EX-99.2

This Management’s Discussion and Analysis (“MD&A”) is dated March 5, 2021 and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2020. Except where otherwise noted, the financial information presented in this MD&A is prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (the “IASB”). We use the United States dollar as our reporting currency and, except where otherwise noted, all currency amounts are stated in United States dollars. In this MD&A, a reference to the “Company” refers to Methanex Corporation and a reference to “Methanex”, “we”, “our” and “us” refers to the Company and its subsidiaries or any one of them as the context requires, as well as their respective interests in joint ventures and partnerships.

As at March 4, 2021, we had 76,209,280 common shares issued and outstanding and stock options exercisable for 1,518,025 additional common shares.

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

Methanol is a clear liquid commodity chemical that is predominantly produced from natural gas and is also produced from coal, particularly in China. Traditional chemical demand, which represents over 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 just under 50% of global methanol demand, includes a number of applications including methanol-to-olefins (“MTO”), methyl tertiary-butyl ether (“MTBE”), fuel applications (including vehicle fuel, marine fuel and as a fuel for industrial boilers and kilns), di-methyl ether (“DME”) and biodiesel.

We are the world’s largest producer and supplier of methanol to the major international markets in Asia Pacific, North America, Europe and South America. Our total annual operating capacity, including Methanex’s interests in jointly owned plants, is currently 9.2 million tonnes and is located in New Zealand, the United States, Trinidad, Chile, Egypt, and Canada. In addition to the methanol produced at our sites, we purchase methanol produced by others under methanol offtake contracts and on the spot market. This gives us flexibility in managing our supply chain while continuing to meet customer needs and support our marketing efforts. We have marketing rights for 100% of the production from the jointly-owned plants in Trinidad and Egypt, which provides us with an additional 1.3 million tonnes per year of methanol offtake supply when the plants are operating at full capacity.

Methanol is a global commodity and our earnings are significantly affected by 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: strength of global and regional economies, industrial production levels, energy prices, pricing of end products and government regulations and policies. Methanol industry supply is impacted by the cost of production, methanol industry operating rates and new methanol industry capacity additions.

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 regulations and policies. The future operating rates and methanol consumption of MTO producers will depend on a number of factors including pricing for their various final products, the degree of downstream integration of these units with other products, the impact of olefin industry feedstock costs, including naphtha, on relative competitiveness and plant maintenance schedules.

In 2020, global methanol demand began to recover in the second half of the year after falling significantly in the first half due to impacts from the COVID-19 pandemic and lower oil price environment. We estimate that global methanol demand totaled approximately 82 million tonnes in 2020, reflecting a 3% decrease compared to 2019.

Traditional chemical demand declined by approximately 5% year-over-year due to lower manufacturing activity due to impacts from the COVID-19 pandemic. Demand into energy-related applications was flat year-over-year. Strong demand into methanol-to-olefins applications was offset by a decline in other energy-related applications, including MTBE and other fuel applications, which were impacted by a decline in ground transportation and fuel demand due to COVID-19.

Growing interest in clean-burning fuels and regulatory changes are playing an increasing role in encouraging new applications for methanol as a fuel due to its lower emissions.

There is growing interest in methanol as a marine fuel given its environmental benefits, wide availability, cost competitiveness and successful and safe use today. Methanol significantly reduces emissions of sulphur oxides (“SOx”), nitrogen oxides (“NOx”) and particulate matter, and with the ability to be produced from renewable sources, offers a pathway to meeting future emissions regulations without further shipowner investment. Approximately 60% of our long-term shipping fleet, or 19 vessels in total, will have the capability to run on methanol by 2023.

We continue to support various pilot projects, including opportunities with cruise ships, ferries, tug boats and barges and the development of operational and safety standards to support the commercialization of methanol as a marine fuel.

In China, Methanex has partnered with the China Waterborne Transportation Research Institute (“CWTRI”), the think-tank of the Ministry of Transport, that is evaluating the technical and operational requirements for the use of methanol as a marine fuel.

There is growing interest in methanol as a vehicle fuel due to its emissions benefits. 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. In 2019, a number of Chinese government ministries published “Guidelines to Promote Methanol Vehicles in China” to expedite the development of methanol vehicles. We are pleased to see significant interest in high-level methanol fuel blends for M100 taxis (able to run on 100% methanol fuel) in China. There are approximately 25,000 taxis in China, representing approximately 500,000 tonnes of methanol demand, running on M100 fuel. Several 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 industrial boilers and industrial kilns in favour of cleaner fuels, creating a growing market for methanol as an alternative fuel. Methanol offers a competitive fuel cost, and as a liquid fuel, requires only a moderate infrastructure investment. We estimate that this growing

demand segment already represents approximately two million tonnes of methanol demand. We continue to support various pilot projects and the development of operational and safety standards to support the commercialization of methanol as an industrial boiler and kiln fuel.

Methanol is predominantly produced from natural gas and is also produced from coal, particularly in China. The cost of production is influenced by the availability and cost of raw materials, including coal and natural gas, as well as freight costs, capital 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.

Approximately four million tonnes of new annualized capacity, including existing capacity expansions, outside of China was introduced in 2020, including the Bushehr (1.65 million tonnes) and Kimiya Pars (1.65 million tonnes) plants in Iran and the Caribbean Gas Chemical Limited (1.0 million tonnes) plant in Trinidad. In China, we estimate that approximately three million tonnes of new production capacity was added in 2020, excluding methanol production that is integrated with production of other downstream products. Global methanol supply operated at lower rates in 2020 as a result of plant shutdowns to respond to lower methanol demand as well as numerous planned and unplanned outages.

Over the next few years, we expect the majority of large-scale capacity additions outside of China to be in the Americas and the Middle East. In Louisiana, Koch Methanol Investments is expected to complete a 1.7 million tonne methanol plant in 2021. There are other large-scale projects under discussion in North America; however, we believe that none have yet reached a final investment decision. We continue to monitor a number of projects in Iran that are at various stages of construction. We anticipate some continued capacity additions in China over the near-to-medium term. We expect that new capacity in China will be consumed in that country.

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 a number of 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 2020 was $247 per tonne compared to $295 per tonne in 2019. Lower methanol pricing in 2020 primarily resulted from the impact of COVID-19 on the global economy.

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: global leadership, low cost and operational excellence. We also 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) to manage issues related to employee 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.

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

We are the leading producer and supplier of methanol to the major international markets in Asia Pacific, North America, Europe and South America. Our 2020 sales volume of 10.7 million tonnes of methanol represented approximately 13% of global methanol demand. This scale allows us the flexibility to meet customer needs across international markets. Our leadership position has also enabled us to play an important role in the methanol industry, which includes publishing Methanex reference prices that are used in each major market as the basis of pricing for our customer contracts.

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

A key component of our global leadership strategy is the scale of our asset position with 9.2 million tonnes of operating capacity.

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

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

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. This contract structure significantly reduced our costs in 2020 in line with lower methanol pricing. In North America, we have fixed price contracts and hedges in place for our Geismar and Medicine Hat facilities with a higher proportion of our gas requirements at fixed prices in the near-term, with the fixed proportion gradually declining as contracts expire. In the near-term, approximately 70% of our North American gas requirements are contracted at fixed prices. We purchase our remaining North American gas requirements through the spot market.

Our production facilities are well located to supply global methanol markets. 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.

We maintain a focus on operational excellence in all aspects of our business. This includes excellence in manufacturing and supply chain processes, marketing and sales, Responsible Care and financial management.

To differentiate ourselves from competitors, we strive to be the best operator and the preferred supplier to customers. We believe that reliability of supply is critical to the success of our customers’ businesses and our goal is to deliver methanol reliably and cost-effectively. Our commitment to Responsible Care drives our commitment to adhere 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, logistics providers and industry associations for methanol and methanol applications through active participation in local and international industry associations, seminars and conferences and online education initiatives.

