amount expected to be payable under a residual value guarantee or if the Company changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed upon a trigger by an event or a significant change in circumstances.

Certain leases contain non-lease components, excluded from the right-of-use asset and lease liability, related to operating charges for ocean vessels, terminal facilities and rail transport contracts. Judgment is applied in the determination of the stand-alone price of the lease and non-lease components.

The Company has elected not to recognize right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less and leases of low-value assets, except for terminal and vessel leases. The Company recognizes the lease payments associated with these leases as an expense 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 transferred to 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 ("PSUs") granted from 2019 onwards are redeemable for cash based on the market value of the Company's common shares and are non-dilutive to shareholders. PSUs vest over three years and include two performance factors: (i) relative total shareholder return of Methanex shares versus a specific market index (the market performance factor) and (ii) three year average Return on Capital Employed ("ROCE") (the non-market performance factor). The market performance factor is measured by the Company at the grant date and reporting date using a Monte-Carlo simulation model to determine fair value. The non-market performance factor reflects management's best estimate of ROCE over the performance period (using actual ROCE as applicable) to determine the expected number of units to vest. Based on these performance factors the performance share unit payout will range between 0% to 200%.

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 14.

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 13.

n) Revenue recognition:

Revenue is recognized based on individual contract terms at the point in time when control of 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 contractual performance obligation has not been met during shipment. For methanol sold on a consignment basis, revenue is recognized at the point in time the customer draws down the consigned methanol. Revenue is measured and recorded at the most likely amount of consideration the Company expects to receive.

By contract, the Company sells all the methanol produced by the Atlas Joint Venture and earns a commission on the sale of the methanol. As the Company obtains title and control of the methanol from the Atlas facility and directs the sale of the methanol to the Company's customers, the Company recognizes the revenue on these sales to customers at the gross amount receivable from the customers based on the Company's revenue recognition policy noted above. Cost of sales is recognized for these sales as the amount due to the Atlas Joint Venture which is the gross amount receivable less the commission earned by the Company.

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.

Assessment of contracts as derivative instruments, applicability of the own use exemption, determination of whether hybrid instruments contain embedded derivatives to be separated, the valuation of financial instruments and derivatives and hedge effectiveness assessments require a high degree of judgment and are considered critical accounting judgements and estimates due to the complex nature of these products and the potential impact on our financial statements.

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 19.

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.

Uncertain tax positions derive from the complexity of tax law and its interpretation by tax authorities and ultimately the judicial system in place in each jurisdiction. Uncertain tax positions, including interest and penalties, are recognized and measured applying management estimates. Given the complexity, management engages third-party experts as required, for the interpretation of tax law, transfer pricing regulations and determination of the ultimate resolution of its tax positions. The Company is subject to various taxation authorities who may interpret tax legislation differently, and resolve matters over longer-periods of time. The differences in judgement in assessing uncertain tax positions may result in material differences in the final amount or timing of the payment of taxes or settlement of tax assessments.

r) Segmented information:

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

s) Application of new and revised accounting standards:

The Company has adopted the amendments to IAS 1 Presentation of Financial Statements as well as IAS 8 Changes in Accounting Estimates and Errors regarding the disclosure of accounting policies and accounting estimates, and IAS 12, Income Taxes ("IAS 12") regarding deferred tax related to assets and liabilities arising from a single transaction, which were effective for annual periods beginning on January 1, 2023. The amendments did not have a material impact on the Company's consolidated financial statements.

In May 2023, the IASB issued a further amendment to IAS 12, establishing a mandatory exception for recognition and disclosure of deferred taxes related to the Pillar Two model rules published by the Organization for Economic Co-operation and Development (“Pillar Two rules”). The Pillar Two rules establish a global minimum fifteen percent top-up tax regime and are expected to apply to Methanex beginning in 2024. The Company has applied this mandatory exception in the current period. Refer to note 16 for further disclosure on the expected impact of Pillar Two rules.

t) Anticipated changes to International Financial Reporting Standards:

The following new or amended standards or interpretations that are effective for annual periods beginning on or after January 1, 2024 are being reviewed to determine the potential impact: amendments to IAS 1, Presentation of Financial Statements regarding the classification of liabilities as current or non-current, IFRS 16, Leases regarding sale-and-leaseback transactions and IAS 7, Statement of Cash Flows regarding supplier finance arrangements.

XML

Trade and other receivables

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Trade and other receivables

Trade and other receivables: 

As at	Dec 31 2023		Dec 31 2022
Trade	$	431,602	$	407,733
Value-added and other tax receivables	22,292		14,986
Other	79,721		78,206
	$	533,615	$	500,925

XML

Inventories	12 Months Ended
	Dec. 31, 2023
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, 2023 is $2,860 million (2022 - $3,157 million).

XML

Property, plant and equipment

12 Months Ended

Dec. 31, 2023

Property, plant and equipment [abstract]

Property, plant and equipment

Property, plant and equipment:

	Owned Assets (a)		Right-of-use assets (b)		Total
Net book value at December 31, 2023	$	3,654,475	$	757,293	$	4,411,768
Net book value at December 31, 2022	$	3,398,805	$	756,478	$	4,155,283

a) Owned assets:

	Buildings, plant installations and machinery		Plants Under Construction1		Ocean vessels		Other		TOTAL
Cost at January 1, 2023	$	5,000,999	$	1,001,888	$	240,867	$	140,081	$	6,383,835
Additions	174,058		353,609		253		4,153		532,073
Disposals and other	(294,850)		—		(397)		(15,571)		(310,818)
Cost at December 31, 2023	4,880,207		1,355,497		240,723		128,663		6,605,090
Accumulated depreciation at January 1, 2023	2,827,870		—		49,310		107,850		2,985,030
Depreciation	248,783		—		12,080		2,153		263,016
Disposals and other	(281,951)		—		—		(15,480)		(297,431)
Accumulated depreciation at December 31, 2023	2,794,702		—		61,390		94,523		2,950,615
Net book value at December 31, 2023	$	2,085,505	$	1,355,497	$	179,333	$	34,140	$	3,654,475

1    The Company is constructing a 1.8 million tonne methanol plant in Geismar, Louisiana adjacent to its Geismar 1 and Geismar 2 facilities. Included in cost of Plants Under Construction are $150 million (2022: $94 million) of capitalized interest and finance charges.

	Buildings, plant installations and machinery		Plants under construction		Ocean vessels		Other		TOTAL
Cost at January 1, 2022	$	4,908,492	$	561,860	$	240,525	$	138,378	$	5,849,255
Additions	140,326		440,028		342		1,703		582,399
Disposals and other	(47,819)		—		—		—		(47,819)
Cost at December 31, 2022	5,000,999		1,001,888		240,867		140,081		6,383,835
Accumulated depreciation at January 1, 2022	2,631,268		—		37,271		105,518		2,774,057
Depreciation	248,032		—		12,039		2,332		262,403
Disposals and other	(51,430)		—		—		—		(51,430)
Accumulated depreciation at December 31, 2022	2,827,870		—		49,310		107,850		2,985,030
Net book value at December 31, 2022	$	2,173,129	$	1,001,888	$	191,557	$	32,231	$	3,398,805

b) Right-of-use (leased) assets:

	Ocean vessels		Terminals and tanks		Other		TOTAL
Cost at January 1, 2023	$	846,977	$	286,036	$	68,701	$	1,201,714
Additions	83,333		52,909		5,951		142,193
Disposals and other	(19,589)		(6,504)		(16,031)		(42,124)
Cost at December 31, 2023	910,721		332,441		58,621		1,301,783
Accumulated depreciation at January 1, 2023	245,873		160,163		39,200		445,236
Depreciation	88,040		36,140		6,583		130,763
Disposals and other	(19,589)		—		(11,920)		(31,509)
Accumulated depreciation at December 31, 2023	314,324		196,303		33,863		544,490
Net book value at December 31, 2023	$	596,397	$	136,138	$	24,758	$	757,293

	Ocean vessels		Terminals and tanks		Other		TOTAL
Cost at January 1, 2022	$	657,774	$	258,743	$	64,700	$	981,217
Additions	232,536		27,293		4,001		263,830
Disposals and other	(43,333)		—		—		(43,333)
Cost at December 31, 2022	846,977		286,036		68,701		1,201,714
Accumulated depreciation at January 1, 2022	214,004		125,494		30,768		370,266
Depreciation	75,586		34,669		8,432		118,687
Disposals and other	(43,717)		—		—		(43,717)
Accumulated depreciation at December 31, 2022	245,873		160,163		39,200		445,236
Net book value at December 31, 2022	$	601,104	$	125,873	$	29,501	$	756,478

XML

Investment in associate

12 Months Ended

Dec. 31, 2023

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 and Tobago. 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 2023		Dec 31 2022
Cash and cash equivalents	$	126,392	$	24,420
Other current assets1	189,062		182,103
Non-current assets	149,354		184,373
Current liabilities1	(157,835)		(92,108)
Other long-term liabilities, including current maturities	(135,940)		(107,416)
Net assets at 100%	$	171,033	$	191,372
Net assets at 63.1%	$	107,921	$	120,755
Long-term receivable from Atlas1	76,328		76,328
Investment in associate	$	184,249	$	197,083

Consolidated statements of income for the years ended December 31	2023		2022
Revenue1	$	466,312	$	532,456
Cost of sales and depreciation and amortization	(289,705)		(332,999)
Gas contract settlement (b)	75,000		—
Operating income	251,607		199,457
Finance costs, finance income and other	(10,316)		(9,433)
Income tax expense	(83,659)		(68,093)
Net earnings at 100%	$	157,632	$	121,931
Earnings of associate at 63.1%	$	99,466	$	76,938
Dividends received from associate	$	112,318	$	97,174

1     Includes related party transactions between Atlas and the Company (see note 23).

b) Gas contract settlement:

Atlas stand-alone financial results for the year ended December 31, 2023 include a $75 million settlement (Methanex share, $47 million, net of tax, $31 million) related to a historical dispute under an existing gas contract. The amount was received in cash in the fourth quarter of 2023.

c) Atlas tax assessments:

The Board of Inland Revenue of Trinidad and Tobago ("the BIR") has audited and issued assessments against Atlas in respect of the 2005 to 2017 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 that commenced in 2005 and continued with affiliates through 2014 and with an unrelated third party through 2019.

The long-term fixed-price sales contracts with affiliates were established as part of the formation of Atlas and management believes these were reflective of market considerations at that time.

During the periods under assessment and continuing through 2014, approximately 50% of Atlas-produced methanol was sold under these fixed-price contracts. From late 2014 through 2019 fixed-price sales to an unrelated third party represented approximately 10% of Atlas produced methanol. Atlas had partial relief from corporation income tax until late July 2014.

The Company believes it is impractical to disclose a reasonable estimate of the potential contingent liability due to the wide range of assumptions and interpretations implicit in the assessments.

The Company has lodged objections to the assessments. No deposits have been required to lodge objections. Based on the merits of the cases and advice from legal counsel, the Company believes its position should be sustained, that Atlas has filed its tax returns and paid applicable taxes in compliance with Trinidadian tax law, and as such has not accrued for any amounts relating to these assessments. Contingencies inherently involve the exercise of significant judgment, and as such the outcomes of these assessments and the financial impact to the Company could be material.

The Company anticipates the resolution of this matter through the court systems to be lengthy and, at this time, cannot predict a date as to when this matter is expected to be ultimately resolved.

d) Impairment testing:

In Trinidad we announced our intention to idle the Atlas plant when its 20-year legacy natural gas supply arrangement expires in September 2024. The expected idling of the Atlas plant has been identified as an impairment indicator for the Atlas cash generating unit ("Atlas CGU"). The impairment test performed on the Atlas CGU resulted in no impairment provision recognized as the estimated recoverable value, determined on a fair value less costs of disposal methodology, exceeded the carrying value. The estimated recoverable value was based on an assumed restart date and an operating period for Atlas aligned to natural gas reserves estimates in Trinidad and Tobago with no terminal value, discounted at an after-tax rate of 16%.

The following table indicates the percentages by which key assumptions would need to change individually for the estimated Atlas CGU recoverable value to be equal to the carrying value:

Key Assumptions	Change Required for Carrying Value to Equal Recoverable Value
Long-term average realized methanol price	10 percent decrease
Production volumes	15 percent decrease
Gas price	10 percent increase
Discount rate (after-tax)	800 basis points increase

The sensitivity above has been prepared considering each variable independently. Historically, our natural gas contracts in Trinidad and Tobago have included terms whereby a change in methanol price results in a change in natural gas price, protecting margins should revenue decrease.

XML

Other assets

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Other assets

Other assets:

As at	Dec 31 2023		Dec 31 2022
Cash flow hedges (note 19)	$	121,108	$	322,748
Chile VAT receivable	17,824		18,343
Restricted cash for debt service and major maintenance of vessels (a)	15,772		14,349
Fair value of Egypt gas supply contract derivative (note 19)	20,402		11,220
Investment in Carbon Recycling International	5,620		5,620
Defined benefit pension plans (note 21)	5,718		3,977
Other	15,416		19,476
Total other assets	201,860		395,733
Less current portion (b)	(3,893)		(39,346)
	197,967		$	356,387

a) Restricted cash

The Company holds $15.8 million (2022 - $14.3 million) of restricted cash for the funding of debt service and major maintenance accounts.

b) Current portion of other assets

Other assets presented as current assets as at December 31, 2023 includes $0.5 million for the current portion of the cash flow hedge (see note 19), and $3.4 million of restricted cash for major maintenance, in particular the anticipated major maintenance costs of four vessels

XML

Long-term debt

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Long-term debt

Long-term debt:

As at	Dec 31 2023		Dec 31 2022
Unsecured notes
(i) $300 million at 4.25% due December 1, 2024	$	299,283	$	298,836
(ii) $700 million at 5.125% due October 15, 2027	694,844		693,649
(iii) $700 million at 5.25% due December 15, 2029	695,824		695,283
(iv) $300 million at 5.65% due December 1, 2044	295,709		295,606
	1,985,660		1,983,374
Other limited recourse debt facilities
(i) 5.58% due through June 30, 2031	56,637		61,978
(ii) 5.35% due through September 30, 2033	65,300		70,312
(iii) 5.21% due through September 15, 2036	34,204		35,849
	156,141		168,139
Total long-term debt1	2,141,801		2,151,513
Less current maturities1	(314,716)		(15,133)
	$	1,827,085	$	2,136,380

1  Long-term debt and current maturities are presented net of discounts and deferred financing fees of $16.8 million as at December 31, 2023 (2022 - $19.4 million).

For the year ended December 31, 2023, non-cash accretion, on an effective interest basis, of deferred financing costs included in finance costs was $2.6 million (2022 - $2.2 million).

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

	Other limited recourse debt facilities		Unsecured notes		Total
2024	$	15,367	$	300,000	$	315,367
2025	13,660		—		13,660
2026	13,796		—		13,796
2027	15,173		700,000		715,173
2028	16,026		—		16,026
Thereafter	84,574		1,000,000		1,084,574
	$	158,596	$	2,000,000	$	2,158,596

The Company has access to a $300 million committed revolving credit facility from a syndicate of highly rated financial institutions expiring in July 2026.

The revolving credit facility is subject to the following significant covenants and default provisions:

i)    the obligation to maintain a minimum EBITDA to interest coverage ratio of greater than or equal to 2:1 calculated on a four-quarter trailing basis and a debt to capitalization ratio of less than or equal to 60%, both calculated in accordance with definitions in the credit agreement that include adjustments to 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 revolving credit facility is secured by certain assets of the Company, and also includes other customary covenants including restrictions on the incurrence of additional indebtedness.

During the year, the Company cancelled the $300 million non-revolving construction facility for the Geismar 3 project. At the time of cancellation, the construction facility was undrawn.

Other limited recourse debt facilities relate to financing for certain of our ocean vessels which we own through less than wholly-owned entities under the Company's control. 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 covenants governing the Company’s unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding the Egypt entity and the Atlas joint venture 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 the Company’s assets. The indenture also contains customary default provisions.

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, 2023, management believes the Company was in compliance with all covenants related to its long-term debt obligations.

XML

Lease obligations

12 Months Ended

Dec. 31, 2023

Disclosure of Leases [Abstract]

Lease obligations

Lease obligations:

	2023		2022
Opening lease obligations	$	870,163	$	717,101
Additions, net of disposals	123,187		262,470
Interest expense	53,418		48,039
Lease payments	(171,577)		(153,901)
Effect of movements in exchange rates and other	(3,071)		(3,546)
Lease obligations at December 31	872,120		870,163
Less: current portion	(120,731)		(108,736)
Lease obligations - non current portion	$	751,389	$	761,427

The Company incurs lease payments related to ocean vessels, terminal facilities, rail cars, vehicles and equipment, and office facilities. Leases are entered into and exited in coordination with specific business requirements which includes the assessment of the appropriate durations for the related leased assets.

The following table presents the contractual undiscounted cash flows for lease obligations as at December 31, 2023:

	Lease payments		Interest component		Lease obligations
2024	$	172,197	$	51,466	$	120,731
2025	142,761		45,617		97,144
2026	123,738		39,998		83,740
2027	112,397		34,419		77,978
2028	108,284		28,547		79,737
Thereafter	514,969		102,179		412,790
	$	1,174,346	$	302,226	$	872,120

Variable lease payments and short-term and low value leases

Certain leases contain non-lease components, excluded from the right-of-use asset and lease liability, related to operating charges for ocean vessels and terminal facilities. The total expense recognized in cost of sales relating to operating charges for 2023 was $83.8 million (2022 - $81.9 million). Short-term leases are leases with a lease term of twelve months or less while low-value leases are comprised of information technology and miscellaneous equipment. Such items recognized within cost of sales in 2023 were $0.2 million (2022 - $0.2 million).

Extension options

Some leases contain extension options exercisable by the Company. Where practicable, the Company seeks to include extension options in new leases to provide operational flexibility. The extension options held are exercisable only by the Company and not by the lessors. The Company assesses, at lease commencement, whether it is reasonably certain to exercise the extension options. The Company reassesses whether it is reasonably certain to exercise the options if there is a significant event or significant change in circumstances within its control. Total potential future lease payments not included in the lease liabilities should the Company exercise these extension options totals $51.8 million (2022 - $53.5 million).

	Lease liabilities recognized (discounted)		Potential future lease payments not included in lease liabilities (undiscounted)
Ocean-going vessels	$	662,903	$	1,512
Terminals and tanks	174,019			38,987
Other	35,198			11,279
Total	$	872,120	$	51,778

Leases not yet commenced

As at December 31, 2023, the Company has entered into lease agreements for which the leases have not yet commenced. Total exposure to undiscounted future cash outflows not reflected in lease liabilities is $68.7 million (2022 - $132.6 million). The leases not yet commenced as at December 31, 2023 related to terminal agreements, railcar agreements, storage tank agreements and the addition of 1 new ocean vessel in 2024 with a 5-year term, replacing an existing ocean vessel lease. The leases not yet commenced as at December 31, 2022 related to terminal agreements, storage tank agreements and 1 ocean vessel lease that commenced in 2023.

