EX-99.2

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Repayments of other long-term liabilities 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. Take-or-pay means that we are obliged to pay for the supplies regardless of whether we take delivery. Such commitments are common in the methanol industry. These contracts generally provide a quantity that is subject to take-or-pay terms that is lower than the maximum quantity that we are entitled to purchase. The amounts disclosed in the table above represent only the minimum take-or-pay quantity.

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

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

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

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

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

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

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

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 item as at December 31, 2017 and December 31, 2016:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Adjusted EBITDA 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, including the U.S. tax reform charge and the Argentina gas settlement. The following table shows a reconciliation from net income (loss) attributable to Methanex shareholders to Adjusted net income (loss) and the calculation of Adjusted diluted net income (loss) per common share:

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

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

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

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

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

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

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

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

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

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

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

∎

expected demand for methanol and its derivatives,

∎

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

∎

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

∎

expected methanol and energy prices,

∎

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

∎

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

∎

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

∎

our expected capital expenditures,

∎

anticipated operating rates of our plants,

∎

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

∎

expected tax rates or resolutions to tax disputes,

∎

expected cash flows, earnings capability and share price,

∎

availability of committed credit facilities and other financing,

∎

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

∎

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

∎

our shareholder distribution strategy and anticipated distributions to shareholders,

∎

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

∎

our financial strength and ability to meet future financial commitments,

∎

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

∎

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

∎

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

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

∎

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

∎

the availability of committed credit facilities and other financing,

∎

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

∎

absence of a material negative impact from major natural disasters,

∎

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

∎

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

∎

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

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

∎

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

∎

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

∎

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

∎

the ability to carry out corporate initiatives and strategies,

∎

actions of competitors, suppliers and financial institutions,

∎

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

∎

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

∎

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

∎

changes in laws or regulations,

∎

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

∎

worldwide economic conditions, and

∎

other risks described in this 2017 MD&A.

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


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


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


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


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


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


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


($ Millions, except number of shares and per share amounts)	2017			2016
Net income (loss) attributable to Methanex shareholders	$	316		$	(13	)
U.S. tax reform charge		37			–
Mark-to-market impact of share-based compensation, net of tax		56			19
Argentina gas settlement, net of tax		–			(21	)
Adjusted net income (loss)	$	409		$	(15	)
Diluted weighted average shares outstanding (millions)		87			90
Adjusted net income (loss) per common share	$	4.71		$	(0.17	)

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


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


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


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


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


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



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