EX-99.2

This Management’s Discussion and Analysis (“MD&A”) is dated March 6, 2017 and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2016. 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 6, 2017, we had 89,847,488 common shares issued and outstanding and stock options exercisable for 1,935,742 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 10% or 6 million tonnes in 2016, leading to total demand, excluding demand from integrated coal-to-olefins facilities, of just over 66 million tonnes in 2016. Energy-related demand, which represents approximately 45% of total demand, grew by approximately 20% in 2016. MTO demand, which represented approximately 15% of methanol demand in 2016, led demand growth as four new plants were completed during the year. This demand segment is anticipated to grow further in 2017, aided by the full impact of the newly built MTO facilities, as well as an additional MTO plant anticipated to be completed in 2017 with the capacity to consume approximately 1.8 million tonnes of methanol annually. The future operating rates and methanol consumption from these facilities will depend on a number of factors, including pricing for their various final products and the impact of feedstock costs on relative competitiveness.

Demand for direct methanol blending into gasoline in China remains strong. China’s high blend (M85-M100) methanol vehicle pilot program has grown from three provinces/regions in 2012 to five currently, with further expansion planned for 2017 and 2018. Blending also gained momentum outside of China in 2016. In December 2016, New Zealand announced updated fuel specifications that would allow 3% methanol in gasoline and is expected to be in place by mid-2017, similar to existing European standards. In Israel, a national standard was approved for 15% methanol blends in late 2016, and the country is testing higher blends. The United Kingdom also announced significant fuel tax incentives to support high-blend methanol fuels.

Regulatory changes are playing an increasing role in encouraging new applications for methanol due to its emissions benefits as a fuel. In Europe and North America there are current regulations limiting sulphur emissions from ocean-going vessels in certain regulated zones. At the end of 2016, the International Maritime Organization expanded the geographical reach of these regulations by requiring a global 0.5% sulphur cap for vessels starting in 2020. With the growing demand for cleaner marine fuel, methanol is emerging as a promising competitive alternative. In 2015, Methanex partnered with Stena Line ferries to convert the world’s first ferry engines to run on methanol, and in 2016 Methanex’s subsidiary, Waterfront Shipping Company Limited, took delivery of seven first-of-their-kind dual-fuel vessels capable of running on methanol. In China, tightening air quality emissions regulations are leading to a phase-out of coal-fueled industrial boilers in favour of cleaner fuels, creating another market for methanol as an alternative fuel. We estimate that this growing demand segment already represents over one million tonnes of methanol demand.

During 2016, traditional chemical demand for methanol grew by approximately 4%. We estimate that traditional chemical derivatives consume approximately 55% of methanol globally and we believe that growth is correlated to GDP and industrial production growth rates.

In late 2015, two new methanol facilities started operation including the 1.3 million tonne Fairway Methanol LLC facility in Texas and Methanex’s Geismar 2 facility in Louisiana. There were no significant new industry capacity additions outside of China in 2016. In China, we estimate that approximately two million tonnes of new non-integrated production capacity was added in 2016.

Over the next few years, the majority of new capacity additions outside of China are expected in the Middle East and the Atlantic Basin. In 2015, an accord was signed to lift international trade sanctions against Iran which had restricted trade in Iranian-produced methanol in Europe and many Asian countries excluding China and India. The removal of these sanctions in early 2016 has improved the outlook of new methanol projects in Iran. There are a number of plants in Iran at various stages of construction and we expect just over four million tonnes of capacity to come onstream over the next two years. The start-up timing and future operating rates at these facilities will be dependent on various factors.

In the Atlantic basin, OCI N.V. and Consolidated Energy Limited (through its subsidiary G2X Energy) continue to progress their jointly owned Natgasoline project, a 1.8 million tonne plant in Beaumont, Texas. There are a number of other projects under discussion in the United States but we believe that none have yet reached a final investment decision.

To the end of 2018, we expect approximately four 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 on new coal-based methanol capacity. We expect that production from new capacity in China will be consumed in that country.