XML

Other long-term liabilities

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Other Long-Term Liabilities

Other long-term liabilities:

As at	Dec 31 2023		Dec 31 2022
Share-based compensation liability (note 14)	$	74,107	$	70,569
Site restoration costs	32,596		36,581
Land mortgage	28,014		28,514
Defined benefit pension plans (note 21)	22,691		19,216
Cash flow hedges (note 19)	91,183		6,739
Other	1,319		2,532
	249,910		164,151
Less current maturities	(94,992)		(29,548)
	$	154,918	$	134,603

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, 2023, the total undiscounted amount of estimated cash flows required to settle the liabilities was $50.6 million (2022 - $52.1 million). The movement in the provision during the year is explained as follows:

	2023		2022
Balance at January 1	$	36,581	$	29,355
New or revised provisions	(5,573)		6,915
Accretion expense	1,588		311
Balance at December 31	$	32,596	$	36,581

XML

Expenses

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Expenses

Expenses:

For the years ended December 31	2023		2022
Cost of sales	$	2,797,794	$	3,238,312
Selling and distribution	552,693		498,552
Administrative expenses	109,415		81,657
Total expenses by function	$	3,459,902	$	3,818,521
Cost of raw materials and purchased methanol	2,329,856		2,789,921
Ocean freight and other logistics	357,495		325,893
Employee expenses, including share-based compensation	243,542		219,012
Other expenses	137,179		111,275
Cost of sales and operating expenses	3,068,072		3,446,101
Depreciation and amortization	391,830		372,420
Total expenses by nature	$	3,459,902	$	3,818,521

For the year ended December 31, 2023 we recorded a share-based compensation expense of $34.5 million (2022 - expense of $15.4 million), the majority of which is included in administrative expenses for the total expenses by function presentation above.

Included in cost of sales is $466.3 million (2022 - $532.5 million) of cost of sales which are recognized as sales to Methanex in our Atlas equity investee’s statements of income.

XML

Finance costs

12 Months Ended

Dec. 31, 2023

Borrowing costs [abstract]

Finance costs

Finance costs:

For the years ended December 31	2023		2022
Finance costs before capitalized interest	$	172,814	$	167,066
Less capitalized interest related to Geismar plant under construction	(55,448)		(36,314)
Finance costs	$	117,366	$	130,752

Finance costs are primarily comprised of interest on the unsecured notes, limited recourse debt facilities, finance lease obligations, amortization of deferred financing fees, and accretion expense associated with site restoration costs. Interest during construction projects is capitalized until the plant is substantially completed and ready for productive use.

XML

Net income per common share

12 Months Ended

Dec. 31, 2023

Earnings per share [abstract]

Net income per common share

Net income per common share:

Diluted net income 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 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 per common share as compared to the cash-settled method. The cash-settled method was more dilutive for the year ended December 31, 2023, and no adjustment was required for the numerator or the denominator. The equity-settled method was more dilutive for the year ended December 31, 2022, and an adjustment was required for both the numerator and denominator.

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 TSARs. For the year ended December 31, 2023 and 2022, stock options were dilutive, resulting in an adjustment to the denominator. For the year ended December 31, 2023, TSARs were not dilutive, resulting in no adjustment to the denominator. For the year ended December 31, 2022, TSARs were dilutive, resulting in an adjustment to the denominator.

A reconciliation of the numerator used for the purposes of calculating diluted net income per common share is as follows:

For the years ended December 31	2023		2022
Numerator for basic net income per common share	$	174,140	$	353,830
Adjustment for the effect of TSARs:
Cash-settled recovery included in net income	—		(316)
Equity-settled expense	—		(5,503)
Numerator for diluted net income per common share	$	174,140	$	348,011

A reconciliation of the denominator used for the purposes of calculating diluted net income per common share is as follows:

For the years ended December 31	2023	2022
Denominator for basic net income per common share	67,805,220	71,422,360
Effect of dilutive stock options	6,395	10,108
Effect of dilutive TSARS	—	245,016
Denominator for diluted net income per common share	67,811,615	71,677,484

For the years ended December 31, 2023 and 2022, basic and diluted net income per common share attributable to Methanex shareholders were as follows:

For the years ended December 31	2023		2022
Basic net income per common share	$	2.57	$	4.95
Diluted net income per common share	$	2.57	$	4.86

XML

Share-based compensation

12 Months Ended

Dec. 31, 2023

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, 2023, the Company had 4,010,076 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 from the date of grant. SARs and TSARs units outstanding at December 31, 2023 and 2022 are as follows:

	SARs			TSARs
	Number of units	Exercise price USD		Number of units	Exercise price USD
Outstanding at December 31, 2021	666,256	$	45.70	2,380,237	$	42.05
Granted	32,730	48.49		266,090	48.49
Exercised	(129,162)	37.17		(290,577)	35.94
Cancelled	(12,900)	55.70		(21,922)	46.45
Expired	(149,237)	55.66		(145,469)	55.82
Outstanding at December 31, 2022	407,687	$	44.67	2,188,359	$	42.68
Granted	51,160	50.49		169,190	50.49
Exercised	(50,715)	33.85		(336,535)	31.88
Cancelled	(5,600)	53.69		(13,544)	51.36
Outstanding at December 31, 2023	402,532	$	46.65	2,007,470	$	45.10

Information regarding the SARs and TSARs outstanding as at December 31, 2023 is as follows:

	Units outstanding at December 31, 2023				Units exercisable at December 31, 2023
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
$29.27 to $38.79	3.52	112,962	$	32.60	99,800	$	31.78
$45.40 to $50.49	2.93	171,010	49.93		98,029	49.96
$54.65 to $78.59	1.39	118,560	55.30		118,560	55.30
	2.64	402,532	$	46.65	316,389	$	46.23
TSARs
$29.27 to $38.79	3.57	776,194	$	33.05	666,922	$	32.11
$45.40 to $50.49	3.65	673,316	49.55		330,265	49.62
$54.65 to $78.59	1.66	557,960	56.48		557,960	56.48
	3.07	2,007,470	$	45.10	1,555,147	$	44.57

The fair value of each outstanding SARs and TSARs grant was estimated on December 31, 2023 and 2022 using the Black-Scholes option pricing model with the following weighted average assumptions:

	2023		2022
Risk-free interest rate	4.5%		4.4%
Expected dividend yield	1.6%		1.9%
Expected life of SARs and TSARs (years)	1.4		1.8
Expected volatility	38%		51%
Expected forfeitures	0%		0%
Weighted average fair value (USD per unit)	$	10.75	$	8.72

Compensation expense for SARs and TSARs is measured based on their fair value and is recognized over the vesting period. Changes in fair value each period are recognized in net income for the proportion of the service that has been rendered at each reporting date. The fair value as at December 31, 2023 was $26.7 million compared with the recorded liability of $25 million. The

difference between the fair value and the recorded liability of $1.7 million will be recognized over the weighted average remaining vesting period of approximately 1.4 years.

For the year ended December 31, 2023, compensation expense related to SARs and TSARs included an expense in cost of sales and operating expenses of $10.5 million (2022 - expense of $1.8 million). This included an expense of $6.6 million (2022 - recovery of $3.7 million) related to the effect of the change in the Company’s share price.

b) Deferred, restricted and performance share units (old plan and new plan):

Deferred, restricted and performance share units (old plan and new plan) outstanding as at December 31, 2023 and 2022 are as follows:

	Number of deferred share units	Number of restricted share units	Number of performance share units (new plan)
Outstanding at December 31, 2021	133,418	332,385	689,688
Granted	19,909	104,810	199,430
Performance factor impact on redemption1	—	—	(14,796)
Granted in lieu of dividends	2,434	5,561	11,764
Redeemed	—	(82,039)	(119,714)
Cancelled	—	(19,788)	(21,485)
Outstanding at December 31, 2022	155,761	340,929	744,887
Granted	18,417	104,980	179,340
Performance factor impact on redemption1	—	—	143,065
Granted in lieu of dividends	2,484	5,267	10,411
Redeemed	(18,962)	(131,398)	(435,035)
Cancelled	—	(8,924)	(11,546)
Outstanding at December 31, 2023	157,700	310,854	631,122

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. These units relate to performance share units redeemed in the quarter ended March 31, 2023 and the quarter ended March 31, 2022.

Performance share units are redeemable for cash based on the market value of the Company's common shares and are non-dilutive to shareholders. Units vest over three years and include two equally weighted performance factors: (i) relative total shareholder return of Methanex shares versus a specific market index (the market performance factor) and (ii) three year average Return on Capital Employed (the non-market performance factor). The market performance factor is measured by the Company at the grant date and reporting date using a Monte-Carlo simulation model to determine fair value. The non-market performance factor reflects management's best estimate to determine the expected number of units to vest. Based on these performance factors the performance share unit payout will range between 0% to 200%.

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 for the proportion of the service that has been rendered at each reporting date. The fair value of deferred, restricted and performance share units at December 31, 2023 was $58.6 million compared with the recorded liability of $48.9 million. The difference between the fair value and the recorded liability of $9.7 million will be recognized over the weighted average remaining vesting period of approximately 1.7 years.

For the year ended December 31, 2023, compensation expense related to deferred, restricted and performance share units included in cost of sales and operating expenses was an expense of $23.9 million (2022 - expense of $13.5 million). This included an expense of $8.8 million (2022 - recovery of $3.4 million) related to the effect of the change in the Company’s share price.

XML

Segmented information

12 Months Ended

Dec. 31, 2023

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, 2023 and 2022, revenues attributed to geographic regions, based on the location of customers, were as follows:

Revenue	China			Europe			United States			South America			South Korea			Other Asia			Canada			TOTAL
2023	$	1,042,723		$	722,578		$	574,951		$	428,617		$	391,821		$	387,373		$	175,412		$	3,723,475
	28		%	19		%	15		%	12		%	11		%	10		%	5		%	100		%
2022	$	1,105,610		$	830,507		$	657,495		$	458,989		$	542,646		$	518,901		$	197,040		$	4,311,188
	26		%	19		%	15		%	11		%	13		%	12		%	4		%	100		%

As at December 31, 2023 and 2022, the net book value of property, plant and equipment by geographic region, and the Company's shipping business, was as follows:

Property, plant and equipment 1	United States		Egypt		New Zealand		Canada		Chile		Trinidad		Waterfront Shipping		Other		TOTAL
December 31, 2023	$	2,537,515	$	520,497	$	232,831	$	157,483	$	113,789	$	43,835	$	775,729	$	30,089	$	4,411,768
December 31, 2022	$	2,211,333	$	564,454	$	211,544	$	165,783	$	102,467	$	70,432	$	792,016	$	37,254	$	4,155,283

1 Includes right-of-use (leased) assets.

XML

Income and other taxes

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Income and other taxes

Income and other taxes:

a) Income tax (expense) recovery:

For the years ended December 31	2023		2022
Current tax (expense) recovery:
Current period before undernoted items	$	(64,679)	$	(127,254)
Adjustments to prior years including resolution for certain outstanding audits	14,755		(324)
	(49,924)		(127,578)
Deferred tax recovery (expense):
Origination and reversal of temporary differences	46,982		9,589
Adjustments to prior years including resolution for certain outstanding audits	6,904		(400)
Changes in tax rates	(5,828)		(23)
Impact of foreign exchange and other	377		(1,447)
	48,435		7,719
Total income tax expense	$	(1,489)	$	(119,859)

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 before income taxes as follows:

For the years ended December 31	2023			2022
Income before income taxes	$	285,611		$	582,147
Deduct earnings of associate	(99,466)			(76,938)
	186,145			505,209
Canadian statutory tax rate	24.5		%	24.5		%
Income tax expense calculated at Canadian statutory tax rate	(45,606)			(123,776)
Decrease (increase) in income tax expense resulting from:
Impact of income and losses taxed in foreign jurisdictions	27,260			1,346
Utilization of unrecognized loss carryforwards and temporary differences	7,381			7,077
Impact of tax rate changes	(5,828)			(23)
Impact of foreign exchange	5,287			3,783
Other business taxes	(13,943)			(11,065)
Impact of items not taxable for tax purposes	2,373			3,624
Adjustments to prior years including resolution for certain outstanding audits	21,658			(724)
Other	(71)			(101)
Total income tax expense	$	(1,489)		$	(119,859)

c) Net deferred income tax assets and liabilities:

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

As at			Dec 31, 2023						Dec 31, 2022
	Net		Deferred tax assets		Deferred tax liabilities		Net		Deferred tax assets		Deferred tax liabilities
Property, plant and equipment (owned)	$	(363,644)	$	(189,646)	$	(173,998)	$	(403,505)	$	(230,756)	$	(172,749)
Right-of-use assets	(35,883)		(28,299)		(7,584)		(33,477)		(26,486)		(6,991)
Repatriation taxes	(109,186)		(7)		(109,179)		(106,989)		—		(106,989)
Other	(31,630)		(9,259)		(22,371)		(78,305)		(60,850)		(17,455)
	(540,343)		(227,212)		(313,131)		(622,276)		(318,092)		(304,184)
Non-capital loss carryforwards	358,774		321,602		37,172		353,986		322,608		31,378
Lease obligations	48,633		37,854		10,779		46,438		35,957		10,481
Share-based compensation	16,391		651		15,740		17,068		2,096		14,972
Other	50,955		19,355		31,600		24,141		3,784		20,357
	474,753		379,462		95,291		441,633		364,445		77,188
Net deferred income tax assets (liabilities)	$	(65,590)	$	152,250	$	(217,840)	$	(180,643)	$	46,353	$	(226,996)

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in the United States. These loss carryforwards expire as follows:

	Dec 31 2023
	Gross amount		Tax effect
Expire
Losses generated in 2015 (expires 2035)	$	282,437	$	62,136
Losses generated in 2016 (expires 2036)	432,581		95,168
Losses generated in 2017 (expires 2037)	234,941		51,687
	949,959		208,991
No expiry
Losses generated in 2019	255,244		56,154
Losses generated in 2020	121,321		26,691
Losses generated in 2023	29,235		6,432
Total non-capital loss carryforwards	$	1,355,760	$	298,267

Losses generated in the United States on or after January 1, 2018 may be carried forward indefinitely against future taxable income. Tax losses generated before December 31, 2017 may be carried forward for a 20 year period.

As at December 31, 2023 the Company had $201 million (2022 - $231 million) of deductible temporary differences in the United States that have not been recognized.

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in Trinidad. The loss carryforwards total $82 million (2022 - $70 million), which result in a deferred income tax asset of $29 million (2022 - $24 million). The losses generated in Trinidad may be carried forward indefinitely against future taxable income.

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in New Zealand. The loss carryforwards total $25 million (2022 - $7 million), which result in a deferred income tax asset of $7 million (2022 - $2 million). The losses generated in New Zealand may be carried forward indefinitely against future taxable income.

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in Canada. The loss carryforwards total $123 million (2022 - $121 million), which result in a deferred income tax asset of $30 million (2022 - $30 million). The losses were generated in 2020 and can be carried forward 20 years against future taxable income.

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

			2023						2022
	Net		Deferred tax assets		Deferred tax liabilities		Net		Deferred tax assets		Deferred tax liabilities
Balance, January 1	$	(180,643)	$	46,353	$	(226,996)	$	(114,536)	$	98,169	$	(212,705)
Deferred income tax recovery (expense) included in net income	48,435		40,159		8,276		7,719		22,578		(14,859)
Deferred income tax recovery (expense) included in other comprehensive income	66,636		65,738		898		(72,440)		(74,394)		1,954
Other	(17)		—		(17)		(1,386)		—		(1,386)
Balance, December 31	$	(65,590)	$	152,250	$	(217,840)	$	(180,643)	$	46,353	$	(226,996)

International Tax Reform — Pillar Two Rules

Pillar Two rules were published by the Organization for Economic Co-operation and Development and establish a global minimum fifteen percent top-up tax regime. Under currently proposed legislation, Pillar Two rules are expected to be implemented in Canada and be effective for tax years beginning January 1, 2024. The Company is in scope of the proposed legislation and has performed a preliminary assessment of the potential exposure to to-up taxes that would apply based on our historical financial results in the jurisdictions in which we operate. Based on the assessment, we do not expect to have a material exposure to Pillar Two top-up taxes.

XML

Supplemental cash flow information

12 Months Ended

Dec. 31, 2023

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, 2023 and 2022 were as follows:

For the years ended December 31	2023		2022
Changes in non-cash working capital:
Trade and other receivables	$	(32,690)	$	50,442
Inventories	12,997		19,785
Prepaid expenses	(19,439)		(2,622)
Trade, other payables and accrued liabilities	(17,333)		(46,751)
	(56,465)		20,854
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid and interest received	6,027		59,283
Changes in non-cash working capital having a cash effect	$	(50,438)	$	80,137
These changes relate to the following activities:
Operating	$	(59,058)	$	54,122
Financing	68,750		1,771
Investing	(60,130)		24,244
Changes in non-cash working capital	$	(50,438)	$	80,137

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

	Long term debt (note 8)		Lease obligations (note 9)
Balance at December 31, 2022	$	2,151,513	$	870,163
Changes from financing cash flows
Repayment of long-term debt and financing fees	(12,280)		—
Payment of lease obligations	—		(118,159)
Total changes from financing cash flows	(12,280)		(118,159)
Liability-related other changes
Finance costs	2,568		—
New lease obligations	—		123,187
Other	—		(3,071)
Total liability-related other changes	2,568		120,116
Balance at December 31, 2023	$	2,141,801	$	872,120

XML

Capital disclosures

12 Months Ended

Dec. 31, 2023

Liquidity And Capitalization [Abstract]

Capital disclosures

Capital disclosures:

The Company’s objective in managing liquidity and capital is to safeguard the Company’s ability to continue as a going concern and to provide financial capacity and flexibility to meet its strategic objectives, with a focus on cash preservation and liquidity.

As at	Dec 31 2023		Dec 31 2022
Liquidity:
Cash and cash equivalents	$	458,015	$	857,747
Undrawn credit facility	300,000		300,000
Undrawn G3 construction facility	—		300,000
Total liquidity	$	758,015	$	1,457,747
Capitalization:
Unsecured notes, including current portion	1,985,660		1,983,374
Other limited recourse debt facilities, including current portion	156,141		168,139
Total debt	2,141,801		2,151,513
Non-controlling interests	242,090		317,444
Shareholders’ equity	1,930,927		2,112,013
Total capitalization	$	4,314,818	$	4,580,970
Total debt to capitalization 1	50%		47%
Net debt to capitalization 2	44%		35%

1     Total debt (including Other limited recourse debt facilities) divided by total capitalization.

2     Total debt (including Other 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, private placements by limited recourse subsidiaries, 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.

The Company has access to a $300 million committed revolving credit facility with a syndicate of highly rated financial institutions expiring in July 2026. The credit facility is subject to certain financial covenants (note 8). During the year ended December 31, 2023, the Company cancelled the $300 million non-revolving construction facility for the Geismar 3 plant.

XML

Financial instruments

12 Months Ended

Dec. 31, 2023

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 the 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 or accumulated other comprehensive income when the underlying hedged transaction is recognized in earnings or inventory. 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 2023		Dec 31 2022
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	121,108	$	322,748
Fair value of Egypt gas supply contract derivative 2	20,402		11,220
Financial assets not measured at fair value:
Cash and cash equivalents	458,015		857,747
Trade and other receivables, excluding tax receivable	514,739		488,184
Restricted cash included in other assets	15,772		14,349
Total financial assets 3	$	1,130,036	$	1,694,248
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	91,653	$	8,466
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	672,237		656,010
Lease obligations, including current portion	872,120		870,163
Long-term debt, including current portion	2,141,801		2,151,513
Land mortgage	28,014		28,514
Total financial liabilities	$	3,805,825	$	3,714,666

1     The Geismar 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 Egypt natural gas supply contract is measured at fair value using a Monte-Carlo model classified within Level 3 of the fair value hierarchy.

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

As at December 31, 2023, 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 were 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 and those using significant unobservable inputs classified as Level 3. The fair value of all of the Company's derivative contracts as presented in the consolidated statements of financial position are determined based on present values and the discount rates used are adjusted 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 in other comprehensive income as the forward element excluded from the hedging relationships. Once a commodity hedge settles, the amount realized during the period and not recognized immediately in the statement of income is reclassified from accumulated other comprehensive income (equity) to inventory and ultimately through cost of goods sold. Foreign currency hedges settled, are realized during the period directly to the statement of income reclassified from the statement of other comprehensive income.

Until settled, the fair value of Level 2 derivative financial instruments will fluctuate based on changes in commodity prices or foreign currency exchange rates and the fair value of Level 3 derivative financial instruments will fluctuate based on changes in the observable and unobservable valuation model inputs.

North American natural gas forward contracts

The Company manages 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: both financial and physical.

