EX-99 2 a2024annual_glossypdf.htm EX-99

TABLE OF CONTENTS 2 2024 Financial Highlights 3 President’s Message to Shareholders 5 Chair’s Message to Shareholders 6 Management’s Discussion and Analysis 49 Consolidated Financial Statements 54 Notes to Consolidated Financial Statements Methanex Corporation is the world’s largest producer and supplier of methanol and serves customers in Asia Pacific, North America, Europe and South America. Our methanol production sites are located in the United States, Chile, Egypt, New Zealand, Trinidad and Tobago, and Canada. Our primary objective is to create value through our leadership in the global production, marketing and delivery of methanol to customers. Methanol is a clear, biodegradable liquid commodity chemical that is a key ingredient in a variety of chemical derivatives, and serves as a building block to produce a multitude of everyday consumer and industrial items. Methanol is also used in a number of energy-related applications as an alternative fuel.

Methanex – Global Methanol Industry Leader ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- Global Production Facilities Methanex’s global production sites are strategically positioned to supply customers globally. United States Our plants in Geismar, Louisiana, have the capability to serve global methanol demand. We have three plants in the United States, Geismar 1, Geismar 2, and Geismar 3. New Zealand Our New Zealand production site supplies methanol primarily to customers in Asia Pacific. We have one operating plant in Motunui. The second Motunui plant, along with a third in Waitara Valley, are idled indefinitely. Trinidad and Tobago Our Trinidad production site supplies methanol to customers globally. We have two plants in Trinidad and Tobago: Atlas (Methanex interest 63.1%) and Titan. The Titan plant resumed operations in September 2024, whereupon the Atlas plant was idled. Chile Our Chile production site supplies methanol to customers in South America and Asia Pacific. We have two plants in Chile: Chile I and Chile IV. Egypt The Egypt plant (Methanex interest 50%) is located on the Mediterranean Sea and primarily supplies methanol to domestic and European customers, but can also supply customers in Asia. Canada Our plant in Medicine Hat, Alberta, supplies methanol to customers in North America. Global Supply Chain Methanex has an extensive global supply chain and distribution network of terminals and storage facilities throughout Asia Pacific, North America, Europe and South America. Methanex’s majority owned Waterfront Shipping subsidiary operates the largest methanol ocean tanker fleet in the world. The fleet forms a seamless transportation network dedicated to keeping an uninterrupted flow of methanol moving to storage terminals and customers’ plant sites around the world. Our Responsible Care Commitment The Responsible Care Ethic and Principles for Sustainability are foundational to everything we do. This United Nations- recognized chemical industry initiative informs the governance and management of our environmental and social matters. It includes our commitment to environmental protection (including greenhouse gas emissions), health and safety (occupational and process safety), physical security and product stewardship, business continuity and crisis management, and our social responsibility program and strategy. 1

2024 Financial Highlights (U.S.$ millions, except where noted) Operations Revenue 3,720 3,723 4,311 4,415 2,650 Net income (loss) (attributable to Methanex shareholders) 164 174 354 482 (157) Adjusted net income (loss) 1 252 153 343 460 (123) Adjusted EBITDA 1 764 622 932 1,108 346 Cash flows from operating activities 737 660 987 994 461 Diluted per Share Amounts (U.S.$ per common share) Net income (loss) (attributable to Methanex shareholders) 2.39 2.57 4.86 6.13 (2.06) Adjusted net income (loss) 1 3.72 2.25 4.79 6.03 (1.62) Financial Position Cash and cash equivalents 892 458 858 932 834 Total assets 6,597 6,427 6,631 6,090 5,696 Long-term debt, including current portion 2,415 2,142 2,152 2,158 2,363 Net debt to capitalization 1 2 39 % 44 % 35 % 39 % 51 % Other Information Average realized price (U.S.$ per tonne) 3 355 333 397 393 247 Total sales volume (000s tonnes) 10,469 11,169 10,774 11,184 10,740 Sales of Methanex-produced methanol (000s tonnes) 6,094 6,455 6,141 6,207 6,704 Total production (000s tonnes) 6,358 6,642 6,118 6,514 6,614 2024 2023 2022 2021 2020 1 The Company has used the terms Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share, and Net debt to capitalization 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 39 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures. 2 Defined as total debt less cash and cash equivalents divided by the sum of total equity and total debt less cash and cash equivalents (including 100% of debt related to the Egypt methanol facility). 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. 2

President’s Message to Shareholders DEAR FELLOW SHAREHOLDERS, 2024 was a highly successful and pivotal year for Methanex with the achievement of the company’s best-ever safety performance and the completion of significant milestones to strengthen our asset position. In 2024, our team did an outstanding job around the globe safely managing the day-to-day operations, performing maintenance and turnaround activities and executing the startup of Geismar 3 all while achieving safety performance that places the company in the top ten percent of safety performance among the American Chemistry Council’s Responsible Care® members. The startup of Geismar 3 ("G3") and the announcement of the acquisition of OCI Global’s (“OCI”) international methanol business represent significant milestones achieved during the year that position us well as a company to continue to execute on our long-term strategy. During 2024, the team did an outstanding job managing natural gas feedstock opportunities and risks at our locations outside of North America through the extension of gas contracts in Chile to underpin higher production levels, executing the switchover between the Atlas plant and the Titan plant in Trinidad, and moving to a one-plant operation in New Zealand in response to a change in the gas outlook. Our global team successfully navigated these changes while also safely and seamlessly managing supply chain implications to preserve our key competitive advantage of security of supply to our customers. Safety is our top priority Safety, environmental excellence, and the well-being of the communities in which we operate are core to our business. In 2024, we achieved our best occupational safety performance on record and operated our assets with no major process safety or environmental events. This is an outstanding achievement that is the result of our long commitment to Responsible Care, and I am proud of our global team’s many efforts to continuously improve how we safely plan and execute the business and their ongoing dedication and commitment to our Responsible Care culture. Delivering the Geismar 3 plant and acquiring OCI Global’s international methanol business Continuing to strengthen our leadership position through value accretive growth is a key element of our strategy and we achieved significant milestones in 2024. The addition of the 1.8 million tonne G3 plant significantly strengthens our asset portfolio and cash flow capability and adds the lowest carbon intensity plant in our asset network. I am proud of our team who proactively responded to the unanticipated delay in commercial operations in February and developed a robust restart plan. The G3 plant safely started up and produced first methanol in July and completed its commercial performance tests in October. In September, we announced the acquisition of OCI’s international methanol business for approximately $2.05 billion, subject to regulatory approval and other closing conditions. Throughout the transaction process in 2024, the team did an outstanding job delivering extensive and well-planned due diligence, developing and executing a robust financing strategy and ensuring strong executive oversight and Board governance. By acquiring world-scale North American methanol assets at an attractive price relative to brownfield replacement cost and increased exposure to stable and low-cost natural gas, the OCI acquisition is expected to drive shareholder value. Actively managing our portfolio through changing gas dynamics In 2024, we produced approximately 6.4 million tonnes of methanol while dealing with changing gas dynamics outside of North America. In Chile, we successfully extended gas contracts with Chilean and Argentinian gas producers until 2030 and 2027, respectively. This has driven our fourth consecutive annual increase in production guidance for Chile for 2025, and we continue to see positive developments that we expect will allow more gas to be available during the Southern Hemisphere winter. In Egypt, the team safely managed the plant through intermittent gas constraints during the summer months adjusting operating rates to match gas availability. In Trinidad, we successfully restarted our wholly owned Titan plant in September, which has been idle since 2019, and idled the Atlas plant after the expiration of its legacy 20-year gas supply agreement. In New Zealand, the integral role we play in the country’s energy security was evident when we temporarily halted operations in August 2024 to provide our contracted natural gas to the New Zealand electricity market at favourable economics as the country’s overall energy balances were strained. Based on the medium-term gas outlook from our gas suppliers, we made the difficult decision to indefinitely idle one of our New Zealand plants and optimize the site to a one-plant operation. We are committed to maintaining optionality in these regions and working with our gas suppliers to obtain a sustainable and economic gas supply. As you can see, 2024 was a dynamic year for our operations, and I am proud of the agility demonstrated by our team who navigated these changes safely and efficiently and delivered an outstanding level of plant reliability based on available natural gas feedstock. I also want to recognize our global and regional supply chain teams who worked tirelessly to optimize our logistics during these shifts in 3

our operations. Our global supply chain advantage positions us well in 2025 to manage any impacts associated with ongoing geopolitical uncertainties around the world. Planning for the low-carbon future In 2024, we continued to progress our low carbon objectives and are actively working to develop supply options, understand the evolving regulatory landscape, and work with customers to meet their needs. We remain focused on the opportunity of methanol being used as a marine fuel. By 2030, we believe there will be over 350 methanol dual-fuel vessels on the water which represents considerable demand potential for methanol. We are working with many shipping companies to help navigate this new opportunity and ensure conventional and low-carbon methanol is available when and where it is needed. In July, we announced our partnership with Entropy, a leader in carbon capture and storage solutions, and entered a Preliminary Front-End Engineering and Design study for carbon capture, utilization and sequestration at our Medicine Hat plant in Alberta. This project could allow us to significantly lower our carbon emissions in Medicine Hat while also increasing our production. Tightening methanol markets drove higher pricing and strong financial results We saw tight industry fundamentals in 2024 driven by continued demand growth and tight supply conditions through the year. Methanol demand grew by approximately three million tonnes in 2024, driven by increasing demand from traditional chemical and energy applications and steady demand from the methanol-to-olefin segment. Methanol markets tightened over the year in response to structural supply constraints in several producing regions combined with unplanned outages. Our 2024 average realized price was $22 dollars per metric tonne higher than in 2023, and we generated adjusted EBITDA of $764 million and adjusted net income per share of $3.72. Continued commitment to a strong balance sheet and disciplined capital allocation During 2024, we completed the G3 project on budget and repaid a $300 million bond with cash generated from operations and successfully executed the financing plan for the OCI acquisition. A critical element of the financing plan was to ensure we had flexibility to repay debt to enable us to reach our leverage goals. To achieve this, we completed a number of financing activities in late 2024 including the renewal and increase of the $500 million undrawn credit facility, the syndication of a $650 million Term Loan A (undrawn at December 31, 2024) and the issuance of a $600 million bond. We ended 2024 in a strong financial position with $892 million in cash. LOOKING AHEAD TO 2025 AND BEYOND As we enter 2025, we believe we are well positioned as a business with a stronger and growing asset base in an industry with a favourable supply and demand outlook. With the startup of G3 in 2024 and the expected closing of the OCI acquisition, our production capability is expected to be significantly enhanced in 2025. This also represents a meaningful shift in our asset base to approximately 65% of production in North America accessing stable and low-cost gas supply. We believe this positions us well to deliver stable and increasing production in a tight methanol market with continued demand growth expected to outpace supply given the limited capacity additions projected in the industry. Our 2025 top priorities are to safely execute and deliver strong results from the core business, close the OCI transaction, safely and efficiently integrate OCI’s operating assets achieving the identified synergies, and reduce our leverage by repaying $550 million to $600 million in debt over the next 18 months. Along with the release of this 2024 Annual Report, we are publishing our 2024 Sustainability Report. I encourage you to read it to learn more about how we plan and deliver on important sustainability initiatives across our business. I would like to end by thanking our global team and Board of Directors for their ongoing dedication as well as all our stakeholders for their partnership with Methanex. I’m optimistic about the future of Methanex as a leader in an industry with a favourable outlook, and I believe that by continuing to deliver on our strategic priorities, we’ll generate significant value for stakeholders. Rich Sumner President & Chief Executive Officer 4

Chair’s Message to Shareholders DEAR FELLOW SHAREHOLDERS, 2024 was an exceptional year for Methanex and our Board as we oversaw the acquisition process that led to an agreement to acquire OCI Global’s (“OCI”) international methanol business (subject to regulatory approval and other closing conditions). This acquisition enhances Methanex’s asset portfolio with low-cost production and is consistent with its capital allocation philosophy. Methanex has a long track record of making disciplined capital investments, and this acquisition was pursued with the same stringent return criteria. Upon OCI's decision to initiate a formal process to sell its global methanol business, Methanex's management quickly assembled a strong internal team, with support from external advisors, to evaluate the opportunity and determine whether to recommend pursuing a bid. The Board then established two special committees to provide oversight of the bid process and eventual acquisition: the Manufacturing Special Committee and the Transaction Special Committee. The Manufacturing Committee provided oversight of all matters related to manufacturing due diligence, including a robust validation of all relevant operating assumptions utilized for valuation purposes. The Transaction Committee reviewed and validated the strategic rationale, valuation, bid contents, and financing. Following multiple formal meetings of both special committees, management presented the Board with a well-structured bid strategy that outlined compelling drivers for the acquisition, supported by a solid financing plan with a clear path to reducing debt and returning the Company to its target leverage. Management convincingly demonstrated that this acquisition would add reliability to Methanex’s manufacturing base by providing access to abundant and favourably priced North American natural gas. Moreover, the price paid is below brownfield replacement cost with no capital construction risk. After extensive and in-depth discussion, the Board unanimously approved management's recommendation to bid for and acquire OCI’s global methanol business. Following the signing of the definitive agreement to acquire OCI’s methanol business, the Board has continued to provide oversight on financing – which has now been fully executed – and management’s plans to integrate the business and realize the business case synergies. The foundation that allows the Methanex Board to work productively with management in its oversight of a transaction such as this is our adherence to our core responsibility of overseeing the Company’s strategy. Robust consideration of the Methanex strategy is a regular feature of Methanex Board meetings, culminating annually in a comprehensive review where the Board and senior management review and debate strategy while challenging the underlying assumptions and business risks. The final strategic plan is then reviewed and approved by the full Board. As such, Methanex’s well-defined strategy is built on three pillars: global leadership, low cost and operational excellence. Interlinked with the strategy is the Company’s disciplined approach to capital allocation, which balances meeting operating capital and financial commitments, investing in growth projects that meet a stringent rate of return hurdle and returning cash to shareholders through dividends and share buybacks. It is against this backdrop that the Board carefully considered and ultimately approved the acquisition of OCI’s methanol business. An informed decision about a relatively large acquisition can only be made by a board that has been deliberate about ensuring it has the right mix of skills and competencies. Methanex’s Board has such a mix, bringing together directors who have deep chemical industry knowledge, strong financial backgrounds, experience with large capital assets and an understanding of the risks inherent in commodity cycles. These complementary perspectives enabled the Board to conduct a robust process and ensure that management’s recommendation to bid for the OCI methanol business was aligned with the Company’s strategic priorities. I would like to take this opportunity to recognize two retiring directors, Bob Kostelnik and Margaret (Maggi) Walker. Bob is Methanex’s longest-serving director, and his experience in navigating methanol price cycles has been invaluable to the Board. However, his most significant legacy lies in his 10 years as Chair of the Responsible Care Committee and his relentless and ultimately successful pursuit of embedding a strong safety culture at Methanex. Maggi, along with bringing a uniquely diverse set of corporate skills, has also been an extremely effective champion of safety and an unwavering advocate for the Responsible Care ethic. In addition, both Bob and Maggi were instrumental in the Board’s oversight of the G3 project, in recent times one of Methanex’s most ambitious and impactful undertakings. On behalf of Methanex and all shareholders, I extend my sincere gratitude for their service and wish them the very best in the future. Doug Arnell Chair of the Board 5