Methanex’s average realized price in 2016 was $242 per tonne versus $322 per tonne in 2015. A steep drop in oil and related product prices in the second half of 2015 lowered the affordability of methanol into a number of energy applications and put downward pressure on methanol pricing. Despite the strong MTO-led methanol demand growth in 2016, methanol prices remained under pressure as oil prices fell to 12-year lows early in the year. A significant decline in the price of coal and the devaluation of the Chinese Yuan also lowered the relative cost of production for coal based methanol in China which reduced cost curve support for methanol prices. At the same time, methanol supply was healthy in the first half of 2016, supported by relatively strong industry operating performance and new North American capacity. As a result, methanol prices were range-bound at bottom-of-cycle pricing for the first three quarters of 2016, but rebounded sharply in the last two months of the year as increases in the prices of coal, oil, olefins and other energy derivatives, along with continued strong growth in demand from new MTO capacity, provided support for methanol demand and pricing. Methanol prices continued to move higher in the first quarter of 2017.

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. 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 2016 sales volume of 9.5 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 2016. We achieved record production in 2016 of 7.0 million tonnes, a 35% increase in production over 2015. Still, our Chile operations are currently operating at less than full production capacity and provide further potential to reach our full production capacity of 9.4 million tonnes.

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 and continue 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, expand margins 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.

Our production facilities are well located to supply global methanol markets. 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. During 2016, we consented to the assignment of the Geismar 1 gas supply contract. As part of the assignment, the methanol revenue sharing component of the gas contract was eliminated, and the fixed price component remains unchanged. We have forward contracts to hedge natural gas prices for approximately 40% of the natural gas requirements of our Geismar 2 facility for a remaining nine-year period.

We have a 0.6 million tonne facility located in Medicine Hat, Alberta, for which we have entered into fixed price contracts to supply a proportion of our natural gas requirements from 2017 to 2022.

We continue to pursue opportunities to further lock-in our gas costs for our North American operations.

The cost to distribute methanol from production locations to customers is also 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. In 2016, we added seven new 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 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 reduce the likelihood of unplanned events and 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 late 2019. As at December 31, 2016, we had a strong balance sheet and a cash balance of $224 million. We believe we are well-positioned to meet our financial commitments, invest to grow the Company and return excess cash to shareholders.

The following table details the annual production capacity and actual production of our facilities in 2016 and 2015:

In New Zealand, we produced 2.2 million tonnes of methanol in 2016 compared with 1.9 million tonnes in 2015. Mechanical issues at our New Zealand plants impacted production in 2015. 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.

We have entered into several natural gas purchase agreements with various suppliers to underpin the future operation of our New Zealand facilities. Each natural gas purchase agreement has base and variable components, where the gas price varies with methanol prices.

The Geismar facilities produced 2.1 million tonnes of methanol in 2016 compared with 1.0 million tonnes in 2015. Both of our Geismar facilities commenced first methanol production in 2015: Geismar 1 during the first quarter and Geismar 2 late in the fourth quarter. Production in 2016 from our Geismar facilities reflects both plants being onstream for a full year.

During 2016, we consented to the assignment of the Geismar 1 gas supply contract. As part of the assignment, the methanol revenue sharing component of the gas contract was eliminated, and the fixed price component remains unchanged. The Geismar 1 gas contract expires in 2025. We have forward contracts to hedge natural gas prices for approximately 40% of the natural gas requirements of our Geismar 2 facility for a remaining nine-year period.

Our equity ownership of 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 Atlas gas contract expires in 2024 and the Titan gas contract expires in 2019. The Trinidad facilities produced a total of 1.6 million tonnes of methanol (Methanex share) in 2015 and 2016. In 2016, we operated these facilities at below operating capacity due to natural gas restrictions. In addition, the Atlas facility underwent a planned 45-day turnaround during the first quarter of 2016 and returned to normal operation at the end of March.

During 2015 and 2016, we continued to experience some 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 some 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 and is underpinned by a natural gas purchase agreement where the gas price varies with methanol prices. We produced 586,000 tonnes of methanol (Methanex share of 293,000) at the plant during 2016, compared to 148,000 tonnes (Methanex share of 74,000) in 2015.

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, 2016 have improved significantly compared to the same period in 2015. It continues to be difficult to predict when the gas supply situation will be fully restored. However, 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 28 for more information.

The Medicine Hat facility produced 488,000 tonnes of methanol in 2016 compared to 456,000 tonnes in 2015. A mechanical issue at the Medicine Hat facility impacted production in 2016. Repairs to address the issue were completed early in 2017. We have entered into fixed price contracts to supply a proportion of our natural gas requirements from 2017 to 2022.

The Chile facility produced 395,000 tonnes of methanol in 2016 compared to 204,000 tonnes in 2015. Production increased for 2016 as compared to 2015 as a result of improved natural gas availability from our Chilean suppliers allowing us to operate our Chile plant through the year for the first time since 2012.