The Company has entered into forward contracts designated as cash flow hedges to manage its exposure to changes in natural gas prices for Geismar. Natural gas is fungible across the Geismar plants. Other costs incurred to transport natural gas from the contracted delivery point, Henry Hub, to the relevant production facility represent an insignificant portion of the overall underlying risk and are recognized as incurred outside of the hedging relationship. No hedge ineffectiveness has been recognized in 2023 or 2022.

As at	Dec 31 2023		Dec 31 2022
Maturities	2024-2032		2023-2032
Notional quantity 1	347,190		307,900
Notional quantity per day, annualized 1	50 - 170		50 - 150
Notional amount	$	1,183,319	$	1,014,264
Net fair value	$	29,925	$	316,008

1    In thousands of Million British Thermal Units (MMBtu)

Information regarding the gross amounts of the Company's natural gas forward contracts designated as cash flow hedges in the audited consolidated statements of financial position is as follows:

As at	Dec 31 2023		Dec 31 2022
Other current assets	$	470	$	32,768
Other non-current assets	120,638		289,979
Other current liabilities	(60,532)		(317)
Other long-term liabilities	(30,651)		(6,422)
Net fair value	$	29,925	$	316,008

For the year ended December 31, 2023, the Company reclassified a loss of $22.5 million (2022 - gain of $55.0 million) for natural gas hedge settlements from accumulated other comprehensive income. Realized gains and losses related to settlements of natural gas hedges are presented separately within the Consolidated Statement of Changes in Equity.

Euro forward exchange contracts

The Company manages its foreign currency exposure to euro denominated sales by executing a number of forward contracts which it has designated as cash flow hedges for its highly probable forecast euro collections. 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 2023 or 2022.

As at December 31, 2023, the Company had outstanding forward exchange contracts designated as cash flow hedges to sell a notional amount of 12.2 million euros (2022 - 21.1 million euros). The euro contracts had a negative fair value of $0.5 million included in current liabilities (2022 - negative fair value of $1.7 million included in current liabilities).

For the year ended December 31, 2023, the Company reclassified a loss of $3.1 million (2022 - gain of $5.7 million) for foreign currency hedge settlements from other comprehensive income.

Changes in cash flow hedges and excluded forward element

Information regarding the impact of changes in cash flow hedges and cost of hedging reserve in the consolidated statement of comprehensive income is as follows:

For the years ended December 31	2023		2022
Change in fair value of cash flow hedges	$	(276,619)	$	(27,742)
Forward element excluded from hedging relationships	(33,837)		406,029
	$	(310,456)	$	378,287

Fair value - Level 2 instruments

The table below shows the nominal cash outflows for derivative hedging instruments including natural gas forward contracts and forward exchange contracts, excluding credit risk adjustments, based upon contracted settlement dates. The amounts reflect the maturity profile of the hedging instruments 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 2023		Dec 31 2022
Within one year	$	65,034	$	2,050
1-3 years	17,771		7,132
3-5 years	5,537		—
More than 5 years	11,378		—
	$	99,720	$	9,182

The fair value of the Company’s derivative financial instruments as disclosed above are determined based on Bloomberg quoted market prices, 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 investment-grade counterparties. 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 $121.1 million as at December 31, 2023 (2022 - $322.7 million).

The carrying values of the Company’s financial instruments approximate their fair values, except as follows:

As at	December 31, 2023				December 31, 2022
	Carrying value		Fair value		Carrying value		Fair value
Long-term debt excluding deferred financing fees	$	2,156,534	$	2,063,661	$	2,168,585	$	1,953,932

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.

Fair value - Level 3 instrument

The Company holds a long-term natural gas supply contract expiring in 2035 with the Egyptian Natural Gas Holding Company ("EGAS"), a State-Owned enterprise in Egypt. The natural gas supply contract includes a base fixed price plus a premium based on the realized price of methanol for the full volume of natural gas to supply the plant through 2035. As a result of the amendment in 2022, the contract is being treated as a derivative measured at fair value.

There is no observable, liquid spot market or forward curve for natural gas in Egypt. In addition, there are limited observable prices for natural gas in Egypt as all natural gas purchases and sales are controlled by the government and the observed prices differ based on the produced output or usage.

Due to the absence of an observable market price for an equivalent or similar contract to measure fair value, the contract's fair value is estimated using a Monte-Carlo model. The Monte-Carlo model includes significant unobservable inputs and as a result is classified within Level 3 of the fair value hierarchy. We consider market participant assumptions in establishing the model inputs and determining fair value, including adjusting the base fixed price and methanol based premium at the valuation date to consider estimates of inflation since contract inception.

At December 31, 2023 the fair value of the derivative associated with the remaining term of the natural gas supply contract is $20.4 million (2022 - $11.2 million) recorded in Other assets. Changes in fair value of the contract are recognized in Finance income and other.

The table presents the Level 3 inputs and the sensitivities of the Monte-Carlo model valuation to changes in these inputs:

	Sensitivities
Valuation input	Input value or range	Change in input	Resulting change in valuation
Methanol price volatility (before impact of mean reversion)	35%	+/- 5%	$+/-7 million
Methanol price forecast	$300 - $415 per MT	+/- $25 per MT	$-5/+7 million
Discount rate	7.6%	+/- 1%	$-/+1 million

It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

XML

Financial risk management

12 Months Ended

Dec. 31, 2023

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 linked 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 and Tobago, 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 financial hedges in Geismar 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 the undrawn credit facility.

As at	Dec 31 2023		Dec 31 2022
Fixed interest rate debt:
Unsecured notes	$	1,985,660	$	1,983,374
Other limited recourse debt facilities	156,141		168,139
	$	2,141,801	$	2,151,513

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 19) of approximately $100.5 million as of December 31, 2023 (2022 - $104.8 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 Chinese yuan, euros, 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, 2023, the Company had a net working capital asset of $74.4 million in non U.S. dollar currencies (2022 - $69.9 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 $7.4 million (2022 - $7.0 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, 2023, the Company had a strong liquidity position including a cash and cash equivalents balance of $458 million. In addition, the Company has access to a $300 million committed undrawn revolving credit facility.

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, 2023	Carrying amount		Contractual cash flows		1 year or less		1-3 years		3-5 years		More than 5 years
Trade and other payables 1	$	659,723	$	659,723	$	659,723	$	—	$	—	$	—
Lease obligations 2	872,120		1,174,346		172,197		266,499		220,681		514,969
Other long-term liabilities2	28,014		53,348		2,200		4,400		4,400		42,348
Long-term debt 2	2,141,801		2,932,911		425,953		220,901		879,530		1,406,527
Cash flow hedges 3	91,653		99,720		65,034		17,771		5,537		11,378
	$	3,793,311	$	4,920,048	$	1,325,107	$	509,571	$	1,110,148	$	1,975,222

1     Excludes tax, accrued interest and euro foreign currency hedges.

2     Contractual cash flows include contractual interest payments related to debt obligations and lease obligations.

3 The expected cash flows of hedges are based on current valuations of the expected settlement amounts, which will fluctuate at settlement dependent on the market prices at the future settlement dates

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, 2023 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.

XML

Retirement plans

12 Months Ended

Dec. 31, 2023

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 2023		Dec 31 2022
Accrued benefit obligations:
Balance, beginning of year	$	53,586	$	62,208
Current service cost	2,246		2,329
Past service cost	2,479		—
Interest cost on accrued benefit obligations	2,549		2,007
Benefit payments	(4,280)		(5,760)
Settlements	(3,738)		—
Actuarial (gain) loss	2,074		(4,047)
Foreign exchange (gain) loss	265		(3,151)
Balance, end of year	55,181		53,586
Fair values of plan assets:
Balance, beginning of year	38,347		46,608
Interest income on assets	1,901		1,221
Contributions	5,687		4,457
Benefit payments	(4,280)		(5,760)
Settlements	(3,680)		—
Return on plan assets	(705)		(5,173)
Foreign exchange gain (loss)	938		(3,006)
Balance, end of year	38,208		38,347
Unfunded status	16,973		15,239
Minimum funding requirement	—		—
Defined benefit obligation, net	$	16,973	$	15,239

The net defined benefit obligation above is comprised of unfunded retirement obligations and funded retirement net assets from defined benefit pension plans, as follows:

The Company has an unfunded retirement obligation of $20.2 million as at December 31, 2023 (2022 - obligation of $19.2 million) for its employees in Chile that will be funded in accordance with Chilean law. The Company also has an unfunded retirement obligation of $2.5 million as at December 31, 2023 (2022 - nil) for its employees in Egypt. The accrued benefits for the unfunded retirement arrangement in Chile and Egypt are paid when an employee leaves the Company in accordance with the plan terms and country regulations.The Company estimates that it may make benefit payments based on actuarial assumptions related to the unfunded retirement obligation of $11.3 million in Chile and $0.1 million in Egypt for 2024. Actual benefit payments in future periods will fluctuate based on employee retirements.

The Company has a net funded retirement asset of $5.3 million as at December 31, 2023 (2022 - $3.6 million) for certain employees and retirees in Canada and a net funded retirement asset of $0.4 million as at December 31, 2023 (2022 - asset of $0.4 million) in Europe. The Company estimates that it will make no additional contributions relating to its defined benefit pension plan in Canada and that it will make additional contributions relating to its defined benefit pension plan in Europe of $0.5 million in 2024.

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 7 years.

The Company’s net defined benefit pension plan expense charged to the consolidated statements of income for the years ended December 31, 2023 and 2022 is as follows:

For the years ended December 31	2023		2022
Net defined benefit pension plan expense:
Current service cost	$	2,246	$	2,329
Past service cost	2,479		—
Net interest cost	648		786
Cost of settlement	(58)		—
Total net defined benefit pension plan expense	$	5,315	$	3,115

The Company’s current year actuarial losses, recognized in the consolidated statements of comprehensive income for the years ended December 31, 2023 and 2022, are as follows:

For the years ended December 31	2023		2022
Actuarial loss	$	(2,827)	$	(726)

The Company had no minimum funding requirement for the years ended December 31, 2023 and 2022.

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, 2022 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, 2025.

The discount rate is the most significant actuarial assumption used in accounting for the defined benefit pension plans. As at December 31, 2023, the weighted average discount rate for the defined benefit obligation was 5.3% (2022 - 5.1%). A change of 1% in the weighted average discount rate at the end of the reporting period, while holding all other assumptions constant, would result in a change to the defined benefit obligation of approximately $3.6 million.

The asset allocation for the defined benefit pension plan assets as at December 31, 2023 and 2022 is as follows:

As at	Dec 31 2023	Dec 31 2022
Equity securities	15%	20%
Debt securities	52%	49%
Cash and other short-term securities	33%	31%
Total	100%	100%

The fair value of the above equity and debt instruments are determined based on quoted market prices in active markets whereas the fair value 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, 2023 was $11.0 million (2022 - $9.7 million).

XML

Commitments and contingencies

12 Months Ended

Dec. 31, 2023

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 for our operating plants and Geismar 3 project up to 2044. The minimum estimated commitment under these contracts, except as noted below, is as follows:

As at December 31, 2023

2024		2025		2026		2027		2028		Thereafter
$	438,284	$	517,793	$	324,251	$	254,155	$	215,417	$	923,105

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 Tobago, Egypt and certain contracts in Chile are take-or-pay contracts denominated in United States dollars and include base and variable price components to manage our commodity price risk exposure. The variable price component of each natural gas contract is adjusted by a formula linked to methanol prices. 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 representative of the minimum take-or-pay commitment.

b) Other commitments:

The Company has future minimum payments relating primarily to short-term vessel charters, terminal facilities, and other commitments that are not leases, as follows:

As at December 31, 2023

2024		2025		2026		2027		2028		Thereafter
$	94,534	$	4,665	$	1,314	$	560	$	358	$	1,183

Refer to note 9 for a summary of lease commitments.

c) 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 0.6 million tonnes per year of methanol offtake supply when Egypt operates at capacity and 0.6 million tonnes per year of methanol offtake supply for Atlas. The offtake commitment for Atlas for 2024 will be reduced to 0.4 million tonnes of supply due to the facility running only until September 2024, when the legacy gas supply agreement expires. As at December 31, 2023, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2024. 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.

XML

Related parties

12 Months Ended

Dec. 31, 2023

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 2023	Dec 31 2022
Significant subsidiaries:
Methanex Asia Pacific Limited	Hong Kong	Marketing & distribution	100%	100%
Methanex Services (Shanghai) Co., Ltd.	China	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 SpA	Chile	Production	100%	100%
Methanex New Zealand Limited	New Zealand	Production	100%	100%
Methanex Trinidad (Titan) Unlimited	Trinidad and Tobago	Production	100%	100%
Methanex USA LLC	United States	Production	100%	100%
Methanex Louisiana LLC	United States	Production	100%	100%
Methanex Geismar III LLC	United States	Geismar 3 project development	100%	100%
Waterfront Shipping Limited 1	Canada	Shipping	60%	60%
Significant joint ventures:
Atlas Methanol Company Unlimited 2	Trinidad and Tobago	Production	63.1%	63.1%

1     On February 1, 2022, we closed the shipping partnership with Mitsui O.S.K. Lines, Ltd. ("MOL") whereby MOL acquired a 40% minority interest in Waterfront Shipping Limited.

2     Summarized financial information for the investment in Atlas is disclosed in note 6.

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, 2023 of $466 million (2022 - $532 million) is a related party transaction included in cost of sales of the Company as Methanex has marketing rights for 100% of the methanol produced by Atlas. Balances outstanding with Atlas as at December 31, 2023 and provided in the summarized financial information in note 6 include receivables owing from Atlas to the Company of $74 million (2022 - $73 million), and payables to Atlas of $172 million (2022 - $198 million). The Company has total loans outstanding to Atlas as at December 31, 2023 of $76 million (2022 - $76 million) which are unsecured and due at maturity.

Remuneration to non-management directors and senior management, which includes the members of the executive leadership team, is as follows:

For the years ended December 31	2023		2022
Short-term employee benefits	$	9,034	$	11,760
Post-employment benefits	681		656
Other long-term employee benefits	59		52
Share-based compensation expense 1	10,046		6,142
Total	$	19,820	$	18,610

1  Balance includes realized and unrealized expenses and recoveries from share-based compensation awards granted.

XML

Non-controlling interests

12 Months Ended

Dec. 31, 2023

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, 2023						Dec 31, 2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Current assets	$	129,320	$	154,308	$	283,628	$	133,499	$	180,227	$	313,726
Non-current assets	521,708		791,512		1,313,220		557,484		806,079		1,363,563
Current liabilities	(123,969)		(185,459)		(309,428)		(56,689)		(112,085)		(168,774)
Non-current liabilities	(101,810)		(718,915)		(820,725)		(104,101)		(744,936)		(849,037)
Net assets	425,249		41,446		466,695		530,193		129,285		659,478
Carrying amount of Methanex non-controlling interests	$	214,568	$	27,522	$	242,090	$	251,949	$	65,495	$	317,444

For the years ended December 31			2023						2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Revenue	$	258,782	$	670,834	$	929,616	$	212,339	$	576,810	$	789,149
Net and total comprehensive income	55,428		129,411		184,839		107,375		67,670		175,045
Net and total comprehensive income attributable to Methanex non-controlling interests	56,310		53,672		109,982		77,133		31,325		108,458
Sale of partial interest in non-controlling interests and equity contributions by non-controlling interest	$	—	$	—	$	—	$	—	$	22,545	$	22,545
Distributions made and accrued to non-controlling interests	$	(93,696)	$	(91,640)	$	(185,336)	$	(75,996)	$	(8,718)	$	(84,714)

For the years ended December 31			2023						2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Cash flows from operating activities	$	131,667	$	251,290	$	382,957	$	226,647	$	94,355	$	321,002
Cash flows from (used in) financing activities	(99,490)		(300,824)		(400,314)		(152,806)		(52,796)		(205,602)
Cash flows from (used in) investing activities	$	(5,560)	$	2,686	$	(2,874)	$	(35,110)	$	215	$	(34,895)

1    On February 1, 2022, we closed the shipping partnership with Mitsui O.S.K. Lines, Ltd. ("MOL") whereby MOL acquired a minority interest in Waterfront Shipping Limited.

XML

Sale of interest in subsidiary	12 Months Ended
	Dec. 31, 2023
Interests In Other Entities [Abstract]
Sale of interest in subsidiary	Sale of interest in subsidiary:In 2022, the Company completed the sale of a 40% equity interest in Waterfront Shipping Limited ("WFS") for cash proceeds of approximately $149 million. The sale reduces the Company's interest in WFS to 60% while retaining control of the consolidated WFS group of companies. The sale has been accounted for as a transaction between equity holders as Methanex controls WFS before and after the transaction and the $126 million gain on sale has been reflected as an increase in shareholders' equity.

XML

Egypt gas redirection and sale proceeds

12 Months Ended

Dec. 31, 2023

Oil and Gas Assets [Abstract]

Egypt gas redirection and sale proceeds

Egypt gas redirection and sale proceeds:

In 2022, the Company entered into an agreement to redirect and sell the Egypt plant's contracted natural gas during an extended turnaround for a three-month period.

The Company has recognized $118 million ($59 million - attributable to Methanex) for the year ended December 31, 2022 to redirect and sell the contracted natural gas during the diversion period.

XML

Material accounting policies (Policies)

12 Months Ended

Dec. 31, 2023

Corporate information and statement of IFRS compliance [abstract]

Statement of compliance

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 7, 2024.

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 controlled by the Company. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. 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. 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)), leases (note 2(i)), 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

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.

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 records provisions for expected credit losses for receivables measured at amortized cost. The Company records an allowance for doubtful accounts or writes down the receivable to estimated net realizable value, if not collectible in full, based on expected credit losses. Expected credit losses are based on historic and forward looking customer specific factors including historic credit losses incurred.

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 ocean freight costs for the shipment of product.

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 at installation, excluding costs related to turnarounds, initially range up to 25 years depending on the specific asset component and the production facility to which it is related. Right-of-use (leased) assets are depreciated from the lease commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. 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. The estimated useful life of production facilities may be adjusted from time-to-time based on turnarounds, plant refurbishments and gas availability. 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.

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 may 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 the asset or idle the asset for a significant period of time; 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. Fair value less costs of disposal is determined by estimating the price that would be received to sell an asset in an orderly transaction between market participants under current market conditions, less incremental costs directly attributable to the disposal, excluding finance costs and income tax expense. 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.

When impairment indicators exist, 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, incorporating third-party assumptions, forecasts and market observable prices when appropriate. 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 when testing for impairment 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. In relation to previous impairment charges, we do not believe that there are significant changes in events or circumstances that would support their reversal.

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.

Financing fees

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:

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether:

•the contract involves the use of an identified asset - this may be specified explicitly or implicitly and should be physically distinct or represent substantially all of the capacity of a physically distinct asset. If the supplier has a substantive substitution right, then the asset is not identified;

•the Company has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use; and

•the Company has the right to direct the use of the asset. The Company has the right when it has the decision-making rights that are most relevant to changing how and for what purpose the asset is used.

For contracts that contain a lease, the Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. The estimated useful lives of right-of-use assets are determined on the same basis as those of property, plant and equipment. In addition, the right-of-use asset is assessed for impairment losses, should a trigger be identified and adjusted for impairment if required. Lease terms range up to 20 years for vessels, terminals, equipment, and other items.

The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Company’s estimate of the amount expected to be payable under a residual value guarantee or if the Company changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed upon a trigger by an event or a significant change in circumstances.

Certain leases contain non-lease components, excluded from the right-of-use asset and lease liability, related to operating charges for ocean vessels, terminal facilities and rail transport contracts. Judgment is applied in the determination of the stand-alone price of the lease and non-lease components.