In 2020, our strategy of operational excellence in financial management focused on the liquidity and financial flexibility of the Company to withstand the economic uncertainty accompanying COVID-19 including a challenging methanol price environment. As at December 31, 2020, we had strong liquidity with over $800 million in cash and a $300 million undrawn credit facility, with no bonds due until end of 2024. 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. We have maintained healthy financial capacity and ensured flexibility to navigate the current environment and emerge stronger over the cycle as conditions improve.

The following table details the annual operating capacity and actual production at our facilities in 2020 and 2019:

In New Zealand, we produced 1.7 million tonnes of methanol in 2020 compared with 1.9 million tonnes in 2019. Production for 2020 was lower than 2019 due to lower gas deliveries.

Leading into 2021, our outlook for New Zealand production is uncertain as our gas suppliers have recently advised that a major offshore gas field which supplies the New Zealand market and underpins a portion of our production, has experienced significant and unexpected production declines, which will result in lower gas deliveries. Given that gas deliveries are expected to be lower in 2021, we are consolidating production at our two larger Motunui plants, which have a combined operating capacity of 1.7 million tonnes, and indefinitely idling our smaller Waitara Valley plant. We estimate production in 2021 of 1.5 to 1.6 million tonnes compared to our production of 1.7 million tonnes in 2020. Refer to the Risk Factors and Risk Management – New Zealand section on page 28 for more information.

Geismar produced 2.0 million tonnes of methanol in 2020 compared with 1.9 million tonnes in 2019. Production at the Geismar site was higher for 2020 compared with 2019 primarily due to the 2019 planned turnaround at Geismar 1. Additionally, Geismar produced at high operating rates throughout 2020, with Geismar 1 realizing the benefits of the debottlenecking project completed in late 2020. Refer to the Risk Factors and Risk Management – United States section on page 29 for more information.

Our ownership interest in the methanol facilities in Trinidad represents 2.0 million tonnes of annual operating capacity. The Trinidad facilities produced 1.0 million tonnes of methanol (Methanex share) in 2020 compared with 1.7 million tonnes in 2019. Production in Trinidad was lower in 2020 as we idled the Titan plant effective March 16, 2020 in response to the reduction in global manufacturing activity and methanol demand resulting from the global pandemic. In January 2021, we announced that we expect Titan will remain idled indefinitely as we have not been successful in reaching an agreement for a commercially acceptable longer-term natural gas supply agreement.

Based on current gas deliveries, we estimate Trinidad production in 2021 of approximately 1.1 million tonnes (Methanex share) compared to our production of 1.0 million tonnes (Methanex share) in 2020. All 2021 production is expected to come from the Atlas facility. Refer to the Risk Factors and Risk Management – Trinidad section on page 29 for more information.

The Chile facilities produced 0.8 million tonnes of methanol in 2020 compared to 1.1 million tonnes in 2019. Production decreased in 2020 as compared to 2019 as we idled the Chile IV plant effective April 1, 2020 in response to the reduction in manufacturing activity

and methanol demand resulting from the global pandemic, and then due to lower gas deliveries resulting from upstream production declines in Argentina in the fourth quarter. Our Chile IV plant remains idle today and it is uncertain how long these lower gas deliveries will persist. We estimate production in 2021 of 0.9 to 1.0 million tonnes. Refer to the Risk Factors and Risk Management - Chile section on page 29 for more information.

We operate the 1.3 million tonne per year methanol facility in Egypt, that we have a 50% economic interest in, and have marketing rights for 100% of the production. We produced 1.2 million tonnes of methanol (Methanex share of 0.6 million) at the plant during 2020, compared to 0.8 million tonnes (Methanex share of 0.4 million) in 2019. Production for 2020 was higher compared to 2019 as the Egypt facility operated at high rates throughout 2020 as compared to 2019, when the facility experienced an outage in April 2019 and remained offline until August 2019 for inspections and repair work. Refer to the Risk Factors and Risk Management – Egypt section on page 30 for more information.

Medicine Hat produced 0.5 million tonnes of methanol in 2020 compared with 0.6 million tonnes in 2019. Production at Medicine Hat was lower for 2020 compared to 2019 as we completed a planned turnaround in 2020. Refer to the Risk Factors and Risk Management – Canada section on page 30 for more information.

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 expenses, and income taxes.

The Company has used the terms Adjusted EBITDA, Adjusted net income (loss), Adjusted net income (loss) per common share, Adjusted revenue and Operating income (loss) throughout this document. These items are non-GAAP measures that do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Refer to the Supplemental Non-GAAP Measures section on page 40 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:

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

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

For the year ended December 31, 2020, we reported a net loss attributable to Methanex shareholders of $157 million ($2.06 loss per common share on a diluted basis), compared with net income attributable to Methanex shareholders of $88 million ($1.01 income per common share on a diluted basis) for the year ended December 31, 2019.

For the year ended December 31, 2020, we reported Adjusted EBITDA of $346 million and Adjusted net loss of $123 million ($1.62 Adjusted net loss per common share), compared with Adjusted EBITDA of $566 million and Adjusted net income of $71 million ($0.93 Adjusted net income per common share) for the year ended December 31, 2019.

We calculate Adjusted EBITDA and Adjusted net income (loss) by including amounts related to our equity share of the Atlas facility (63.1% interest) and by excluding the non-controlling interests’ share, the mark-to-market impact of share-based compensation as a result of changes in our share price and the impact of certain items associated with specific identified events. For 2019 and 2020, there have been no specifically identified events impacting Adjusted EBITDA or Adjusted net income (loss).

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

A summary of our consolidated statements of income (loss) for 2020 and 2019 is as follows:

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 $2.7 billion in 2020 compared to $3.3 billion in 2019. The lower revenue reflects a lower average realized price in 2020 compared to 2019.

We publish regional non-discounted reference prices for each major methanol market and these posted prices are reviewed and revised monthly or quarterly based on industry fundamentals and market conditions. Most of our customer contracts use published Methanex reference prices as a basis for pricing, and we offer discounts to customers based on various factors. Our average non-discounted published reference price in 2020 was $297 per tonne compared with $353 per tonne in 2019. Our average realized price in 2020 was $247 per tonne compared to $295 per tonne in 2019.

The geographic distribution of revenue by customer location for 2020 was comparable to 2019 . Details are as follows:

2020 Adjusted EBITDA was $346 million compared with 2019 Adjusted EBITDA of $566 million, a decrease of $220 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).

Our average realized price for the year ended December 31, 2020 was $247 per tonne compared to $295 per tonne for 2019, and this decreased Adjusted EBITDA by $468 million (refer to the Financial Results – Revenue section on page 14 for more information).

Methanol sales volume, excluding commission sales volume, for the year ended December 31, 2020 decreased by 0.4 million tonnes to 9.7 million tonnes from 10.1 million tonnes in 2019, and this decreased Adjusted EBITDA by $28 million. Including commission sales volume from the Atlas and Egypt facilities, our total methanol sales volume was 10.7 million tonnes in 2020 compared with 11.1 million tonnes in 2019. Sales volume was lower for 2020 compared to 2019 primarily due to the impact of COVID-19 on methanol demand globally.

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

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

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

The changes in Adjusted EBITDA due to changes in total cash costs for 2020 compared with 2019 were due to the following:

Natural gas is the primary feedstock at our methanol facilities and is the most significant component of Methanex-produced methanol costs. We purchase natural gas for more than half of our production under natural gas purchase agreements where the unique terms of each contract include a base price and a variable price component linked to methanol revenue 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. This contract structure significantly reduced our costs in 2020 in line with lower methanol pricing. Methanex-produced methanol costs were lower in 2020 compared with 2019 by $225 million, primarily due to the impact of lower realized methanol prices on the variable portion of our natural gas costs, changes in spot gas prices 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 23.

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 2020 due to lower production and this increased costs and decreased Adjusted EBITDA by $58 million for 2020 compared with 2019.