During the year, we entered into an agreement with our main gas supplier in Chile, Empresa Nacional del Petróleo (“ENAP”), for gas supply for the period through May 2018. We also amended our gas supply agreement with GeoPark Fell SpA extending the term for an additional 10 years beyond April 2017 and signed a new tolling agreement with YPF SA in Argentina through April 2018 whereby natural gas received is converted into methanol and then re-delivered to Argentina. 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. 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, gain on terminal services agreement, 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, 2016, we reported net loss attributable to Methanex shareholders of $13 million ($0.14 loss per common share on a diluted basis), compared with net income attributable to Methanex shareholders of $201 million ($2.01 income per common share on a diluted basis) for the year ended December 31, 2015.

For the year ended December 31, 2016, we reported Adjusted EBITDA of $287 million and Adjusted net loss of $15 million ($0.17 Adjusted net loss per common share), compared with Adjusted EBITDA of $401 million and Adjusted net income of $110 million ($1.20 Adjusted net income per common share) for the year ended December 31, 2015.

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 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”). In 2015, we recorded a gain of $65 million ($57 million after-tax) related to the termination of a terminal services agreement.

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

A summary of our consolidated statements of income (loss) for 2016 and 2015 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 was $2.0 billion in 2016 compared to revenue of $2.2 billion in 2015. The lower revenue reflects a decrease in our average realized price in 2016, partially offset by higher sales volume.

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 2016 was $279 per tonne compared with $374 per tonne in 2015. Our average realized price in 2016 was $242 per tonne compared with $322 per tonne in 2015.

Due to strong sales growth in China, we have seen an increase in the proportion of our sales to customers in China in 2016 when compared to 2015, with a relative decrease in the United States, Europe, South Korea and South America. Details are as follows:

2016 Adjusted EBITDA was $287 million compared with 2015 Adjusted EBITDA of $401 million, a decrease of $114 million. The key drivers of changes 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 13 for more information).

Our average realized price for the year ended December 31, 2016 was $242 per tonne compared with $322 per tonne for 2015, and this decreased Adjusted EBITDA by $693 million (refer to the Financial Results – Revenue section on page 15 for more information).

Methanol sales volume, excluding commission sales volume, for the year ended December 31, 2016 was 890,000 tonnes higher than in 2015, and this increased Adjusted EBITDA by $73 million. Including commission sales volume from the Atlas and Egypt facilities, our total methanol sales volume was 9.5 million tonnes in 2016 compared with 8.5 million tonnes in 2015.

The primary drivers of changes in our total cash costs are changes in the cost of Methanex-produced methanol and changes in the cost of purchased methanol. All of our production facilities except Medicine Hat and Geismar have natural gas purchase agreements with pricing terms that include base and variable price components. 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.

The changes in our total cash costs for 2016 compared with 2015 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 the New Zealand, Trinidad, Chile and Egypt methanol facilities 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. We believe these pricing relationships enable each facility to be competitive throughout the methanol price cycle. Methanex-produced methanol costs were lower in 2016 compared with 2015 by $188 million, primarily due to the impact of lower methanol prices on our natural gas costs, timing of inventory flows and changes in the mix of production sold from inventory. For additional information regarding our natural gas supply agreements, refer to the Liquidity and Capital Resources – Summary of Contractual Obligations and Commercial Commitments section on page 22.

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 significant increase in production in 2016 has resulted in sales of Methanex-produced methanol making up a higher proportion of our total sales and this increased Adjusted EBITDA by $157 million for 2016 compared with 2015.

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 2016 and the timing of inventory flows and purchases, the cost of purchased methanol per tonne decreased and this increased Adjusted EBITDA by $175 million compared with 2015.

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. For the year ended December 31, 2016 compared with 2015, ocean freight and other logistics costs were higher, decreasing Adjusted EBITDA, the impact of which was partially offset by lower unabsorbed fixed production costs as a result of higher production and lower selling, general and administrative expenses.

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 $33.01 per share at December 31, 2015 to $43.80 per share at December 31, 2016. 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 $22 million mark-to-market expense related to share-based compensation during 2016.

Depreciation and amortization was $228 million for the year ended December 31, 2016 compared with $195 million for the year ended December, 31 2015. The increase in depreciation and amortization in 2016 compared with 2015 is primarily the result of a full year of depreciation in 2016 associated with the Geismar facilities.