The Company has elected not to recognize right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less and leases of low-value assets, except for terminal and vessel leases. The Company recognizes the lease payments associated with these leases as an expense 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 transferred to 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 ("PSUs") granted from 2019 onwards are redeemable for cash based on the market value of the Company's common shares and are non-dilutive to shareholders. PSUs vest over three years and include two performance factors: (i) relative total shareholder return of Methanex shares versus a specific market index (the market performance factor) and (ii) three year average Return on Capital Employed ("ROCE") (the non-market performance factor). The market performance factor is measured by the Company at the grant date and reporting date using a Monte-Carlo simulation model to determine fair value. The non-market performance factor reflects management's best estimate of ROCE over the performance period (using actual ROCE as applicable) to determine the expected number of units to vest. Based on these performance factors the performance share unit payout will range between 0% to 200%.

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.

Net income (loss) per common 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.

Revenue recognition

Revenue recognition:

Revenue is recognized based on individual contract terms at the point in time when control of 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 contractual performance obligation has not been met during shipment. For methanol sold on a consignment basis, revenue is recognized at the point in time the customer draws down the consigned methanol. Revenue is measured and recorded at the most likely amount of consideration the Company expects to receive.

By contract, the Company sells all the methanol produced by the Atlas Joint Venture and earns a commission on the sale of the methanol. As the Company obtains title and control of the methanol from the Atlas facility and directs the sale of the methanol to the Company's customers, the Company recognizes the revenue on these sales to customers at the gross amount receivable from the customers based on the Company's revenue recognition policy noted above. Cost of sales is recognized for these sales as the amount due to the Atlas Joint Venture which is the gross amount receivable less the commission earned by the Company.

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.

Assessment of contracts as derivative instruments, applicability of the own use exemption, determination of whether hybrid instruments contain embedded derivatives to be separated, the valuation of financial instruments and derivatives and hedge effectiveness assessments require a high degree of judgment and are considered critical accounting judgements and estimates due to the complex nature of these products and the potential impact on our financial statements.

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.

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.

Uncertain tax positions derive from the complexity of tax law and its interpretation by tax authorities and ultimately the judicial system in place in each jurisdiction. Uncertain tax positions, including interest and penalties, are recognized and measured applying management estimates. Given the complexity, management engages third-party experts as required, for the interpretation of tax law, transfer pricing regulations and determination of the ultimate resolution of its tax positions. The Company is subject to various taxation authorities who may interpret tax legislation differently, and resolve matters over longer-periods of time. The differences in judgement in assessing uncertain tax positions may result in material differences in the final amount or timing of the payment of taxes or settlement of tax assessments.

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

Application of new and revised accounting standards:

The Company has adopted the amendments to IAS 1 Presentation of Financial Statements as well as IAS 8 Changes in Accounting Estimates and Errors regarding the disclosure of accounting policies and accounting estimates, and IAS 12, Income Taxes ("IAS 12") regarding deferred tax related to assets and liabilities arising from a single transaction, which were effective for annual periods beginning on January 1, 2023. The amendments did not have a material impact on the Company's consolidated financial statements.

In May 2023, the IASB issued a further amendment to IAS 12, establishing a mandatory exception for recognition and disclosure of deferred taxes related to the Pillar Two model rules published by the Organization for Economic Co-operation and Development (“Pillar Two rules”). The Pillar Two rules establish a global minimum fifteen percent top-up tax regime and are expected to apply to Methanex beginning in 2024. The Company has applied this mandatory exception in the current period. Refer to note 16 for further disclosure on the expected impact of Pillar Two rules.

Anticipated changes to International Financial Reporting Standards: The following new or amended standards or interpretations that are effective for annual periods beginning on or after January 1, 2024 are being reviewed to determine the potential impact: amendments to IAS 1, Presentation of Financial Statements regarding the classification of liabilities as current or non-current, IFRS 16, Leases regarding sale-and-leaseback transactions and IAS 7, Statement of Cash Flows regarding supplier finance arrangements.

XML

Trade and other receivables (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Schedule of trade and other receivables

As at	Dec 31 2023		Dec 31 2022
Trade	$	431,602	$	407,733
Value-added and other tax receivables	22,292		14,986
Other	79,721		78,206
	$	533,615	$	500,925

XML

Property, plant and equipment (Tables)

12 Months Ended

Dec. 31, 2023

Property, plant and equipment [abstract]

Schedule of property, plant and equipment

	Owned Assets (a)		Right-of-use assets (b)		Total
Net book value at December 31, 2023	$	3,654,475	$	757,293	$	4,411,768
Net book value at December 31, 2022	$	3,398,805	$	756,478	$	4,155,283

	Buildings, plant installations and machinery		Plants Under Construction1		Ocean vessels		Other		TOTAL
Cost at January 1, 2023	$	5,000,999	$	1,001,888	$	240,867	$	140,081	$	6,383,835
Additions	174,058		353,609		253		4,153		532,073
Disposals and other	(294,850)		—		(397)		(15,571)		(310,818)
Cost at December 31, 2023	4,880,207		1,355,497		240,723		128,663		6,605,090
Accumulated depreciation at January 1, 2023	2,827,870		—		49,310		107,850		2,985,030
Depreciation	248,783		—		12,080		2,153		263,016
Disposals and other	(281,951)		—		—		(15,480)		(297,431)
Accumulated depreciation at December 31, 2023	2,794,702		—		61,390		94,523		2,950,615
Net book value at December 31, 2023	$	2,085,505	$	1,355,497	$	179,333	$	34,140	$	3,654,475

1    The Company is constructing a 1.8 million tonne methanol plant in Geismar, Louisiana adjacent to its Geismar 1 and Geismar 2 facilities. Included in cost of Plants Under Construction are $150 million (2022: $94 million) of capitalized interest and finance charges.

	Buildings, plant installations and machinery		Plants under construction		Ocean vessels		Other		TOTAL
Cost at January 1, 2022	$	4,908,492	$	561,860	$	240,525	$	138,378	$	5,849,255
Additions	140,326		440,028		342		1,703		582,399
Disposals and other	(47,819)		—		—		—		(47,819)
Cost at December 31, 2022	5,000,999		1,001,888		240,867		140,081		6,383,835
Accumulated depreciation at January 1, 2022	2,631,268		—		37,271		105,518		2,774,057
Depreciation	248,032		—		12,039		2,332		262,403
Disposals and other	(51,430)		—		—		—		(51,430)
Accumulated depreciation at December 31, 2022	2,827,870		—		49,310		107,850		2,985,030
Net book value at December 31, 2022	$	2,173,129	$	1,001,888	$	191,557	$	32,231	$	3,398,805

Schedule of right-of-use assets

	Ocean vessels		Terminals and tanks		Other		TOTAL
Cost at January 1, 2023	$	846,977	$	286,036	$	68,701	$	1,201,714
Additions	83,333		52,909		5,951		142,193
Disposals and other	(19,589)		(6,504)		(16,031)		(42,124)
Cost at December 31, 2023	910,721		332,441		58,621		1,301,783
Accumulated depreciation at January 1, 2023	245,873		160,163		39,200		445,236
Depreciation	88,040		36,140		6,583		130,763
Disposals and other	(19,589)		—		(11,920)		(31,509)
Accumulated depreciation at December 31, 2023	314,324		196,303		33,863		544,490
Net book value at December 31, 2023	$	596,397	$	136,138	$	24,758	$	757,293

	Ocean vessels		Terminals and tanks		Other		TOTAL
Cost at January 1, 2022	$	657,774	$	258,743	$	64,700	$	981,217
Additions	232,536		27,293		4,001		263,830
Disposals and other	(43,333)		—		—		(43,333)
Cost at December 31, 2022	846,977		286,036		68,701		1,201,714
Accumulated depreciation at January 1, 2022	214,004		125,494		30,768		370,266
Depreciation	75,586		34,669		8,432		118,687
Disposals and other	(43,717)		—		—		(43,717)
Accumulated depreciation at December 31, 2022	245,873		160,163		39,200		445,236
Net book value at December 31, 2022	$	601,104	$	125,873	$	29,501	$	756,478

XML

Investment in associate (Tables)

12 Months Ended

Dec. 31, 2023

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 2023		Dec 31 2022
Cash and cash equivalents	$	126,392	$	24,420
Other current assets1	189,062		182,103
Non-current assets	149,354		184,373
Current liabilities1	(157,835)		(92,108)
Other long-term liabilities, including current maturities	(135,940)		(107,416)
Net assets at 100%	$	171,033	$	191,372
Net assets at 63.1%	$	107,921	$	120,755
Long-term receivable from Atlas1	76,328		76,328
Investment in associate	$	184,249	$	197,083

Consolidated statements of income for the years ended December 31	2023		2022
Revenue1	$	466,312	$	532,456
Cost of sales and depreciation and amortization	(289,705)		(332,999)
Gas contract settlement (b)	75,000		—
Operating income	251,607		199,457
Finance costs, finance income and other	(10,316)		(9,433)
Income tax expense	(83,659)		(68,093)
Net earnings at 100%	$	157,632	$	121,931
Earnings of associate at 63.1%	$	99,466	$	76,938
Dividends received from associate	$	112,318	$	97,174

1     Includes related party transactions between Atlas and the Company (see note 23).

Schedule of key assumptions for investment in associate

The following table indicates the percentages by which key assumptions would need to change individually for the estimated Atlas CGU recoverable value to be equal to the carrying value:

Key Assumptions	Change Required for Carrying Value to Equal Recoverable Value
Long-term average realized methanol price	10 percent decrease
Production volumes	15 percent decrease
Gas price	10 percent increase
Discount rate (after-tax)	800 basis points increase

XML

Other assets (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Schedule of other assets

As at	Dec 31 2023		Dec 31 2022
Cash flow hedges (note 19)	$	121,108	$	322,748
Chile VAT receivable	17,824		18,343
Restricted cash for debt service and major maintenance of vessels (a)	15,772		14,349
Fair value of Egypt gas supply contract derivative (note 19)	20,402		11,220
Investment in Carbon Recycling International	5,620		5,620
Defined benefit pension plans (note 21)	5,718		3,977
Other	15,416		19,476
Total other assets	201,860		395,733
Less current portion (b)	(3,893)		(39,346)
	197,967		$	356,387

XML

Long-term debt (Tables)

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Schedule of long-term debt

As at	Dec 31 2023		Dec 31 2022
Unsecured notes
(i) $300 million at 4.25% due December 1, 2024	$	299,283	$	298,836
(ii) $700 million at 5.125% due October 15, 2027	694,844		693,649
(iii) $700 million at 5.25% due December 15, 2029	695,824		695,283
(iv) $300 million at 5.65% due December 1, 2044	295,709		295,606
	1,985,660		1,983,374
Other limited recourse debt facilities
(i) 5.58% due through June 30, 2031	56,637		61,978
(ii) 5.35% due through September 30, 2033	65,300		70,312
(iii) 5.21% due through September 15, 2036	34,204		35,849
	156,141		168,139
Total long-term debt1	2,141,801		2,151,513
Less current maturities1	(314,716)		(15,133)
	$	1,827,085	$	2,136,380

1  Long-term debt and current maturities are presented net of discounts and deferred financing fees of $16.8 million as at December 31, 2023 (2022 - $19.4 million).

Schedule of minimum principal payments for long-term debt

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

	Other limited recourse debt facilities		Unsecured notes		Total
2024	$	15,367	$	300,000	$	315,367
2025	13,660		—		13,660
2026	13,796		—		13,796
2027	15,173		700,000		715,173
2028	16,026		—		16,026
Thereafter	84,574		1,000,000		1,084,574
	$	158,596	$	2,000,000	$	2,158,596

XML

Lease obligations (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of Leases [Abstract]

Disclosure of additional information about leasing activities for lessee

	2023		2022
Opening lease obligations	$	870,163	$	717,101
Additions, net of disposals	123,187		262,470
Interest expense	53,418		48,039
Lease payments	(171,577)		(153,901)
Effect of movements in exchange rates and other	(3,071)		(3,546)
Lease obligations at December 31	872,120		870,163
Less: current portion	(120,731)		(108,736)
Lease obligations - non current portion	$	751,389	$	761,427

Disclosure of maturity analysis of lease payments

The following table presents the contractual undiscounted cash flows for lease obligations as at December 31, 2023:

	Lease payments		Interest component		Lease obligations
2024	$	172,197	$	51,466	$	120,731
2025	142,761		45,617		97,144
2026	123,738		39,998		83,740
2027	112,397		34,419		77,978
2028	108,284		28,547		79,737
Thereafter	514,969		102,179		412,790
	$	1,174,346	$	302,226	$	872,120

Disclosure of potential lease options

	Lease liabilities recognized (discounted)		Potential future lease payments not included in lease liabilities (undiscounted)
Ocean-going vessels	$	662,903	$	1,512
Terminals and tanks	174,019			38,987
Other	35,198			11,279
Total	$	872,120	$	51,778

XML

Other long-term liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Composition of other liabilities

As at	Dec 31 2023		Dec 31 2022
Share-based compensation liability (note 14)	$	74,107	$	70,569
Site restoration costs	32,596		36,581
Land mortgage	28,014		28,514
Defined benefit pension plans (note 21)	22,691		19,216
Cash flow hedges (note 19)	91,183		6,739
Other	1,319		2,532
	249,910		164,151
Less current maturities	(94,992)		(29,548)
	$	154,918	$	134,603

Provision for site restoration costs

The movement in the provision during the year is explained as follows:

	2023		2022
Balance at January 1	$	36,581	$	29,355
New or revised provisions	(5,573)		6,915
Accretion expense	1,588		311
Balance at December 31	$	32,596	$	36,581

XML

Expenses (Tables)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Schedule of expenses

For the years ended December 31	2023		2022
Cost of sales	$	2,797,794	$	3,238,312
Selling and distribution	552,693		498,552
Administrative expenses	109,415		81,657
Total expenses by function	$	3,459,902	$	3,818,521
Cost of raw materials and purchased methanol	2,329,856		2,789,921
Ocean freight and other logistics	357,495		325,893
Employee expenses, including share-based compensation	243,542		219,012
Other expenses	137,179		111,275
Cost of sales and operating expenses	3,068,072		3,446,101
Depreciation and amortization	391,830		372,420
Total expenses by nature	$	3,459,902	$	3,818,521

XML

Finance costs (Tables)

12 Months Ended

Dec. 31, 2023

Borrowing costs [abstract]

Schedule of finance costs

For the years ended December 31	2023		2022
Finance costs before capitalized interest	$	172,814	$	167,066
Less capitalized interest related to Geismar plant under construction	(55,448)		(36,314)
Finance costs	$	117,366	$	130,752

XML

Net income per common share (Tables)

12 Months Ended

Dec. 31, 2023

Earnings per share [abstract]

Earnings per share reconciliation

A reconciliation of the numerator used for the purposes of calculating diluted net income per common share is as follows:

For the years ended December 31	2023		2022
Numerator for basic net income per common share	$	174,140	$	353,830
Adjustment for the effect of TSARs:
Cash-settled recovery included in net income	—		(316)
Equity-settled expense	—		(5,503)
Numerator for diluted net income per common share	$	174,140	$	348,011

A reconciliation of the denominator used for the purposes of calculating diluted net income per common share is as follows:

For the years ended December 31	2023	2022
Denominator for basic net income per common share	67,805,220	71,422,360
Effect of dilutive stock options	6,395	10,108
Effect of dilutive TSARS	—	245,016
Denominator for diluted net income per common share	67,811,615	71,677,484

For the years ended December 31, 2023 and 2022, basic and diluted net income per common share attributable to Methanex shareholders were as follows:

For the years ended December 31	2023		2022
Basic net income per common share	$	2.57	$	4.95
Diluted net income per common share	$	2.57	$	4.86

XML

Share-based compensation (Tables)

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangements [Abstract]

Changes in number and exercise prices of other equity instruments

SARs and TSARs units outstanding at December 31, 2023 and 2022 are as follows:

	SARs			TSARs
	Number of units	Exercise price USD		Number of units	Exercise price USD
Outstanding at December 31, 2021	666,256	$	45.70	2,380,237	$	42.05
Granted	32,730	48.49		266,090	48.49
Exercised	(129,162)	37.17		(290,577)	35.94
Cancelled	(12,900)	55.70		(21,922)	46.45
Expired	(149,237)	55.66		(145,469)	55.82
Outstanding at December 31, 2022	407,687	$	44.67	2,188,359	$	42.68
Granted	51,160	50.49		169,190	50.49
Exercised	(50,715)	33.85		(336,535)	31.88
Cancelled	(5,600)	53.69		(13,544)	51.36
Outstanding at December 31, 2023	402,532	$	46.65	2,007,470	$	45.10

Deferred, restricted and performance share units (old plan and new plan) outstanding as at December 31, 2023 and 2022 are as follows:

	Number of deferred share units	Number of restricted share units	Number of performance share units (new plan)
Outstanding at December 31, 2021	133,418	332,385	689,688
Granted	19,909	104,810	199,430
Performance factor impact on redemption1	—	—	(14,796)
Granted in lieu of dividends	2,434	5,561	11,764
Redeemed	—	(82,039)	(119,714)
Cancelled	—	(19,788)	(21,485)
Outstanding at December 31, 2022	155,761	340,929	744,887
Granted	18,417	104,980	179,340
Performance factor impact on redemption1	—	—	143,065
Granted in lieu of dividends	2,484	5,267	10,411
Redeemed	(18,962)	(131,398)	(435,035)
Cancelled	—	(8,924)	(11,546)
Outstanding at December 31, 2023	157,700	310,854	631,122

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. These units relate to performance share units redeemed in the quarter ended March 31, 2023 and the quarter ended March 31, 2022.