A key element of our corporate strategy is global leadership and, as such, we have built a leading market position in each of the major global markets where methanol is sold. We supplement our production with purchased methanol through methanol offtake contracts and on the spot market to meet customer needs and support our marketing efforts within the major global markets. In structuring purchase agreements, we look for opportunities that provide synergies with our existing supply chain that allow us to purchase methanol in the most cost effective region. The cost of purchased methanol consists principally of the cost of the methanol itself, which is directly related to the price of methanol at the time of purchase, and is also driven by the volume of methanol purchased. Lower methanol prices in 2020 and the timing of inventory flows and purchases, partially offset by the increase in purchased methanol volume, decreased the cost of purchased methanol per tonne and this increased Adjusted EBITDA by $136 million compared with 2019.

Our investment in global distribution and supply infrastructure includes a dedicated fleet of ocean-going vessels. We utilize these vessels to enhance value to customers by providing reliable and secure supply and to optimize supply chain costs overall, including through third-party backhaul arrangements when available. Logistics costs can also vary from period to period depending on the levels of production from each of our production facilities and the resulting impact on our supply chain. Logistics costs in 2020 were $3 million higher than in 2019, decreasing Adjusted EBITDA. Logistics costs were marginally higher due primarily to slightly lower backhaul recoveries.

We experienced an outage at the Egypt plant from April to August 2019. In 2019, we recorded a $50 million (Methanex share - $25 million) insurance recovery which partially offsets repair costs charged to earnings and lost margins. We recorded an additional $10 million (Methanex share - $5 million) for final settlement in 2020, the difference resulting in a decrease in Adjusted EBITDA for 2020 compared to 2019.

Other, net relates to unabsorbed fixed costs, selling, general and administrative expenses and other operational items. For the year ended December 31, 2020 compared with the same period in 2019, other costs were higher by $4 million on a net basis, as lower selling, general, and administrative expenses were offset by higher unabsorbed costs primarily at idled plants.

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

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 prior to 2018 have an additional feature where the ultimate number of units that vest will be determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting.

Performance share units granted in 2019 onwards reflect a new 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 (the market performance factor), and (ii) three year average Return on Capital Employed (the non-market performance factor). The market performance factor is measured by the Company at the grant date and each reporting date using a Monte-Carlo simulation model to determine fair value. The non-market 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 increased from $38.63 per share at December 31, 2019 to $46.08 per share at December 31, 2020. As a result of the increase in the share price and the resulting impact on the fair value of the outstanding units, we recorded an $39 million mark-to-market expense related to share-based compensation during 2020.

Depreciation and amortization was $357 million for the year ended December 31, 2020 compared with $344 million for the year ended December, 31 2019. The increase in depreciation and amortization in 2020 compared with 2019 was primarily due to less depreciation in ending inventory at December 31, 2020 and higher vessel lease depreciation.

Finance costs are primarily comprised of interest on borrowings and lease obligations and were $165 million for the year ended December 31, 2020 compared to $124 million for the year ended December 31, 2019. Finance costs are higher due to a one time make-whole interest charge triggered by the early redemption of bonds originally due in 2022 and increased borrowings outstanding during 2020. The Company increased borrowings, including drawing and repaying its revolving credit facility within the year, primarily as a precautionary measure to increase liquidity in light of the uncertainty associated with the impacts of COVID-19. Capitalized interest relates to interest costs capitalized for the Geismar 3 project. Refer to the Liquidity and Capital Resources section of page 19 for more information.

Finance income and other expenses was negligible for the year ended December 31, 2020 compared to a gain of $4 million December 31, 2019. Finance income and other expenses is primarily related to the impact of changes in foreign exchange rates, changes in interest earned on cash balances and well as immaterial disposals of assets.

We earn the majority of our income in New Zealand, Trinidad, the United States, Egypt, Canada and Chile. The statutory tax rates in Chile and Egypt increased in 2020 to 44.5% and 30%, respectively as a result of increases to the applicable withholding tax rate on foreign distributions. In Trinidad the statutory tax rate is 35%. The statutory tax rate in New Zealand is 28%. In Canada, the statutory tax rate applicable to Methanex is 25.6% and the United States statutory tax rate applicable to Methanex is 23%. We accrue for taxes that will be incurred upon distributions from 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 (loss).

The effective tax rate related to Adjusted net loss was a 27% tax recovery for the year ended December 31, 2020 compared with a 30% tax expense on an Adjusted net income for the year ended December 31, 2019. Adjusted net income (loss) represents the amount that is attributable to Methanex shareholders and excludes the mark-to-market impact of share-based compensation and the impact of certain items associated with specific identified events. The effective tax rate differs from period to period depending on the source of earnings (losses) and the impact of foreign exchange fluctuations against the United States dollar on our tax balances. In periods with low income levels or losses, the distribution of income and loss between jurisdictions can result in income tax rates that are not indicative of the longer term corporate tax rate. In addition, the effective tax rate is impacted by changes in tax legislation in the jurisdictions in which we operate. The 2020 effective tax rate was lower than the 2019 effective tax rate primarily due to the re-measurement of deferred tax liabilities as a result of the statutory tax rate changes in Chile and Egypt applicable for 2020.

For additional information regarding income taxes, refer to note 16 of our 2020 consolidated financial statements.

Cash flows from operating activities for the year ended December 31, 2020 were $461 million compared with $515 million for the year ended December 31, 2019. The decrease in cash flows from operating activities is primarily due to lower earnings partially offset by changes in non-cash working capital.

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

Changes in non-cash working capital increased cash flows from operating activities by $65 million for the year ended December 31, 2020, compared with an increase of $9 million for the year ended December 31, 2019. Trade and other receivables decreased in 2020 and this increased cash flows from operating activities by $75 million, primarily due to the collection of the non-recurring insurance recovery receivable for our Egypt outage during 2020. Inventories increased primarily due to the impact of a higher proportion of purchased methanol volume compared to Methanex-produced methanol volume held at the end of 2020 compared to 2019, which decreased cash flows from operating activities by $35 million. Accounts payable and accrued liabilities increased in 2020 compared to 2019 due to the impact of higher methanol prices on purchased methanol in the fourth quarter of 2020 compared to the fourth quarter of 2019, which increased cash flows from operating activities by $24 million.

In April 2020 to preserve liquidity in response to the uncertainty from COVID-19, we reduced the dividend by 90% to $0.0375 per common share per quarter from $0.36 per common share per quarter. Total dividend payments in 2020 were $36 million compared with $108 million in 2019. Total interest payments in 2020 were $165 million compared with $115 million in 2019. The increase in interest payments in 2020 compared to 2019 was primarily due higher borrowing levels and a make-whole interest charge of $15 million in the third quarter of 2020 for the early redemption of the $250 million unsecured notes originally due March 2022.

In 2020, the Company issued $700 million of senior unsecured notes bearing a coupon of 5.125%, due October 15, 2027 to increase our cash position in the uncertain environment and enhance financial flexibility. The Company used the proceeds from the newly issued bond to repay our $250 million bond originally due in March 2022. The Company has no debt maturities until December 2024, other than normal course obligations for principal repayments related to our Egypt and other limited recourse debt facilities. Additionally, the Company drew $173 million from the $800 million construction credit facility for the Geismar 3 project and drew and repaid from the revolving credit facility in the year.

The Company also repaid debt of $30 million relating to our limited recourse Egypt debt facility and $10 million relating to other limited recourse debt facilities for ocean vessels. During the year, the Company also entered into and drew on a new vessel construction facility for $13 million.

Distributions to non-controlling interests including the 50% ownership of the Egypt entity and the 50% ownership in multiple ocean going vessels not attributable to Methanex were $35 million in 2020 compared to $24 million in 2019.