Management’s Discussion and Analysis Exhibit 99.2 Index 6 Overview of the Business 36 Critical Accounting Estimates 8 Our Strategy 39 Adoption of New Accounting Standards 10 Financial Highlights 39 Anticipated Changes to International Financial Reporting Standards 11 Production Summary 39 Non-GAAP Measures 12 How We Analyze Our Business 41 Quarterly Financial Data (Unaudited) 13 Financial Results 41 Selected Annual Information 19 Liquidity and Capital Resources 42 Controls and Procedures 25 Risk Factors and Risk Management 43 Forward-Looking Statements This Management’s Discussion and Analysis ("MD&A") is dated March 7, 2025, and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2024. 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 39 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 and Methanol Market Services Asia, an Energy Aspects (EA) company. 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 6, 2025 we had 67,395,212 common shares issued and outstanding and stock options exercisable for 1,123,150 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 approximately 20% 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 and serve customers in Asia Pacific, North America, Europe and South America. Our total annual operating capacity, including Methanex's interests in jointly owned plants, is currently 10.6 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 plant in Egypt, which provides us with an additional 0.6 million 6

tonnes per year of methanol offtake supply when the plant is operating at full capacity. We also had marketing rights for 100% of the production from the jointly-owned Atlas plant in Trinidad and Tobago, which provided us with an additional 0.7 million tonnes per year of methanol offtake supply when the plant was operating at full capacity. Refer to the Production Summary section on page 11 for more information. Acquisition of OCI Global's Methanol Business On September 8, 2024, Methanex announced that it entered into a definitive agreement to acquire OCI Global’s (“OCI”) international methanol business for approximately $2.05 billion ("OCI Acquisition"). The transaction includes a methanol facility with an annual production capacity of 910,000 metric tonnes ("MT") of methanol and 340,000 MT of ammonia and a 50 percent interest in a second methanol facility operated by the joint venture Natgasoline LLC (“Natgasoline”) which has an annual capacity of 1.7 million MT of methanol of which Methanex’s share will be 850,000 MT. The transaction also includes a low-carbon methanol production and marketing business and a currently idled methanol facility in the Netherlands. Under the definitive agreement with OCI, the approximate $2.05 billion purchase price will consist of $1.18 billion in cash, the issuance of 9.9 million common shares of Methanex valued at $450 million (based on a $45 per share price) and the assumption of approximately $450 million in debt and leases. Closing of the transaction is expected in the second quarter of 2025 and is subject to receipt of certain regulatory approvals and other closing conditions including TSX approval for the issuance of Methanex shares to OCI. There is currently a legal proceeding between OCI and its Natgasoline joint venture partner over certain shareholder rights. The obligation of Methanex to purchase OCI’s 50% stake in Natgasoline is subject to the resolution of this legal proceeding. If it is not settled within a certain period, Methanex has the option to carve out the purchase of the Natgasoline joint venture and close only on the remainder of the transaction. 2024 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 and government regulations and policies. Methanol industry supply is impacted by the cost of production, methanol industry operating rates and methanol industry capacity changes. Demand We estimate that global methanol demand increased to approximately 97 million tonnes in 2024 driven primarily by growth in traditional chemical and energy applications and stable demand 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 availability of methanol supply, 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 clean-burning attributes and potential to reduce greenhouse gas emissions if made from a renewable feedstock. 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 potential 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 350 dual-fueled ships on the water by 2030. 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 25,000 taxis and methanol hybrid passenger cars and 5,000 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 7

this demand segment represents approximately seven million tonnes of methanol demand. We continue to support 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 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 feedstock materials, freight costs, other operating and maintenance costs and government policies. Operating rates continue to be uncertain and challenged due to the impact of trade sanctions, plant technical issues, and structural and seasonal natural gas constraints. The methanol industry ran at similar rates in 2024 compared to 2023. In 2024, there were approximately 1.5 million tonnes of production capacity additions in China. In North America, our new 1.8 million tonne Geismar 3 facility completed its commercial performance tests and is now operating at full rates. With the idling of Atlas and the restart of Titan in September 2024 overall production in Trinidad is lower by approximately 1 million tonnes annually. In Malaysia, we understand that a 1.8 million tonne plant started up in early 2025. We expect limited capacity additions in the next five years. In Iran, projects under development are showing slow progress due to technical and financing challenges from sanctions and the operating rates of existing methanol plants are constrained by gas availability due to depleting gas fields. If sanctions impacting Iran and/or other methanol producing countries are eased or removed, this could lead to an increase in methanol supply. China has planned capacity additions which we expect will be somewhat offset by the closure of some inefficient 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 2024 was $355 per tonne compared to $333 per tonne in 2023. 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 safely and 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 customers in Asia Pacific, North America, Europe and South America. Our 2024 sales volume of 10.5 million tonnes of methanol represented approximately 11% of global methanol demand. This scale allows us the flexibility to meet customer needs globally. 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 region as the basis of pricing for our customer contracts. The geographically diverse locations of our production sites and our shipping fleet allow us to deliver methanol cost-effectively to customers globally. 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 ports, 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. 8

We have storage capacity and offices in strategic global locations that allows us to cost-effectively manage supply to customers and ensure customer service and industry positioning. 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 natural gas supply contracts and financial 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. 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 safely, 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 2024, our strategy of operational excellence in financial management supported the completion of the Geismar 3 project. We also announced the OCI Acquisition for approximately $2.05 billion, subject to regulatory approval and other closing conditions. While managing both current and future capital needs we also returned cash to shareholders through the regular dividend. As at December 31, 2024, we remain in a strong liquidity position with $892 million in cash and $500 million of undrawn back-up liquidity through our revolving credit facility. In the fourth quarter of 2024, we completed the financing plan for the OCI Acquisition including renewing and increasing the undrawn credit facility, syndicating a $650 million Term Loan A and issuing $600 million in unsecured notes. The OCI Acquisition financing has been structured to allow the flexible repayment of the term loan commitment to support our capital allocation priority to reduce debt. During the fourth quarter, we also repaid $300 million in unsecured notes that were due in December 2024 with cash generated from operations. 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 material sustainability topics, which are those environmental, social or governance topics that can significantly impact our business success and are of interest to our key stakeholders. The materiality assessment that we conducted in 2023 included external stakeholder outreach and confirmed greenhouse gas ("GHG") emissions, transition to a low-carbon economy, employee and contractor safety and process safety as our most material sustainability topics. We completed a double materiality assessment at the end of 2024 to prepare for the European Corporate Sustainability Reporting Directive (CSRD). Our most material sustainability topics are unchanged. We are 9

also monitoring the EU Omnibus proposal, which was published on February 26, 2025 and will adjust our reporting approach as appropriate. 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. To improve decision making and evaluate organizational risks and opportunities under different plausible futures, we started incorporating scenario planning into our strategy development process. As part of our strategic planning in 2024, we used a dynamic general equilibrium energy model to analyze the potential implications to energy markets (including methanol) of several scenarios that differed on the pace of the energy transition. 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 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 Equity, Diversity, and Inclusion Council, made up of senior leaders from around the globe, supports the development and execution of our vision and its integration into the business. In 2024, we made significant strides towards achieving our vision, including the development of a new guide to inclusive and equitable recruitment to support the hiring process. We also established three new Employee Resource Groups, which create a safe environment for team members who share an interest in a specific dimension of diversity to connect and raise awareness. In March 2025, we issued our 2024 Sustainability Report, aligned with the Sustainability Accounting Standards Board (SASB) and the Task-Force on Climate-related Financial Disclosures (TCFD).The Report is also a transitional report as we shift towards CSRD and European Sustainability Reporting Standards requirements for 2025. The 2024 Sustainability Report is available at https:// www.methanex.com/sustainability. FINANCIAL HIGHLIGHTS Production (thousands of tonnes) (attributable to Methanex shareholders) 6,358 6,642 Sales volume (thousands of tonnes) Methanex-produced methanol 6,094 6,455 Purchased methanol 3,471 3,527 Commission sales 904 1,187 Total sales volume 1 10,469 11,169 Methanex average non-discounted posted price ($ per tonne) 2 508 434 Average realized price ($ per tonne) 3 4 355 333 Revenue 3,720 3,723 Net income (attributable to Methanex shareholders) 164 174 Adjusted net income 4 252 153 Adjusted EBITDA 4 764 622 Cash flows from operating activities 737 660 Basic net income per common share ($ per share) 2.43 2.57 Diluted net income per common share ($ per share) 2.39 2.57 Adjusted net income per common share ($ per share) 4 3.72 2.25 Common share information (millions of shares) Weighted average number of common shares 67 68 Diluted weighted average number of common shares 68 68 Number of common shares outstanding, end of year 67 67 ($ Millions, except as noted) 2024 2023 1 Methanex-produced methanol represents our equity share of volume produced at our facilities and excludes volume marketed on behalf of partners 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 39 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures. 10

PRODUCTION SUMMARY The following table details the annual operating capacity and actual production at our facilities in 2024 and 2023: USA (Geismar) 2 4,000 2,529 2,142 Trinidad (Methanex interest) 3 1,960 956 1,074 New Zealand 4 1,720 670 1,381 Chile 1,700 1,180 993 Egypt (50% interest) 630 460 504 Canada (Medicine Hat) 600 563 548 10,610 6,358 6,642 (Thousands of tonnes) Annual operating capacity 1 2024 Production 2023 Production 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 at these facilities. Actual production for a facility in any given year may be higher or lower than operating capacity due to a number of factors, including natural gas 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 G3 completed its commercial performance tests in October 2024. 3 The operating capacity of Trinidad is made up of the Titan (100% interest) and Atlas (63.1% interest) plants. The Atlas plant is currently idle. (Refer to the Trinidad and Tobago section below.) 4 The operating capacity of New Zealand is made up of the two Motunui facilities, one of which is idle.(Refer to the New Zealand section below.) United States Our Geismar plants in Louisiana produced 2.5 million tonnes of methanol in 2024, compared with 2.1 million in 2023. Production at the Geismar site was higher in 2024 as a result of production from the start-up of the Geismar 3 plant. The plant produced first methanol at the end of July and successfully completed its commercial performance tests in early October. Subsequent to first methanol production, a number of shutdowns of Geismar 3 were taken to calibrate and inspect newly commissioned equipment to ensure reliability of plant operations. Refer to the Risk Factors and Risk Management – United States section on page 29 for more information. Trinidad and Tobago We operate our fully-owned Titan facility and the Atlas facility, in which we have a 63.1% economic interest and had marketing rights for 100% of the production. Together, the two facilities represent 2.0 million tonnes of Methanex share of annual operating capacity. We produced 1.0 million tonnes of methanol (Methanex share) in 2024, compared with 1.1 million tonnes in 2023. Production in Trinidad was lower in 2024 due to the Atlas plant (Methanex 63.1% or 1,085,000 tonnes per year capacity) being idled in September, as its legacy 20-year natural gas supply agreement expired. Concurrent with the idling of the Atlas plant, the Titan plant (875,000 tonnes per year capacity) was restarted upon commencement of a two year natural gas supply agreement with the National Gas Company of Trinidad and Tobago (NGC). Refer to the Risk Factors and Risk Management – Trinidad and Tobago section on page 29 for more information. New Zealand In New Zealand, we produced 0.7 million tonnes of methanol in 2024 compared with 1.4 million tonnes in 2023. Production for 2024 was lower than 2023 due to the temporary idling of operations from August to the end of October as we entered into short-term commercial arrangements to provide contracted natural gas into the New Zealand electricity market at favourable economic terms as the country's overall energy balances were strained. Additionally, based on the medium-term gas outlook from our gas suppliers for the next few years, the decision was made to indefinitely idle one of the two Motunui plants. Based on the current outlook from our gas suppliers, we estimate production for 2025 to be between 0.5 - 0.7 million tonnes. Future production will be dependent on gas availability and any on-selling of gas into the electricity market to support New Zealand's energy needs. We are continuing discussions with our gas suppliers to ensure our contractual entitlements, which are in place until 2029, are being respected as well as engaging with our gas suppliers and government agencies in supporting efforts to improve energy balances in the country. Refer to the Risk Factors and Risk Management – New Zealand section on page 29 for more information. 11

Chile The Chile facilities produced 1.2 million tonnes of methanol in 2024 compared with 1.0 million tonnes in 2023. Production in Chile was higher in 2024 due to higher gas availability from Argentina. Both plants are expected to run at full rates from the end of September 2024 through April 2025, the southern hemisphere summer months. We estimate production for 2025 will be between 1.3 - 1.4 million tonnes. This production is supported by gas contracts in place with Chilean and Argentinean gas producers until 2030 and 2027, respectively, which underpin approximately 55% of the site's gas requirements year round. We continue to expect seasonality in production but are seeing positive developments making gas available for longer periods. Refer to the Risk Factors and Risk Management – Chile section on page 30 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 0.9 million tonnes of methanol (Methanex share of 0.5 million) in Egypt in 2024 compared to 1.0 million tonnes (Methanex share of 0.5 million) in 2023. While both years were similarly impacted by an unplanned outage caused by a mechanical failure in the synthesis gas compressor lasting from October 2023 through February 2024, we had lower levels of production from Egypt in 2024 due to fluctuating operating rates based on gas availability. In Egypt, industrial plants were impacted by gas curtailments due to increased seasonal demand for power generation due to elevated temperatures coupled with lower domestic supply. We are monitoring the gas market closely and expect to experience some curtailments in 2025, particularly in the summer months, depending on gas supply and demand dynamics. Refer to the Risk Factors and Risk Management – Egypt section on page 30 for more information. Canada Medicine Hat produced 0.6 million tonnes of methanol in 2024 compared with 0.5 million tonnes in 2023. Refer to the Risk Factors and Risk Management – Canada section on page 30 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 39 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. 12

We own 63.1% of the Atlas methanol facility and, up to the expiry of its legacy 20-year natural gas supply agreement and the idling of the plant, we marketed 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, 2024, we reported a net income attributable to Methanex shareholders of $164 million ($2.39 net income per common share on a diluted basis), compared with a net income attributable to Methanex shareholders of $174 million ($2.57 net income per common share on a diluted basis) for the year ended December 31, 2023. Net income attributable to Methanex shareholders for the year ended December 31, 2024 is lower compared to the year ended December 31, 2023, primarily due to the impact of the non-recurring asset impairment expense in relation to our New Zealand cash generating unit ("New Zealand CGU") discussed in the Critical Accounting Estimates section and elsewhere in this MD&A. This was partially offset by a higher average realized price, the New Zealand gas sale net proceeds and the Egypt insurance proceeds recorded in 2024. For the year ended December 31, 2024, we reported Adjusted EBITDA of $764 million and Adjusted net income of $252 million ($3.72 Adjusted net income per common share), compared with Adjusted EBITDA of $622 million and Adjusted net income of $153 million ($2.25 Adjusted net income per common share) for the year ended December 31, 2023. 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 and New Zealand gas contract revaluations included in finance income and other and the impact of certain items associated with specific identified events. For 2024, the impact of the asset impairment charge was excluded from Adjusted EBITDA and Adjusted net income due to the non-recurring nature of the expense and to better reflect the operating performance of the Company's business. 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. 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: Net income attributable to Methanex shareholders $ 164 $ 174 Mark-to-market impact of share-based compensation, net of tax 2 13 Impact of Egypt and New Zealand gas contract revaluation, net of tax (4) (3) Asset impairment charge, net of tax 90 — Impact on earnings of associate of gas contract settlement, net of tax — (31) Adjusted net income $ 252 $ 153 Diluted weighted average shares outstanding (millions) 68 68 Adjusted net income per common share $ 3.72 $ 2.25 ($ Millions, except number of shares and per share amounts) 2024 2023 13

A summary of our consolidated statements of income for 2024 and 2023 is as follows: Consolidated statements of income: Revenue $ 3,720 $ 3,723 Cost of sales and operating expenses (3,009) (3,068) New Zealand gas sale net proceeds 103 — Egypt insurance recovery 59 — Mark-to-market impact of share-based compensation 2 16 Adjusted EBITDA attributable to associate 82 135 Amounts excluded from Adjusted EBITDA attributable to non-controlling interests (193) (184) Adjusted EBITDA 764 622 Mark-to-market impact of share-based compensation (2) (16) Depreciation and amortization (386) (392) Gas contract settlement, net of tax — 31 Finance costs (133) (117) Finance income and other 12 40 Income tax expense (30) (1) Asset impairment charge (125) — Earnings of associate adjustment 1 (43) (67) Non-controlling interests adjustment 1 107 74 Net income attributable to Methanex shareholders $ 164 $ 174 Net income $ 250 $ 284 ($ Millions) 2024 2023 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 2024 compared to $3.7 billion in 2023. The comparable revenue reflects a higher average realized price, offset by lower sales volume in 2024 compared to 2023. We publish regional non-discounted reference prices for each methanol sales region 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 2024 was $508 per tonne compared with $434 per tonne in 2023. Our average realized price in 2024 was $355 per tonne compared to $333 per tonne in 2023. Distribution of Revenue The geographic distribution of revenue by customer location for 2024 was comparable to 2023. Details are as follows: China $ 828 22 % $ 1,043 28 % Europe 842 23 % 722 19 % United States 502 13 % 575 15 % South America 479 13 % 429 12 % South Korea 483 13 % 392 11 % Other Asia 402 11 % 387 10 % Canada 184 5 % 175 5 % $ 3,720 100 % $ 3,723 100 % ($ Millions, except where noted) 2024 2023 14