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, 2023 is as follows:

	Units outstanding at December 31, 2023				Units exercisable at December 31, 2023
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
$29.27 to $38.79	3.52	112,962	$	32.60	99,800	$	31.78
$45.40 to $50.49	2.93	171,010	49.93		98,029	49.96
$54.65 to $78.59	1.39	118,560	55.30		118,560	55.30
	2.64	402,532	$	46.65	316,389	$	46.23
TSARs
$29.27 to $38.79	3.57	776,194	$	33.05	666,922	$	32.11
$45.40 to $50.49	3.65	673,316	49.55		330,265	49.62
$54.65 to $78.59	1.66	557,960	56.48		557,960	56.48
	3.07	2,007,470	$	45.10	1,555,147	$	44.57

SARs and TSARs outstanding and exercisable by range of exercise prices

Information regarding the SARs and TSARs outstanding as at December 31, 2023 is as follows:

	Units outstanding at December 31, 2023				Units exercisable at December 31, 2023
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
$29.27 to $38.79	3.52	112,962	$	32.60	99,800	$	31.78
$45.40 to $50.49	2.93	171,010	49.93		98,029	49.96
$54.65 to $78.59	1.39	118,560	55.30		118,560	55.30
	2.64	402,532	$	46.65	316,389	$	46.23
TSARs
$29.27 to $38.79	3.57	776,194	$	33.05	666,922	$	32.11
$45.40 to $50.49	3.65	673,316	49.55		330,265	49.62
$54.65 to $78.59	1.66	557,960	56.48		557,960	56.48
	3.07	2,007,470	$	45.10	1,555,147	$	44.57

Weighted average assumptions of outstanding SARs and TSARs

The fair value of each outstanding SARs and TSARs grant was estimated on December 31, 2023 and 2022 using the Black-Scholes option pricing model with the following weighted average assumptions:

	2023		2022
Risk-free interest rate	4.5%		4.4%
Expected dividend yield	1.6%		1.9%
Expected life of SARs and TSARs (years)	1.4		1.8
Expected volatility	38%		51%
Expected forfeitures	0%		0%
Weighted average fair value (USD per unit)	$	10.75	$	8.72

XML

Segmented information (Tables)

12 Months Ended

Dec. 31, 2023

Operating Segments [Abstract]

Revenue attributed to geographic regions

During the years ended December 31, 2023 and 2022, revenues attributed to geographic regions, based on the location of customers, were as follows:

Revenue	China			Europe			United States			South America			South Korea			Other Asia			Canada			TOTAL
2023	$	1,042,723		$	722,578		$	574,951		$	428,617		$	391,821		$	387,373		$	175,412		$	3,723,475
	28		%	19		%	15		%	12		%	11		%	10		%	5		%	100		%
2022	$	1,105,610		$	830,507		$	657,495		$	458,989		$	542,646		$	518,901		$	197,040		$	4,311,188
	26		%	19		%	15		%	11		%	13		%	12		%	4		%	100		%

As at December 31, 2023 and 2022, the net book value of property, plant and equipment by geographic region, and the Company's shipping business, was as follows:

Property, plant and equipment 1	United States		Egypt		New Zealand		Canada		Chile		Trinidad		Waterfront Shipping		Other		TOTAL
December 31, 2023	$	2,537,515	$	520,497	$	232,831	$	157,483	$	113,789	$	43,835	$	775,729	$	30,089	$	4,411,768
December 31, 2022	$	2,211,333	$	564,454	$	211,544	$	165,783	$	102,467	$	70,432	$	792,016	$	37,254	$	4,155,283

1 Includes right-of-use (leased) assets.

XML

Income and other taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Components of income tax (expense) recovery

Income tax (expense) recovery:

For the years ended December 31	2023		2022
Current tax (expense) recovery:
Current period before undernoted items	$	(64,679)	$	(127,254)
Adjustments to prior years including resolution for certain outstanding audits	14,755		(324)
	(49,924)		(127,578)
Deferred tax recovery (expense):
Origination and reversal of temporary differences	46,982		9,589
Adjustments to prior years including resolution for certain outstanding audits	6,904		(400)
Changes in tax rates	(5,828)		(23)
Impact of foreign exchange and other	377		(1,447)
	48,435		7,719
Total income tax expense	$	(1,489)	$	(119,859)

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 before income taxes as follows:

For the years ended December 31	2023			2022
Income before income taxes	$	285,611		$	582,147
Deduct earnings of associate	(99,466)			(76,938)
	186,145			505,209
Canadian statutory tax rate	24.5		%	24.5		%
Income tax expense calculated at Canadian statutory tax rate	(45,606)			(123,776)
Decrease (increase) in income tax expense resulting from:
Impact of income and losses taxed in foreign jurisdictions	27,260			1,346
Utilization of unrecognized loss carryforwards and temporary differences	7,381			7,077
Impact of tax rate changes	(5,828)			(23)
Impact of foreign exchange	5,287			3,783
Other business taxes	(13,943)			(11,065)
Impact of items not taxable for tax purposes	2,373			3,624
Adjustments to prior years including resolution for certain outstanding audits	21,658			(724)
Other	(71)			(101)
Total income tax expense	$	(1,489)		$	(119,859)

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 is as follows:

As at			Dec 31, 2023						Dec 31, 2022
	Net		Deferred tax assets		Deferred tax liabilities		Net		Deferred tax assets		Deferred tax liabilities
Property, plant and equipment (owned)	$	(363,644)	$	(189,646)	$	(173,998)	$	(403,505)	$	(230,756)	$	(172,749)
Right-of-use assets	(35,883)		(28,299)		(7,584)		(33,477)		(26,486)		(6,991)
Repatriation taxes	(109,186)		(7)		(109,179)		(106,989)		—		(106,989)
Other	(31,630)		(9,259)		(22,371)		(78,305)		(60,850)		(17,455)
	(540,343)		(227,212)		(313,131)		(622,276)		(318,092)		(304,184)
Non-capital loss carryforwards	358,774		321,602		37,172		353,986		322,608		31,378
Lease obligations	48,633		37,854		10,779		46,438		35,957		10,481
Share-based compensation	16,391		651		15,740		17,068		2,096		14,972
Other	50,955		19,355		31,600		24,141		3,784		20,357
	474,753		379,462		95,291		441,633		364,445		77,188
Net deferred income tax assets (liabilities)	$	(65,590)	$	152,250	$	(217,840)	$	(180,643)	$	46,353	$	(226,996)

As at December 31, 2023, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in the United States. These loss carryforwards expire as follows:

	Dec 31 2023
	Gross amount		Tax effect
Expire
Losses generated in 2015 (expires 2035)	$	282,437	$	62,136
Losses generated in 2016 (expires 2036)	432,581		95,168
Losses generated in 2017 (expires 2037)	234,941		51,687
	949,959		208,991
No expiry
Losses generated in 2019	255,244		56,154
Losses generated in 2020	121,321		26,691
Losses generated in 2023	29,235		6,432
Total non-capital loss carryforwards	$	1,355,760	$	298,267

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

			2023						2022
	Net		Deferred tax assets		Deferred tax liabilities		Net		Deferred tax assets		Deferred tax liabilities
Balance, January 1	$	(180,643)	$	46,353	$	(226,996)	$	(114,536)	$	98,169	$	(212,705)
Deferred income tax recovery (expense) included in net income	48,435		40,159		8,276		7,719		22,578		(14,859)
Deferred income tax recovery (expense) included in other comprehensive income	66,636		65,738		898		(72,440)		(74,394)		1,954
Other	(17)		—		(17)		(1,386)		—		(1,386)
Balance, December 31	$	(65,590)	$	152,250	$	(217,840)	$	(180,643)	$	46,353	$	(226,996)

XML

Supplemental cash flow information (Tables)

12 Months Ended

Dec. 31, 2023

Cash Flow Statement [Abstract]

Changes in non-cash working capital

Changes in non-cash working capital for the years ended December 31, 2023 and 2022 were as follows:

For the years ended December 31	2023		2022
Changes in non-cash working capital:
Trade and other receivables	$	(32,690)	$	50,442
Inventories	12,997		19,785
Prepaid expenses	(19,439)		(2,622)
Trade, other payables and accrued liabilities	(17,333)		(46,751)
	(56,465)		20,854
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid and interest received	6,027		59,283
Changes in non-cash working capital having a cash effect	$	(50,438)	$	80,137
These changes relate to the following activities:
Operating	$	(59,058)	$	54,122
Financing	68,750		1,771
Investing	(60,130)		24,244
Changes in non-cash working capital	$	(50,438)	$	80,137

Reconciliation of liabilities arising from financing activities

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

	Long term debt (note 8)		Lease obligations (note 9)
Balance at December 31, 2022	$	2,151,513	$	870,163
Changes from financing cash flows
Repayment of long-term debt and financing fees	(12,280)		—
Payment of lease obligations	—		(118,159)
Total changes from financing cash flows	(12,280)		(118,159)
Liability-related other changes
Finance costs	2,568		—
New lease obligations	—		123,187
Other	—		(3,071)
Total liability-related other changes	2,568		120,116
Balance at December 31, 2023	$	2,141,801	$	872,120

XML

Capital disclosures (Tables)

12 Months Ended

Dec. 31, 2023

Liquidity And Capitalization [Abstract]

Schedule of liquidity and capitalization

As at	Dec 31 2023		Dec 31 2022
Liquidity:
Cash and cash equivalents	$	458,015	$	857,747
Undrawn credit facility	300,000		300,000
Undrawn G3 construction facility	—		300,000
Total liquidity	$	758,015	$	1,457,747
Capitalization:
Unsecured notes, including current portion	1,985,660		1,983,374
Other limited recourse debt facilities, including current portion	156,141		168,139
Total debt	2,141,801		2,151,513
Non-controlling interests	242,090		317,444
Shareholders’ equity	1,930,927		2,112,013
Total capitalization	$	4,314,818	$	4,580,970
Total debt to capitalization 1	50%		47%
Net debt to capitalization 2	44%		35%

1     Total debt (including Other limited recourse debt facilities) divided by total capitalization.

2     Total debt (including Other limited recourse debt facilities) less cash and cash equivalents divided by total capitalization less cash and cash equivalents.

XML

Financial instruments (Tables)

12 Months Ended

Dec. 31, 2023

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 2023		Dec 31 2022
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	121,108	$	322,748
Fair value of Egypt gas supply contract derivative 2	20,402		11,220
Financial assets not measured at fair value:
Cash and cash equivalents	458,015		857,747
Trade and other receivables, excluding tax receivable	514,739		488,184
Restricted cash included in other assets	15,772		14,349
Total financial assets 3	$	1,130,036	$	1,694,248
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	91,653	$	8,466
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	672,237		656,010
Lease obligations, including current portion	872,120		870,163
Long-term debt, including current portion	2,141,801		2,151,513
Land mortgage	28,014		28,514
Total financial liabilities	$	3,805,825	$	3,714,666

1     The Geismar 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 Egypt natural gas supply contract is measured at fair value using a Monte-Carlo model classified within Level 3 of the fair value hierarchy.

3     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 following table provides the carrying value of each category of financial assets and liabilities and the related balance sheet item:

As at	Dec 31 2023		Dec 31 2022
Financial assets:
Financial assets measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	121,108	$	322,748
Fair value of Egypt gas supply contract derivative 2	20,402		11,220
Financial assets not measured at fair value:
Cash and cash equivalents	458,015		857,747
Trade and other receivables, excluding tax receivable	514,739		488,184
Restricted cash included in other assets	15,772		14,349
Total financial assets 3	$	1,130,036	$	1,694,248
Financial liabilities:
Financial liabilities measured at fair value:
Derivative instruments designated as cash flow hedges 1	$	91,653	$	8,466
Financial liabilities not measured at fair value:
Trade, other payables and accrued liabilities, excluding tax payable	672,237		656,010
Lease obligations, including current portion	872,120		870,163
Long-term debt, including current portion	2,141,801		2,151,513
Land mortgage	28,014		28,514
Total financial liabilities	$	3,805,825	$	3,714,666

1     The Geismar 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 Egypt natural gas supply contract is measured at fair value using a Monte-Carlo model classified within Level 3 of the fair value hierarchy.

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

The carrying values of the Company’s financial instruments approximate their fair values, except as follows:

As at	December 31, 2023				December 31, 2022
	Carrying value		Fair value		Carrying value		Fair value
Long-term debt excluding deferred financing fees	$	2,156,534	$	2,063,661	$	2,168,585	$	1,953,932

Fair value, natural gas forward contracts and cash flow hedges and excluded forward element

As at	Dec 31 2023		Dec 31 2022
Maturities	2024-2032		2023-2032
Notional quantity 1	347,190		307,900
Notional quantity per day, annualized 1	50 - 170		50 - 150
Notional amount	$	1,183,319	$	1,014,264
Net fair value	$	29,925	$	316,008

1    In thousands of Million British Thermal Units (MMBtu)

Information regarding the gross amounts of the Company's natural gas forward contracts designated as cash flow hedges in the audited consolidated statements of financial position is as follows:

As at	Dec 31 2023		Dec 31 2022
Other current assets	$	470	$	32,768
Other non-current assets	120,638		289,979
Other current liabilities	(60,532)		(317)
Other long-term liabilities	(30,651)		(6,422)
Net fair value	$	29,925	$	316,008

Information regarding the impact of changes in cash flow hedges and cost of hedging reserve in the consolidated statement of comprehensive income is as follows:

For the years ended December 31	2023		2022
Change in fair value of cash flow hedges	$	(276,619)	$	(27,742)
Forward element excluded from hedging relationships	(33,837)		406,029
	$	(310,456)	$	378,287

Fair value, level 2 maturity profile

The table below shows the nominal cash outflows for derivative hedging instruments including natural gas forward contracts and forward exchange contracts, excluding credit risk adjustments, based upon contracted settlement dates. The amounts reflect the maturity profile of the hedging instruments 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 2023		Dec 31 2022
Within one year	$	65,034	$	2,050
1-3 years	17,771		7,132
3-5 years	5,537		—
More than 5 years	11,378		—
	$	99,720	$	9,182

Fair value, level 3 inputs and the sensitivities, valuation to changes

The table presents the Level 3 inputs and the sensitivities of the Monte-Carlo model valuation to changes in these inputs:

	Sensitivities
Valuation input	Input value or range	Change in input	Resulting change in valuation
Methanol price volatility (before impact of mean reversion)	35%	+/- 5%	$+/-7 million
Methanol price forecast	$300 - $415 per MT	+/- $25 per MT	$-5/+7 million
Discount rate	7.6%	+/- 1%	$-/+1 million

XML

Financial risk management (Tables)

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Schedule of interest rate risk exposure

The Company’s interest rate risk exposure is mainly related to the undrawn credit facility.

As at	Dec 31 2023		Dec 31 2022
Fixed interest rate debt:
Unsecured notes	$	1,985,660	$	1,983,374
Other limited recourse debt facilities	156,141		168,139
	$	2,141,801	$	2,151,513

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, 2023	Carrying amount		Contractual cash flows		1 year or less		1-3 years		3-5 years		More than 5 years
Trade and other payables 1	$	659,723	$	659,723	$	659,723	$	—	$	—	$	—
Lease obligations 2	872,120		1,174,346		172,197		266,499		220,681		514,969
Other long-term liabilities2	28,014		53,348		2,200		4,400		4,400		42,348
Long-term debt 2	2,141,801		2,932,911		425,953		220,901		879,530		1,406,527
Cash flow hedges 3	91,653		99,720		65,034		17,771		5,537		11,378
	$	3,793,311	$	4,920,048	$	1,325,107	$	509,571	$	1,110,148	$	1,975,222

1     Excludes tax, accrued interest and euro foreign currency hedges.

2     Contractual cash flows include contractual interest payments related to debt obligations and lease obligations.

3 The expected cash flows of hedges are based on current valuations of the expected settlement amounts, which will fluctuate at settlement dependent on the market prices at the future settlement dates

XML

Retirement plans (Tables)

12 Months Ended

Dec. 31, 2023

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 2023		Dec 31 2022
Accrued benefit obligations:
Balance, beginning of year	$	53,586	$	62,208
Current service cost	2,246		2,329
Past service cost	2,479		—
Interest cost on accrued benefit obligations	2,549		2,007
Benefit payments	(4,280)		(5,760)
Settlements	(3,738)		—
Actuarial (gain) loss	2,074		(4,047)
Foreign exchange (gain) loss	265		(3,151)
Balance, end of year	55,181		53,586
Fair values of plan assets:
Balance, beginning of year	38,347		46,608
Interest income on assets	1,901		1,221
Contributions	5,687		4,457
Benefit payments	(4,280)		(5,760)
Settlements	(3,680)		—
Return on plan assets	(705)		(5,173)
Foreign exchange gain (loss)	938		(3,006)
Balance, end of year	38,208		38,347
Unfunded status	16,973		15,239
Minimum funding requirement	—		—
Defined benefit obligation, net	$	16,973	$	15,239

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, 2023 and 2022 is as follows:

For the years ended December 31	2023		2022
Net defined benefit pension plan expense:
Current service cost	$	2,246	$	2,329
Past service cost	2,479		—
Net interest cost	648		786
Cost of settlement	(58)		—
Total net defined benefit pension plan expense	$	5,315	$	3,115

Expense recognized in other comprehensive income

The Company’s current year actuarial losses, recognized in the consolidated statements of comprehensive income for the years ended December 31, 2023 and 2022, are as follows:

For the years ended December 31	2023		2022
Actuarial loss	$	(2,827)	$	(726)

Disclosure of fair value of plan assets

The asset allocation for the defined benefit pension plan assets as at December 31, 2023 and 2022 is as follows:

As at	Dec 31 2023	Dec 31 2022
Equity securities	15%	20%
Debt securities	52%	49%
Cash and other short-term securities	33%	31%
Total	100%	100%

XML

Commitments and contingencies (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023

2024		2025		2026		2027		2028		Thereafter
$	438,284	$	517,793	$	324,251	$	254,155	$	215,417	$	923,105

Schedule of contractual obligations

The Company has future minimum payments relating primarily to short-term vessel charters, terminal facilities, and other commitments that are not leases, as follows:

As at December 31, 2023

2024		2025		2026		2027		2028		Thereafter
$	94,534	$	4,665	$	1,314	$	560	$	358	$	1,183

Refer to note 9 for a summary of lease commitments.

XML

Related parties (Tables)

12 Months Ended

Dec. 31, 2023

Related Party [Abstract]

Schedule of disclosure of interests in subsidiaries and joint ventures

The Company has interests in significant subsidiaries and joint ventures as follows:

Name	Country of incorporation	Principal activities	Interest %
			Dec 31 2023	Dec 31 2022
Significant subsidiaries:
Methanex Asia Pacific Limited	Hong Kong	Marketing & distribution	100%	100%
Methanex Services (Shanghai) Co., Ltd.	China	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 SpA	Chile	Production	100%	100%
Methanex New Zealand Limited	New Zealand	Production	100%	100%
Methanex Trinidad (Titan) Unlimited	Trinidad and Tobago	Production	100%	100%
Methanex USA LLC	United States	Production	100%	100%
Methanex Louisiana LLC	United States	Production	100%	100%
Methanex Geismar III LLC	United States	Geismar 3 project development	100%	100%
Waterfront Shipping Limited 1	Canada	Shipping	60%	60%
Significant joint ventures:
Atlas Methanol Company Unlimited 2	Trinidad and Tobago	Production	63.1%	63.1%

1     On February 1, 2022, we closed the shipping partnership with Mitsui O.S.K. Lines, Ltd. ("MOL") whereby MOL acquired a 40% minority interest in Waterfront Shipping Limited.

2     Summarized financial information for the investment in Atlas is disclosed in note 6.

Schedule of disclosure of transactions between related parties

Remuneration to non-management directors and senior management, which includes the members of the executive leadership team, is as follows:

For the years ended December 31	2023		2022
Short-term employee benefits	$	9,034	$	11,760
Post-employment benefits	681		656
Other long-term employee benefits	59		52
Share-based compensation expense 1	10,046		6,142
Total	$	19,820	$	18,610

1  Balance includes realized and unrealized expenses and recoveries from share-based compensation awards granted.

XML

Non-controlling interests (Tables)

12 Months Ended

Dec. 31, 2023

Interest In Other Entities [Abstract]

Schedule of financial information for each subsidiary with 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, 2023						Dec 31, 2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Current assets	$	129,320	$	154,308	$	283,628	$	133,499	$	180,227	$	313,726
Non-current assets	521,708		791,512		1,313,220		557,484		806,079		1,363,563
Current liabilities	(123,969)		(185,459)		(309,428)		(56,689)		(112,085)		(168,774)
Non-current liabilities	(101,810)		(718,915)		(820,725)		(104,101)		(744,936)		(849,037)
Net assets	425,249		41,446		466,695		530,193		129,285		659,478
Carrying amount of Methanex non-controlling interests	$	214,568	$	27,522	$	242,090	$	251,949	$	65,495	$	317,444

For the years ended December 31			2023						2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Revenue	$	258,782	$	670,834	$	929,616	$	212,339	$	576,810	$	789,149
Net and total comprehensive income	55,428		129,411		184,839		107,375		67,670		175,045
Net and total comprehensive income attributable to Methanex non-controlling interests	56,310		53,672		109,982		77,133		31,325		108,458
Sale of partial interest in non-controlling interests and equity contributions by non-controlling interest	$	—	$	—	$	—	$	—	$	22,545	$	22,545
Distributions made and accrued to non-controlling interests	$	(93,696)	$	(91,640)	$	(185,336)	$	(75,996)	$	(8,718)	$	(84,714)

For the years ended December 31			2023						2022
	Methanex Egypt		Waterfront Shipping Limited		Total		Methanex Egypt		Waterfront Shipping Limited 1		Total
Cash flows from operating activities	$	131,667	$	251,290	$	382,957	$	226,647	$	94,355	$	321,002
Cash flows from (used in) financing activities	(99,490)		(300,824)		(400,314)		(152,806)		(52,796)		(205,602)
Cash flows from (used in) investing activities	$	(5,560)	$	2,686	$	(2,874)	$	(35,110)	$	215	$	(34,895)

1    On February 1, 2022, we closed the shipping partnership with Mitsui O.S.K. Lines, Ltd. ("MOL") whereby MOL acquired a minority interest in Waterfront Shipping Limited.