During 2020, we incurred capital expenditures relating to our consolidated operations of $129 million (2019 - $208 million) primarily related to planned turnarounds in Atlas and Medicine Hat, the debottleneck project at Geismar, and ongoing construction of one ocean going vessel. In addition, we incurred capital expenditures of $213 million (2019 - $115 million) related to the construction of the Geismar 3 project.

Our objective in 2020 in managing liquidity and capital was to provide financial capacity and flexibility to meet our strategic objectives, with a focus on cash preservation and liquidity.

The following table provides information on our liquidity and capitalization position as at December 31, 2020 and December 31, 2019:

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. The strategies we have employed include the issue or repayment of general corporate debt, the issue of project debt, the payment of dividends and the repurchase of shares.

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

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, 2020, we had a cash balance of $834 million, including $77 million of cash related to our Egypt entity consolidated on a 100% basis and $8 million of cash related to our joint venture interests in ocean going vessels 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, 2020, our revolving credit facility is undrawn and we have $627 million remaining undrawn from our $800 million non-revolving construction credit facility for the Geismar 3 project. During 2020 we have secured additional financial flexibility by negotiating covenant relief and amending the terms of the revolving credit facility and non-revolving construction facility. Both facilities are with a syndicate of highly rated financial institutions and expire in July 2024.

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

The credit facilities also include other customary covenants including restrictions on the incurrence of additional indebtedness, with specific restrictions against the sale or abandonment of the Geismar 3 project, as well as requirements associated with completion of plant construction and commissioning.

During the year ended December 31, 2020, the Company amended the terms of the committed revolving credit facility and the non-revolving construction facility for the Geismar 3 project, with the lenders agreeing to modify and waive certain covenants. As part of the amendments, the debt to capitalization ratio has been increased to 60% for all the measurement periods starting on June 30, 2020 and ending on June 30, 2023. Additionally, the minimum interest coverage ratio threshold was lowered or waived for each of the measurement periods starting June 30, 2020 and ending on December 31, 2021. The impact on the remaining periods for which the waivers apply is as follows:

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

The Egypt limited recourse debt facilities have covenants and default provisions that apply only to the Egypt entity, including restrictions on the incurrence of additional indebtedness and a requirement to fulfill certain conditions before the payment of cash or other shareholder distributions. Namely, shareholder distributions are not permitted unless the average gas deliveries over the prior 12 months are greater than 70% of gas nominations.

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, 2020, management believes the Company was in compliance with all significant terms and default provisions related to its long-term debt obligations.

The Geismar 3 project is a 1.8 million tonne methanol plant budgeted for $1.3 to $1.4 billion, under construction in Geismar, Louisiana adjacent to our Geismar 1 and Geismar 2 plants with significant capital and operating cost advantages. In April 2020, we announced the deferral of approximately $500 million of the planned capital budget for the Geismar 3 project for up to 18 months,

and put the project on temporary care and maintenance in response to the uncertainty in the global economy from the COVID-19 pandemic. At the time the deferral was announced, the project was in excellent shape and progress had been safe, on time and on budget and the project had been significantly de-risked. As at December 31, 2020, the project remains on temporary care and maintenance. We anticipate investing approximately $80 million over the next 9 months on costs that were already committed, completing activities that preserve flexibility to complete the project in the future including key engineering activities and procurement of critical path equipment. We have a robust decision making process and before deciding whether to restart construction, management and our Board will need to carefully consider many factors including the strength of the global economic recovery and methanol industry outlook. Our preference is to have a strategic partner for the project. To date, we have invested $365 million at Geismar 3, excluding capitalized interest of $22 million.

Our planned operational capital expenditures directed towards maintenance, turnarounds, and catalyst changes, including our 63.1% share of Atlas and 50% of Egypt, are currently estimated to be approximately $110 million for 2021.

A summary of the amount and estimated timing of cash flows related to our contractual obligations and minimum commercial commitments as at December 31, 2020 is as follows:

We have $300 million of unsecured notes that mature in 2024, $700 million of unsecured notes that mature in 2027, $700 million of unsecured notes that mature in 2029, and $300 million of unsecured notes that mature in 2044. We have drawn $173 million on the $800 million Geismar 3 specific construction facility due in 2024. The remaining debt repayments represent the normal course obligations for principal repayments related to our limited recourse debt facilities. Interest obligations related to variable interest rate long-term debt were estimated using current interest rates in effect as at December 31, 2020. For additional information, refer to note 8 of our 2020 consolidated financial statements.

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

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

We have commitments under take-or-pay contracts to purchase natural gas, to pay for transportation capacity related to the delivery of natural gas and to purchase oxygen and other feedstock requirements for our operating plants and Geismar 3 project. Take-or-pay means that we are obliged to pay for the supplies regardless of whether we take delivery. Such commitments are common in the methanol industry. These contracts generally provide a quantity that is subject to take-or-pay terms that is lower than the maximum quantity that we are entitled to purchase. The amounts disclosed in the table above represent only the minimum take-or-pay quantity.

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

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

We have marketing rights for 100% of the production from our jointly owned Atlas and Egypt plants which results in purchase commitments of up to an additional 1.2 million tonnes per year of methanol offtake supply when these plants operate at capacity. As at December 31, 2020, the Company also had commitments to purchase methanol from other suppliers for approximately 1.2 million tonnes for 2021 and 1.1 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, as these expenditures may change, or any obligations with original maturities of less than one year.

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 2020 consolidated financial statements.

As at December 31, 2020, 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.

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.

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

The following table shows the carrying value of each of our categories of financial assets and liabilities and the related balance sheet items as at December 31, 2020 and December 31, 2019:

As at December 31, 2020, 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. 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 separately 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. Settled foreign currency hedges, are realized during the period directly to the statement of income reclassified from the statement of other comprehensive income.

The Company has derivative instruments designated as cash flow hedges for Geismar and Medicine Hat to manage its exposure to changes in natural gas prices for its highly probable forecast natural gas purchases in North America.

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

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 37, to be among the most important for understanding the issues that face our business and our approach to risk management.

In the first half of 2020, we saw a substantial reduction in global manufacturing and general economic activity due to COVID-19. As a result, we experienced lower demand and prices for methanol through a substantial part of 2020. The global response to the pandemic increased economic activity later in the year with methanol demand and prices recovering to some degree, despite a continuing pandemic.

Uncertainty remains with respect to the potential future impact of COVID-19, including the emergence of variants of the virus, and future viral outbreaks or pandemics on the global economy and our business. The magnitude of the impact will depend on future developments which 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.

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 a number of 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 a number of 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.

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. In addition, increasing public 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 changes in methanol demand will not negatively impact methanol demand growth, which could have an adverse effect on our results of operations and financial condition.

Demand for energy-related applications, which represents just under 50% of global methanol demand, includes a number of applications including methanol-to-olefins (“MTO”), methyl tertiary-butyl ether (“MTBE”), fuel applications (including vehicle fuel, marine fuel and as a fuel for industrial boilers and kilns), di-methyl ether (“DME”) and biodiesel.

Methanol demand growth for these applications has been led, in part, by the cost of methanol relative to the price of other feedstock including oil and derivative products.

Methanol is an alternative feedstock for the production of light olefins in the methanol-to-olefins application and in 2020, methanol demand for MTO represented approximately 18% of global demand. MTO competes with olefins made from ethane, propane and naptha which are natural gas and oil based feedstocks. The price of methanol relative to the price of ethane, propane and naptha can impact the competitiveness of methanol in this application. The price of olefins and downstream derivative products are also affected by their supply and demand. In a low olefin and/or downstream derivative 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 (a methanol derivative) 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.

Traditional chemical demand, which represents over 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. 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.

Changes in environmental, health and safety laws, regulations or requirements in any country where methanol is produced or consumed could impact methanol demand.