Adjusted EBITDA (Attributable to Methanex Shareholders) 2024 Adjusted EBITDA was $764 million compared with 2023 Adjusted EBITDA of $622 million, an increase of $142 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). Average realized price $ 206 Sales volume (31) Geismar 3 delay costs (22) New Zealand gas sale proceeds, net of gas and fixed costs during idle period 91 Total cash costs (102) Increase in Adjusted EBITDA $ 142 ($ Millions) 2024 vs. 2023 Average Realized Price Our average realized price for the year ended December 31, 2024, was $355 per tonne compared to $333 per tonne for 2023, and this increased Adjusted EBITDA by $206 million (refer to the Financial Results – Revenue section on page 14 for more information). Sales Volume Methanol sales volume, excluding commission sales volume, for the year ended December 31, 2024, decreased to 9.6 million tonnes from 10.0 million tonnes in 2023, and this decreased Adjusted EBITDA by $31 million. Including commission sales volume from the Atlas and Egypt facilities, our total methanol sales volume was 10.5 million tonnes in 2024 compared with 11.2 million tonnes in 2023. Sales volume may vary year to year depending on customer requirements and inventory levels as well as the available commission sales volume. Geismar 3 Delay Costs The operating costs related to the delay in start-up of our Geismar 3 project include organizational build-up, take-or-pay obligations on utilities contracts as well as additional recognition of gas hedges. The total delay costs for the year ended December 31, 2024 compared to the same period in 2023 were $22 million higher, primarily due to over-hedged gas costs of $16 million which was identified when a portion of our existing natural gas hedges exceeded the expected Geismar site production requirements. This over- hedged gas cost was recorded in early 2024 and covered the entire period of the delay. New Zealand Gas Sale Proceeds, Net of Gas and Fixed Costs In 2024 we entered short-term commercial arrangements to provide available natural gas into the New Zealand electricity market as the country’s overall energy balances were very strained. The total net proceeds less fixed costs for the year ended December 31, 2024 were $91 million. There are no equivalent transactions in 2023. This does not include the impact of lost margin on the sale of methanol that was not produced in the period and additional supply chain costs incurred. 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 globally. 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. 15

The changes in Adjusted EBITDA due to changes in total cash costs for 2024 compared with 2023 were due to the following: Methanex-produced methanol costs $ 1 Proportion of Methanex-produced methanol sales (7) Purchased methanol costs (39) Logistics costs (39) Egypt insurance recovery 30 Other, net (48) Increase in Adjusted EBITDA due to changes in total cash costs $ (102) ($ Millions) 2024 vs. 2023 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 2024, 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 2024 compared with 2023 by $1 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 22. Proportion of Methanex-Produced Methanol Sales The cost of purchased methanol is directly linked to the selling price for methanol at the time of purchase and the cost of purchased methanol is generally higher than the cost of Methanex-produced methanol. Accordingly, an increase in the proportion of Methanex- produced methanol sales results in a decrease in our overall cost structure for a given period, while a decrease in the proportion of Methanex-produced methanol will increase our cost structure. The proportion of Methanex-produced methanol sales decreased in 2024 due to lower production and this increased costs and decreased Adjusted EBITDA by $7 million for 2024 compared with 2023. 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 regions 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 each region. 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. Higher methanol prices in 2024 and the timing of inventory flows and purchases increased the cost of purchased methanol per tonne and this decreased Adjusted EBITDA by $39 million compared with 2023. 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 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 2024 decreased Adjusted EBITDA by $39 million compared to 2023. Logistics costs increased in 2024 compared to 2023 primarily due to the mix of production from various plants, unplanned outages including at our Egypt facility, the impact on ocean freight of longer supply routes and a lower contribution from backhaul ocean freight journeys earned from third parties. Egypt Insurance Recovery We experienced an outage at the Egypt plant from October 2023 to February 2024. The insurance recovery of $30 million (Methanex share) was recognized in 2024 which partially offsets repair costs charged to earnings and lost margins incurred in the fourth quarter of 2023 and first quarter of 2024. 16

Other, Net Other, net relates to unabsorbed fixed costs, selling, general and administrative expenses and other operational items. For the year ended December 31, 2024 compared with the same period in 2023, other costs were higher by $48 million mainly due to higher unabsorbed costs in 2024 compared to 2023 and higher costs relating to the OCI Acquisition . Additionally, the decision to indefinitely idle one of the plants in New Zealand led to restructuring costs of $4 million in 2024, for which there is no equivalent transaction in 2023. 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. Methanex Corporation share price 1 $ 49.94 $ 47.36 Grant date fair value expense included in Adjusted EBITDA and Adjusted net income 21 19 Mark-to-market impact 2 2 16 Total share-based compensation expense, before tax $ 23 $ 35 ($ Millions, except share price) 2024 2023 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 $47.36 per share at December 31, 2023, to $49.94 per share at December 31, 2024. 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 $2 million mark-to-market expense related to share-based compensation during 2024. Depreciation and Amortization Depreciation and amortization was $386 million for the year ended December 31, 2024, and is comparable to the $392 million for the year ended December, 31 2023. 17

Finance Costs Finance costs before capitalized interest $ 184 $ 172 Less capitalized interest (51) (55) Finance costs $ 133 $ 117 ($ Millions) 2024 2023 Finance costs are primarily comprised of interest on borrowings and lease obligations and were $133 million for the year ended December 31, 2024, compared to $117 million for the year ended December 31, 2023. Finance costs are higher primarily due to financing fees incurred on a bridge facility entered into in October 2024 to support the OCI Acquisition and additional interest on the new debt issued (see note 8 of our 2024 consolidated financial statements for more information). Capitalized interest relates to interest costs capitalized for the Geismar 3 project. Capitalized interest was lower compared to the year ended December 31, 2023 as Geismar 3 completed its commercial performance tests in October 2024, whereupon interest ceased to be capitalized. Refer to the Liquidity and Capital Resources section of page 19 for more information. Finance Income and Other ($ Millions) 2024 2023 Finance income and other before gas supply contract mark-to-market impact $ 9 $ 31 New Zealand gas contract mark-to-market impact 9 — Egypt gas supply contract mark-to-market impact (6) 9 Finance income and other expenses $ 12 $ 40 Finance income and other were $12 million for the year ended December 31, 2024, compared to $40 million for the year ended December 31, 2023. Finance income and other were lower during the year ended December 31, 2024 compared to the same period in 2023 primarily due to the impact of changes in foreign exchange rates, changes in interest income earned on cash balances, and the mark-to-market impact on the New Zealand and Egypt gas supply contracts. Income Taxes A summary of our income taxes for 2024 compared with 2023 is as follows: Per consolidated statement of income Adjusted 1 2 Per consolidated statement of income Adjusted 1 2 Net income before income tax $ 280 $ 325 $ 286 $ 199 Income tax expense (30) (73) (2) (46) Net income after income tax $ 250 $ 252 $ 284 $ 153 Effective tax rate 11 % 22 % 1 % 23 % ($ Millions, except where noted) 2024 2023 1 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. 2 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. See Non-GAAP Measures on page 39 for more information. 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 22%, New Zealand is 28%, Trinidad and Tobago is 38%, Chile is 35%, Egypt is 32.5% 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 22% for the year ended December 31, 2024, compared to 23% for the year ended December 31, 2023. 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. 18

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: Net income $ 250 $ 284 Adjusted for: Income tax expense 30 1 Earnings from associate (38) (99) Share of associate's income before tax 54 152 Net income before tax of non-controlling interests (93) (103) Mark-to-market impact of share-based compensation 3 16 Impact of Egypt gas contract revaluation 3 (5) Impact of New Zealand gas contract revaluation (9) — Asset impairment charge 125 — Gas contract settlement — (47) Adjusted net income before tax $ 325 $ 199 Income tax expense $ (30) $ (1) Adjusted for: Inclusion of our share of associate's adjusted tax expense (15) (37) Removal of non-controlling interest's share of tax (recovery) expense 6 (7) Tax (recovery) expense on mark-to-market impact of share-based compensation — (3) Tax on impact of Egypt gas contract revaluation (1) 2 Tax on impact of New Zealand gas contract revaluation 2 — Tax on asset impairment charge (35) — Adjusted income tax expense $ (73) $ (46) ($ Millions, except where noted) 2024 2023 For additional information regarding income taxes, refer to note 16 of our 2024 consolidated financial statements. LIQUIDITY AND CAPITAL RESOURCES A summary of our consolidated statements of cash flows is as follows: Cash flows from/(used in) operating activities: Cash flows from operating activities before changes in non-cash working capital $ 861 $ 719 Changes in non-cash working capital related to operating activities (124) (59) 737 660 Cash flows from/(used in) financing activities: Payments for the repurchase of shares — (86) Dividend payments to Methanex Corporation shareholders (50) (49) Interest paid (169) (169) Net proceeds on issue of long-term debt 585 — Repayment of long-term debt and financing fees (322) (12) Repayment of lease obligations (141) (118) Distributions to non-controlling interests (41) (185) Proceeds on exercise of stock options and movements in restricted cash 1 (1) Changes in non-cash working capital relating to financing activities (68) 69 (205) (551) Cash flows from/(used in) investing activities: Property, plant and equipment (101) (178) Geismar plant under construction (73) (270) Proceeds of share capital reduction from associate 13 — Loan repayment from associate 76 — Changes in non-cash working capital relating to investing activities (15) (60) (100) (509) Increase (decrease) in cash and cash equivalents 432 (400) Cash and cash equivalents, end of year $ 892 $ 458 ($ Millions) 2024 2023 19

Cash Flow Highlights Cash Flows from Operating Activities Cash flows from operating activities for the year ended December 31, 2024 were $737 million compared with $660 million for the year ended December 31, 2023. The increase in cash flows from operating activities is primarily due to higher operational earnings, partially offset by working capital movements. The following table provides a summary of these items for 2024 and 2023: Net income $ 250 $ 284 Deduct earnings of associate (38) (99) Add dividends received from associate 32 112 Add (deduct) non-cash items: Depreciation and amortization 386 392 Income tax expense 30 1 Share-based compensation expense 24 35 Finance costs 133 117 Mark-to-market impact of Level 3 derivatives (3) — Asset impairment charge 125 — Interest received 15 22 Income taxes paid (53) (82) Other (40) (63) Cash flows from operating activities before changes in non-cash working capital 861 719 Changes in non-cash working capital: Trade and other receivables 62 (33) Inventories (12) 16 Prepaid expenses (3) (19) Accounts payable and accrued liabilities (171) (23) (124) (59) Cash flows from operating activities $ 737 $ 660 ($ Millions) 2024 2023 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 13. Changes in non-cash working capital decreased cash flows from operating activities by $124 million for the year ended December 31, 2024, compared with a decrease of $59 million for the year ended December 31, 2023. Trade and other receivables decreased in 2024 and this increased cash flows from operating activities by $62 million, primarily due to timing of invoices and payments by customers by the end of 2024 compared to 2023. Inventories increased primarily due to the higher cost of production in the fourth quarter of 2024 compared to the fourth quarter of 2023 driven by the impact of higher methanol prices on our natural gas costs, which decreased cash flows from operating activities by $12 million. Accounts payable and accrued liabilities decreased in 2024 compared to 2023 due to lower purchased methanol activity due to the start-up of Geismar 3 and the cessation of operations at Atlas. This decreased cash flows from operating activities by $171 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, while no repurchases were made in 2024. Total dividend payments in 2024 were $50 million compared with $49 million in 2023, reflecting a full year of quarterly dividends of $0.185 per share following an increase from $0.175 per share in April 2023. Total interest payments in 2024 and in 2023 were $169 million. We repaid $300 million of unsecured notes due in December 2024 with cash flows generated from operations. We also completed the financing plan for the OCI Acquisition which included issuing $600 million of unsecured notes with net proceeds of $585 million. The Company has no debt maturities until December 2027, 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 $41 million in 2024 compared to $185 million in 2023. The lower distributions to non- controlling interests for 2024 compared to 2023 were primarily due to higher return of capital to shareholders in 2023 and changes in earnings of Egypt and Waterfront Shipping. 20

Cash Flows from Investing Activities During 2024, we incurred cash outflows on capital expenditures relating to our consolidated operations of $101 million (2023 - $178 million) primarily related to planned turnarounds in Geismar, Medicine Hat, and Chile, and the restart of Titan. The 2023 capital expenditures were primarily related to related to planned turnarounds in Geismar, New Zealand and Chile. In addition, we incurred cash outflows on capital expenditures of $73 million (2023 - $270 million) related to the construction of the Geismar 3 project. Liquidity and Capitalization We successfully met our objective in 2024 to repay rather than re-finance $300 million of unsecured notes due at the end of 2024 and our new OCI Acquisition financing has been structured to allow the flexible repayment of the term loan commitment to support our capital allocation priority to reduce debt. The following table provides information on our liquidity and capitalization position as at December 31, 2024, and December 31, 2023: Liquidity: Cash and cash equivalents $ 892 $ 458 Undrawn credit facility 500 300 Total liquidity 1 $ 1,392 $ 758 Capitalization: Unsecured notes, including current portion 2,274 1,986 Other limited recourse debt facilities, including current portion 141 156 Total debt 2,415 2,142 Non-controlling interests 288 242 Shareholders’ equity 2,094 1,931 Total capitalization $ 4,797 $ 4,315 Total debt to capitalization 2 50 % 50 % Net debt to capitalization 3 39 % 44 % ($ Millions, except where noted) 2024 2023 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 39 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 39 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, 2024, we had a cash balance of $892 million, including $16 million of cash related to Egypt and $26 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, 2024, we have access to a $500 million committed revolving credit facility, which is with a syndicate of highly rated financial institutions. During the year, the maturity date of the previously established $300 million revolving credit facility was renewed to April 2028 and an additional $200 million tranche was added which expires in April 2026, increasing the total amount available under the revolving credit facility as at December 31, 2024 to $500 million. To support the OCI Acquisition, the Company renewed its $500 million revolving credit facility by increasing the existing $300 million tranche to $400 million with a new five-year tenor, and the renewal of the $200 million tranche with a new three-year tenor, both from the closing date of the OCI Acquisition. Additionally, a term loan commitment of $650 million was added to partially finance the OCI Acquisition. The increase to a total availability of $600 million under the revolving credit facility and availability of the $650 million term loan commitment are subject to the closing of the OCI Acquisition. 21

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 indentures governing the Company, 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 indentures also contains customary default provisions. The significant covenants and default provisions under the credit facility include: a) the obligation to maintain a minimum interest coverage ratio of EBITDA to net interest expense greater than or equal to 2:1 calculated on a four-quarter trailing basis and a funded debt to total 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; 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 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 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, 2024, management believes the Company was in compliance with all covenants related to its long-term debt obligations. Capital Projects During the year, the Geismar 3 plant successfully completed its commercial performance tests. The capital costs totaling slightly less than $1.30 billion, excluding fixed costs related to the delay. The plant completed its commercial performance tests in October and the project is now complete. 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, 2024, is as follows: Long-term debt repayments $ 14 $ 729 $ 732 $ 968 $ 2,443 Long-term debt interest obligations 135 261 192 347 935 Lease obligations 169 264 226 423 1,082 Repayments of other long-term liabilities 53 40 15 90 198 Natural gas and other 518 728 551 766 2,563 Other commitments 86 39 33 2 160 $ 975 $ 2,061 $ 1,749 $ 2,596 $ 7,381 ($ Millions) 2025 2026-2027 2028-2029 After 2029 Total Long-Term Debt Repayments and Long-Term Debt Interest Obligations We have $700 million of unsecured notes that mature in 2027, $700 million of unsecured notes that mature in 2029, $600 million of unsecured notes that mature in 2032 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 2024 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. 22