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.

In 2015, we recorded a gain of $65 million ($57 million after-tax) related to the termination of a terminal services agreement. The Company received $30 million on termination of the agreement in 2015 and the remaining $35 million in early 2016.

Finance costs before capitalized interest are primarily comprised of interest on borrowings and finance lease obligations. Capitalized interest in 2015 related to interest costs capitalized for the Geismar project.

Finance income and other expenses was a gain of $4 million for the year ended December 31, 2016 compared to a loss of $6 million for the year ended December 31, 2015. The change in finance income and other expenses in 2016 compared with 2015 is primarily related to the impact of changes in foreign exchange rates.

We earn the majority of our pre-tax earnings in New Zealand, the United States, Trinidad, Egypt, Canada and Chile. In Trinidad and Chile, the statutory tax rate is 35%. The statutory rates in Canada and New Zealand are 26.5% and 28%, respectively. The United States statutory rate is 36% and the Egypt statutory 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 not included in total income taxes.

In Chile, the tax rate consists of a first-tier tax that is payable when income is earned and a second-tier tax that is due when earnings are distributed from Chile. The second category tax is initially recorded as future income tax expense and is subsequently reclassified to current income tax expense when earnings are distributed. Accordingly, the ratio of Chile’s current income tax expense to total income tax expense is dependent on the level of cash distributed from Chile.

The effective tax rate related to Adjusted net income (loss) was 44% for the year ended December 31, 2016 compared with 17% for the year ended December 31, 2015. 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.

For additional information regarding income taxes, refer to note 15 of our 2016 consolidated financial statements.

Cash flows from operating activities for the year ended December 31, 2016 were $250 million compared with $297 million for the year ended December 31, 2015. The decrease in cash flows from operating activities is primarily due to lower net income, after excluding depreciation and amortization, share-based compensation recovery, finance costs and changes in non-cash working capital. The following table provides a summary of these items for 2016 and 2015:

For a discussion of the changes in net income (loss), depreciation and amortization, share-based compensation recovery and finance costs, refer to the analysis of our financial results on page 14.

Changes in non-cash working capital decreased cash flows from operating activities by $64 million for the year ended December 31, 2016, compared with a decrease of $117 million for the year ended December 31, 2015. Trade and other receivables increased in 2016 and this decreased cash flows from operating activities by $14 million, primarily due to the impact of trade receivables related to higher sales in 2016 compared to 2015. This increase was mostly offset by a working capital release on the termination of a terminal services agreement and recoveries related to gas supplier commitments. Inventories increased primarily due to the impact of higher production rates which decreased cash flows from operating activities by $28 million. Accounts payable and accrued liabilities, including long-term payables, decreased cash flows from operating activities by $21 million, primarily due to the impact of gas supplier payments.

During 2016, we maintained our regular quarterly dividend at $0.275 per common share. Total dividend payments in 2016 were $99 million compared with $97 million in 2015 and total interest payments in 2016 were $83 million compared with $82 million in 2015.

In 2016, we drew down $66 million on our limited recourse debt facilities related to the financing of two vessels and repaid $48 million of other limited recourse debt compared to $194 million of unsecured notes and other limited recourse debt repayments in 2015.

During 2016, we incurred capital expenditures of $100 million primarily related to vessels acquired through less than wholly-owned entities and sustaining projects in New Zealand, Geismar, Egypt, Medicine Hat and Trinidad. Included in the 2015 capital expenditures is $328 million related to completion of the Geismar project.

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, 2016 and December 31, 2015:

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, 2016, we had a cash balance of $224 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 have not been met, resulting in a restriction on shareholder distributions from the Egypt entity. As at December 31, 2016, the Egypt cash balance on a 100% ownership basis was $46 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.

As at December 31, 2016, management believes the Company was in compliance with all significant terms and default provisions related to its long-term debt obligations.

Our planned capital maintenance expenditure program directed towards maintenance, turnarounds and catalyst changes for existing operations is currently estimated to total approximately $80 million to the end of 2017.

We believe we are well positioned to meet our financial commitments, invest to grow the Company and return excess cash to shareholders.