Above certain inhalation and ingestion levels, methanol is toxic to humans. The United States Environmental Protection Agency (“EPA”) issued a draft assessment for methanol in 2010 classifying methanol as likely to be carcinogenic to humans. A final non-cancer assessment released by the EPA in 2013 established the maximum ingestion and inhalation levels for methanol that it claims will not result in adverse health impacts. We are unable to determine whether the current draft classification relating to the carcinogenicity of methanol will be maintained in the final cancer assessment or if this will lead other government agencies to 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 – Formaldehyde and Other Methanol Derived Products

In 2020, methanol demand for the production of formaldehyde represented approximately 26% of global methanol demand and is the largest demand segment. The largest use for formaldehyde is as a component of urea-formaldehyde and phenol-formaldehyde resins, which are used in adhesives for plywood, particleboard, oriented strand board, medium-density fibreboard and other reconstituted or engineered wood products. There is also demand for formaldehyde as a raw material for engineering plastics and in the manufacture of a variety of other products, including elastomers, paints, building products, foams, polyurethane and automotive products.

Formaldehyde is classified as a known human carcinogen by the EPA, and as carcinogenic to humans by the World Health Organization. The EPA classifies a substance in this manner when there is sufficient evidence of carcinogenicity from studies in humans, which indicates a causal relationship between exposure to the agent, substance, or mixture, and human cancer. In 2019, formaldehyde was selected as one of twenty priority chemicals for review under the Toxic Substances Control Act of the EPA with an anticipated final risk evaluation date of December 2022. We are unable to determine whether the current classification or future reclassifications of formaldehyde could impose limits or restrictions related to formaldehyde in the United States or elsewhere. Any such actions could reduce future methanol demand for use in producing formaldehyde, which could have an adverse effect on our results of operations and financial condition.

Further, any government regulation or policy relating to any other methanol derived product could also reduce future methanol demand for that product, which could have an adverse effect on our results of operations and financial condition.

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

The industry has historically operated below stated capacity on a consistent basis, even in periods of high methanol prices, due primarily to shutdowns for planned and unplanned repairs and maintenance as well as shortages of feedstock and other production inputs. 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, by carrying out expansions of existing plants or by debottlenecking existing plants to increase their operating capacity. There is typically a span of four to six years to plan and construct a new world-scale methanol plant.

Typical of most commodity chemicals, periods of high methanol prices encourage high-cost producers to operate at maximum rates and also encourage the construction of new plants and expansion projects, leading to the possibility of oversupply in the market.

However, historically, many of the announced capacity additions have not been constructed for a variety of reasons. There are significant barriers to entry in this industry. The construction of world-scale methanol facilities requires significant capital over a long lead time, a location with access to significant natural gas or coal feedstock with appropriate pricing, and an ability to cost-effectively and reliably deliver methanol to customers.

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.

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

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

We have entered into several agreements with various natural gas suppliers with terms that range in length up to 2029. All gas supply agreements in New Zealand are take-or-pay agreements and include U.S. dollar base and variable price components where the variable price component is adjusted by a formula linked to methanol prices above a certain level. We believe this pricing relationship enables these facilities to be competitive at all points in the methanol price cycle. Certain contracts require the supplier to deliver a minimum amount of natural gas with additional volume dependent on the success of exploring and developing the related natural gas field.

We continue to pursue opportunities to contract additional natural gas to supply our plants in New Zealand, including gas to underpin the restart of the currently idled Waitara Valley plant.

The future operation of our New Zealand facilities, including the restart of the currently idled Waitara Valley plant, 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 or with the optimal CO₂ composition. These factors could have an adverse impact on our results of operations and financial condition.

We have two plants in Geismar, Louisiana with an annual operating capacity of 2.0 million tonnes. Late in 2020, Geismar 1 completed a debottlenecking project that will increase its annual operating capacity by 10% or 100,000 tonnes. A similar debottlenecking project is planned for Geismar 2 for 2021. The Geismar 3 project is currently on care and maintenance.

We have several fixed price hedges and fixed price physical supply agreements to manage natural gas price risk for our Geismar facilities. We currently have hedges and fixed price supply agreements for approximately 70% of all natural gas requirements on average for the Geismar facilities for 2021 to 2023 and a declining percentage at fixed prices continuing to 2032. The balance of our gas requirements are purchased under contracts 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.

We have two plants in Trinidad, Atlas (Methanex interest 63.1%) and Titan, with Methanex’s interest in Trinidad representing an operating capacity of 2.0 million tonnes per year. Natural gas for our Atlas methanol production facility in Trinidad, with our share of total production capacity being 1.1 million tonnes per year, is supplied under a take-or-pay contract with the National Gas Company of Trinidad and Tobago Limited (“NGC”), which purchases the natural gas from upstream gas producers. Gas paid for, but not taken, in any year may be received in subsequent years subject to certain limitations. The contract for Atlas has a U.S. dollar base and variable price components, where the variable portion is adjusted by a formula linked to methanol prices above a certain level and expires in 2024.

Large industrial consumers in Trinidad, including our Titan and Atlas facilities, have at times, experienced curtailments of natural gas supply due to a mismatch between upstream supply to NGC and downstream demand from NGC’s customers. The long-term gas contract for Titan with the NGC expired at the end of 2019 and we entered into a series of short-term gas contracts with NGC for the period starting January 1, 2020 before the plant was idled indefinitely from March 16, 2020. Early in 2021, we announced the decision to restructure our operations in Trinidad to support a one-plant (Atlas) operation, reducing our Trinidad workforce as we have been unable to secure a commercially acceptable longer-term natural gas agreement with the NGC.

While we believe the supply and demand fundamentals for natural gas in Trinidad will support the future operations at Atlas and the restart and future operations of Titan, 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 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.

Natural gas for our two plants in Chile is supplied by various producers in Chile and Argentina. A portion of the contracted gas is subject to deliver-or-pay and take-or-pay provisions. Our current gas agreements and export permits provide for sufficient gas to allow for a two-plant operation in Chile during the southern hemisphere summer months and up to a maximum of 75% of a two-plant operation on an annual basis, or annual production of up to 1.3 million tonnes.

In 2020, the Chile IV plant was idled effective April 1, 2020 in response to the reduction in manufacturing activity and methanol demand resulting from the COVID-19 pandemic. Following a brief restart in the fourth quarter, Chile IV was again idled due to lower gas deliveries resulting from upstream production declines in Argentina. Our Chile IV plant remains idle and it is uncertain how long these lower gas deliveries will persist.

The price paid for natural gas is a mix of both fixed price and 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. Our primary Chilean natural gas supplier is Empresa Nacional del Petróleo (“ENAP”). ENAP has made significant investments over the past several years in the development of natural gas from unconventional reservoirs which has resulted in increased gas deliveries from ENAP to our facilities. The agreements for natural gas supply with ENAP underpin approximately 25% of the 1.7 million tonnes of annual operating capacity for 2021 through 2025.

In 2020, we received natural gas from Argentina from four different natural gas suppliers pursuant to interruptible supply agreements. These agreements expire at the end of 2021. We also received Argentine natural gas in 2020 from a fifth supplier, YPF S.A.. We have a gas supply agreement with YPF S.A. that expires at the end of 2025.

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.

We have a 25-year, take-or-pay natural gas supply agreement expiring in 2036 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. Gas paid for, but not taken, in any year may be received in subsequent years subject to limitations. In addition, the natural gas supply agreement has a mechanism whereby we are partially compensated when gas delivery shortfalls in excess of a certain threshold occur. Natural gas is supplied to this facility from the same gas delivery grid infrastructure that supplies other industrial users in Egypt, as well as the general Egyptian population.

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. The restrictions experienced in past years may occur in the future. We cannot provide assurance that our contracted supplier will be able to meet its commitments or that exploration and development activities in Egypt will be successful to enable us to operate at capacity or at all. These factors could have an adverse impact on our results of operations and financial condition.

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 are 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.