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. 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 and renewable 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 Egypt plant 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. Up to the idling of the jointly- owned Atlas plant, we also had marketing rights for 100% of the production. Upon cessation of the offtake agreement, the offtake commitment for Atlas is nil. As at December 31, 2024, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2025 and 0.4 million tonnes in aggregate thereafter. The pricing under these purchase commitments is referenced to pricing at the time of purchase or sale, and accordingly, no amounts have been included in the table above. The above table does not include costs for planned capital maintenance or expansion expenditures for which no commitment has been made to vendors to purchase materials, 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 2024 consolidated financial statements. Off-Balance Sheet Arrangements As at December 31, 2024, 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. 23

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, 2024 and December 31, 2023: Financial assets: Financial assets measured at fair value: Derivative instruments designated as cash flow hedges 1 $ 129 $ 121 Fair value of Egypt gas supply contract derivative 2 14 20 Fair value of New Zealand gas supply contract derivative 3 9 — Financial assets not measured at fair value: Cash and cash equivalents 892 458 Trade and other receivables, excluding tax receivable 454 515 Restricted cash included in other assets 14 16 Total financial assets 4 $ 1,512 $ 1,130 Financial liabilities: Financial liabilities measured at fair value: Derivative instruments designated as cash flow hedges 1 $ 37 $ 92 Financial liabilities not measured at fair value: Trade, other payables and accrued liabilities, excluding tax payable 430 672 Lease obligations, including current portion 818 872 Long-term debt, including current portion 2,415 2,142 Land mortgage 27 28 Total financial liabilities $ 3,727 $ 3,806 ($ Millions) 2024 2023 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 New Zealand natural gas supply contract is measured at fair value using an economic model classified within Level 3 of the fair value hierarchy. 4 The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods. As at December 31, 2024, 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 2024 consolidated financial statements for information on our related party transactions. 24

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 36, 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 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 approximately 20% 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 naphtha, which are typically derived from natural gas and oil-based feedstocks. The price of methanol relative to the price of ethane, propane and naphtha 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. 25

Methanol Supply Methanol industry supply is impacted by the cost of production, methanol industry operating rates and methanol industry capacity changes. Methanol is 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 feedstock materials, 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 sustained high methanol prices encourage 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. 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. Operating rates continue to be uncertain and challenged due to the impact of trade sanctions, plant technical issues, and structural and seasonal natural gas constraints. The methanol industry ran at similar rates in 2024 compared to 2023. In 2024, there were approximately 1.5 million tonnes of production capacity additions in China. In North America, our new 1.8 million tonne Geismar 3 facility completed its commercial performance tests and is now operating at full rates. With the idling of Atlas and the restart of Titan in September 2024 overall production in Trinidad is lower by approximately 1 million tonnes annually. In Malaysia, we understand that a 1.8 million tonne plant started up in early 2025. We expect limited capacity additions in the next five years. In Iran, projects under development are showing slow progress due to technical and financing challenges from sanctions and the operating rates of existing methanol plants are constrained by gas availability due to depleting gas fields. If sanctions impacting Iran and/or other methanol producing countries are eased or removed, this could lead to an increase in methanol supply. China has planned capacity additions which we expect will be somewhat offset by the closure of some inefficient 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 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 war between Ukraine and 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 26

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 regions 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. There is also heightened uncertainty and volatility with regards to the implementation of further tariffs between various countries in which we produce or sell methanol. Over the years, methanol demand growth has been concentrated in certain high-demand regions, while our production has also become more concentrated in certain jurisdictions. As a result, we face potential risks related to access to certain regions, as governments in key regions may impose tariffs, increase duties, or implement other trade restrictions that could limit methanol trade to or from certain jurisdictions or cause it to become uneconomical. Diversion of trade flows to avoid uneconomical consequences of such restrictions may also create longer supply chain routes at additional cost. There can be no assurance that the countries where we produce methanol will continue to have access to all sales regions, that duties or tariffs will not increase, that duties or tariffs will not be levied in other jurisdictions in the future or that we will be able to mitigate the impact of future duties or tariffs, if levied, or that future duties or tariffs 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. 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. Financial Risks Taxation Risk The Company is subject to taxes, duties, levies, governmental royalties and other government-imposed compliance costs in numerous jurisdictions, as well as to the global minimum tax as developed by the Organization for Economic Co-operation and Development (“OECD”). 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 and Legal Proceedings on page 36 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. 27

Liquidity Risk As at December 31, 2024, we had a cash balance of $892 million, as well as an undrawn $500 million revolving credit facility with a syndicate of highly rated financial institutions. We renewed the $500 million revolving credit facility and increased the total amount available thereunder to $600 million, and a term loan commitment of $650 million was added. Both are subject to the closing of the OCI Acquisition. Our ability to maintain access to the facilities is subject to meeting certain financial covenants, including a interest coverage ratio of EBITDA to net interest expense and a funded debt to total 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, 2024, our long-term debt obligations include $2,274 million in unsecured notes and $141 million related to other limited recourse debt for ocean-going vessels (100% basis). The covenants governing the unsecured notes, which are specified in indentures governing the Company, 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 indentures also contain customary default provisions. For additional information regarding long-term debt, refer to note 8 of our 2024 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. Risks Related to Our Indebtedness We monitor our level of debt for optimal leverage. Our expected leverage at closing of the OCI Acquisition is higher than it has been traditionally and to bring it down to a normalized level requires sufficient cash generation from our operating business to meet planned debt repayments. We cannot provide assurance that our operations will transpire as planned and that our target level of debt will be achieved in the timeline anticipated. 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. 28

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 shut down such plants, which could have an adverse effect on our results of operations and financial condition. United States With our new 1.8 million tonne Geismar 3 facility reaching commercial production in 2024, we now 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 the United States, 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. 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 Titan plant is supplied by the National Gas Company of Trinidad and Tobago Limited ("NGC"), pursuant to a two-year take-or-pay contract that commenced in September 2024. The Titan plant successfully restarted operations in September 2024, having previously been idled in the first quarter of 2020. The natural gas sale agreement for Titan is a take-or-pay contract with the NGC, which purchases the natural gas from upstream gas producers. The contract 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. The legacy natural gas agreement for our Atlas methanol production facility in Trinidad and Tobago, with our share of total production capacity being 1.1 million tonnes per year, expired in September 2024, after which the plant was idled. 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. New Zealand We have two plants located at Motunui in New Zealand with a total operating capacity of 1.7 million tonnes of methanol per year. In September 2024, we restructured our operations in New Zealand to support a one-plant operation, and idled one of the Motunui plants. A third plant located at nearby Waitara Valley was idled indefinitely in the first quarter of 2021. The plants were idled due to a lack of available gas supply. We have 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 New Zealand methanol production 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. Supplier upstream development activities have not delivered the expected gas production results and have resulted in reduced gas quantities delivered under our contracts. 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. 29

Chile We have two long-term natural gas supply agreements for our two plants in Chile with each of Empresa Nacional del Petróleo ("ENAP") and YPF S.A. ("YPF"). As of 2024, 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. Both of these long-term supply agreements are subject to deliver-or-pay and take-or-pay provisions. In 2024, both plants operated at full capacity for seven months during the southern hemisphere summer, and one plant operated at close to minimum capacity production levels for the remaining five months of the year. Our primary Chilean natural gas supplier, 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. In August 2024, Methanex extended its gas supply agreement with ENAP until 2030. In August 2024 we extended our gas supply agreement with YPF securing gas until the end of 2027. In addition, in 2024, we received natural gas from Argentina from four different natural gas suppliers pursuant to firm supply agreements from January through April and from September through December. Each of the four supply agreements were subject to deliver-or-pay and take-or-pay provisions. We have similar firm contracts for 2025 in place. 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. Over the past few years demand for natural gas for power generation has increased substantially while domestic natural gas supply has declined, increasing reliance on pipeline and LNG imports to meet demand. This has contributed to recent gas curtailments to our plant, particularly during the summer months when demand for natural gas for power generation is at its peak. The restrictions experienced in recent periods 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 safely, 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. 30

Capital Projects Our ability to effectively allocate capital, including successfully identifying, developing, constructing, completing, and starting up 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, completing, and starting up the projects within the contemplated budgets and schedules, and other risks commonly associated with the design, construction, completion, 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 construction, completion, and start up or estimated cost or ability to construct, complete, and start up 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. Acquisition of OCI Global's Methanol Business The OCI Acquisition involves various risks that may have a negative effect on our results of operations and financial condition. Closing of the Acquisition The closing of the OCI Acquisition is subject to the receipt of required regulatory approvals and the satisfaction of certain closing conditions. There is no certainty, nor can we provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied. If the conditions to the closing of the OCI Acquisition are not satisfied or waived, it will not be completed. If the OCI Acquisition is not completed as contemplated, we could suffer adverse consequences, including the loss of investor confidence. Any delay in completing the OCI Acquisition could cause us not to realize some or all of the benefits that we expect to achieve if the acquisition is successfully completed within the expected timeframe. Inclusion of Joint Venture in the OCI Acquisition Approximately 40% of the gross transaction and operating metrics in respect of the OCI Acquisition are attributable to the OCI global methanol business's 50% joint venture interest in Natgasoline. If the dispute between OCI and its joint venture partner in Natgasoline is not successfully resolved and Methanex exercises its right to carve the Natgasoline interest out of the acquisition, the benefits of the acquisition to Methanex may not be as significant as anticipated. If the dispute is not successfully resolved and we nonetheless determine to proceed with the acquisition of the Natgasoline interest, the anticipated benefit of acquiring the interest in Natgasoline could be adversely impacted by the ongoing dispute. Failure to Realize Anticipated Benefits There is a risk that some or all of the expected benefits of the OCI Acquisition may fail to materialize, may cost more to achieve or may not occur within the time periods that we anticipate. The realization of such benefits may be affected by a number of factors, many of which are beyond our control. Realization of the anticipated benefits of the OCI Acquisition will also depend in part on management’s ability to successfully achieve the anticipated growth opportunities and synergies from the acquisition. Unexpected Costs The decision to acquire OCI's global methanol business is based in large part on engineering, environmental, commercial and economic assessments made by independent engineers, consultants, and directly by us. These assessments include a series of assumptions regarding factors such as commodity pricing, non-commodity input costs, plant operating rates and efficiencies, market interest rates, government policies, among others. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of engineering, environmental, commercial and regulatory uncertainty that could result in lower income or higher operating or capital expenditures than anticipated. In connection with the OCI Acquisition, there may be liabilities that we failed to discover or was unable to quantify in the due diligence conducted prior to the execution of the acquisition agreement, which does not contain any indemnities for breached representations and warranties, The discovery or quantification of any material liabilities could have a material adverse effect on our results of operations and financial condition. Significant Demands of Managing a Business Combination As a result of the combination of our business with OCI's global methanol business, significant demands will be placed on our operational and financial personnel and systems as well as those of OCI's global methanol business. We cannot provide assurance that the collective systems, procedures and controls will be adequate to support the expansion of operations following and resulting from the combination of the businesses. The future operating results of the combined company will be affected by the ability of our officers and key employees to manage changing business conditions and to implement and expand our operational and financial controls and reporting systems in response. 31

Significant Transaction Costs We expect to incur significant costs and expenses associated with completing the OCI Acquisition and integrating the acquired business with our operations, and additional unanticipated costs may yet be incurred. Any expected elimination of duplicative costs and the expected realization of other operational synergies, which may offset incremental transaction and transaction-related costs over time, may not be achieved as projected, or at all. Further, while we anticipate that certain expenses will be incurred, such expenses are difficult to estimate accurately, and may exceed current estimates. Accordingly, unexpected costs incurred or delays in integrating the acquired business with our existing business and assets could have a negative effect on our results of operations and financial condition. Exposure to Litigation We may be exposed to litigation from customers, suppliers, shareholders or other third-parties in connection with the OCI Acquisition. Such litigation may have an adverse impact on our business and results of operations or may cause disruptions to our operations. Even if any such claims are without merit, defending against such claims can result in substantial costs and divert the time and resources of management. Furthermore, public attitudes towards the OCI Acquisition could result in negative press coverage and other adverse public statements. Adverse press coverage and other adverse statements could negatively impact our ability to achieve the benefits of the OCI Acquisition or take advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on our business, financial condition, results of operations and cash flows. Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into acquisition agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting consummation of the OCI Acquisition, then that injunction may delay or prevent the OCI Acquisition from being completed. 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. 32

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. Cyberattacks are becoming increasingly sophisticated, particularly with the use of artificial intelligence. 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. 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. In addition, the use of artificial intelligence tools may increase our exposure to data privacy and security risks. 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 2025, we issued our 2024 Sustainability Report, aligned with the Sustainability Accounting Standards Board (SASB) and the Task-Force on Climate-related Financial Disclosures (TCFD).The Report is also a transitional report as we shift towards CSRD and European Sustainability Reporting Standards requirements for 2025. The 2024 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. 33

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 methanol. 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, volume of 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 and their respective operations. 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. In 2025, Waterfront Shipping will need to purchase and surrender 70 percent of EU ETS credits for shipping emissions within the EU and 100 percent in 2026. 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 The European Union and the International Maritime Organization (IMO) are moving to regulate maritime GHG emissions on a lifecycle basis, which includes upstream production, transport and storage. They have also set multiple maritime decarbonization targets that variously imply the requirement to decrease the GHG emissions intensity of energy used by ships, reduce absolute emissions from shipping as a whole, and increase uptake of zero and near zero ("ZNZ") emission fuels. Regulation that is intended to enable and ensure these targets are met, and which has the potential to effectively drive the uptake of low carbon fuels, includes the EU's FuelEU Maritime that took effect on January 1, 2025, and the IMO's "midterm measures", which are anticipated to take effect during 2027. 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. 34

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. The EPA released risk evaluation findings for formaldehyde in 2024. These are under review 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 35

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 ("the "BIR") 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. During 2024, the Trinidad tax court issued a ruling in the Company's favour. At present, the BIR is reviewing whether to proceed with an appeal and should it decide to proceed, the Company will continue to defend its position. We anticipate the resolution of this matter through the court systems may 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 29. See note 2 to our 2024 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, 2024, the net book value of our property, plant and equipment was $4.2 billion. 36

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, 2024, we had accrued $38 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 ("impairment indicators"). Examples of such impairment indicators 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 an impairment indicator 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 37

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 2024, we announced our intention to idle the Motunui I plant indefinitely and restructure to a single-plant operation in New Zealand moving forward. The reorganizing of operations to a single plant operation was identified as an impairment indicator for the New Zealand CGU. The impairment test performed on the New Zealand CGU resulted in a non-cash before-tax asset impairment charge of $125 million ($90 million after-tax) to write down the carrying value of the New Zealand assets to $93 million. We believe the estimated recoverable amount of all long-lived assets exceed their carrying value as at December 31, 2024. 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, 2024, we had recognized deferred tax assets of $204 million primarily relating to non-capital loss carryforwards and other temporary differences in the United States, Trinidad and Tobago, and New Zealand. As at December 31, 2024, the Company had $170 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. 38