A summary of the estimated amount and estimated timing of cash flows related to our contractual obligations and commercial commitments as at December 31, 2016 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, 2016. For additional information, refer to note 8 of our 2016 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 a multi-year fixed price natural gas supply contract to supply one production facility in Geismar, natural gas forward contracts to hedge natural gas purchases in Geismar and natural gas forward supply contracts at fixed prices to manage exposure to natural gas price risk in Medicine Hat. 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, 2016, the Company also had commitments to purchase methanol from other suppliers for approximately 1.0 million tonnes for 2017 and 1.1 million tonnes 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.

As at December 31, 2016, 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, 2016 and December 31, 2015:

As at December 31, 2016, 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 relationship.

The Company has elected to manage its exposure to changes in natural gas prices for the Geismar 2 facility 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 34, 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 to naphtha as a feedstock in the production of olefins. 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.

A steep drop in oil and related product prices in the second half of 2015 lowered the affordability for methanol into a number of energy applications and put downward pressure on methanol pricing. Despite the strong MTO-led methanol demand growth in 2016, methanol prices remained at low levels as oil prices fell to 12-year lows early in the year. 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 2016, methanol demand for the production of formaldehyde represented approximately 28% 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. In 2010, the EPA released its draft formaldehyde assessment, proposing formaldehyde as “Known to be Carcinogenic to Humans.” The EPA IRIS assessment will likely be impacted by the recent listing of formaldehyde as “Known to be a Human Carcinogen” issued under the National Toxicology Program’s (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. The draft will be revised on the outcome of the external federal agency review, currently underway, then sent for 60-day public comment, anticipated in the first half of 2017.

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.

In late 2015, two new methanol facilities started operations including the 1.3 million tonne Fairway Methanol LLC facility in Texas and Methanex’s Geismar 2 facility in Louisiana. There was no significant new industry capacity additions outside of China in 2016. In China, we estimate that approximately two million tonnes of new production capacity was added in 2016.

Over the next few years, outside of China, the majority of new capacity additions are expected in the Atlantic basin and the Middle East. OCI N.V. and Consolidated Energy Limited (through its subsidiary G2X Energy) continue to progress their jointly owned Natgasoline project, a 1.8 million tonne plant under construction in Beaumont, Texas. In Iran, we expect just over four million tonnes of capacity to come onstream over the next two years. However, the timing of start-up and future operating rates at these facilities will be dependent on various factors. To the end of 2018, we expect approximately four million tonnes of new capacity to be added in China. Beyond 2018, we anticipate that new capacity additions in China will be modest due to an increasing degree of restrictions

placed on new coal-based methanol capacity additions and the trend of integration from coal to downstream chemicals for new projects in that country. There are a number of other projects under discussion in the United States but we believe that none have yet reached a final investment decision.

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: Geismar 1 in the first quarter and Geismar 2 late in the fourth quarter.

We have a fixed price take-or-pay agreement for the supply of all of the natural gas requirements for the Geismar 1 facility that expires in 2025. Under the contract, the supplier is obligated to supply, and we are obliged to take or pay for, a specified annual quantity of natural gas.

During 2015, we entered into forward contracts to hedge natural gas prices for the Geismar 2 facility. These contracts have a remaining period of nine years. We have hedged approximately 40% of the natural gas requirements and continue to pursue opportunities to contract additional natural gas to supply the facility.

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 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 supply 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 periodic curtailments of natural gas supply due to a mismatch between upstream supply to NGC and downstream demand from NGC’s customers. We are engaged with key stakeholders to find a solution to this issue, but in the meantime expect to continue to experience some gas curtailments to our Trinidad facilities. 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 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 from mid-2012, resulting in our Egypt plant operating below full capacity. In early 2016, we experienced a 30 day gas curtailment due to the sabotage of a gas pipeline feeding Damietta.

Although curtailments persisted in 2016, we saw significant improvements in gas deliveries compared to 2015, particularly in the latter half of the year. Over the past several years, the Egyptian government has made a significant effort 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 longer or greater than anticipated natural gas restrictions and that this would not have an adverse impact on our results of operations and financial condition.

We have a program in place to purchase natural gas for the 0.6 million tonnes per year Medicine Hat facility on the Alberta gas market. We have entered into fixed price contracts to supply a proportion of our natural gas requirements from 2017 to 2022.

The future operation of our Medicine Hat facility depends on methanol industry supply and demand fundamentals and our ability to secure sufficient natural gas on commercially acceptable terms. We believe that the long-term natural gas dynamics in North America will support the long-term operations of this facility; however, we cannot provide assurance 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 our long-term gas supply agreements. In the short term, we do not expect to receive any further natural gas supply from Argentina under such long-term gas supply agreements. In 2015, we continued to receive some natural gas from Argentina pursuant to a tolling agreement whereby the Company converts the natural gas received into methanol and then re-delivers the methanol to Argentina.