Our ability to effectively allocate capital, including successfully identifying, developing and completing capital projects is subject to a number of risks, including finding and selecting favourable locations for new facilities where sufficient natural gas and other feedstock is available with acceptable commercial terms, obtaining project or other financing on satisfactory terms, constructing and completing the projects within the contemplated budgets and schedules and other risks commonly associated with the design, construction and start-up of large complex industrial projects.

In addition, the COVID-19 pandemic or other similar events could impact our ability to access necessary parts and equipment in a timely manner, meet key equipment delivery timelines, obtain permits, complete testing and inspection, and carry out project activities as a result of labour shortages or restrictions. These factors could result in schedule delays and cost escalation in completing capital projects.

Our Geismar 3 Project remains on temporary care and maintenance, and the Company has not made a decision whether to restart construction on the project. The Geismar 3 Project is subject to the capital project risks described above.

We are subject to potential risks associated with further deferral of the Geismar 3 project, beyond the original 18-month temporary care and maintenance period, including our ability to obtain permits, carry out project activities as a result of labour shortages or loss of personnel, renegotiate supply agreements with commercially acceptable terms and obtain project or other financing on satisfactory terms. These factors could result in schedule delays and cost escalation in completing the Geismar 3 project.

We are subject to potential risks associated with cancellation of the project including additional costs related to committed take-or-pay obligations, wind-down and exit costs.

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

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 increase the risk of defaults by customers, suppliers, insurers and other counterparties. Considering these potential impacts, we cannot provide assurance that a deterioration in economic conditions will not have an adverse impact on our results of operations and financial condition.

Our operations and investments are primarily located in North America, New Zealand, Trinidad, 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, 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 geo-political disputes between countries in which we operate and 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.

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

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

Methanol is a globally traded commodity produced at facilities located around the world. Trade in methanol is subject to duty in a number of jurisdictions. Methanol sold in certain markets from the countries in which we produce methanol is currently subject to import duties ranging from 0% to 5.5%. As well, there is currently an additional 25% tariff on methanol imported from the US to China and from China to the US. Over the past number of years, methanol demand has grown faster in China compared to other markets. This growth has resulted in China currently representing approximately 60% of total methanol demand, which is supplied by both local and imported methanol. This concentration of industry demand creates a risk of market access from any production source as China may increase tariffs, restrict imports or take other measures to prevent or limit the import of methanol from a particular producing country. There can be no assurance that the countries where we produce methanol will continue to have access to all markets, including China, that duties will not increase, that duties will not be levied in other jurisdictions in the future or that we will be able to mitigate the impact of future duties, if levied, or that future duties will not have a significant negative effect.

Some producers and marketers of methanol may have direct or indirect contacts with countries that may, from time to time, be subject to international trade sanctions or other similar prohibitions (“Sanctioned Countries”). Methanol produced in Sanctioned

Countries may sell at a lower price to methanol produced in non-sanctioned countries creating competitive price pressure for the methanol we produce. In addition to the methanol we produce, we purchase methanol from third parties under purchase contracts or on the spot market in order to meet our commitments to customers, and we also engage in product exchanges with other producers and marketers. We believe that we are in compliance with all applicable laws with respect to sales and purchases of methanol and product exchanges. However, as a result of the participation of Sanctioned Countries in our industry, we cannot provide assurance that we will not be exposed to reputational or other risks that could have an adverse impact on our results of operations and financial condition.

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

We have organized our operations in part based on certain assumptions about various tax laws (including capital gains, withholding taxes and transfer pricing), foreign currency exchange and capital repatriation laws and other relevant laws of a variety of foreign jurisdictions. While we believe that such assumptions are reasonable, we cannot provide assurance that foreign taxation or other authorities will reach the same conclusion. The results of audit of prior tax filings and the final determination of these events may have a material impact on the Company. Refer to Litigation Risk and Legal Proceedings on page 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.

As at December 31, 2020, we had a cash balance of $834 million an undrawn $300 million revolving credit facility, and $627 million undrawn on the non-revolving construction credit facility specifically related to the Geismar 3 project. Both credit facilities are with a syndicate of highly rated financial institutions and expire in July 2024. Our ability to maintain access to each facility is subject to meeting certain financial covenants, including an EBITDA to interest coverage ratio and a debt to capitalization ratio, both ratios calculated in accordance with definitions in the credit agreement that include adjustments related to the Company’s limited recourse subsidiaries.

As at December 31, 2020, our long-term debt obligations include $1,979 million in unsecured notes, $161 million related to other limited recourse debt for ocean going vessels (100% basis) and $47 million related to the Egypt limited recourse debt facilities (100% basis).

The covenants governing the unsecured notes, which are specified in an indenture, apply to the Company and its subsidiaries, excluding the Egypt entity, and include restrictions on liens, sale and lease-back transactions, a merger or consolidation with another corporation or a sale of all or substantially all of the Company’s assets. The indenture also contains customary default provisions. The Egypt limited recourse debt facilities are described as limited recourse as they are secured only by the assets of the Egypt entity. Accordingly, the lenders to the limited recourse debt facilities have no recourse to the Company or its other subsidiaries. The Egypt limited recourse debt facilities have covenants and default provisions that apply only to the Egypt entity, including restrictions on the incurrence of additional indebtedness and a requirement to fulfill certain conditions before the payment of cash or other distributions.

For additional information regarding long-term debt, refer to note 8 of our 2020 consolidated financial statements.

We cannot provide assurance that we will be able to access new financing in the future on commercially acceptable terms or at all, or that the financial institutions providing the credit 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.

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

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.

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

Many of our methanol plants have been in operation for multiple decades and with appropriate maintenance they are still capable of operating efficiently and cost effectively today as 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 introduction of new technologies for methanol production, including those that reduce the CO₂ emissions intensity of methanol production, may make our plants less cost competitive or obsolete over time. In addition, regulatory changes could require Methanex to invest in new technologies to reduce its GHG emissions which 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.

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.

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.

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.

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.

Climate change poses a number of potential risks and impacts to Methanex which 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.

Four of our methanol production sites rely on access to fresh water, converted to steam, in the methanol production process. Our other two sites, Trinidad and Chile, have desalination units. Water shortages at sites without desalination units may have the impact of restricting methanol production.

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 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 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.

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.

Methanex generates GHG emissions directly and indirectly through the production, distribution and use of its products. Carbon dioxide (“CO₂”) is a by-product of the development and extraction of hydrocarbons including natural gas used as a feedstock in methanol production. CO₂ is also a by-product of the methanol production process. The amount of CO₂generated by the methanol production process depends on the production technology, plant age, feedstock, operating rate of the plant and any export of the by-product hydrogen. CO₂ emissions are also generated from our marine operations when fuel is consumed during the global transport of methanol. We monitor and manage our CO₂ emissions intensity, defined as the quantity of CO₂ released per unit of production or transported tonne, relating to both methanol production and marine operations. Our CO₂ emissions intensity has decreased over time due to newer technology and higher efficiency at our plants and in our vessel fleet. Plant efficiency, and thus CO₂ emissions, is highly dependent on the design of the methanol plant and availability of natural gas among other factors, and accordingly the CO₂ emission figure may vary from year to year depending on the mix of production assets and vessels in operation.

Public attitudes around climate change and the transition to a lower-carbon economy are changing. As a result, 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 greenhouse gas (“GHG”) emissions, and/or impose carbon taxes. We are currently subject to GHG regulations in New Zealand, Canada and Chile, while our production in the United States, Trinidad 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, 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.

There are ongoing reviews and potential changes to government GHG regulations in New Zealand, Canada and Chile.

In New Zealand, an Emissions Trading Scheme (“ETS”) imposes a carbon price on producers of fossil fuels, including natural gas, which is passed on to Methanex, increasing the cost of gas that Methanex purchases in New Zealand. However, as a trade exposed company, Methanex is entitled to a free allocation of emissions units to partially offset those increased costs. The amount of free allocation emission units that Methanex is entitled to is expected to gradually decrease over time. We cannot predict the impact of future New Zealand government regulations and initiatives, related to climate change, which could have an adverse impact on our results of operations and financial condition.