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. The Company holds a long-term natural gas supply contract expiring in 2029 with OMV New Zealand ("OMV"), one of the largest gas suppliers in New Zealand. The natural gas supply contract includes a base fixed price plus a premium based on the realized price of methanol. During 2024 the Company entered into short-term commercial arrangements to provide its contracted natural gas into the New Zealand electricity market. The on-sale of natural gas has impacted the accounting assessment for the contract whereby it is now considered a derivative to be measured at fair value. The New Zealand wholesale gas market is relatively small and concentrated as there are a limited number of suppliers and consumers. There is a limited observable, liquid spot market and no forward curve for natural gas in New Zealand. The gas trading platform used to facilitate short-term balance in the gas market trades inconsequential volumes relative to the scope of the Company’s gas consumption and the overall gas market. The Company does not believe transactions on this platform take place with sufficient frequency and volume to provide pricing information. Due to the absence of an observable market price for an equivalent or similar contract to measure fair value, we have estimated fair value using an economic model. The model includes significant unobservable inputs and as a result is classified within Level 3 of the fair value hierarchy. We have considered market participant assumptions in establishing the model inputs and determining fair value, including potential sharing mechanisms for gas on-sales to consider the change in the local market gas supply and demand dynamics since contract inception. Refer to note 19 of our 2024 consolidated financial statements for more information. ADOPTION OF NEW ACCOUNTING STANDARDS The Company has adopted the 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, which were effective for annual periods beginning on January 1, 2024. The amendments did not have a material impact on the Company's consolidated financial statements. 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, 2025 and subsequent years are being reviewed to determine the potential impact: amendments to IAS 21, The Effects of Changes in Foreign Exchange Rates regarding the lack of exchangeability, IFRS 9, Financial Instruments and IFRS 7, Financial Instruments: Disclosures regarding the classification and measurement of financial instruments and the accounting for power purchase agreements and IFRS 18, Presentation and Disclosure in Financial Statements regarding the replacement of IAS 1, Presentation of Financial Statements. 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 39

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, asset impairment charge, gas contract settlement charge, 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: Net income attributable to Methanex shareholders $ 164 $ 174 Mark-to-market impact of share-based compensation 2 16 Gas contract settlement, net of tax — (31) Depreciation and amortization 386 392 Finance costs 133 117 Finance income and other (12) (40) Income tax expense 30 1 Asset impairment charge 125 — Earnings of associate adjustment 1 43 67 Non-controlling interests adjustment 1 (107) (74) Adjusted EBITDA (attributable to Methanex shareholders) $ 764 $ 622 ($ Millions) 2024 2023 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 and New Zealand 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: Net income attributable to Methanex shareholders $ 164 $ 174 Mark-to-market impact of share-based compensation, net of tax 2 13 Impact on earnings of associate of gas contract settlement, net of tax — (31) Impact of Egypt and New Zealand gas contract revaluation, net of tax (4) (3) Asset impairment charge, net of tax 90 — Adjusted net income $ 252 $ 153 Diluted weighted average shares outstanding (millions) 68 68 Adjusted net income per common share $ 3.72 $ 2.25 ($ Millions, except number of shares and per share amounts) 2024 2023 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 and New Zealand gas contract 40

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. The exclusion of the asset impairment charge is due to the item not being operational in nature. 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: ($ Millions, except per share amounts) Dec 31 Sep 30 Jun 30 Mar 31 2024 Revenue $ 949 $ 935 $ 920 $ 916 Cost of sales and operating expenses (734) (794) (745) (736) Net income (attributable to Methanex shareholders) 45 31 35 53 Basic net income per common share 0.67 0.46 0.52 0.78 Diluted net income per common share 0.67 0.35 0.52 0.77 Adjusted EBITDA 1 224 216 164 160 Adjusted net income 1 84 82 42 44 Adjusted net income per common share 1 1.24 1.21 0.62 0.65 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 Three months ended 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 39 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 2024 is set out in our fourth quarter of 2024 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 Total assets $ 6,597 $ 6,427 $ 6,631 Total long-term liabilities (excluding deferred income tax) 3,247 2,733 3,032 Revenue 3,720 3,723 4,311 Net income (attributable to Methanex shareholders) 164 174 354 Adjusted net income 1 252 153 343 Adjusted EBITDA 1 764 622 932 Basic net income per common share 2.43 2.57 4.95 Diluted net income per common share 2.39 2.57 4.86 Adjusted net income per common share 1 3.72 2.25 4.79 Cash dividends declared per common share 0.740 0.730 0.620 ($ Millions, except per share amounts) 2024 2023 2022 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 39 for a description of each non-GAAP measure and reconciliations to the most comparable GAAP measures. 41

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, 2024, 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, 2024, 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, 2024. The attestation report is included in our consolidated financial statements on page 48. 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, 2024, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 42

FORWARD-LOOKING STATEMENTS This 2024 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: ▪ anticipated closing date of the OCI Acquisition and the expected benefits of the OCI Acquisition, including benefits related to expected synergies and commodity diversification, ▪ anticipated synergies and Methanex's ability to achieve such synergies following closing of the OCI Acquisition, ▪ whether the OCI Acquisition will include OCI Global's 50% share of the Natgasoline plant, ▪ 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 increase in methanol production of assets to be acquired as part of the OCI Acquisition, ▪ 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, debt reduction and deleveraging plans, 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, ▪ our financial strength and ability to meet future financial commitments, ▪ expected global or regional economic activity (including industrial production levels) and gross domestic product 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: ▪ future expectations and assumptions concerning the receipt of all regulatory approvals required to complete the OCI Acquisition, ▪ Methanex's ability to realize the expected strategic, financial and other benefits of the OCI Acquisition in the timeframe anticipated or at all, ▪ 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, 43

▪ 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, ▪ our ability to sustain the designed operating rates of the Geismar 3 plant, ▪ global and regional economic activity (including industrial production levels) and gross domestic product 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: ▪ failure to complete the OCI Acquisition in accordance with the material terms of the OCI Acquisition agreement or at all, ▪ failure to obtain any of the approvals required for the OCI Acquisition, ▪ failure to acquire OCI Global's 50% joint venture interest in Natgasoline, ▪ failure to close the OCI Acquisition credit facility, ▪ unforeseen difficulties in integrating the business operations or assets purchased pursuant to the OCI Acquisition into our business and operations, ▪ failure to realize the expected strategic, financial and other benefits of the OCI Acquisition in the timeframe anticipated or at all, ▪ unexpected costs or liabilities associated with the OCI Acquisition, ▪ increased litigation or negative public perception as a result of the OCI Acquisition, ▪ increased indebtedness of Methanex, ▪ conditions in the methanol and other industries, including fluctuations in the supply, demand and price for methanol and its derivatives, including demand for methanol for energy uses, ▪ the price of natural gas, coal, oil and oil derivatives, ▪ our ability to obtain natural gas feedstock on commercially acceptable terms to underpin current operations and future production growth opportunities, ▪ the ability to carry out corporate initiatives and strategies, ▪ actions of competitors, suppliers and financial institutions, ▪ conditions within the natural gas delivery systems that may prevent delivery of our natural gas supply requirements, ▪ competing demand for natural gas, especially with respect to 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 2024 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. 44

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, 2024. 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 7, 2025 Rich Sumner President and Chief Executive Officer Dean Richardson Senior Vice President, Finance and Chief Financial Officer 45

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, 2024 and 2023, 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, 2024, 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, 2024 and 2023, and its financial performance and its cash flows for each of the years in the two- year period ended December 31, 2024, 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, 2024, 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 7, 2025 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 matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 critical audit matters 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Recognition and Measurement of Uncertain Tax Positions As discussed in Notes 6(b) 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. 46

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. Assessment of the Recoverable Amount of the New Zealand Cash Generating Unit As discussed in Note 2(g) to the consolidated financial statements, long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When such an impairment indicator is identified, the recoverability of long-lived assets is measured by comparing the carrying value of the asset or cash-generating unit to the estimated recoverable amount. As discussed in Note 5(b) to the consolidated financial statements, the Company identified an impairment indicator for the New Zealand cash-generating unit (“New Zealand CGU”) and the carrying value of the New Zealand CGU was tested for impairment. The recoverable amount was determined using a discounted cash flow approach to measure the fair value less costs of disposal of the New Zealand CGU. During the year ended December 31, 2024, the Company recorded an asset impairment charge of $125 million in property, plant and equipment to write down the carrying value of the New Zealand CGU to its recoverable amount. We identified the assessment of the recoverable amount of the New Zealand CGU to be a critical audit matter. Challenging auditor judgment was required to evaluate the availability of natural gas assumption used in determining the recoverable amount of the New Zealand CGU, as the assumption is subject to significant measurement uncertainty. Changes in the availability of natural gas assumption could have had a significant impact on the recoverable amount of the New Zealand CGU. The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of an internal control over the Company's process to determine the recoverable amount of the New Zealand CGU, including the availability of natural gas assumption. We compared the availability of natural gas assumption to third party gas supplier forecasts of gas volumes available during the forecast period. We compared the Company’s historical forecasts to actual results to assess the accuracy of the Company’s forecasting process. We performed a sensitivity analysis over the availability of natural gas assumption to assess the impact on the Company’s determination of the recoverability of the New Zealand CGU. /s/ KPMG LLP Chartered Professional Accountants We have served as the Company's auditor since 1992. Vancouver, Canada March 7, 2025 47

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, 2024, 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, 2024, 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, 2024 and 2023, 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, 2024, and the related notes (collectively, the consolidated financial statements), and our report dated March 7, 2025 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, 2024. 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 7, 2025 48

Consolidated Statements of Financial Position (thousands of U.S. dollars, except number of common shares) ASSETS Current assets: Cash and cash equivalents $ 891,910 $ 458,015 Trade and other receivables (note 3) 473,336 533,615 Inventories (note 4) 453,463 426,774 Prepaid expenses 61,290 58,024 Other assets (note 7) 30,820 3,893 1,910,819 1,480,321 Non-current assets: Property, plant and equipment (note 5) 4,197,509 4,411,768 Investment in associate (note 6) 101,438 184,249 Deferred income tax assets (note 16) 204,091 152,250 Other assets (note 7) 183,269 197,967 4,686,307 4,946,234 $ 6,597,126 $ 6,426,555 LIABILITIES AND EQUITY Current liabilities: Trade, other payables and accrued liabilities $ 546,305 $ 771,867 Current maturities on long-term debt (note 8) 13,727 314,716 Current maturities on lease obligations (note 9) 122,744 120,731 Current maturities on other long-term liabilities (note 10) 46,840 94,992 729,616 1,302,306 Non-current liabilities: Long-term debt (note 8) 2,401,208 1,827,085 Lease obligations (note 9) 695,461 751,389 Other long-term liabilities (note 10) 150,462 154,918 Deferred income tax liabilities (note 16) 239,113 217,840 3,486,244 2,951,232 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, 2024 were 67,395,212 (2023 - 67,387,492) 392,201 391,924 Contributed surplus 1,950 1,838 Retained earnings 1,629,386 1,514,264 Accumulated other comprehensive income 70,022 22,901 Shareholders’ equity 2,093,559 1,930,927 Non-controlling interests 287,707 242,090 Total equity 2,381,266 2,173,017 $ 6,597,126 $ 6,426,555 As at Dec 31 2024 Dec 31 2023 Commitments and contingencies (note 22) See accompanying notes to consolidated financial statements. Approved by the Board: Benita Warmbold (Director) Rich Sumner (Director) 49

Consolidated Statements of Income (thousands of U.S. dollars, except number of common shares and per share amounts) Revenue $ 3,719,829 $ 3,723,475 Cost of sales and operating expenses (note 11) (3,009,407) (3,068,072) Depreciation and amortization (note 11) (385,703) (391,830) New Zealand gas sale net proceeds (note 25) 102,969 — Egypt insurance recovery (note 26) 59,065 — Asset impairment charge (note 5) (124,788) — Operating income 361,965 263,573 Earnings of associate (note 6) 38,335 99,466 Finance costs (note 12) (132,634) (117,366) Finance income and other 12,420 39,938 Income before income taxes 280,086 285,611 Income tax (expense) recovery (note 16): Current (74,126) (49,924) Deferred 44,285 48,435 (29,841) (1,489) Net income $ 250,245 $ 284,122 Attributable to: Methanex Corporation shareholders $ 163,986 $ 174,140 Non-controlling interests (note 24) 86,259 109,982 $ 250,245 $ 284,122 Income per common share for the year attributable to Methanex Corporation shareholders: Basic net income per common share (note 13) $ 2.43 $ 2.57 Diluted net income per common share (note 13) $ 2.39 $ 2.57 Weighted average number of common shares outstanding (note 13) 67,387,809 67,805,220 Diluted weighted average number of common shares outstanding (note 13) 67,560,060 67,811,615 For the years ended December 31 2024 2023 See accompanying notes to consolidated financial statements. 50

Consolidated Statements of Comprehensive Income (thousands of U.S. dollars) Net income $ 250,245 $ 284,122 Other comprehensive income: Items that may be reclassified to income: Change in cash flow hedges and excluded forward element (note 19) (23,211) (310,456) Realized losses (gains) on foreign exchange hedges reclassified to revenue (3,604) 3,105 Amounts reclassified on discontinuation of hedging relationship (note 19) 11,702 — Items that will not be reclassified to income: Actuarial gain (loss) on defined benefit pension plans (note 21(a)) 1,353 (2,827) Taxes on above items (14,096) 66,636 (27,856) (243,542) Comprehensive income $ 222,389 $ 40,580 Attributable to: Methanex Corporation shareholders $ 136,130 $ (69,402) Non-controlling interests (note 24) 86,259 109,982 $ 222,389 $ 40,580 For the years ended December 31 2024 2023 See accompanying notes to consolidated financial statements. 51

Consolidated Statements of Changes in Equity (thousands of U.S. dollars, except number of common shares) 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 Net income — — — 163,986 — 163,986 86,259 250,245 Other comprehensive income (loss) — — — 1,003 (28,859) (27,856) — (27,856) Compensation expense recorded for stock options — — 162 — — 162 — 162 Issue of shares on exercise of stock options 7,720 227 — — — 227 — 227 Reclassification of grant date fair value on exercise of stock options — 50 (50) — — — — — Dividend payments to Methanex Corporation shareholders ($0.740 per common share) — — — (49,867) — (49,867) — (49,867) Distributions made and accrued to non- controlling interests — — — — — — (40,642) (40,642) Realized hedge losses recognized in cash flow hedges — — — — 75,980 75,980 — 75,980 Balance, December 31, 2024 67,395,212 $392,201 $1,950 $1,629,386 $70,022 $2,093,559 $287,707 $2,381,266 Number of common shares Capital stock Contributed surplus Retained earnings Accumulated other comprehensive income (loss) Shareholders’ equity Non- controlling interests Total equity See accompanying notes to consolidated financial statements. 52

Consolidated Statements of Cash Flows (thousands of U.S. dollars) CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES Net income $ 250,245 $ 284,122 Deduct earnings of associate (38,335) (99,466) Add dividends received from associate 32,181 112,318 Add (deduct) non-cash items: Depreciation and amortization 385,703 391,830 Income tax expense 29,841 1,489 Share-based compensation expense 23,973 34,502 Finance costs 132,634 117,366 Mark-to-market impact of Level 3 derivatives (2,652) — Asset impairment charge 124,788 — Other (6,316) (24,651) Interest received 15,120 21,633 Income taxes paid (52,544) (81,922) Other cash payments, including share-based compensation (33,805) (37,894) Cash flows from operating activities before undernoted 860,833 719,327 Changes in non-cash working capital (note 17(a)) (123,655) (59,058) 737,178 660,269 CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES Payments for repurchase of shares — (86,392) Dividend payments to Methanex Corporation shareholders (49,867) (49,378) Interest paid (168,762) (168,636) Net proceeds on issue of long-term debt 585,393 — Repayment of long-term debt and financing fees (note 8) (322,378) (12,280) Repayment of lease obligations (141,247) (118,159) Distributions to non-controlling interests (40,642) (185,336) Proceeds on issue of shares on exercise of stock options 227 1,437 Restricted cash for debt service accounts 1,467 (1,424) Changes in non-cash working capital related to financing activities (note 17(a)) (67,737) 68,750 (203,546) (551,418) CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES Property, plant and equipment (101,259) (178,464) Geismar plant under construction (72,813) (269,989) Proceeds of share capital reduction from associate 12,643 — Loan repayment from associate 76,328 — Changes in non-cash working capital related to investing activities (note 17(a)) (14,636) (60,130) (99,737) (508,583) Increase (decrease) in cash and cash equivalents 433,895 (399,732) Cash and cash equivalents, beginning of year 458,015 857,747 Cash and cash equivalents, end of year $ 891,910 $ 458,015 For the years ended December 31 2024 2023 See accompanying notes to consolidated financial statements. 53