Approximately 60% during 2014 and 35% during 2015 of the Chile production was produced using natural gas supplied from Argentina under this arrangement. In November 2016, we executed a new tolling agreement with YPF S.A. and anticipate that we will receive some natural gas under this arrangement in 2017.

Since July 2007, all of the methanol production at our Chile facilities, other than natural gas received under tolling arrangements, has been produced from Chilean natural gas.

During 2016, we operated one of the two plants with Chilean gas at an average of 45% capacity. In July 2016, Methanex reached an agreement with Empresa Nacional del Petróleo (“ENAP”) for gas supply for the period through May 2018. The Company also agreed with GeoPark Fell SpA (“GeoPark”) to extend the existing gas supply agreement for an additional 10 year term, beyond April 2017.

Since 2015, ENAP has made significant investments in the development of natural gas from unconventional reservoirs and this has resulted in increased gas deliveries to our facilities in Chile. 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 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.

The future of our Chile operations is primarily dependent on the level of 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 cannot provide assurance that we will be able to continue to secure a sustainable natural gas supply to our facilities on economic terms to operate our Chile operations 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 that we are currently subject to 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, 2016, we had a cash balance of $224 million, including $23 million relating to the non-controlling interest in Egypt, and an undrawn $300 million revolving credit facility with a syndicate of banks. The facility expires in December 2019 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 21, there is currently a restriction on shareholder distributions from the Egypt entity; however, 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.

As at December 31, 2016, our long-term debt obligations include $1,200 million in unsecured notes ($350 million that matures in 2019, $250 million that matures in 2022, $300 million that matures in 2024 and $300 million that matures in 2044), $289 million related to the Egypt limited recourse debt facilities (100% basis) and $81 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 2016 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 our 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.

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 or relocation of existing 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.

Our CO₂ emissions intensity, defined as the quantity of CO₂ released per unit of production, decreased by 34% between 1994 and 2016. This was a result of some of our older plants being removed from active service, newer, more energy efficient plants being added, and improved plant reliability and energy efficiency at our existing plants. 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 asset mix that is operating. Carbon dioxide emissions are also generated from our marine operations when fuel is consumed during the global transport of methanol. Between 2002 and 2016, we reduced our CO₂ emissions intensity (i.e. tonnes of CO₂ from fuel burned per tonne of product transported) from marine operations by nearly 19%. This was primarily a result of improving transport efficiency by arranging another suitable cargo (backhaul of cargo) on the return voyage after delivering methanol to its intended destination, and newer more energy efficient vessels being added to the fleet.

We manufacture methanol in New Zealand, Trinidad, the United States, Egypt, Canada and Chile. While each of these countries (except the United States) signed and ratified the Kyoto Protocol, Canada has since removed itself from that agreement. During the United Nations Climate Change Conference (21^st meeting of the Conference of the Parties) in Paris in late 2015, 195 participating countries agreed by consensus to the Paris Agreement, the aim of which is to reduce GHG emissions. On November 4^th, 2016, the Paris Agreement entered into force following ratification by at least 55 countries which together represent at least 55% of global GHG emissions. Parties to the Paris Agreement put forward their best GHG reduction efforts through “nationally determined contributions” (“NDCs”) and to strengthen these efforts in the years ahead. The Agreement will supersede the Kyoto Protocol once it comes into effect in 2020.

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.

New Zealand passed legislation to establish an Emissions Trading Scheme (“ETS”) that came into force in 2010. The 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.

In late 2015, the New Zealand government commenced a review of the ETS to consider changes including removal of, or reduction to, some or all of the current moderating features. In May 2016, as an immediate outcome of that review the government announced the phasing out by 2019 of the transitional measure which halved the number of emission units that liable participants are required to surrender to the government. Further measures are also being considered by the government for future implementation that might impact the price of carbon in New Zealand or industry entitlements to free allocations. The government has indicated that further policy decisions will be made in mid-2017.

We do not expect the changes that have been announced and those still being considered under the current ETS review will have a material impact on our New Zealand business. Nevertheless, we cannot provide assurance that unanticipated changes to the ETS will not have a material impact on our business beyond 2016.