Since 2017, Chile has imposed a carbon tax on certain CO₂ emissions. More recent legislation will have the effect of increasing carbon taxes in Chile over the coming years.

In Canada, the Alberta government implemented the Technology Innovation and Emissions Reduction (“TIER”) program in 2020 which provides up to 90% free emission allocations. To the extent Methanex does not have free emission allocations, we must purchase offset credits for an additional cost, or purchase fund credits under the TIER program at a cost of $30/tonne of CO₂ for 2020 and $40/tonne of CO₂ for 2021. The federal Greenhouse Gas Pollution Pricing Act (“GGPPA”) has not been applied in Alberta due to the existence of the provincial TIER program which the federal government has deemed equivalent to the GGPPA. Recent proposals under the GGPPA seek to increase carbon pricing in Canada to $170 per tonne by 2030. If this is implemented, Alberta may increase the costs of fund credits under the TIER program for it to continue to be a compliant carbon-pricing regime. The Alberta government, along with two other provinces, has challenged the federal government’s application of the GGPPA and a decision from the Supreme Court of Canada is expected in 2021. We cannot provide assurance that GHG legislation changes, new legislation, or changes in carbon prices will not have an adverse impact on our results of operations and financial condition.

The US has reentered the Paris Agreement and has announced plans to implement its objectives with respect to GHG emissions reduction. We cannot predict the impact of future US government regulations and initiatives, related to climate change, which could have an adverse impact on our results of operations and financial condition.

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, CO₂, health or safety matters), whether true or not. Many stakeholders are expecting action to address climate change and a 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. 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, obtain 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.

Our business processes rely on Information Technology (“IT”) systems that are interconnected with external networks, which increases the threat of cyber attack and the importance of cyber security. In particular, if a cyber attack was targeted at our production facilities or our supply chain, the result could harm our plants, 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 could have an adverse impact on our results of operations, financial condition and reputation. We have previously been the subject of cyber attacks on our internal systems, but these incidents have not had a significant negative impact on our results of operations.

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

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

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.

The Board of Inland Revenue of Trinidad and Tobago has audited and issued assessments against our 63.1% owned joint venture, Atlas, in respect of the 2005 to 2014 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 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 represent 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 cases and advice from legal counsel, we believe our position should be sustained, that Atlas has filed its tax returns and paid applicable taxes in compliance with Trinidadian tax law, and as such has not accrued for any amounts relating to these assessments. Contingencies inherently involve the exercise of significant judgment, and as such the outcomes of these assessments and the financial impact to the Company could be material.

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

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 28. See note 2 to our 2020 consolidated financial statements for our significant accounting policies.

Our business is capital intensive and has required, and will continue to require, significant investments in property, plant and equipment. As at December 31, 2020, the net book value of our property, plant and equipment was $3.7 billion.

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, 2020, we had accrued $32 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 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 from 10 to 25 years depending on the specific asset component and the production facility to which it is related. The Company determines the estimated useful lives of individual asset components based on the shorter of its physical life or economic life. The physical life of these assets is generally longer than the economic life. The economic life is primarily determined by the nature of the natural gas feedstock available to our various production facilities. 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.

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

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

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

In Trinidad we have indefinitely idled the Titan plant because we have not been successful in securing a commercially acceptable long-term gas supply agreement. This led to the decision to restructure our operations in Trinidad to support a one-plant operation dedicated to the operation of our Atlas plant. As a result, we have identified an impairment indicator in our Titan cash generating unit (“Titan CGU”). The impairment test performed on the Titan CGU resulted in no impairment as the estimated recoverable value, determined on a fair value less costs of disposal methodology, exceeded the carrying value. The estimated recoverable value was based on an operating period for Titan aligned to natural gas reserves estimates in Trinidad with no terminal value, discounted at an after-tax rate of 13%.

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

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

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

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

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

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

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, 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, 2020, we had recognized deferred tax assets of $132 million primarily relating to non-capital loss carryforwards and other temporary differences in the United States. As at December 31, 2020, the Company had $292 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.

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

We have adopted the amendments to IFRS 16, Leases regarding COVID-19 – Related Rent Concessions, which were effective retrospectively for annual periods beginning on or after January 1, 2020. The amendments did not have a material impact on the Company’s consolidated financial statements.

The Company does not expect that any new or amended standards or interpretations that are effective for annual periods beginning on or after January 1, 2021 will have a significant impact on the Company’s results of operations or financial position.

The Company does not expect the implementation of amendments to IAS 16, Property, Plant, and Equipment, regarding the accounting for proceeds before intended use, effective for annual periods beginning on or after January 1, 2022 to have a significant impact on the Company’s results of operations or financial position.

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

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

Adjusted EBITDA differs from the most comparable GAAP measure, net income (loss) attributable to Methanex shareholders, because it excludes finance costs, finance income and other expenses, income tax expense, depreciation and amortization,

mark-to-market impact of share-based compensation and the Argentina gas settlement. Adjusted EBITDA includes an amount representing our 63.1% share of the Atlas facility and excludes the non-controlling shareholders’ interests in entities which we control but do not fully own.

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

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

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

Adjusted revenue differs from the most comparable GAAP measure, revenue, because it excludes our partners’ share of revenue marketed on a commission basis related to 36.9% of the Atlas methanol facility and 50% of the Egypt methanol facility that we do not own. A reconciliation from revenue to Adjusted revenue is as follows:

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

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

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 including the restated revenue and cost of sales and operating expenses is as follows:

A discussion and analysis of our results for the fourth quarter of 2020 is set out in our fourth quarter of 2020 Management’s Discussion and Analysis filed with the Canadian Securities Administrators on SEDAR at www.sedar.com and the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov and is incorporated herein by reference.

Disclosure controls and procedures (as defined in Rules 13a 15(e) and 15d 15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), 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, 2020, 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 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, 2020, 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, 2020. The attestation report is included in our consolidated financial statements on page 49.

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, 2020 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting other than changes resulting from the measures that were implemented during 2020 to remediate the previously identified material weakness, as further described in the Company’s Q3 2020 MD&A filed October 28, 2020.

This 2020 Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements with respect to us and our industry. These statements relate to future events or our future performance. All statements other than statements of historical fact are forward-looking statements. Statements that include the words “believes,” “expects,” “may,” “will,” “should,” “potential,” “estimates,” “anticipates,” “aim”, “goal”, “targets”, “plan”, “predict” or other comparable terminology and similar statements of a future or forward-looking nature identify forward-looking statements.

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

∎

expected demand for methanol and its derivatives,

∎

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

∎

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

∎

expected methanol and energy prices,

∎

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

∎

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

∎

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

∎

our expected capital expenditures,

∎

anticipated operating rates of our plants,

∎

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

∎

expected tax rates or resolutions to tax disputes,

∎

expected cash flows, earnings capability and share price,

∎

availability of committed credit facilities and other financing,

∎

our ability to meet covenants associated with our long-term debt obligations, including, without limitation, the Egypt limited recourse debt facilities that have conditions associated with the payment of cash or other distributions,

∎

our shareholder distribution strategy and anticipated distributions to shareholders,

∎

commercial viability and timing of, or our ability to execute future projects, plant restarts, capacity expansions, plant relocations or other business initiatives or opportunities, including our Geismar 3 Project,

∎

our financial strength and ability to meet future financial commitments,

∎

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

∎

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

∎

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

∎

the potential future impact of the COVID-19 pandemic.