XML

Material accounting policies - Property plant and equipment (Details)	12 Months Ended
	Dec. 31, 2023
Buildings, plant installations and machinery | Top of range
Disclosure of detailed information about property, plant and equipment [line items]
Estimated useful lives	25 years

XML

Material accounting policies - Leases (Details)	12 Months Ended
	Dec. 31, 2023
Top of range
Disclosure of Finance Leases [Line Items]
Lease term	20 years

XML

Material accounting policies - Share-based compensation (Details) - Performance shares	12 Months Ended
	Dec. 31, 2023 performanceFactor
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Number of performance factors	2
Return on capital employed average period	3 years
Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	0.00%
Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	200.00%

XML

Material accounting policies - Segmented information (Details)	12 Months Ended
	Dec. 31, 2023 segment
Corporate information and statement of IFRS compliance [abstract]
Number of operating segments	1

XML

Trade and other receivables (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Trade	$ 431,602	$ 407,733
Value-added and other tax receivables	22,292	14,986
Other	79,721	78,206
Trade and other receivables	$ 533,615	$ 500,925

XML

Inventories (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Inventories [Abstract]
Cost of inventories recognized as expense	$ 2,860	$ 3,157

XML

Property, plant and equipment - Book value (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, plant and equipment [abstract]
Owned assets	$ 3,654,475	$ 3,398,805
Right-of-use assets	757,293	756,478
Total	$ 4,411,768	$ 4,155,283

XML

Property, plant and equipment - Owned assets (Details) $ in Thousands, t in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) t	Dec. 31, 2022 USD ($)
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	$ 3,398,805
Value at end of period	3,654,475	$ 3,398,805
Buildings, plant installations and machinery
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	2,173,129
Value at end of period	2,085,505	2,173,129
Plants under construction
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	1,001,888
Value at end of period	$ 1,355,497	1,001,888
Plants under construction | Methanol plant in Geismar, Louisiana
Reconciliation of changes in property, plant and equipment [abstract]
Owned asset (in tonnes) | t	1.8
Ocean vessels
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	$ 191,557
Value at end of period	179,333	191,557
Other
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	32,231
Value at end of period	34,140	32,231
Cost
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	6,383,835	5,849,255
Additions	532,073	582,399
Disposals and other	310,818	47,819
Value at end of period	6,605,090	6,383,835
Cost | Buildings, plant installations and machinery
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	5,000,999	4,908,492
Additions	174,058	140,326
Disposals and other	294,850	47,819
Value at end of period	4,880,207	5,000,999
Cost | Plants under construction
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	1,001,888	561,860
Additions	353,609	440,028
Disposals and other	0	0
Value at end of period	1,355,497	1,001,888
Cost | Plants under construction | Methanol plant in Geismar, Louisiana
Reconciliation of changes in property, plant and equipment [abstract]
Owned assets, capitalized interest	150,000	94,000
Cost | Ocean vessels
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	240,867	240,525
Additions	253	342
Disposals and other	397	0
Value at end of period	240,723	240,867
Cost | Other
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	140,081	138,378
Additions	4,153	1,703
Disposals and other	15,571	0
Value at end of period	128,663	140,081
Accumulated depreciation
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(2,985,030)	(2,774,057)
Disposals and other	(297,431)	(51,430)
Depreciation	263,016	262,403
Value at end of period	(2,950,615)	(2,985,030)
Accumulated depreciation | Buildings, plant installations and machinery
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(2,827,870)	(2,631,268)
Disposals and other	(281,951)	(51,430)
Depreciation	248,783	248,032
Value at end of period	(2,794,702)	(2,827,870)
Accumulated depreciation | Plants under construction
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	0	0
Disposals and other	0	0
Depreciation	0	0
Value at end of period	0	0
Accumulated depreciation | Ocean vessels
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(49,310)	(37,271)
Disposals and other	0	0
Depreciation	12,080	12,039
Value at end of period	(61,390)	(49,310)
Accumulated depreciation | Other
Reconciliation of changes in property, plant and equipment [abstract]
Value at beginning of period	(107,850)	(105,518)
Disposals and other	(15,480)	0
Depreciation	2,153	2,332
Value at end of period	$ (94,523)	$ (107,850)

XML

Property, plant and equipment - Right of use assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	$ 756,478
Right-of-use assets, ending balance	757,293	$ 756,478
Cost
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	1,201,714	981,217
Additions	142,193	263,830
Disposals and other	42,124	43,333
Right-of-use assets, ending balance	1,301,783	1,201,714
Accumulated depreciation
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	(445,236)	(370,266)
Disposals and other	(31,509)	(43,717)
Depreciation	130,763	118,687
Right-of-use assets, ending balance	(544,490)	(445,236)
Ocean vessels
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	601,104
Right-of-use assets, ending balance	596,397	601,104
Ocean vessels | Cost
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	846,977	657,774
Additions	83,333	232,536
Disposals and other	19,589	43,333
Right-of-use assets, ending balance	910,721	846,977
Ocean vessels | Accumulated depreciation
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	(245,873)	(214,004)
Disposals and other	(19,589)	(43,717)
Depreciation	88,040	75,586
Right-of-use assets, ending balance	(314,324)	(245,873)
Terminals and tanks
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	125,873
Right-of-use assets, ending balance	136,138	125,873
Terminals and tanks | Cost
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	286,036	258,743
Additions	52,909	27,293
Disposals and other	6,504	0
Right-of-use assets, ending balance	332,441	286,036
Terminals and tanks | Accumulated depreciation
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	(160,163)	(125,494)
Disposals and other	0	0
Depreciation	36,140	34,669
Right-of-use assets, ending balance	(196,303)	(160,163)
Other
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	29,501
Right-of-use assets, ending balance	24,758	29,501
Other | Cost
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	68,701	64,700
Additions	5,951	4,001
Disposals and other	16,031	0
Right-of-use assets, ending balance	58,621	68,701
Other | Accumulated depreciation
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets, beginning balance	(39,200)	(30,768)
Disposals and other	(11,920)	0
Depreciation	6,583	8,432
Right-of-use assets, ending balance	$ (33,863)	$ (39,200)

XML

Investment in associate - Narrative (Details) $ in Thousands, t in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) t	Dec. 31, 2022 USD ($)
Disclosure of associates [line items]
Percentage of sales	100.00%	100.00%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Annual methanol production facility owned (in tonnes) | t	1.8
Ownership rate	100.00%
Gas contract settlement	$ 75,000	$ 0
Atlas Methanol Company Unlimited | Fixed-price contracts | Methanol | 2005 through 2014
Disclosure of associates [line items]
Percentage of sales	50.00%
Atlas Methanol Company Unlimited | Fixed-price contracts | Methanol | Late 2014 through 2019
Disclosure of associates [line items]
Percentage of sales	10.00%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Percentage of ownership interest in associates	63.10%	63.10%
Natural gas supply arrangement term	20 years
Atlas Methanol Company Unlimited | Cash-generating unit
Disclosure of associates [line items]
Discount rate used in current estimate of value in use	16.00%
Atlas Methanol Company Unlimited | Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Gas contract settlement, methanex share	$ 47,000
Gas contract settlement, net of tax	$ 31,000

XML

Investment in associate - Statements of financial position (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of associates [line items]
Cash and cash equivalents	$ 458,015	$ 857,747	$ 932,069
Other current assets	3,893	39,346
Non-current assets	4,946,234	4,755,106
Current liabilities	(1,302,306)	(942,617)
Investment in associate	184,249	197,083
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Net assets	107,921	120,755
Long-term receivable from Atlas	76,328	76,328
Investment in associate	$ 184,249	$ 197,083
Percentage of ownership interest in associates	63.10%	63.10%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Cash and cash equivalents	$ 126,392	$ 24,420
Other current assets	189,062	182,103
Non-current assets	149,354	184,373
Current liabilities	(157,835)	(92,108)
Other long-term liabilities, including current maturities	(135,940)	(107,416)
Net assets	$ 171,033	$ 191,372
Ownership rate	100.00%

XML

Investment in associate - Statements of income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of associates [line items]
Revenue	$ 3,723,475	$ 4,311,188
Operating income	263,573	610,613
Income tax expense	(1,489)	(119,859)
Net income	284,122	462,288
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Net income	99,466	76,938
Dividends received from associate	$ 112,318	$ 97,174
Percentage of ownership interest in associates	63.10%	63.10%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Revenue	$ 466,312	$ 532,456
Cost of sales and depreciation and amortization	(289,705)	(332,999)
Gas contract settlement	75,000	0
Operating income	251,607	199,457
Finance costs, finance income and other	(10,316)	(9,433)
Income tax expense	(83,659)	(68,093)
Net income	$ 157,632	$ 121,931
Ownership rate	100.00%

XML

Investment in associate - Key assumptions (Details) - Cash-generating unit - Atlas Methanol Company Unlimited	Dec. 31, 2023
Long-term average realized methanol price
Disclosure of detailed information about property, plant and equipment [line items]
Change Required for Carrying Value to Equal Recoverable Value	0.10
Production volumes
Disclosure of detailed information about property, plant and equipment [line items]
Change Required for Carrying Value to Equal Recoverable Value	0.15
Gas price
Disclosure of detailed information about property, plant and equipment [line items]
Change Required for Carrying Value to Equal Recoverable Value	0.10
Discount rate (after-tax)
Disclosure of detailed information about property, plant and equipment [line items]
Change Required for Carrying Value to Equal Recoverable Value	0.0800

XML

Other assets - Components of other assets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Cash flow hedges (note 19)	$ 121,108	$ 322,748
Chile VAT receivable	17,824	18,343
Restricted cash for debt service and major maintenance of vessels	15,772	14,349
Fair value of Egypt gas supply contract derivative (note 19)	20,402	11,220
Investment in Carbon Recycling International	5,620	5,620
Defined benefit pension plans (note 21)	5,718	3,977
Other	15,416	19,476
Total other assets	201,860	395,733
Less current portion	(3,893)	(39,346)
Other assets	$ 197,967	$ 356,387

XML

Other assets - Narrative (Details) $ in Millions	Dec. 31, 2023 USD ($) vessel	Dec. 31, 2022 USD ($)
Subclassifications of assets, liabilities and equities [abstract]
Restricted cash and cash equivalents	$ 15.8	$ 14.3
Restricted cash, cash flow hedge	0.5
Restricted cash, major maintenance	$ 3.4
Restricted cash, number of vessels | vessel	4

XML

Long-term debt - Components of long-term debt (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 2,141,801,000	$ 2,151,513,000
Less current maturities	(314,716,000)	(15,133,000)
Non-current portion of long-term debt	1,827,085,000	2,136,380,000
Debt discounts and deferred financing fees	16,800,000	19,400,000
Unsecured notes
Disclosure of detailed information about borrowings [line items]
Total long-term debt	1,985,660,000	1,983,374,000
$300 million at 4.25% due December 1, 2024
Disclosure of detailed information about borrowings [line items]
Total long-term debt	299,283,000	298,836,000
Notional amount	$ 300,000,000
$300 million at 4.25% due December 1, 2024 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate	4.25%
$700 million at 5.125% due October 15, 2027
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 694,844,000	693,649,000
Notional amount	$ 700,000,000
$700 million at 5.125% due October 15, 2027 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate	5.125%
$700 million at 5.25% due December 15, 2029
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 695,824,000	695,283,000
Notional amount	$ 700,000,000
$700 million at 5.25% due December 15, 2029 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate	5.25%
$300 million at 5.65% due December 1, 2044
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 295,709,000	295,606,000
Notional amount	$ 300,000,000
$300 million at 5.65% due December 1, 2044 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate	5.65%
Other limited recourse debt facilities
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 156,141,000	168,139,000
5.58% due June 30, 2031
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 56,637,000	61,978,000
5.58% due June 30, 2031 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate	5.58%
5.35% due September 30, 2033
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 65,300,000	70,312,000
5.35% due September 30, 2033 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate	5.35%
5.21% due September 15, 2036
Disclosure of detailed information about borrowings [line items]
Total long-term debt	$ 34,204,000	$ 35,849,000
5.21% due September 15, 2036 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Interest rate	5.21%

XML

Long-term debt - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Disclosure of detailed information about borrowings [line items]
Accretion of deferred financing costs	$ 2,600,000	$ 2,200,000
Undrawn credit facility
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing facilities	$ 300,000,000	300,000,000
Debt covenant, EBITDA to interest coverage ratio	2
Debt covenant, debt to capitalization ratio	60.00%
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
G3 construction facility
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing facilities	0	$ 300,000,000
Cancellation of non-revolving construction facility	$ 300,000,000

XML

Long-term debt - Maturity (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	$ 2,141,801	$ 2,151,513
Other limited recourse debt facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	156,141	168,139
Unsecured notes
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	1,985,660	$ 1,983,374
Carrying amount
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	2,158,596
Carrying amount | 2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	315,367
Carrying amount | 2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	13,660
Carrying amount | 2026
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	13,796
Carrying amount | 2027
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	715,173
Carrying amount | 2028
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	16,026
Carrying amount | Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	1,084,574
Carrying amount | Other limited recourse debt facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	158,596
Carrying amount | Other limited recourse debt facilities | 2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	15,367
Carrying amount | Other limited recourse debt facilities | 2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	13,660
Carrying amount | Other limited recourse debt facilities | 2026
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	13,796
Carrying amount | Other limited recourse debt facilities | 2027
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	15,173
Carrying amount | Other limited recourse debt facilities | 2028
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	16,026
Carrying amount | Other limited recourse debt facilities | Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	84,574
Carrying amount | Unsecured notes
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	2,000,000
Carrying amount | Unsecured notes | 2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	300,000
Carrying amount | Unsecured notes | 2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	0
Carrying amount | Unsecured notes | 2026
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	0
Carrying amount | Unsecured notes | 2027
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	700,000
Carrying amount | Unsecured notes | 2028
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	0
Carrying amount | Unsecured notes | Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long-term debt	$ 1,000,000

XML

Lease obligations - Lease activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of Leases [Abstract]
Opening lease obligations, beginning balance	$ 870,163	$ 717,101
Additions, net of disposals	123,187	262,470
Interest expense	53,418	48,039
Lease payments	(171,577)	(153,901)
Effect of movements in exchange rates and other	(3,071)	(3,546)
Lease obligations, ending balance	872,120	870,163
Less: current portion	(120,731)	(108,736)
Lease obligations - non current portion	$ 751,389	$ 761,427

XML

Lease obligations - Lease payments (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Disclosure Of Maturity Analysis Of Lease Payments [Line Items]
Lease payments	$ 1,174,346
Interest component	302,226
Lease obligations	872,120
2024
Disclosure Of Maturity Analysis Of Lease Payments [Line Items]
Lease payments	172,197
Interest component	51,466
Lease obligations	120,731
2025
Disclosure Of Maturity Analysis Of Lease Payments [Line Items]
Lease payments	142,761
Interest component	45,617
Lease obligations	97,144
2026
Disclosure Of Maturity Analysis Of Lease Payments [Line Items]
Lease payments	123,738
Interest component	39,998
Lease obligations	83,740
2027
Disclosure Of Maturity Analysis Of Lease Payments [Line Items]
Lease payments	112,397
Interest component	34,419
Lease obligations	77,978
2028
Disclosure Of Maturity Analysis Of Lease Payments [Line Items]
Lease payments	108,284
Interest component	28,547
Lease obligations	79,737
Thereafter
Disclosure Of Maturity Analysis Of Lease Payments [Line Items]
Lease payments	514,969
Interest component	102,179
Lease obligations	$ 412,790

XML

Lease obligations - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) vessel	Dec. 31, 2022 USD ($) vessel
Disclosure of Leases [Abstract]
Expense relating to variable lease payments not included in measurement of lease liabilities	$ 83,800	$ 81,900
Expense relating to short-term leases for which recognition exemption has been used	200	200
Potential future lease payments not included in lease liabilities (undiscounted)	51,778	53,500
Lease not yet commenced, amount	$ 68,700	$ 132,600
Lease not yet commenced, number of vessel, additions | vessel	1
Lease not yet commenced, term (in years)	5 years
Lease not yet commenced, number of vessels | vessel		1

XML

Lease obligations - Extension options (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure of Finance Leases [Line Items]
Lease liabilities recognized (discounted)	$ 872,120
Potential future lease payments not included in lease liabilities (undiscounted)	51,778	$ 53,500
Ocean-going vessels
Disclosure of Finance Leases [Line Items]
Lease liabilities recognized (discounted)	662,903
Potential future lease payments not included in lease liabilities (undiscounted)	1,512
Terminals and tanks
Disclosure of Finance Leases [Line Items]
Lease liabilities recognized (discounted)	174,019
Potential future lease payments not included in lease liabilities (undiscounted)	38,987
Other
Disclosure of Finance Leases [Line Items]
Lease liabilities recognized (discounted)	35,198
Potential future lease payments not included in lease liabilities (undiscounted)	$ 11,279

XML

Other long-term liabilities - Components of other long-term liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Share-based compensation liability (note 14)	$ 74,107	$ 70,569
Site restoration costs	32,596	36,581
Land mortgage	28,014	28,514
Defined benefit pension plans (note 21)	22,691	19,216
Cash flow hedges (note 19)	91,183	6,739
Other	1,319	2,532
Other long-term liabilities	249,910	164,151
Less current maturities	(94,992)	(29,548)
Other non-current liabilities	$ 154,918	$ 134,603

XML

Other long-term liabilities - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Undiscounted amount of estimated cash flows required to settle liabilities	$ 50.6	$ 52.1

XML

Other long-term liabilities - Provision for site restoration costs (Details) - Provision for site restoration costs - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of changes in other provisions [abstract]
Balance at beginning of period	$ 36,581	$ 29,355
New or revised provisions	(5,573)	6,915
Accretion expense	1,588	311
Balance at end of period	$ 32,596	$ 36,581

XML

Expenses - Components of expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Analysis of income and expense [abstract]
Cost of sales	$ 2,797,794	$ 3,238,312
Selling and distribution	552,693	498,552
Administrative expenses	109,415	81,657
Total expenses by function	3,459,902	3,818,521
Cost of raw materials and purchased methanol	2,329,856	2,789,921
Ocean freight and other logistics	357,495	325,893
Employee expenses, including share-based compensation	243,542	219,012
Other expenses	137,179	111,275
Cost of sales and operating expenses	3,068,072	3,446,101
Depreciation and amortization	391,830	372,420
Total expenses by nature	$ 3,459,902	$ 3,818,521

XML

Expenses - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Expenses [Line Items]
Share-based compensation expense	$ 34,502	$ 15,398
Revenue	3,723,475	4,311,188
Atlas Methanol Company Unlimited
Expenses [Line Items]
Revenue	$ 466,312	$ 532,456

XML

Finance costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Borrowing costs [abstract]
Finance costs before capitalized interest	$ 172,814	$ 167,066
Less capitalized interest related to Geismar plant under construction	(55,448)	(36,314)
Finance costs	$ 117,366	$ 130,752

XML

Net income per common share - Reconciliation of numerator used for calculation of diluted net income per common share (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Earnings per share [abstract]
Numerator for basic net income per common share	$ 174,140	$ 353,830
Adjustment for the effect of TSARs:
Cash-settled recovery included in net income	0	(316)
Equity-settled expense	0	(5,503)
Numerator for diluted net income per common share	$ 174,140	$ 348,011

XML

Net income per common share - Reconciliation of denominator used for calculation of diluted net income per common share (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Earnings per share [abstract]
Denominator for basic net income per common share (in shares)	67,805,220	71,422,360
Effect of dilutive stock options (in shares)	6,395	10,108
Effect of dilutive TSARS (in shares)	0	245,016
Denominator for diluted net income per common share (in shares)	67,811,615	71,677,484

XML

Net income per common share - Basic and diluted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Earnings per share [abstract]
Basic net income per common share (in usd per share)	$ 2.57	$ 4.95
Diluted net income per common share (in usd per share)	$ 2.57	$ 4.86