Our Medicine Hat facility is located in the Canadian province of Alberta, which has an established GHG reduction regulation that applies to our plant. The regulation requires that facilities reduce emissions intensity annually relative to established emissions intensity baseline. In order to meet the reduction obligation, a facility can choose to make emissions reduction improvements or it can purchase one of the following: technology fund credits, carbon offset credits, or environmental performance credits.

In 2016, the emissions reduction target was 15% relative to baseline, and in 2017 will increase 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 2016 emissions intensity and its established GHG baseline intensity, was not material in 2016.

In October 2016, the Canadian government announced that national carbon pricing must be in effect in provinces by 2018. The Company is monitoring this program closely. We cannot provide assurance that changes under this program will not have a material impact on our business in 2018 and beyond.

In 2015, Chile passed legislation introducing a carbon tax in 2017. A tax of $5/tonne of CO₂ emissions initially covers large boilers and electricity generators, but not other emissions sources from our plant such as the reformer. As a result, the cost impact to our business will be minimal. 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, including the production of methanol, internal and external communications, ordering and managing shipments of materials for our operations, coordinating transportation of our products and reporting our results. These processes are becoming more reliant on technology and more interconnected with external networks, which increases the risk of cyber security. We have a comprehensive program to protect our assets, detect an intrusion and respond in the event of a cyber security incident. We have 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. 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. Further, as cyber attacks continue to evolve, we may be required to commit additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks.

The Board of Inland Revenue of Trinidad and Tobago has issued assessments against our 63.1% owned joint venture, Atlas, in respect of the 2005, 2006, 2007, 2008, 2009 and 2010 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 27. See note 2 to our 2016 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, 2016, the net book value of our property, plant and equipment was $3.1 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, 2016, we had accrued $31 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 $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 in 2015 and 2016 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. Our management routinely reviews these judgments. As at December 31, 2016, we had recognized deferred tax assets of $137 million relating to non-capital loss carryforwards in the United States, $415 million of unrecognized deductible temporary differences in the United States and $153 million of unrecognized non-capital loss carryforwards in Egypt that expire between 2017 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, 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 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 is in the process of determining the impact of IFRS 15 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 has started an assessment of the impact of IFRS 16 on its consolidated financial statements. At this stage, 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. 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, 2016 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, 2017 will have a significant impact on the Company’s results of operations or financial position.

In addition to providing measures prepared in accordance with International Financial Reporting Standards (“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, gain related to the termination of a terminal services agreement 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 gain related to the termination of a terminal services agreement 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:

Adjusted revenue differs from the most comparable GAAP measure, revenue, because it excludes the non-controlling interests’ share of revenue, but includes an amount representing our 63.1% share of Atlas revenue and revenue on volume marketed on a commission basis related to the 36.9% of the Atlas methanol facility and 50% of the Egypt methanol facility that we do not own. A reconciliation from revenue to Adjusted revenue is as follows:

Operating Income 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 2016 is set out in our fourth quarter of 2016 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, 2016, 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, 2016, 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, 2016. The attestation report is included in our consolidated financial statements on page 44.

There have been no changes during the year ended December 31, 2016 to internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.

This 2016 Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements with respect to us and our industry. These statements relate to future events or our future performance. All statements other than statements of historical fact are forward-looking statements. Statements that include the words “believes,” “expects,” “may,” “will,” “should,” “potential,” “estimates,” “anticipates,” “aim”, “goal” or other comparable terminology and similar statements of a future or forward-looking nature identify forward-looking statements.

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

∎

expected demand for methanol and its derivatives,

∎

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

∎

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

∎

expected methanol and energy prices,

∎

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

∎

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

∎

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

∎

our expected capital expenditures,

∎

anticipated operating rates of our plants,

∎

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

∎

expected tax rates or resolutions to tax disputes,

∎

expected cash flows, earnings capability and share price,

∎

availability of committed credit facilities and other financing,

∎

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

∎

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

∎

our shareholder distribution strategy and anticipated distributions to shareholders,

∎

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

∎

our financial strength and ability to meet future financial commitments,

∎

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

∎

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

∎

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

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

∎

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

∎

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

∎

operating rates of our facilities,

∎

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

∎

the establishment of new fuel standards,

∎

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),

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 2016 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
		Financial Results