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

∎

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

∎

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

∎

operating rates of our facilities,

∎

receipt or issuance of third-party consents or approvals or governmental approvals related to rights to purchase natural gas,

∎

the establishment of new fuel standards,

∎

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

∎

the availability of committed credit facilities and other financing,

∎

the commercial viability of the Geismar 3 Project and the expected timing and capital cost thereof,

∎

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

∎

absence of a material negative impact from major natural disasters,

∎

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

∎

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

∎

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

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

∎

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

∎

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

∎

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

∎

the ability to carry out corporate initiatives and strategies,

∎

actions of competitors, suppliers and financial institutions,

∎

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

∎

the commercial viability of the Geismar 3 Project and our ability to meet timeline and budget targets for the Geismar 3 Project, including the impact of any cost pressures arising from labour costs,

∎

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,

∎

world-wide economic conditions,

∎

the impacts of the COVID-19 pandemic, and

∎

other risks described in this 2020 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.



42		Quarterly Financial Data (Unaudited)

42		Selected Annual Information

43		Controls and Procedures

44		Forward-Looking Statements


($ Millions, except as noted)	2020			2019

Production (thousands of tonnes) (attributable to Methanex shareholders)		6,614			7,589

Sales volume (thousands of tonnes)

Methanex-produced methanol		6,704			7,611

Purchased methanol		2,994			2,492

Commission sales		1,042			1,031

Total sales volume¹		10,740			11,134

Methanex average non-discounted posted price ($ per tonne)²		297			353

Average realized price ($ per tonne)³		247			295

Revenue		2,650			3,284

Adjusted revenue⁴		2,399			2,988

Net income (loss) (attributable to Methanex shareholders)		(157	)		88

Adjusted net income (loss)⁴		(123	)		71

Adjusted EBITDA⁴		346			566

Cash flows from operating activities		461			515

Basic net income (loss) per common share ($ per share)		(2.06	)		1.15

Diluted net income (loss) per common share ($ per share)		(2.06	)		1.01

Adjusted net income (loss) per common share ($ per share)⁴		(1.62	)		0.93

Common share information (millions of shares)

Weighted average number of common shares		76			77

Diluted weighted average number of common shares		76			77

Number of common shares outstanding, end of year		76			76


(Thousands of tonnes)	Annual operating capacity¹		2020 Production		2019 Production

New Zealand²		2,200		1,672		1,865

USA (Geismar)³		2,000		2,040		1,929

Trinidad (Methanex interest)⁴		2,000		998		1,743

Chile		1,720		836		1,050

Egypt (50% interest)		630		578		392

Canada (Medicine Hat)		600		490		610

		9,150		6,614		7,589


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, including produced and purchased methanol and excluding commission sales volume, plus the difference from period to period in commission revenue.
CASH COSTS		The change in Adjusted EBITDA as a result of changes in cash costs is calculated as the difference from period to period in cash costs per tonne multiplied by the current period total methanol sales volume including produced and purchased methanol and 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.


($ Millions)	2020			2019
Consolidated statements of income (loss):
Revenue	$	2,650		$	3,284
Cost of sales and operating expenses		(2,355	)		(2,800	)
Egypt insurance recovery		10			50
Mark-to-market impact of share-based compensation		39			(18	)
Adjusted EBITDA (attributable to associate)		72			115
Amounts excluded from Adjusted EBITDA attributable to non-controlling interests		(70	)		(65	)
Adjusted EBITDA (attributable to Methanex shareholders)		346			566
Mark-to-market impact of share-based compensation		(39	)		18
Depreciation and amortization		(357	)		(344	)
Finance costs		(165	)		(124	)
Finance income and other expenses		–			4
Income tax recovery (expense)		62			(4	)
Earnings of associate adjustment¹		(42	)		(64	)
Non-controlling interests adjustment¹		38			36
Net income (loss) attributable to Methanex shareholders	$	(157	)	$	88
Net income (loss)	$	(125	)	$	116



6		Overview of the Business

8		Our Strategy

10		Financial Highlights

11		Production Summary

12		How We Analyze Our Business

13		Financial Results

19		Liquidity and Capital Resources



25		Risk Factors and Risk Management

37		Critical Accounting Estimates

40		Adoption of New Accounting Standards

40		Anticipated Changes to International Financial Reporting Standards

40		Supplemental Non-GAAP Measures


($ Millions, except number of shares and per share amounts)	2020			2019
Net income (loss) attributable to Methanex shareholders	$	(157	)	$	88
Mark-to-market impact of share-based compensation, net of tax		34			(17	)
Adjusted net income (loss)	$	(123	)	$	71
Diluted weighted average shares outstanding (millions)		76			77
Adjusted net income (loss) per common share	$	(1.62	)	$	0.93


($ Millions, except where noted)	2020				2019
China	$	828	31	%	$	998	30	%
Europe		489	18	%		635	19	%
United States		419	16	%		582	18	%
South Korea		284	12	%		320	11	%
South America		270	10	%		308	9	%
Canada		118	4	%		145	4	%
Other Asia		242	9	%		296	9	%
	$	2,650	100	%	$	3,284	100	%


($ Millions)	2020 vs. 2019
Average realized price	$	(468	)
Sales volume		(28	)
Total cash costs		276
Decrease in Adjusted EBITDA	$	(220	)


($ Millions)	2020 vs. 2019
Methanex-produced methanol costs	$	225
Proportion of Methanex-produced methanol sales		(58	)
Purchased methanol costs		136
Logistics costs		(3	)
Egypt insurance recovery		(20	)
Other, net		(4	)
Increase in Adjusted EBITDA due to changes in total cash costs	$	276


($ Millions, except share price)	2020		2019
Methanex Corporation share price¹	$	46.08	$	38.63
Grant-date fair value expense included in Adjusted EBITDA and Adjusted net income (loss)		16		14
Mark-to-market impact due to change in share price²		39		(18	)
Total share-based compensation expense (recovery), before tax	$	55	$	(4	)


Four quarters ended	Minimum interest coverage ratio²	Minimum EBITDA^{1 2}
Q4 2020	not applicable	$25 million
Q1 2021	not applicable	$30 million
Q2 2021	not applicable	$70 million
Q3 2021	1.00x	not applicable
Q4 2021	1.25x	not applicable
Q1 2022 & thereafter	2.00x	not applicable


($ Millions)	2021		2022-2023		2024-2025		After 2025		Total
Long-term debt repayments	$	40	$	41	$	499	$	1,805	$	2,385
Long-term debt interest obligations		118		234		209		563		1,124
Lease obligations		142		228		192		420		982
Repayments of other long-term liabilities		40		92		79		144		355
Natural gas and other		398		828		894		1,561		3,681
Other commitments		65		4		1		3		73
	$	803	$	1,427	$	1,874	$	4,496	$	8,600


Key Assumptions		Change Required for Carrying Value to Equal Recoverable Value
Long-term average realized price		3 percent decrease
Production volumes		11 percent decrease
Gas price		7 percent increase
Discount rate (after-tax)		330 basis points increase



	Three months ended
($ Millions, except per share amounts)	Dec 31			Sep 30			Jun 30			Mar 31
2020
Revenue	$	811		$	581		$	512		$	745
Cost of sales and operating expenses		(715	)		(557	)		(484	)		(599	)
Net income (loss) (attributable to Methanex shareholders)		(27	)		(88	)		(65	)		23
Basic net income (loss) per common share		(0.35	)		(1.15	)		(0.85	)		0.30
Diluted net income (loss) per common share		(0.35	)		(1.15	)		(0.85	)		0.21
Adjusted EBITDA		136			40			32			138
Adjusted net income (loss)		12			(79	)		(64	)		8
Adjusted net income (loss) per common share		0.15			(1.03	)		(0.84	)		0.10
2019
Revenue	$	769		$	765		$	847		$	902
Cost of sales and operating expenses		664			696			689			751
Net income (loss) (attributable to Methanex shareholders)		9			(10	)		50			38
Basic net income (loss) per common share		0.12			(0.13	)		0.65			0.50
Diluted net income (loss) per common share		0.12			(0.21	)		0.51			0.50
Adjusted EBITDA		136			90			146			194
Adjusted net income (loss)		10			(21	)		26			56
Adjusted net income (loss) per common share		0.13			(0.27	)		0.34			0.73