Notes to Consolidated Financial Statements (Tabular dollar amounts are shown in thousands of U.S. dollars, except where noted) Year ended December 31, 2024 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 and serves customers in 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 6, 2025. 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)), 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 54

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 55

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: 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. 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 56

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. 57

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 at the time of 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. 58

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. The Company has applied the mandatory exception for recognition and disclosure of deferred taxes under IAS 12 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 apply to Methanex beginning in 2024. Refer to note 16 for further disclosure on the impact of Pillar Two rules. 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 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, which were effective for annual periods beginning on January 1, 2024. The amendments did not have a material impact on the Company's consolidated financial statements. 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, 2025 and subsequent years are being reviewed to determine the potential impact: amendments to IAS 21, The Effects of Changes in Foreign Exchange Rates regarding the lack of exchangeability, IFRS 9, Financial Instruments and IFRS 7, Financial Instruments: Disclosures regarding the classification and measurement of financial instruments and the accounting for power purchase agreements and IFRS 18, Presentation and Disclosure in Financial Statements regarding the replacement of IAS 1, Presentation of Financial Statements. 3. Trade and other receivables: Trade $ 433,519 $ 431,602 Value-added and other tax receivables 22,123 22,292 Other 17,694 79,721 $ 473,336 $ 533,615 As at Dec 31 2024 Dec 31 2023 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, 2024 is $2,800 million (2023 - $2,860 million). 5. Property, plant and equipment: Net book value at December 31, 2024 $ 3,501,683 $ 695,826 $ 4,197,509 Net book value at December 31, 2023 $ 3,654,475 $ 757,293 $ 4,411,768 Owned Assets (a) Right-of-use assets (c) Total 59

a) Owned assets: Cost at January 1, 2024 $ 4,880,207 $ 1,355,497 $ 240,723 $ 128,663 $ 6,605,090 Additions 97,439 123,881 2,013 1,807 225,140 Disposals and other (91,338) (8,266) (277) (550) (100,431) Transfers 1,471,112 (1,471,112) — — — Cost at December 31, 2024 6,357,420 — 242,459 129,920 6,729,799 Accumulated depreciation at January 1, 2024 2,794,702 — 61,390 94,523 2,950,615 Depreciation 236,398 — 11,829 2,090 250,317 Asset impairment charge (b) 124,788 — — — 124,788 Disposals and other (96,828) — — (776) (97,604) Accumulated depreciation at December 31, 2024 3,059,060 — 73,219 95,837 3,228,116 Net book value at December 31, 2024 $ 3,298,360 $ — $ 169,240 $ 34,083 $ 3,501,683 Buildings, plant installations and machinery Plants Under Construction1 Ocean vessels Other TOTAL 1 Geismar 3 completed its commercial performance tests and reached the use intended by management in 2024. As a result, it was transferred to Buildings, Plant Installations & Machinery during the year. Included in the final cost of the Geismar 3 plant is $201 million (2023: $150 million) of capitalized interest and finance charges. 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 Buildings, plant installations and machinery Plants under construction Ocean vessels Other TOTAL Based on natural gas feedstock availability and the completion of Geismar 3, the Company has extended the useful lives of the Chile facilities and Geismar 1 and 2. The effect of these changes on actual and expected depreciation expense was as follows. 2024 2025 2026 2027 2028 Later (Decrease) increase in depreciation expense $ (9,691) $ (61,099) $ (10,193) $ (10,985) $ (13,363) $ 105,331 b) Asset impairment charge: The Company reviews the carrying value of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The Company decided to restructure its New Zealand operations to a single plant operation in September 2024 due to a forecasted decline in New Zealand’s gas profile. The restructuring and shift to a one plant operation has been identified as an impairment indicator for the New Zealand cash generating unit ("New Zealand CGU") and the carrying value of the New Zealand CGU was tested for impairment during the year. The recoverable amount of the New Zealand CGU was based on fair value less costs of disposal, estimated using discounted cash flows. The model contains significant unobservable inputs and as a result is classified within Level 3 of the fair value hierarchy. Impairment was measured by comparing the carrying value of the New Zealand CGU to estimated fair value, discounted at a rate of 9%. There are two key variables that impact the Company’s estimates of future cash flows: (1) the methanol price and (2) the price and availability of natural gas feedstock. Methanol price estimates are based on supply and demand fundamentals and consideration is given to many factors, including, but not limited to, estimates of global industrial production rates, energy prices, changes in general economic conditions, future global methanol production capacity, industry operating rates and the global industry cost structure. The Company’s estimate of the price and availability of natural gas takes into consideration the current contracted terms, as well as factors that it believes are relevant to supply under these contracts and supplemental natural gas sources. Other assumptions included in the Company’s 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. The values assigned to the key assumptions represent management's assessment of future trends and have been based on historical data from both external and internal sources. 60

Based on the test performed, the Company recorded a non-cash before-tax asset impairment charge of $125 million ($90 million after- tax) in property, plant and equipment to write down the carrying value of the New Zealand CGU to its recoverable amount. The following table presents the Level 3 inputs and the sensitivities of the fair value less costs of disposal model to changes in these inputs: Sensitivities Valuation input Input value or range Change in input Resulting change in valuation Methanol price forecast $317 - $365 per MT +/- $25 per MT $+24/-27 million Natural gas availability Annual estimates based on third party forecasts +/-10% $+19/-21 million Discount rate (after-tax) 9% +/- 1% $+/-2 million The sensitivity has been prepared considering each variable independently. 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. c) Right-of-use (leased) assets: Cost at January 1, 2024 $ 910,721 $ 332,441 $ 58,621 $ 1,301,783 Additions 40,055 46,029 4,721 90,805 Disposals and other (15,607) (11,921) (4,980) (32,508) Cost at December 31, 2024 935,169 366,549 58,362 1,360,080 Accumulated depreciation at January 1, 2024 314,324 196,303 33,863 544,490 Depreciation 107,690 38,011 6,364 152,065 Disposals and other (15,607) (11,743) (4,951) (32,301) Accumulated depreciation at December 31, 2024 406,407 222,571 35,276 664,254 Net book value at December 31, 2024 $ 528,762 $ 143,978 $ 23,086 $ 695,826 Ocean vessels Terminals and tanks Other TOTAL 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 61

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. In mid-September the Atlas facility was idled, as its legacy 20-year natural gas supply agreement expired. The Company accounts for its interest in Atlas using the equity method. Summarized financial information of Atlas (100% basis) is as follows: Cash and cash equivalents $ 18,934 $ 126,392 Other current assets1 49,803 189,062 Non-current assets 145,298 149,354 Current liabilities1 (42,901) (157,835) Other long-term liabilities, including current maturities (10,376) (135,940) Net assets at 100% $ 160,758 $ 171,033 Net assets at 63.1% $ 101,438 $ 107,921 Long-term receivable from Atlas1 — 76,328 Investment in associate $ 101,438 $ 184,249 Consolidated statements of financial position as at Dec 31 2024 Dec 31 2023 Revenue1 $ 344,892 $ 466,312 Cost of sales and depreciation and amortization (254,047) (289,705) Gas contract settlement — 75,000 Operating income 90,845 251,607 Finance costs, finance income and other expenses (5,739) (10,316) Income tax expense (b) (24,353) (83,659) Net earnings at 100% $ 60,753 $ 157,632 Earnings of associate at 63.1% $ 38,335 $ 99,466 Dividends received from associate $ 32,181 $ 112,318 Share capital reduction $ 12,643 $ — Consolidated statements of income for the years ended December 31 2024 2023 1 Includes related party transactions between Atlas and the Company (see note 23). b) 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 2018 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. During the year, the Trinidad tax court issued a ruling in the Company's favour. At present the BIR is reviewing whether to proceed with an appeal and should it decide to proceed, the Company will continue to defend its position. 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. 62

7. Other assets: Cash flow hedges (note 19) $ 128,414 $ 121,108 Chile VAT receivable 15,834 17,824 Restricted cash for debt service and major maintenance of vessels (a) 14,305 15,772 Fair value of Egypt gas supply contract derivatives (note 19) 14,341 — Fair value of New Zealand gas supply contract derivatives (note 19) 8,713 20,402 Deposit for catalyst supply 6,274 — Investment in Carbon Recycling International 5,620 5,620 Defined benefit pension plans (note 21) 3,733 5,718 Other 16,855 15,416 Total other assets 214,089 201,860 Less current portion (b) (30,820) (3,893) $ 183,269 $ 197,967 As at Dec 31 2024 Dec 31 2023 a) Restricted cash The Company holds $14.3 million (2023 - $15.8 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, 2024 includes $27.7 million (2023 - $0.5 million) for the current portion of the cash flow hedge (see note 19), and $3.1 million (2023 - $3.4 million) of restricted cash for major maintenance, in particular the anticipated major maintenance costs of four vessels. 8. Long-term debt: Unsecured notes (i) $300 million at 4.25% due December 1, 2024 $ — $ 299,283 (ii) $700 million at 5.125% due October 15, 2027 696,104 694,844 (iii) $700 million at 5.25% due December 15, 2029 696,395 695,824 (iv) $600 million at 6.25% due March 15, 2032 585,562 — (v) $300 million at 5.65% due December 1, 2044 295,820 295,709 2,273,881 1,985,660 Other limited recourse debt facilities (i) 5.58% due through June 30, 2031 49,450 56,637 (ii) 5.35% due through September 30, 2033 59,138 65,300 (iii) 5.21% due through September 15, 2036 32,466 34,204 141,054 156,141 Total long-term debt1 2,414,935 2,141,801 Less current maturities1 (13,727) (314,716) $ 2,401,208 $ 1,827,085 As at Dec 31 2024 Dec 31 2023 1 Long-term debt and current maturities are presented net of discounts and deferred financing fees of $28.3 million as at December 31, 2024 (2023 - $16.8 million). For the year ended December 31, 2024, non-cash accretion, on an effective interest basis, of deferred financing costs included in finance costs was $3.1 million (2023 - $2.6 million). 63

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 2025 $ 13,660 $ — $ 13,660 2026 13,796 — 13,796 2027 15,173 700,000 715,173 2028 16,026 — 16,026 2029 16,210 700,000 716,210 Thereafter 68,363 900,000 968,363 $ 143,228 $ 2,300,000 $ 2,443,228 During the year, the maturity date of the previously established $300 million revolving credit facility was renewed to April 2028 and an additional $200 million tranche was added which expires in April 2026, increasing the total amount available under the revolving credit facility as at December 31, 2024 to $500 million. The facilities are with a syndicate of highly rated financial institutions. The existing revolving credit facility was entered into with the following significant covenants and default provisions: i) the obligation to maintain a minimum interest coverage ratio of EBITDA to net interest expense greater than or equal to 2:1 calculated on a four-quarter trailing basis and a funded debt to total 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 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 limited recourse subsidiaries. The revolving credit facility is partially secured by certain assets of the Company, and also includes other customary covenants including restrictions on the incurrence of additional indebtedness. To support the OCI Acquisition (Refer to note 27 - Agreement to acquire OCI Global's methanol business), the Company renewed its $500 million revolving credit facility by increasing the existing $300 million tranche to $400 million with a new five-year tenor, and the renewal of the $200 million tranche with a new three-year tenor, both from the closing date of the OCI Acquisition. Additionally, a term loan commitment of $650 million was added to partially finance the OCI Acquisition. The increase to a total availability of $600 million under the revolving credit facility and availability of the $650 million term loan commitment are subject to the closing of the OCI Acquisition. During the year ended December 31, 2024, the Company (through its wholly-owned US subsidiary, Methanex US Operations Inc.) also issued $600 million of senior unsecured notes bearing a coupon of 6.25% and due March 15, 2032. The $600 million senior unsecured notes are subject to a special mandatory redemption if either (1) the OCI Acquisition is not completed within the time period required by the related acquisition agreement, as it may be extended (but in no event later than May 31, 2026) or (2) Methanex publicly announces that it will not proceed with the OCI Acquisition for any reason, as further described in the terms of the notes. The Company also repaid $300 million of unsecured notes due December 1, 2024. In October, to support the OCI Acquisition, the Company successfully syndicated a 364-day bridge facility (“Bridge Facility”). As a result of the successful syndication of the $650 million term loan commitment and successful issuance of the $600 million senior unsecured notes, the commitment under the Bridge Facility was reduced to nil and the facility was terminated in November 2024. The covenants governing the Company’s and Methanex US Operations Inc.'s unsecured notes, which are specified in an indenture, apply to the Company, Methanex US Operations Inc. 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 indentures also contain customary default provisions. Failure to comply with any of the covenants or default provisions of the long-term debt arrangements 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, 2024, management believes the Company was in compliance with all covenants related to long-term debt obligations. Other limited recourse debt facilities relate to financing for a certain number 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. 64

9. Lease obligations: 2024 2023 Opening lease obligations $ 872,120 $ 870,163 Additions, net of disposals 90,486 123,187 Interest expense 54,560 53,418 Lease payments (195,807) (171,577) Effect of movements in exchange rates and other (3,154) (3,071) Lease obligations at December 31 818,205 872,120 Less: current portion (122,744) (120,731) Lease obligations - non current portion $ 695,461 $ 751,389 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, 2024: Lease payments Interest component Lease obligations 2025 $ 168,554 $ 48,592 $ 119,962 2026 141,732 42,146 99,586 2027 122,035 35,975 86,060 2028 116,342 29,632 86,710 2029 109,387 23,138 86,249 Thereafter 422,555 82,917 339,638 $ 1,080,605 $ 262,400 $ 818,205 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 2024 was $90.9 million (2023 - $83.8 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 2024 were $0.4 million (2023 - $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 $56.5 million (2023 - $51.8 million). Lease liabilities recognized (discounted) Potential future lease payments not included in lease liabilities (undiscounted) Ocean-going vessels $ 602,537 $ 9,173 Terminals and tanks 183,138 36,741 Other 32,530 10,561 Total $ 818,205 $ 56,475 Leases not yet commenced As at December 31, 2024, 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 $2.8 million (2023 - $68.7 million). The leases not yet commenced as at December 31, 2024 related to the addition of 1 new ocean vessel in 2025 with a 1-year term. 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 that commenced in 2024. 65

10. Other long-term liabilities: Share-based compensation liability (note 14) $ 73,547 $ 74,107 Site restoration costs 38,048 32,596 Land mortgage 27,483 28,014 Defined benefit pension plans (note 21) 20,531 22,691 Cash flow hedges (note 19) 36,811 91,183 Other 882 1,319 197,302 249,910 Less current maturities (46,840) (94,992) $ 150,462 $ 154,918 As at Dec 31 2024 Dec 31 2023 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, 2024, the total undiscounted amount of estimated cash flows required to settle the liabilities was $64.1 million (2023 - $50.6 million). The movement in the provision during the year is explained as follows: Balance at January 1 $ 32,596 $ 36,581 New or revised provisions 3,831 (5,573) Accretion expense 1,621 1,588 Balance at December 31 $ 38,048 $ 32,596 2024 2023 11. Expenses: Cost of sales $ 2,678,081 $ 2,797,794 Selling and distribution 583,357 552,693 Administrative expenses 133,672 109,415 Total expenses by function $ 3,395,110 $ 3,459,902 Cost of raw materials and purchased methanol 2,219,459 2,329,856 Ocean freight and other logistics 362,282 357,495 Employee expenses, including share-based compensation 251,149 243,542 Other expenses 176,517 137,179 Cost of sales and operating expenses 3,009,407 3,068,072 Depreciation and amortization 385,703 391,830 Total expenses by nature $ 3,395,110 $ 3,459,902 For the years ended December 31 2024 2023 For the year ended December 31, 2024 we recorded a share-based compensation expense of $24.0 million (2023 - expense of $34.5 million), the majority of which is included in administrative expenses for the total expenses by function presentation above. Included in cost of sales is $344.9 million (2023 - $466.3 million) of cost of sales which are recognized as sales to Methanex in our Atlas equity investee’s statements of income. 12. Finance costs: For the years ended December 31 2024 2023 Finance costs before capitalized interest $ 183,699 $ 172,814 Less capitalized interest related to Geismar plant under construction (51,065) (55,448) Finance costs $ 132,634 $ 117,366 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. The Geismar 3 plant completed its commercial performance tests rates during the fourth quarter of 2024, and accordingly, we ceased capitalizing interest costs related to Geismar 3 from the date. 66