XML

Share-based compensation - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) performanceFactor shares	Dec. 31, 2022 USD ($)
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 (in shares) | shares	4,010,076
Liabilities from share-based payment transactions	$ 74,107	$ 70,569
SARs and TSARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	7 years
Vesting rate	33.33%
Fair value of share-based payment transactions	$ 26,700
Liabilities from share-based payment transactions	25,000
Intrinsic value of liabilities from share-based payment transactions	$ 1,700
Weighted average remaining vesting period	1 year 4 months 24 days
Expense from share-based payment transactions with employees	$ 10,500	1,800
Expense (recovery) from share-based payment transactions with employees, effect of change in share price	$ 6,600	(3,700)
Performance Share Units (PSU) New Plan
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Number of performance factors | performanceFactor	2
Performance Share Units (PSU) New Plan | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	0.00%
Performance Share Units (PSU) New Plan | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	200.00%
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	$ 58,600
Liabilities from share-based payment transactions	48,900
Intrinsic value of liabilities from share-based payment transactions	$ 9,700
Weighted average remaining vesting period	1 year 8 months 12 days
Expense from share-based payment transactions with employees	$ 23,900	13,500
Expense (recovery) from share-based payment transactions with employees, effect of change in share price	$ 8,800	$ (3,400)
Performance shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Number of performance factors | performanceFactor	2
Return on capital employed average period	3 years
Performance shares | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	0.00%
Performance shares | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share-based compensation arrangement vesting rights, percentage	200.00%

XML

Share-based compensation - Changes in SARs and TSARs (Details)	12 Months Ended
	Dec. 31, 2023 shares $ / shares	Dec. 31, 2022 shares $ / shares
SARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period (in units) | shares	407,687	666,256
Number of outstanding units granted (in units) | shares	51,160	32,730
Number of outstanding units exercised (in units) | shares	(50,715)	(129,162)
Number of outstanding units cancelled (in units) | shares	(5,600)	(12,900)
Number of outstanding units expired (in units) | shares		(149,237)
Number of outstanding units, end of period (in units) | shares	402,532	407,687
Exercise price of outstanding units, beginning of period (in usd per unit) | $ / shares	$ 44.67	$ 45.7
Exercise price of outstanding units granted (in usd per unit) | $ / shares	50.49	48.49
Exercise price of outstanding units exercised (in usd per unit) | $ / shares	33.85	37.17
Exercise price of outstanding units cancelled (in usd per unit) | $ / shares	53.69	55.70
Exercise price of outstanding units expired (in usd per unit) | $ / shares		55.66
Exercise price of outstanding units, end of period (in usd per unit) | $ / shares	$ 46.65	$ 44.67
TSARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period (in units) | shares	2,188,359	2,380,237
Number of outstanding units granted (in units) | shares	169,190	266,090
Number of outstanding units exercised (in units) | shares	(336,535)	(290,577)
Number of outstanding units cancelled (in units) | shares	(13,544)	(21,922)
Number of outstanding units expired (in units) | shares		(145,469)
Number of outstanding units, end of period (in units) | shares	2,007,470	2,188,359
Exercise price of outstanding units, beginning of period (in usd per unit) | $ / shares	$ 42.68	$ 42.05
Exercise price of outstanding units granted (in usd per unit) | $ / shares	50.49	48.49
Exercise price of outstanding units exercised (in usd per unit) | $ / shares	31.88	35.94
Exercise price of outstanding units cancelled (in usd per unit) | $ / shares	51.36	46.45
Exercise price of outstanding units expired (in usd per unit) | $ / shares		55.82
Exercise price of outstanding units, end of period (in usd per unit) | $ / shares	$ 45.10	$ 42.68

XML

Share-based compensation - Range of exercise prices in SARs and TSARs (Details)	12 Months Ended
	Dec. 31, 2023 shares $ / shares	Dec. 31, 2022 shares $ / shares	Dec. 31, 2021 shares $ / shares
SARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	2 years 7 months 20 days
Number of units outstanding (in units) | shares	402,532	407,687	666,256
Weighted average exercise price of units outstanding (in usd per unit)	$ 46.65	$ 44.67	$ 45.7
Number of units exercisable (in units) | shares	316,389
Weighted average exercise price of units exercisable (in usd per unit)	$ 46.23
SARs | $29.27 to $38.79
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	3 years 6 months 7 days
Number of units outstanding (in units) | shares	112,962
Weighted average exercise price of units outstanding (in usd per unit)	$ 32.60
Number of units exercisable (in units) | shares	99,800
Weighted average exercise price of units exercisable (in usd per unit)	$ 31.78
SARs | $29.27 to $38.79 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	29.27
SARs | $29.27 to $38.79 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 38.79
SARs | $45.40 to $50.49
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	2 years 11 months 4 days
Number of units outstanding (in units) | shares	171,010
Weighted average exercise price of units outstanding (in usd per unit)	$ 49.93
Number of units exercisable (in units) | shares	98,029
Weighted average exercise price of units exercisable (in usd per unit)	$ 49.96
SARs | $45.40 to $50.49 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	45.40
SARs | $45.40 to $50.49 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 50.49
SARs | $54.65 to $78.59
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	1 year 4 months 20 days
Number of units outstanding (in units) | shares	118,560
Weighted average exercise price of units outstanding (in usd per unit)	$ 55.30
Number of units exercisable (in units) | shares	118,560
Weighted average exercise price of units exercisable (in usd per unit)	$ 55.30
SARs | $54.65 to $78.59 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	54.65
SARs | $54.65 to $78.59 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 78.59
TSARs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	3 years 25 days
Number of units outstanding (in units) | shares	2,007,470	2,188,359	2,380,237
Weighted average exercise price of units outstanding (in usd per unit)	$ 45.10	$ 42.68	$ 42.05
Number of units exercisable (in units) | shares	1,555,147
Weighted average exercise price of units exercisable (in usd per unit)	$ 44.57
TSARs | $29.27 to $38.79
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	3 years 6 months 25 days
Number of units outstanding (in units) | shares	776,194
Weighted average exercise price of units outstanding (in usd per unit)	$ 33.05
Number of units exercisable (in units) | shares	666,922
Weighted average exercise price of units exercisable (in usd per unit)	$ 32.11
TSARs | $29.27 to $38.79 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	29.27
TSARs | $29.27 to $38.79 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 38.79
TSARs | $45.40 to $50.49
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	3 years 7 months 24 days
Number of units outstanding (in units) | shares	673,316
Weighted average exercise price of units outstanding (in usd per unit)	$ 49.55
Number of units exercisable (in units) | shares	330,265
Weighted average exercise price of units exercisable (in usd per unit)	$ 49.62
TSARs | $45.40 to $50.49 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	45.40
TSARs | $45.40 to $50.49 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 50.49
TSARs | $54.65 to $78.59
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average remaining contractual life (years)	1 year 7 months 28 days
Number of units outstanding (in units) | shares	557,960
Weighted average exercise price of units outstanding (in usd per unit)	$ 56.48
Number of units exercisable (in units) | shares	557,960
Weighted average exercise price of units exercisable (in usd per unit)	$ 56.48
TSARs | $54.65 to $78.59 | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	54.65
TSARs | $54.65 to $78.59 | Top of range
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average exercise price of units outstanding (in usd per unit)	$ 78.59

XML

Share-based compensation - Weighted average assumptions (Details) - SARs and TSARs - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of terms and conditions of share-based payment arrangement [line items]
Risk-free interest rate	4.50%	4.40%
Expected dividend yield	1.60%	1.90%
Expected life of SARs and TSARs (years)	1 year 4 months 24 days	1 year 9 months 18 days
Expected volatility	38.00%	51.00%
Expected forfeitures	0.00%	0.00%
Weighted average fair value (in usd per unit)	$ 10.75	$ 8.72

XML

Share-based compensation - Changes in other equity instruments (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Deferred share units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period (in units)	155,761	133,418
Number of outstanding units granted (in units)	18,417	19,909
Number of outstanding units performance factor impact on redemption (in units)	0	0
Number of outstanding units granted in lieu of dividends (in units)	2,484	2,434
Number of outstanding units redeemed (in units)	(18,962)	0
Number of outstanding units cancelled (in units)	0	0
Number of outstanding units, end of period (in units)	157,700	155,761
Restricted share units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period (in units)	340,929	332,385
Number of outstanding units granted (in units)	104,980	104,810
Number of outstanding units performance factor impact on redemption (in units)	0	0
Number of outstanding units granted in lieu of dividends (in units)	5,267	5,561
Number of outstanding units redeemed (in units)	(131,398)	(82,039)
Number of outstanding units cancelled (in units)	(8,924)	(19,788)
Number of outstanding units, end of period (in units)	310,854	340,929
Performance Share Units (PSU) New Plan
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of outstanding units, beginning of period (in units)	744,887	689,688
Number of outstanding units granted (in units)	179,340	199,430
Number of outstanding units performance factor impact on redemption (in units)	143,065	(14,796)
Number of outstanding units granted in lieu of dividends (in units)	10,411	11,764
Number of outstanding units redeemed (in units)	(435,035)	(119,714)
Number of outstanding units cancelled (in units)	(11,546)	(21,485)
Number of outstanding units, end of period (in units)	631,122	744,887

XML

Segmented information - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 segment
Operating Segments [Abstract]
Number of operating segments	1

XML

Segmented information - Revenue attributed to geographic location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of geographical areas [line items]
Revenue	$ 3,723,475	$ 4,311,188
Percentage of sales	100.00%	100.00%
China
Disclosure of geographical areas [line items]
Revenue	$ 1,042,723	$ 1,105,610
Percentage of sales	28.00%	26.00%
Europe
Disclosure of geographical areas [line items]
Revenue	$ 722,578	$ 830,507
Percentage of sales	19.00%	19.00%
United States
Disclosure of geographical areas [line items]
Revenue	$ 574,951	$ 657,495
Percentage of sales	15.00%	15.00%
South America
Disclosure of geographical areas [line items]
Revenue	$ 428,617	$ 458,989
Percentage of sales	12.00%	11.00%
South Korea
Disclosure of geographical areas [line items]
Revenue	$ 391,821	$ 542,646
Percentage of sales	11.00%	13.00%
Other Asia
Disclosure of geographical areas [line items]
Revenue	$ 387,373	$ 518,901
Percentage of sales	10.00%	12.00%
Canada
Disclosure of geographical areas [line items]
Revenue	$ 175,412	$ 197,040
Percentage of sales	5.00%	4.00%

XML

Segmented information - Property, plant and equipment, net (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure of geographical areas [line items]
Property, plant and equipment	$ 4,411,768	$ 4,155,283
United States
Disclosure of geographical areas [line items]
Property, plant and equipment	2,537,515	2,211,333
Egypt
Disclosure of geographical areas [line items]
Property, plant and equipment	520,497	564,454
New Zealand
Disclosure of geographical areas [line items]
Property, plant and equipment	232,831	211,544
Canada
Disclosure of geographical areas [line items]
Property, plant and equipment	157,483	165,783
Chile
Disclosure of geographical areas [line items]
Property, plant and equipment	113,789	102,467
Trinidad
Disclosure of geographical areas [line items]
Property, plant and equipment	43,835	70,432
Waterfront Shipping
Disclosure of geographical areas [line items]
Property, plant and equipment	775,729	792,016
Other
Disclosure of geographical areas [line items]
Property, plant and equipment	$ 30,089	$ 37,254

XML

Income and other taxes - Income tax (expense) recovery (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Current tax (expense) recovery:
Current period before undernoted items	$ (64,679)	$ (127,254)
Adjustments to prior years including resolution for certain outstanding audits	14,755	(324)
Current tax recovery (expense)	(49,924)	(127,578)
Deferred tax recovery (expense):
Origination and reversal of temporary differences	46,982	9,589
Adjustments to prior years including resolution for certain outstanding audits	6,904	(400)
Changes in tax rates	(5,828)	(23)
Impact of foreign exchange and other	377	(1,447)
Deferred tax recovery (expense)	48,435	7,719
Total income tax expense	$ (1,489)	$ (119,859)

XML

Income and other taxes - Reconciliation of effective tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Taxes [Abstract]
Income before income taxes	$ 285,611	$ 582,147
Deduct earnings of associate	(99,466)	(76,938)
Income (loss) before income taxes after deduction of earnings of associate	$ 186,145	$ 505,209
Canadian statutory tax rate	24.50%	24.50%
Income tax expense calculated at Canadian statutory tax rate	$ (45,606)	$ (123,776)
Decrease (increase) in income tax expense resulting from:
Impact of income and losses taxed in foreign jurisdictions	27,260	1,346
Utilization of unrecognized loss carryforwards and temporary differences	7,381	7,077
Impact of tax rate changes	(5,828)	(23)
Impact of foreign exchange	5,287	3,783
Other business taxes	(13,943)	(11,065)
Impact of items not taxable for tax purposes	2,373	3,624
Adjustments to prior years including resolution for certain outstanding audits	21,658	(724)
Other	(71)	(101)
Total income tax expense	$ (1,489)	$ (119,859)

XML

Income and other taxes - Net deferred income tax assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	$ (65,590)	$ (180,643)	$ (114,536)
Deferred tax assets	152,250	46,353
Deferred tax liabilities	(217,840)	(226,996)
Temporary differences including temporary differences with liability balances
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(540,343)	(622,276)
Deferred tax assets	(227,212)	(318,092)
Deferred tax liabilities	(313,131)	(304,184)
Property, plant and equipment (owned)
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(363,644)	(403,505)
Deferred tax assets	(189,646)	(230,756)
Deferred tax liabilities	(173,998)	(172,749)
Right-of-use assets
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(35,883)	(33,477)
Deferred tax assets	(28,299)	(26,486)
Deferred tax liabilities	(7,584)	(6,991)
Repatriation taxes
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(109,186)	(106,989)
Deferred tax assets	(7)	0
Deferred tax liabilities	(109,179)	(106,989)
Other
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	(31,630)	(78,305)
Deferred tax assets	(9,259)	(60,850)
Deferred tax liabilities	(22,371)	(17,455)
Temporary differences including temporary differences with asset balances
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	474,753	441,633
Deferred tax assets	379,462	364,445
Deferred tax liabilities	95,291	77,188
Non-capital loss carryforwards
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	358,774	353,986
Deferred tax assets	321,602	322,608
Deferred tax liabilities	37,172	31,378
Lease obligations
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	48,633	46,438
Deferred tax assets	37,854	35,957
Deferred tax liabilities	10,779	10,481
Share-based compensation
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	16,391	17,068
Deferred tax assets	651	2,096
Deferred tax liabilities	15,740	14,972
Other
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net	50,955	24,141
Deferred tax assets	19,355	3,784
Deferred tax liabilities	$ 31,600	$ 20,357

XML

Income and other taxes - Unused tax losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Tax effect	$ (7,381)	$ (7,077)
Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	1,355,760
Tax effect	298,267
Expire | Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	949,959
Tax effect	208,991
Losses generated in 2015 (expires 2035) | Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	282,437
Tax effect	62,136
Losses generated in 2016 (expires 2036) | Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	432,581
Tax effect	95,168
Losses generated in 2017 (expires 2037) | Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	234,941
Tax effect	51,687
Losses generated in 2019 | Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	255,244
Tax effect	56,154
Losses generated in 2020 | Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	121,321
Tax effect	26,691
Losses generated in 2023 | Unused tax losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Gross amount	29,235
Tax effect	$ 6,432

XML

Income and other taxes - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	$ 152,250	$ 46,353	$ 98,169
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	201,000	231,000
Trinidad
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Operating loss carryforwards	82,000	70,000
Deferred tax assets	29,000	24,000
New Zealand
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Operating loss carryforwards	25,000	7,000
Deferred tax assets	7,000	2,000
Canada
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Operating loss carryforwards	123,000	121,000
Deferred tax assets	$ 30,000	$ 30,000

XML

Income and other taxes - Change in deferred income tax liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Net
Net, beginning of period	$ (180,643)	$ (114,536)
Deferred income tax recovery (expense) included in net income	48,435	7,719
Deferred income tax recovery (expense) included in other comprehensive income	66,636	(72,440)
Other	(17)	(1,386)
Net, end of period	(65,590)	(180,643)
Deferred tax assets
Deferred tax assets, beginning of period	46,353	98,169
Deferred income tax recovery (expense) included in net income	40,159	22,578
Deferred income tax recovery (expense) included in other comprehensive income	65,738	(74,394)
Other	0	0
Deferred tax assets, end of period	152,250	46,353
Deferred tax liabilities
Deferred tax liabilities, beginning of period	(226,996)	(212,705)
Deferred income tax recovery (expense) included in net income	8,276	(14,859)
Deferred income tax recovery (expense) included in other comprehensive income	898	1,954
Other	(17)	(1,386)
Deferred tax liabilities, end of period	$ (217,840)	$ (226,996)

XML

Supplemental cash flow information - Changes in non-cash working capital (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Changes in non-cash working capital:
Trade and other receivables	$ (32,690)	$ 50,442
Inventories	12,997	19,785
Prepaid expenses	(19,439)	(2,622)
Trade, other payables and accrued liabilities	(17,333)	(46,751)
Decrease (increase) in non-cash working capital	(56,465)	20,854
Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid and interest received	6,027	59,283
Changes in non-cash working capital	(50,438)	80,137
These changes relate to the following activities:
Operating	(59,058)	54,122
Financing	68,750	1,771
Investing	(60,130)	24,244
Changes in non-cash working capital	$ (50,438)	$ 80,137

XML

Supplemental cash flow information - Reconciliation of liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Changes from financing cash flows
Repayment of long-term debt and financing fees	$ (12,280)	$ (9,151)
Payment of lease obligations	(118,159)	(105,863)
Long term debt
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Outstanding at beginning of period	2,151,513
Changes from financing cash flows
Repayment of long-term debt and financing fees	(12,280)
Payment of lease obligations	0
Total changes from financing cash flows	(12,280)
Liability-related other changes
Finance costs	2,568
New lease obligations	0
Other	0
Total liability-related other changes	2,568
Outstanding at end of period	2,141,801	2,151,513
Lease obligations
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Outstanding at beginning of period	870,163
Changes from financing cash flows
Repayment of long-term debt and financing fees	0
Payment of lease obligations	(118,159)
Total changes from financing cash flows	(118,159)
Liability-related other changes
Finance costs	0
New lease obligations	123,187
Other	(3,071)
Total liability-related other changes	120,116
Outstanding at end of period	$ 872,120	$ 870,163

XML

Capital disclosures (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of liquidity and capitalization [Line Items]
Cash and cash equivalents	$ 458,015,000	$ 857,747,000	$ 932,069,000
Total liquidity	758,015,000	1,457,747,000
Total debt	2,141,801,000	2,151,513,000
Non-controlling interests	242,090,000	317,444,000
Shareholders’ equity	1,930,927,000	2,112,013,000
Total capitalization	$ 4,314,818,000	$ 4,580,970,000
Total debt to capitalization	50.00%	47.00%
Net debt to capitalization	44.00%	35.00%
Undrawn credit facility
Disclosure of liquidity and capitalization [Line Items]
Undrawn credit facility	$ 300,000,000	$ 300,000,000
G3 construction facility
Disclosure of liquidity and capitalization [Line Items]
Undrawn credit facility	0	300,000,000
Cancellation of non-revolving construction facility	300,000,000
Unsecured notes
Disclosure of liquidity and capitalization [Line Items]
Total debt	1,985,660,000	1,983,374,000
Other limited recourse debt facilities
Disclosure of liquidity and capitalization [Line Items]
Total debt	$ 156,141,000	$ 168,139,000