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, tandem share appreciation rights ("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 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 equity-settled method was more dilutive for the year ended December 31, 2024, and an adjustment was required for the numerator and the denominator. The cash-settled method was more dilutive for the year ended December 31, 2023, and no 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 TSAR. For the year ended December 31, 2024 and 2023, stock options were dilutive, resulting in an adjustment to the denominator. For the year ended December 31, 2024, TSARs 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. 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 2024 2023 Numerator for basic net income per common share $ 163,986 $ 174,140 Adjustment for the effect of TSARs: Cash-settled recovery included in net income 1,995 — Equity-settled expense (4,385) — Numerator for diluted net income per common share $ 161,596 $ 174,140 A reconciliation of the denominator used for the purposes of calculating diluted net income per common share is as follows: Denominator for basic net income per common share 67,387,809 67,805,220 Effect of dilutive stock options 6,438 6,395 Effect of dilutive TSARS 165,813 — Denominator for diluted net income per common share 67,560,060 67,811,615 For the years ended December 31 2024 2023 For the years ended December 31, 2024 and 2023, basic and diluted net income per common share attributable to Methanex shareholders were as follows: Basic net income per common share $ 2.43 $ 2.57 Diluted net income per common share $ 2.39 $ 2.57 For the years ended December 31 2024 2023 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, 2024, the Company had 4,211,772 common shares reserved for future grants of stock options and tandem share appreciation rights under the Company’s stock option plan. 67

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, 2024 and 2023 are as follows: Number of units Exercise price USD Number of units Exercise price USD 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 Granted 83,840 43.13 255,540 42.58 Exercised (30,557) 37.10 (185,957) 33.49 Cancelled (2,421) 51.94 (20,893) 50.74 Expired (87,120) 50.15 (236,062) 50.17 Outstanding at December 31, 2024 366,274 $ 45.77 1,820,098 $ 45.21 SARs TSARs Information regarding the SARs and TSARs outstanding as at December 31, 2024 is as follows: 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 2.53 90,318 $ 32.73 90,318 $ 32.73 $42.34 to $50.49 5.53 161,896 46.32 34,360 49.41 $54.65 to $78.59 0.40 114,060 55.33 114,060 55.33 3.19 366,274 $ 45.77 238,738 $ 45.93 TSARs $29.27 to $38.79 2.59 606,205 $ 33.30 606,205 $ 33.30 $42.34 to $50.49 5.18 666,483 46.77 221,562 48.97 $54.65 to $78.59 0.66 547,410 56.50 547,410 56.50 2.96 1,820,098 $ 45.21 1,375,177 $ 45.06 Units outstanding at December 31, 2024 Units exercisable at December 31, 2024 The fair value of each outstanding SARs and TSARs grant was estimated on December 31, 2024 and 2023 using the Black-Scholes option pricing model with the following weighted average assumptions: Risk-free interest rate 4.2 % 4.5 % Expected dividend yield 1.5 % 1.6 % Expected life of SARs and TSARs (years) 1.5 1.4 Expected volatility 35 % 38 % Expected forfeitures 0 % 0 % Weighted average fair value (USD per unit) $ 12.16 $ 10.75 2024 2023 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, 2024 was $28.1 million compared with the recorded liability of $25.3 million. The difference between the fair value and the recorded liability of $2.8 million will be recognized over the weighted average remaining vesting period of approximately 1.5 years. For the year ended December 31, 2024, compensation expense related to SARs and TSARs included an expense in cost of sales and operating expenses of $3.9 million (2023 - expense of $10.5 million). This included a recovery of $1.8 million (2023 - expense of $6.6 million) related to the effect of the change in the Company’s share price. 68

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, 2024 and 2023 are as follows: 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 Granted 28,159 134,080 234,430 Performance factor impact on redemption1 — — 47,473 Granted in lieu of dividends 2,827 5,468 10,113 Redeemed (33,892) (118,135) (297,331) Cancelled — (16,912) (24,305) Outstanding at December 31, 2024 154,794 315,355 601,502 Number of deferred share units Number of restricted share units Number of performance share units (new plan) 1 The number of performance share units that ultimately vest are determined by performance factors as described below. The performance factors impact relates to performance share units redeemed in the quarter ended March 31, 2024 and the quarter ended March 31, 2023. 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 modified 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, 2024 was $60.5 million compared with the recorded liability of $48.5 million. The difference between the fair value and the recorded liability of $12.0 million will be recognized over the weighted average remaining vesting period of approximately 1.7 years. For the year ended December 31, 2024, compensation expense related to deferred, restricted and performance share units included in cost of sales and operating expenses was an expense of $19.9 million (2023 - expense of $23.9 million). This included an expense of $4.3 million (2023 - expense of $8.8 million) related to the effect of the change in the Company’s share price. 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, 2024 and 2023, revenues attributed to geographic regions, based on the location of customers, were as follows: 2024 $ 828,531 $ 841,546 $ 502,134 $ 478,752 $ 482,645 $ 401,830 $ 184,391 $ 3,719,829 22 % 23 % 13 % 13 % 13 % 11 % 5 % 100 % 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 % Revenue China Europe United States South America South Korea Other Asia Canada TOTAL 69

As at December 31, 2024 and 2023, the net book value of property, plant and equipment by geographic region, and the Company's shipping business, was as follows: December 31, 2024 $ 2,582,900 $ 482,764 $ 83,880 $ 161,870 $ 114,327 $ 42,282 $ 698,003 $ 31,483 $ 4,197,509 December 31, 2023 $ 2,537,515 $ 520,497 $ 232,831 $ 157,483 $ 113,789 $ 43,835 $ 775,729 $ 30,089 $ 4,411,768 Property, plant and equipment 1 United States Egypt New Zealand Canada Chile Trinidad Waterfront Shipping Other TOTAL 1 Includes right-of-use (leased) assets. 16. Income and other taxes: a) Income tax (expense) recovery: Current tax (expense) recovery: Current period before undernoted items $ (74,169) $ (64,679) Adjustments to prior years including resolution for certain outstanding audits 43 14,755 (74,126) (49,924) Deferred tax recovery (expense): Origination and reversal of temporary differences 52,396 46,982 Adjustments to prior years including resolution for certain outstanding audits (383) 6,904 Changes in tax rates 34 (5,828) Impact of foreign exchange and other (7,762) 377 44,285 48,435 Total income tax expense $ (29,841) $ (1,489) For the years ended December 31 2024 2023 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: Income before income taxes $ 280,086 $ 285,611 Deduct earnings of associate (38,335) (99,466) 241,751 186,145 Canadian statutory tax rate 24.5% 24.5% Income tax expense calculated at Canadian statutory tax rate (59,229) (45,606) Decrease (increase) in income tax expense resulting from: Impact of income and losses taxed in foreign jurisdictions 14,268 27,260 Utilization of unrecognized loss carryforwards and temporary differences 6,482 7,381 Impact of tax rate changes 34 (5,828) Impact of foreign exchange 1,650 5,287 Other business taxes 2,791 (13,943) Impact of items not taxable for tax purposes 4,555 2,373 Adjustments to prior years including resolution for certain outstanding audits (340) 21,658 Other (52) (71) Total income tax expense $ (29,841) $ (1,489) For the years ended December 31 2024 2023 70

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: Net Deferred tax assets Deferred tax liabilities Net Deferred tax assets Deferred tax liabilities Property, plant and equipment (owned) $ (325,338) $ (162,036) $ (163,302) $ (363,644) $ (189,646) $ (173,998) Right-of-use assets (35,757) (25,816) (9,941) (35,883) (28,299) (7,584) Repatriation taxes (119,281) (30) (119,251) (109,186) (7) (109,179) Other (26,241) (11,267) (14,974) (31,630) (9,259) (22,371) (506,617) (199,149) (307,468) (540,343) (227,212) (313,131) Non-capital loss carryforwards 357,670 346,150 11,520 358,774 321,602 37,172 Lease obligations 48,706 35,740 12,966 48,633 37,854 10,779 Share-based compensation 24,567 8,185 16,382 16,391 651 15,740 Other 40,652 13,165 27,487 50,955 19,355 31,600 471,595 403,240 68,355 474,753 379,462 95,291 Net deferred income tax assets (liabilities) $ (35,022) $ 204,091 $ (239,113) $ (65,590) $ 152,250 $ (217,840) As at Dec 31, 2024 Dec 31, 2023 As at December 31, 2024, 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 2024 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 23,721 5,219 Losses generated in 2024 6,636 1,460 Total non-capital loss carryforwards $ 1,356,881 $ 298,515 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, 2024 the Company had $170 million (2023 - $201 million) of deductible temporary differences in the United States that have not been recognized. As at December 31, 2024, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in Trinidad. The loss carryforwards total $107 million (2023 - $82 million), which result in a deferred income tax asset of $38 million (2023 - $29 million). The losses generated in Trinidad may be carried forward indefinitely against future taxable income. As at December 31, 2024, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in New Zealand. The loss carryforwards total $36 million (2023 - $25 million), which result in a deferred income tax asset of $10 million (2023 - $7 million). The losses generated in New Zealand may be carried forward indefinitely against future taxable income. As at December 31, 2024, deferred income tax assets have been recognized in respect of non-capital loss carryforwards generated in Canada. The loss carryforwards total $47 million (2023 - $123 million), which result in a deferred income tax asset of $12 million (2023 - $30 million). The losses were generated in 2020 and can be carried forward 20 years against future taxable income. 71

(ii) Analysis of the change in deferred income tax assets and liabilities: Net Deferred tax assets Deferred tax liabilities Net Deferred tax assets Deferred tax liabilities Balance, January 1 $ (65,590) $ 152,250 $ (217,840) $ (180,643) $ 46,353 $ (226,996) Deferred income tax recovery (expense) included in net income 44,285 65,244 (20,959) 48,435 40,159 8,276 Deferred income tax recovery (expense) included in other comprehensive income (14,096) (13,403) (693) 66,636 65,738 898 Other 379 — 379 (17) — (17) Balance, December 31 $ (35,022) $ 204,091 $ (239,113) $ (65,590) $ 152,250 $ (217,840) 2024 2023 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. Canada enacted legislation resulting in Pillar Two rules being effective for tax years beginning January 1, 2024. The Company is in scope of the legislation and has performed an assessment of the exposure to top-up taxes that apply based on our financial results in the jurisdictions in which we operate. For the year ended December 31, 2024, $3 million is included in current tax expense relating to Pillar Two top-up obligations. 17. Supplemental cash flow information: a) Changes in non-cash working capital: Changes in non-cash working capital for the years ended December 31, 2024 and 2023 were as follows: Changes in non-cash working capital: Trade and other receivables $ 60,279 $ (32,690) Inventories (26,689) 12,997 Prepaid expenses (3,266) (19,439) Trade, other payables and accrued liabilities (225,562) (17,333) (195,238) (56,465) Adjustments for items not having a cash effect and working capital changes relating to taxes and interest paid and interest received (10,790) 6,027 Changes in non-cash working capital having a cash effect $ (206,028) $ (50,438) These changes relate to the following activities: Operating $ (123,655) $ (59,058) Financing (67,737) 68,750 Investing (14,636) (60,130) Changes in non-cash working capital $ (206,028) $ (50,438) For the years ended December 31 2024 2023 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, 2023 $ 2,141,801 $ 872,120 Changes from financing cash flows Repayment of long-term debt and financing fees (322,378) — Net proceeds on issue of long-term debt 585,393 — Payment of lease obligations — (141,247) Total changes from financing cash flows 263,015 (141,247) Liability-related other changes Finance costs 10,119 — New lease obligations — 89,349 Other — (2,017) Total liability-related other changes 10,119 87,332 Balance at December 31, 2024 $ 2,414,935 $ 818,205 72

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. Liquidity: Cash and cash equivalents $ 891,910 $ 458,015 Undrawn credit facility 500,000 300,000 Total liquidity $ 1,391,910 $ 758,015 Capitalization: Unsecured notes, including current portion 2,273,881 1,985,660 Other limited recourse debt facilities, including current portion 141,054 156,141 Total debt 2,414,935 2,141,801 Non-controlling interests 287,707 242,090 Shareholders’ equity 2,093,559 1,930,927 Total capitalization $ 4,796,201 $ 4,314,818 Total debt to capitalization 1 50 % 50 % Net debt to capitalization 2 39 % 44 % As at Dec 31 2024 Dec 31 2023 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. During the year, the $300 million revolving credit facility was renewed to April 2028 and an additional $200 million tranche was added which expires in April 2026, increasing the total amount available under the revolving credit facility to $500 million. To support the OCI Acquisition (Refer to note 27 - Agreement to acquire OCI Global's methanol business), the Company renewed its $500 million revolving credit facility by increasing the existing $300 million tranche to $400 million with a new five-year tenor, and the renewal of the $200 million tranche with a new three-year tenor, both from the closing date of the OCI Acquisition. Additionally, a term loan commitment of $650 million was added to partially finance the OCI Acquisition. The increase to a total availability of $600 million under the revolving credit facility and availability of the $650 million term loan commitment are subject to the closing of the OCI Acquisition. Both the committed revolving credit facility and term loan commitment are with a syndicate of highly rated financial institutions. The credit facility is subject to certain financial covenants (note 8). 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. 73

The following table provides the carrying value of each category of financial assets and liabilities and the related balance sheet item: Financial assets: Financial assets measured at fair value: Derivative instruments designated as cash flow hedges 1 $ 128,414 $ 121,108 Fair value of Egypt gas supply contract derivative 2 14,341 20,402 Fair value of New Zealand gas supply contract derivative 3 8,713 — Financial assets not measured at fair value: Cash and cash equivalents 891,910 458,015 Trade and other receivables, excluding tax receivable 454,278 514,739 Restricted cash included in other assets 14,305 15,772 Total financial assets 4 $ 1,511,961 $ 1,130,036 Financial liabilities: Financial liabilities measured at fair value: Derivative instruments designated as cash flow hedges 1 $ 36,811 $ 91,653 Financial liabilities not measured at fair value: Trade, other payables and accrued liabilities, excluding tax payable 429,737 672,237 Lease obligations, including current portion 818,205 872,120 Long-term debt, including current portion 2,414,935 2,141,801 Land mortgage 27,483 28,014 Total financial liabilities $ 3,727,171 $ 3,805,825 As at Dec 31 2024 Dec 31 2023 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 New Zealand natural gas supply contract is measured at fair value using an economic model classified within Level 3 of the fair value hierarchy. 4 The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods. As at December 31, 2024, 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. During the year ended December 31, 2024, the Company reclassified $11.7 million (2023 - nil) from other comprehensive income to cost of sales and operating expenses within the statement of income on discontinuation of the hedging relationship for certain gas forward contracts where the hedged future cash flows were no longer highly probable to occur. 74

As at Dec 31 2024 Dec 31 2023 Maturities 2025-2032 2024-2032 Notional quantity 1 310,520 347,190 Notional quantity per day, annualized 1 50 - 210 50 - 170 Notional amount $ 1,048,973 $ 1,183,319 Net fair value $ 89,632 $ 29,925 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 2024 Dec 31 2023 Other current assets $ 25,760 $ 470 Other non-current assets 100,683 120,638 Other current liabilities (14,708) (60,532) Other long-term liabilities (22,103) (30,651) Net fair value $ 89,632 $ 29,925 For the year ended December 31, 2024, the Company reclassified a loss of $76.0 million (2023 - loss of $22.5 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 2024 or 2023. As at December 31, 2024, the Company had outstanding forward exchange contracts designated as cash flow hedges to sell a notional amount of 29.7 million euros (2023 - 12.2 million euros). The euro contracts had a positive fair value of $2.0 million included in Other current assets (2023 - negative fair value of $0.5 million included in Other current liabilities). For the year ended December 31, 2024, the Company reclassified a gain of $3.6 million (2023 - loss of $3.1 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: Change in fair value of cash flow hedges $ 187,921 $ (276,619) Forward element excluded from hedging relationships (211,132) (33,837) $ (23,211) $ (310,456) For the years ended December 31 2024 2023 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. 75

Within one year $ 15,038 $ 65,034 1-3 years 5,808 17,771 3-5 years 4,330 5,537 More than 5 years 20,459 11,378 $ 45,635 $ 99,720 As at Dec 31 2024 Dec 31 2023 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 $128.4 million as at December 31, 2024 (2023 - $121.1 million). The carrying values of the Company’s financial instruments approximate their fair values, except as follows: Carrying value Fair value Carrying value Fair value Long-term debt excluding deferred financing fees $ 2,437,286 $ 2,348,705 $ 2,156,534 $ 2,063,661 As at December 31, 2024 December 31, 2023 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 - Egyptian natural gas supply contract 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, 2024 the fair value of the derivative associated with the remaining term of the natural gas supply contract is $14.3 million (2023 - $20.4 million) recorded in Other assets. Changes in fair value of the contract are recognized in Finance income and other expenses. 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% $+/-6 million Methanol price forecast $360 - $430 per MT +/- $25 per MT $-4/+5 million Discount rate 7.5% +/- 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. 76

Fair value - Level 3 instrument - New Zealand natural gas supply contract The Company holds a long-term natural gas supply contract expiring in 2029 with OMV New Zealand ("OMV"), one of the largest gas suppliers in New Zealand. The natural gas supply contract includes a base fixed price plus a premium based on the realized price of methanol. During 2024, the Company entered into short-term commercial arrangements to provide its contracted natural gas into the New Zealand electricity market (Refer to note 25 - New Zealand gas sale proceeds). The on-sale of natural gas has impacted the accounting assessment for the contract whereby it is now considered a derivative to be measured at fair value. The New Zealand wholesale gas market is relatively small and concentrated as there are a limited number of suppliers and consumers. There is a limited observable, liquid spot market and no forward curve for natural gas in New Zealand. The gas trading platform used to facilitate short-term balance in the gas market trades inconsequential volumes relative to the scope of the Company’s gas consumption and the overall gas market. The Company does not believe transactions on this platform take place with sufficient frequency and volume to provide pricing information. Due to the absence of an observable market price for an equivalent or similar contract to measure fair value, we have estimated fair value using an economic model. The model includes significant unobservable inputs and as a result is classified within Level 3 of the fair value hierarchy. We have considered market participant assumptions in establishing the model inputs and determining fair value, including potential sharing mechanisms for gas on-sales to consider the change in the local market gas supply and demand dynamics since contract inception. At December 31, 2024 the fair value associated with the remaining term of the natural gas supply contract including consideration of on-sales is $8.7 million recorded in Other non-current assets. Changes in fair value of the contract are recognized in Finance income and other expenses. The table presents the Level 3 inputs and the sensitivities of the economic model valuation to changes in these inputs: Sensitivities Valuation input Input value or range Change in input Resulting change in valuation New Zealand forward electricity pricing $65 - $235 NZD$/MWH +/- $50 NZD/MWH $-/+ 0.3 million Methanol price forecast $300 - $360 per MT +/- $25 per MT $-/+0.3 million Natural gas availability Annual estimates based on third party forecasts +/-10% $+/- 2 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. 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. 77

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. Fixed interest rate debt: Unsecured notes $ 2,273,881 $ 1,985,660 Other limited recourse debt facilities 141,054 156,141 $ 2,414,935 $ 2,141,801 As at Dec 31 2024 Dec 31 2023 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 $119.6 million as of December 31, 2024 (2023 - $100.5 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, 2024, the Company had a net working capital asset of $152.7 million in non U.S. dollar currencies (2023 - $74.4 million). Each 10% strengthening of the U.S. dollar against these currencies would decrease the value of net working capital and pre-tax cash flows and earnings by approximately $13.9 million (2023 - $6.8 million). Each 10% weakening of the U.S. dollar against these currencies would increase the value of net working capital and pre-tax cash flows and earnings by approximately $17.0 million (2023 - $8.3 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, 2024, the Company had a strong liquidity position including a cash and cash equivalents balance of $892 million. In addition, the Company has access to a $500 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: Trade and other payables 1 $ 415,120 $ 415,120 $ 415,120 $ — $ — $ — Lease obligations 2 818,205 1,080,605 168,554 263,767 225,729 422,555 Other long-term liabilities2 27,483 51,148 2,200 4,400 4,400 40,148 Long-term debt 2 2,414,935 3,377,269 148,253 989,912 924,064 1,315,040 Cash flow hedges 3 36,811 45,635 15,038 5,808 4,330 20,459 $ 3,712,554 $ 4,969,777 $ 749,165 $ 1,263,887 $ 1,158,523 $ 1,798,202 As at December 31, 2024 Carrying amount Contractual cash flows 1 year or less 1-3 years 3-5 years More than 5 years 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. 78

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, 2024 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. 79

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: Accrued benefit obligations: Balance, beginning of year $ 55,181 $ 53,586 Current service cost 3,395 2,246 Past service cost — 2,479 Interest cost on accrued benefit obligations 2,436 2,549 Benefit payments (3,657) (4,280) Settlements (12,246) (3,738) Actuarial (gain) loss (206) 2,074 Foreign exchange (gain) loss (4,856) 265 Balance, end of year 40,047 55,181 Fair values of plan assets: Balance, beginning of year 38,208 38,347 Interest income on assets 1,680 1,901 Contributions 2,536 5,687 Benefit payments (3,657) (4,280) Settlements (13,305) (3,680) Return on plan assets 45 (705) Foreign exchange gain (loss) (2,258) 938 Balance, end of year 23,249 38,208 Unfunded status 16,798 16,973 Minimum funding requirement — — Defined benefit obligation, net $ 16,798 $ 16,973 As at Dec 31 2024 Dec 31 2023 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 $19.2 million as at December 31, 2024 (2023 - obligation of $20.2 million) for its employees in Chile that will be funded in accordance with Chilean law. The Company also has an unfunded retirement obligation of $1.2 million as at December 31, 2024 (2023 - $2.5 million) 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 $11.0 million in Chile and $0.1 million in Egypt for 2025. Actual benefit payments in future periods will fluctuate based on employee retirements. The Company has a net funded retirement asset of $3.7 million as at December 31, 2024 (2023 - $5.3 million) for certain employees and retirees in Canada and a net funded retirement asset of $0.1 million as at December 31, 2024 (2023 - 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 2025. 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, Chile and Egypt, 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 6 years. 80

The Company’s net defined benefit pension plan expense charged to the consolidated statements of income for the years ended December 31, 2024 and 2023 is as follows: Net defined benefit pension plan expense: Current service cost $ 3,395 $ 2,246 Past service cost — 2,479 Net interest cost 756 648 Cost of settlement 1,059 (58) Total net defined benefit pension plan expense $ 5,210 $ 5,315 For the years ended December 31 2024 2023 The Company’s current year actuarial gain (loss), recognized in the consolidated statements of comprehensive income for the years ended December 31, 2024 and 2023, are as follows: For the years ended December 31 2024 2023 Actuarial gain (loss) $ 1,353 $ (2,827) The Company had no minimum funding requirement for the years ended December 31, 2024 and 2023. 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, 2024, the weighted average discount rate for the defined benefit obligation was 5.2% (2023 - 5.3%). 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 $2.3 million. The asset allocation for the defined benefit pension plan assets as at December 31, 2024 and 2023 is as follows: Equity securities 23 % 15 % Debt securities 14 % 52 % Cash and other short-term securities 63 % 33 % Total 100 % 100 % As at Dec 31 2024 Dec 31 2023 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, 2024 was $12.3 million (2023 - $11.0 million). 81

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 up to 2044. The minimum estimated commitment under these contracts, except as noted below, is as follows: As at December 31, 2024 2025 2026 2027 2028 2029 Thereafter $ 517,656 $ 399,889 $ 328,238 $ 283,234 $ 267,708 $ 766,477 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 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, 2024 2025 2026 2027 2028 2029 Thereafter $ 85,870 $ 21,460 $ 17,515 $ 16,661 $ 16,661 $ 2,393 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 plant in Egypt (in which it has a 50% interest). This results in purchase commitments of an additional 0.6 million tonnes per year of methanol offtake supply when Egypt operates at capacity. As at December 31, 2024, the Company also had commitments to purchase methanol from other suppliers for approximately 0.8 million tonnes for 2025 and 0.4 million tonnes in aggregate thereafter. The pricing under these purchase commitments is referenced to pricing at the time of purchase or sale, and accordingly, no amounts have been included in the table above. 82

23. Related parties: The Company has interests in significant subsidiaries and joint ventures as follows: Dec 31 2024 Dec 31 2023 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 Production 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 % Name Country of incorporation Principal activities Interest % 1 Waterfront Shipping Limited has a controlling interest in multiple ocean-going vessels owned through less than wholly-owned entities as disclosed in note 24. 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, 2024 of $312 million (2023 - $466 million) is a related party transaction included in cost of sales of the Company as Methanex had marketing rights for 100% of the methanol produced by Atlas. Balances outstanding with Atlas as at December 31, 2024 and provided in the summarized financial information in note 6 include receivables owing from Atlas to the Company of nil (2023 - $74 million) and payables to Atlas of $7 million (2023 - $172 million). As at December 31, 2024, Atlas has repaid its total loans outstanding to the Company and the balance is now nil (2023 - $76 million). Remuneration to non-management directors and senior management, which includes the members of the executive leadership team, is as follows: Short-term employee benefits $ 9,575 $ 9,034 Post-employment benefits 653 681 Other long-term employee benefits 45 59 Share-based compensation expense 1 7,697 10,046 Total $ 17,970 $ 19,820 For the years ended December 31 2024 2023 1 Balance includes realized and unrealized expenses and recoveries from share-based compensation awards granted. 83

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. Methanex Egypt Waterfront Shipping Limited Total Methanex Egypt Waterfront Shipping Limited Total Current assets $ 133,097 $ 193,248 $ 326,345 $ 129,320 $ 154,308 $ 283,628 Non-current assets 479,004 712,923 1,191,927 521,708 791,512 1,313,220 Current liabilities (38,424) (154,011) (192,435) (123,969) (185,459) (309,428) Non-current liabilities (95,219) (646,057) (741,276) (101,810) (718,915) (820,725) Net assets 478,458 106,103 584,561 425,249 41,446 466,695 Carrying amount of Methanex non-controlling interests $ 236,600 $ 51,107 $ 287,707 $ 214,568 $ 27,522 $ 242,090 As at Dec 31, 2024 Dec 31, 2023 Methanex Egypt Waterfront Shipping Limited Total Methanex Egypt Waterfront Shipping Limited Total Revenue $ 215,294 $ 720,984 $ 936,278 $ 258,782 $ 670,834 $ 929,616 Net and total comprehensive income 69,209 97,054 166,263 55,428 129,411 184,839 Net and total comprehensive income attributable to Methanex non-controlling interests 47,043 39,216 86,259 56,310 53,672 109,982 Distributions made and accrued to non-controlling interests $ (25,012) $ (15,630) $ (40,642) $ (93,696) $ (91,640) $ (185,336) For the years ended December 31 2024 2023 Methanex Egypt Waterfront Shipping Limited Total Methanex Egypt Waterfront Shipping Limited Total Cash flows from operating activities $ 97,601 $ 227,372 $ 324,973 $ 131,667 $ 251,290 $ 382,957 Cash flows used in financing activities (146,586) (243,950) (390,536) (99,490) (300,824) (400,314) Cash flows from (used in) investing activities $ (14,273) $ (1,736) $ (16,009) $ (5,560) $ 2,686 $ (2,874) For the years ended December 31 2024 2023 25. New Zealand gas sale proceeds: During 2024, the Company entered into short-term commercial arrangements to provide the natural gas available to the Company into the New Zealand electricity market. As a result, the Company has recognized $103 million of net proceeds in the year ended December 31, 2024 relating to gas provided. This does not include fixed costs, the impact of lost margin on the sale of methanol that was not produced in the period and additional supply chain costs incurred. 26. Egypt insurance recovery: We experienced an outage at the Egypt plant from October 2023 to February 2024. For the year ended December 31, 2024, we have recorded a $59 million ($30 million - attributable to Methanex) insurance recovery which partially offsets repair costs charged to earnings and lost margins incurred in the fourth quarter of 2023 and first quarter of 2024. 27. Agreement to acquire OCI Global's methanol business: On September 8, 2024, Methanex entered into a definitive agreement to acquire OCI Global’s international methanol business, subject to certain conditions and approvals. Excluding the impact of cash, debt, and working capital adjustments, and including the assumption of a share of non-recourse debt, consideration for the OCI Acquisition will consist of $1.18 billion in cash and the issuance of 9.9 million common shares of Methanex Corporation. 84

Executive Leadership Team Rich Sumner President and Chief Executive Officer Mark Allard Senior Vice President, Low Carbon Solutions Brad Boyd Senior Vice President, Corporate Resources Karine Delbarre Senior Vice President, Global Marketing and Logistics Kevin Maloney Senior Vice President, Corporate Development Gustavo Parra Senior Vice President, Manufacturing Kevin Price Senior Vice President, General Counsel and Corporate Secretary Dean Richardson Senior Vice President, Finance and Chief Financial Officer Board of Directors Doug Arnell Chair of the Board Board member since October 2016 Rich Sumner President and CEO of Methanex Corporation Board member since January 2023 Jim Bertram Chair of the Human Resources Committee and Member of the Corporate Governance Committee Board member since October 2018 Paul Dobson Member of the Audit, Finance & Risk and Human Resources Committees Board member since April 2019 Maureen Howe Chair of the Corporate Governance Committee Member of the Audit, Finance & Risk and Committee Board member since June 2018 Robert Kostelnik Chair of the Responsible Care Committee Member of the Human Resources Committee Board member since September 2008 Leslie O'Donoghue Member of the Audit, Finance & Risk and Human Resources Committees Board member since April 2020 Roger Perreault Member of the Audit, Finance & Risk and Responsible Care Committees Board member since April 2024 Kevin Rodgers Member of the Corporate Governance and Human Resources Committees Board member since July 2019 John Sampson Member of the Human Resources and Responsible Care Committees Board member since October 2023 Margaret Walker Member of the Audit, Finance & Risk and Responsible Care Committees Board member since April 2015 Benita Warmbold Chair of the Audit, Finance & Risk Committee Member of the Corporate Governance Committee Board member since February 2016 Xiaoping Yang Member of the Corporate Governance and Responsible Care Committees Board member since January 2022 Corporate Information Head Office Methanex Corporation 1800 Waterfront Centre 200 Burrard Street Vancouver, BC V6C 3M1 Tel 604 661 2600 Fax 604 661 2676 Toll Free 1 800 661 8851 Within North America Web Site www.methanex.com Sales Inquiries: sales@methanex.com Transfer Agent TSX Trust Company acts as transfer agent and registrar for Methanex stock and maintains all primary shareholder records. All inquiries regarding share transfer requirements, lost certificates, changes of address, or the elimination of duplicate mailings should be directed to TSX Trust Company at: 1 800 387 0825 toll free within North America. Annual General Meeting The Annual General Meeting will be held at the head office in Vancouver, British Columbia on Thursday, May 1, 2025 at 10:00 a.m. (Pacific Time) with the option to attend virtually. For more information on how to attend and vote online, please refer to the Information Circular dated March 6, 2025. Investor Relations Inquiries Tel 604 661 2600 invest@methanex.com Shares Listed Toronto Stock Exchange - MX Nasdaq Global Select Market - MEOH Annual Information Form (AIF) The corporation’s AIF can be found online at www.sedarplus.ca. A copy of the AIF can also be obtained by contacting our head office.

1800 Waterfront Centre 200 Burrard Street Vancouver, BC V6C 3M1 www.methanex.com