XML

Financial instruments - Financial assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	$ 1,130,036	$ 1,694,248
Financial liabilities	3,805,825	3,714,666
Trade, other payables and accrued liabilities, excluding tax payable | Financial liabilities not measured at fair value:
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	672,237	656,010
Lease obligations, including current portion | Financial liabilities not measured at fair value:
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	872,120	870,163
Long-term debt, including current portion | Financial liabilities not measured at fair value:
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	2,141,801	2,151,513
Land mortgage | Financial liabilities not measured at fair value:
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	28,014	28,514
Cash flow hedges | Derivative instruments designated as cash flow hedges | Financial liabilities measured at fair value:
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities	91,653	8,466
Derivative instruments designated as cash flow hedges | Financial assets measured at fair value: | Cash flow hedges
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	121,108	322,748
Fair value of Egypt gas supply contract derivative | Financial assets measured at fair value: | Cash flow hedges
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	20,402	11,220
Cash and cash equivalents | Financial assets not measured at fair value:
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	458,015	857,747
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	514,739	488,184
Restricted cash included in other assets | Financial assets not measured at fair value:
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets	$ 15,772	$ 14,349

XML

Financial instruments - North american natural gas forward contracts (Details) MMBTU in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MMBTU	Dec. 31, 2022 USD ($) MMBTU
Accumulated other comprehensive income
Disclosure of financial assets [line items]
Reclassification of hedge gain (loss) in cash flow hedge	$ (22,500,000)	$ 55,000,000
North american natural gas forward contract
Disclosure of financial assets [line items]
Hedge ineffectiveness	$ 0	$ 0
North american natural gas forward contract | Cash flow hedges
Disclosure of financial assets [line items]
Hedging instrument, energy (in mmbtu) | MMBTU	347,190	307,900
Notional amount	$ 1,183,319,000	$ 1,014,264,000
Assets, fair value	29,925,000	316,008,000
North american natural gas forward contract | Cash flow hedges | Other current assets
Disclosure of financial assets [line items]
Assets, fair value	470,000	32,768,000
North american natural gas forward contract | Cash flow hedges | Other non-current assets
Disclosure of financial assets [line items]
Assets, fair value	120,638,000	289,979,000
North american natural gas forward contract | Cash flow hedges | Other current liabilities
Disclosure of financial assets [line items]
Liabilities, fair value	(60,532,000)	(317,000)
North american natural gas forward contract | Cash flow hedges | Other long-term liabilities
Disclosure of financial assets [line items]
Liabilities, fair value	$ (30,651,000)	$ (6,422,000)
North american natural gas forward contract | Cash flow hedges | Bottom of range
Disclosure of financial assets [line items]
Hedging instrument, daily energy annualized (in mmbtu) | MMBTU	50	50
North american natural gas forward contract | Cash flow hedges | Top of range
Disclosure of financial assets [line items]
Hedging instrument, daily energy annualized (in mmbtu) | MMBTU	170	150

XML

Financial instruments - Euro forward exchange contracts (Details) € in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2023 EUR (€)	Dec. 31, 2022 EUR (€)
Disclosure of financial assets [line items]
Realized losses (gains) on foreign exchange hedges reclassified to revenue	$ 3,105,000	$ (5,674,000)
Euro forward exchange contracts
Disclosure of financial assets [line items]
Hedge ineffectiveness	0	0
Euro forward exchange contracts | Cash flow hedges
Disclosure of financial assets [line items]
Notional amount | €			€ 12.2	€ 21.1
Euro forward exchange contracts | Cash flow hedges | Current liabilities
Disclosure of financial assets [line items]
Liabilities, fair value	$ 500,000	$ 1,700,000

XML

Financial instruments - Changes in cash flow hedges and excluded forward element (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Financial Instruments [Abstract]
Change in fair value of cash flow hedges	$ (276,619)	$ (27,742)
Forward element excluded from hedging relationships	(33,837)	406,029
Changes in cash flow hedges and excluded forward element	$ (310,456)	$ 378,287

XML

Financial instruments - Fair value - Level 2 instruments, maturity (Details) - Level 2 - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	$ 99,720	$ 9,182
Within one year
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	65,034	2,050
1-3 years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	17,771	7,132
3-5 years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	5,537	0
Thereafter
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	$ 11,378	$ 0

XML

Financial instruments - Fair value - Level 2 instruments, narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure of financial assets [line items]
Financial assets	$ 1,130,036	$ 1,694,248
Financial assets measured at fair value: | Derivative instruments | Cash flow hedges
Disclosure of financial assets [line items]
Financial assets	121,108	322,748
Financial assets measured at fair value: | Derivative instruments | Cash flow hedges | Level 2
Disclosure of financial assets [line items]
Financial assets	$ 121,100	$ 322,700

XML

Financial instruments - Fair value - Level 2 instruments, carrying values of financial instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure of fair value measurement of liabilities [line items]
Carrying value	$ 3,805,825	$ 3,714,666
Long-term debt excluding deferred financing fees | Level 2
Disclosure of fair value measurement of liabilities [line items]
Carrying value	2,156,534	2,168,585
Fair value	$ 2,063,661	$ 1,953,932

XML

Financial instruments - Fair value - Level 3 instrument, narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure Of Financial Assets And Liabilities [Line Items]
Derivative financial assets	$ 20,402	$ 11,220
Fair value of Egypt gas supply contract derivative | Level 3 of fair value hierarchy
Disclosure Of Financial Assets And Liabilities [Line Items]
Derivative financial assets	$ 20,400	$ 11,200

XML

Financial instruments - Fair value - Level 3 instrument, inputs and the sensitivities, valuation to changes (Details) - Level 3 of fair value hierarchy $ in Millions	Dec. 31, 2023 USD ($) $ / Mt
Input value or range | Methanol price volatility (before impact of mean reversion)
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	0.35
Input value or range | Methanol price forecast | Minimum
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets | $ / Mt	300
Input value or range | Methanol price forecast | Maximum
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets | $ / Mt	415
Input value or range | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	0.076
Change in input | Methanol price volatility (before impact of mean reversion)
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	0.05
Change in input | Methanol price forecast
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets | $ / Mt	25
Change in input | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	0.01
Resulting change in valuation | Methanol price volatility (before impact of mean reversion) | Minimum
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	7
Resulting change in valuation | Methanol price forecast | Minimum
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	7
Resulting change in valuation | Methanol price forecast | Maximum
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	5
Resulting change in valuation | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant unobservable input, assets	1

XML

Financial risk management - Interest rate risk (Details) - Interest rate risk - Fixed interest rate - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	$ 2,141,801	$ 2,151,513
Reasonably possible change in risk variable, percent	1.00%
Reasonably possible change in risk variable, impact on debt	$ 100,500	104,800
Unsecured notes
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	1,985,660	1,983,374
Other limited recourse debt facilities
Disclosure of financial instruments by type of interest rate [line items]
Long-term debt	$ 156,141	$ 168,139

XML

Financial risk management - Foreign currency risk (Details) - Currency risk - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of financial instruments by type of interest rate [line items]
Net working capital asset	$ 74.4	$ 69.9
Reasonably possible change in risk variable, percent	10.00%
Impact on value of net working capital	$ 7.4	$ 7.0

XML

Financial risk management - Liquidity risks (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Financial Instruments [Abstract]
Cash and cash equivalents	$ 458,015,000	$ 857,747,000	$ 932,069,000
Carrying amount
Lease obligations	872,120,000	870,163,000	$ 717,101,000
Other long-term liabilities	154,918,000	134,603,000
Long-term debt	2,141,801,000	2,151,513,000
Cash flow hedges	91,183,000	6,739,000
Financial liabilities	3,805,825,000	3,714,666,000
Liquidity risk
Carrying amount
Trade and other payables	659,723,000
Lease obligations	872,120,000
Other long-term liabilities	28,014,000
Long-term debt	2,141,801,000
Cash flow hedges	91,653,000
Financial liabilities	3,793,311,000
Contractual cash flows
Trade and other payables	659,723,000
Lease obligations	1,174,346,000
Other long-term liabilities	53,348,000
Long-term debt	2,932,911,000
Cash flow hedges	99,720,000
Financial liabilities	4,920,048,000
Liquidity risk | 1 year or less
Contractual cash flows
Trade and other payables	659,723,000
Lease obligations	172,197,000
Other long-term liabilities	2,200,000
Long-term debt	425,953,000
Cash flow hedges	65,034,000
Financial liabilities	1,325,107,000
Liquidity risk | 1-3 years
Contractual cash flows
Trade and other payables	0
Lease obligations	266,499,000
Other long-term liabilities	4,400,000
Long-term debt	220,901,000
Cash flow hedges	17,771,000
Financial liabilities	509,571,000
Liquidity risk | 3-5 years
Contractual cash flows
Trade and other payables	0
Lease obligations	220,681,000
Other long-term liabilities	4,400,000
Long-term debt	879,530,000
Cash flow hedges	5,537,000
Financial liabilities	1,110,148,000
Liquidity risk | Thereafter
Contractual cash flows
Trade and other payables	0
Lease obligations	514,969,000
Other long-term liabilities	42,348,000
Long-term debt	1,406,527,000
Cash flow hedges	11,378,000
Financial liabilities	1,975,222,000
Undrawn credit facility
Disclosure of financial liabilities [line items]
Undrawn credit facility	$ 300,000,000	$ 300,000,000

XML

Retirement plans - Defined benefit pension plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	$ 15,239
Past service cost	(2,479)	$ 0
Balance, end of year	16,973	15,239
Unfunded status	16,973	15,239
Minimum funding requirement	0	0
Accrued benefit obligations
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	53,586	62,208
Current service cost	2,246	2,329
Past service cost	2,479	0
Interest cost on accrued benefit obligations / income on assets	2,549	2,007
Benefit payments	(4,280)	(5,760)
Settlements	(3,738)	0
Actuarial (gain) loss	2,074	(4,047)
Foreign exchange gain (loss)	265	(3,151)
Balance, end of year	55,181	53,586
Fair values of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	38,347	46,608
Interest cost on accrued benefit obligations / income on assets	1,901	1,221
Benefit payments	(4,280)	(5,760)
Settlements	(3,680)	0
Contributions	5,687	4,457
Return on plan assets	(705)	(5,173)
Foreign exchange gain (loss)	938	(3,006)
Balance, end of year	$ 38,208	$ 38,347

XML

Retirement plans - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	$ 16,973,000	$ 15,239,000
Weighted average duration of defined benefit obligation	7 years
Minimum funding requirement	$ 0	$ 0
Discount rates	5.30%	5.10%
Defined contribution pension plans	$ 11,000,000	$ 9,700,000
Discount rate
Disclosure of net defined benefit liability (asset) [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	$ 3,600,000
Unfunded | Chile
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	20,200,000	19,200,000
Estimate of contributions expected to be paid to plan for next annual reporting period	11,300,000
Unfunded | Egypt
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	2,500,000	0
Estimate of contributions expected to be paid to plan for next annual reporting period	100,000
Funded
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	(5,300,000)	(3,600,000)
Estimate of contributions expected to be paid to plan for next annual reporting period	0
Funded | Europe
Disclosure of net defined benefit liability (asset) [line items]
Retirement obligation (asset)	(400,000)	$ (400,000)
Estimate of contributions expected to be paid to plan for next annual reporting period	$ 500,000

XML

Retirement plans - Expense recognized in income statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Net defined benefit pension plan expense:
Current service cost	$ 2,246	$ 2,329
Past service cost	2,479	0
Net interest cost	648	786
Cost of settlement	(58)	0
Total net defined benefit pension plan expense	$ 5,315	$ 3,115

XML

Retirement plans - Expense recognized in other comprehensive income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Employee Benefits [Abstract]
Actuarial loss	$ (2,827)	$ (726)

XML

Retirement plans - Asset allocation (Details)	Dec. 31, 2023	Dec. 31, 2022
Employee Benefits [Abstract]
Equity securities	15.00%	20.00%
Debt securities	52.00%	49.00%
Cash and other short-term securities	33.00%	31.00%
Total	100.00%	100.00%

XML

Commitments and contingencies - Minimum purchase contract commitment (Details) - Take-or-pay purchase contracts $ in Thousands	Dec. 31, 2023 USD ($)
2024
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	$ 438,284
2025
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	517,793
2026
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	324,251
2027
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	254,155
2028
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	215,417
Thereafter
Disclosure of contingent liabilities [line items]
Minimum estimated commitment	$ 923,105

XML

Commitments and contingencies - Other commitments (Details) - Contractual obligations $ in Thousands	Dec. 31, 2023 USD ($)
2024
Disclosure of other provisions [line items]
Other commitments	$ 94,534
2025
Disclosure of other provisions [line items]
Other commitments	4,665
2026
Disclosure of other provisions [line items]
Other commitments	1,314
2027
Disclosure of other provisions [line items]
Other commitments	560
2028
Disclosure of other provisions [line items]
Other commitments	358
Thereafter
Disclosure of other provisions [line items]
Other commitments	$ 1,183

XML

Commitments and contingencies - Narrative (Details) - t t in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2024	Dec. 31, 2023	Dec. 31, 2022
Purchase commitment of methanol supply | Within one year
Disclosure of associates [line items]
Purchase commitments (in tonnes)		0.8
Atlas Plant
Disclosure of associates [line items]
Percentage of marketing rights in production		100.00%
Percentage of ownership interest in associates		63.10%	63.10%
Atlas Plant | Purchase commitment of methanol supply
Disclosure of associates [line items]
Purchase commitments (in tonnes)		0.6
Atlas Plant | Purchase commitment of methanol supply | Forecast
Disclosure of associates [line items]
Purchase commitments (in tonnes)	0.4
Atlas Plant | Trinidad
Disclosure of associates [line items]
Percentage of ownership interest in associates		63.10%
Atlas Plant | Egypt
Disclosure of associates [line items]
Percentage of ownership interest in associates		50.00%
Egypt Plant | Purchase commitment of methanol supply
Disclosure of associates [line items]
Purchase commitments (in tonnes)		0.6

XML

Related parties - Subsidiaries and joint ventures (Details)		12 Months Ended
	Feb. 01, 2022	Dec. 31, 2023	Dec. 31, 2022
Methanex Asia Pacific Limited
Disclosure of subsidiaries [line items]
Interest %		100.00%	100.00%
Methanex Services (Shanghai) Co., Ltd.
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 SpA
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 USA LLC
Disclosure of subsidiaries [line items]
Interest %		100.00%	100.00%
Methanex Louisiana LLC
Disclosure of subsidiaries [line items]
Interest %		100.00%	100.00%
Methanex Geismar III LLC
Disclosure of subsidiaries [line items]
Interest %		100.00%	100.00%
Waterfront Shipping Limited
Disclosure of subsidiaries [line items]
Interest %		60.00%	60.00%
Waterfront Shipping Limited | Mitsui O.S.K. Lines, Ltd. (MOL)
Disclosure of subsidiaries [line items]
Interest %	40.00%
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Interest %		63.10%	63.10%

XML

Related parties - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of associates [line items]
Revenue	$ 3,723,475	$ 4,311,188
Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Percentage of marketing rights in production	100.00%
Loans outstanding from related party transactions	$ 76,328	76,328
Associates | Atlas Methanol Company Unlimited
Disclosure of associates [line items]
Revenue	466,000	532,000
Receivables from related party transactions	74,000	73,000
Payables from related party transactions	172,000	198,000
Loans outstanding from related party transactions	$ 76,000	$ 76,000

XML

Related parties - Remuneration (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Related Party [Abstract]
Short-term employee benefits	$ 9,034	$ 11,760
Post-employment benefits	681	656
Other long-term employee benefits	59	52
Share-based compensation expense	10,046	6,142
Total	$ 19,820	$ 18,610

XML

Non-controlling interests - Financial position (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Disclosure of subsidiaries [line items]
Current assets	$ 1,480,321	$ 1,876,374
Non-current assets	4,946,234	4,755,106
Current liabilities	(1,302,306)	(942,617)
Non-current liabilities	(2,951,232)	(3,259,406)
Carrying amount of Methanex non-controlling interests	242,090	317,444
Total
Disclosure of subsidiaries [line items]
Current assets	283,628	313,726
Non-current assets	1,313,220	1,363,563
Current liabilities	(309,428)	(168,774)
Non-current liabilities	(820,725)	(849,037)
Net assets	466,695	659,478
Carrying amount of Methanex non-controlling interests	242,090	317,444
Methanex Egypt
Disclosure of subsidiaries [line items]
Current assets	129,320	133,499
Non-current assets	521,708	557,484
Current liabilities	(123,969)	(56,689)
Non-current liabilities	(101,810)	(104,101)
Net assets	425,249	530,193
Carrying amount of Methanex non-controlling interests	214,568	251,949
Waterfront Shipping Limited
Disclosure of subsidiaries [line items]
Current assets	154,308	180,227
Non-current assets	791,512	806,079
Current liabilities	(185,459)	(112,085)
Non-current liabilities	(718,915)	(744,936)
Net assets	41,446	129,285
Carrying amount of Methanex non-controlling interests	$ 27,522	$ 65,495

XML

Non-controlling interests - Income statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of subsidiaries [line items]
Revenue	$ 3,723,475	$ 4,311,188
Net and total comprehensive income	284,122	462,288
Sale of partial interest in non-controlling interests and equity contributions by non-controlling interest	0	148,990
Distributions made and accrued to non-controlling interests	(185,336)	(84,713)
Total
Disclosure of subsidiaries [line items]
Revenue	929,616	789,149
Net and total comprehensive income	184,839	175,045
Net and total comprehensive income attributable to Methanex non-controlling interests	109,982	108,458
Sale of partial interest in non-controlling interests and equity contributions by non-controlling interest	0	22,545
Distributions made and accrued to non-controlling interests	(185,336)	(84,714)
Methanex Egypt
Disclosure of subsidiaries [line items]
Revenue	258,782	212,339
Net and total comprehensive income	55,428	107,375
Net and total comprehensive income attributable to Methanex non-controlling interests	56,310	77,133
Sale of partial interest in non-controlling interests and equity contributions by non-controlling interest	0	0
Distributions made and accrued to non-controlling interests	(93,696)	(75,996)
Waterfront Shipping Limited
Disclosure of subsidiaries [line items]
Revenue	670,834	576,810
Net and total comprehensive income	129,411	67,670
Net and total comprehensive income attributable to Methanex non-controlling interests	53,672	31,325
Sale of partial interest in non-controlling interests and equity contributions by non-controlling interest	0	22,545
Distributions made and accrued to non-controlling interests	$ (91,640)	$ (8,718)

XML

Non-controlling interests - Cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of subsidiaries [line items]
Cash flows from operating activities	$ 660,269	$ 987,349
Cash flows from (used in) financing activities	(551,418)	(508,534)
Cash flows from (used in) investing activities	(508,583)	(553,137)
Total
Disclosure of subsidiaries [line items]
Cash flows from operating activities	382,957	321,002
Cash flows from (used in) financing activities	(400,314)	(205,602)
Cash flows from (used in) investing activities	(2,874)	(34,895)
Methanex Egypt
Disclosure of subsidiaries [line items]
Cash flows from operating activities	131,667	226,647
Cash flows from (used in) financing activities	(99,490)	(152,806)
Cash flows from (used in) investing activities	(5,560)	(35,110)
Waterfront Shipping Limited
Disclosure of subsidiaries [line items]
Cash flows from operating activities	251,290	94,355
Cash flows from (used in) financing activities	(300,824)	(52,796)
Cash flows from (used in) investing activities	$ 2,686	$ 215

XML

Sale of interest in subsidiary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of subsidiaries [line items]
Increase (decrease) through change in equity of subsidiaries, equity		$ 148,990
Waterfront Shipping Limited
Disclosure of subsidiaries [line items]
Proportion of ownership interests sold		40.00%
Sale of partial interests in subsidiary		$ 149,000
Ownership rate	60.00%	60.00%
Increase (decrease) through change in equity of subsidiaries, equity		$ 126,000

XML

Egypt gas redirection and sale proceeds (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas Assets [Abstract]
Egypt gas redirection and sale proceeds, agreement period		3 months
Egypt gas redirection and sale proceeds	$ 0	$ 117,946
Egypt gas redirection and sale proceeds, parent		$ 59,000