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


($ Millions, except as noted)	2016			2015
Production (thousands of tonnes) (attributable to Methanex shareholders)		7,017			5,193
Sales volume (thousands of tonnes):
Methanex-produced methanol		6,828			5,050
Purchased methanol		1,892			2,780
Commission sales		758			641
Total sales volume¹		9,478			8,471
Methanex average non-discounted posted price ($ per tonne)²		279			374
Average realized price ($ per tonne)³		242			322
Revenue		1,998			2,226
Adjusted revenue⁴		2,118			2,495
Adjusted EBITDA⁴		287			401
Cash flows from operating activities		250			297
Adjusted net income (loss)⁴		(15	)		110
Net income (loss) (attributable to Methanex shareholders)		(13	)		201
Adjusted net income (loss) per common share ($ per share)⁴		(0.17	)		1.20
Basic net income (loss) per common share ($ per share)		(0.14	)		2.21
Diluted net income (loss) per common share ($ per share)		(0.14	)		2.01
Common share information (millions of shares):
Weighted average number of common shares		90			91
Diluted weighted average number of common shares		90			91
Number of common shares outstanding, end of period		90			90


(Thousands of tonnes)	Annual production capacity¹		Annual operating capacity²		2016 Production		2015 Production
New Zealand³		2,430		2,430		2,181		1,856
USA (Geismar)⁴		2,000		2,000		2,055		959
Trinidad (Methanex interest)⁵		2,000		2,000		1,605		1,644
Egypt (50% interest)		630		630		293		74
Canada (Medicine Hat)		600		600		488		456
Chile⁶		1,720		880		395		204
		9,380		8,540		7,017		5,193


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.


		Liquidity and Capital Resources
		Risk Factors and Risk Management
		Critical Accounting Estimates
		Anticipated Changes to International Financial Reporting Standards
		Supplemental Non-GAAP Measures


($ Millions, except number of shares and per share amounts)	2016			2015
Net income (loss) attributable to Methanex shareholders	$	(13	)	$	201
Mark-to-market impact of share-based compensation, net of tax		19			(34	)
Argentina gas settlement, net of tax		(21	)		–
Gain related to the termination of a terminal services agreement, net of tax		–			(57	)
Adjusted net income (loss)	$	(15	)	$	110
Diluted weighted average shares outstanding (millions)		90			91
Adjusted net income (loss) per common share	$	(0.17	)	$	1.20


($ Millions)	2016			2015
Consolidated statements of income:
Revenue	$	1,998		$	2,226
Cost of sales and operating expenses		(1,774	)		(1,858	)
Mark-to-market impact of share-based compensation		22			(43	)
Adjusted EBITDA (attributable to associate)		63			108
Amounts excluded from Adjusted EBITDA attributable to non-controlling interests		(22	)		(32	)
Adjusted EBITDA (attributable to Methanex shareholders)		287			401
Mark-to-market impact of share-based compensation		(22	)		43
Depreciation and amortization		(228	)		(195	)
Argentina gas settlement		33			–
Gain related to the termination of a terminal services agreement		–			65
Finance costs		(90	)		(70	)
Finance income and other expenses		4			(6	)
Income tax recovery (expense)		9			(11	)
Earnings of associate adjustment¹		(43	)		(56	)
Non-controlling interests adjustment¹		37			30
Net income (loss) attributable to Methanex shareholders	$	(13	)	$	201
Net income (loss)	$	(28	)	$	202


($ Millions, except where noted)	2016				2015
China	$	518	26	%	$	361	16	%
Europe		404	20	%		480	22	%
United States		359	18	%		465	21	%
South Korea		258	13	%		327	15	%
South America		179	9	%		266	12	%
Canada		110	6	%		136	6	%
Other Asia		170	8	%		191	8	%
	$	1,998	100	%	$	2,226	100	%


($ Millions)	2016 vs. 2015
Average realized price	$	(693	)
Sales volume		73
Total cash costs		506
Decrease in Adjusted EBITDA	$	(114	)


($ Millions)	2016 vs. 2015
Methanex-produced methanol costs	$	188
Proportion of Methanex-produced methanol sales		157
Purchased methanol costs		175
Other, net		(14	)
Decrease in total cash costs	$	506


($ Millions)	2017		2018-2019		2020-2021		After 2021		Total
Long-term debt repayments	$	54	$	467	$	172	$	881	$	1,574
Long-term debt interest obligations		64		125		97		432		718
Repayments of other long-term liabilities		38		40		49		254		381
Natural gas and other		472		740		505		1,070		2,787
Operating lease commitments		106		166		108		197		577
	$	734	$	1,538	$	931	$	2,834	$	6,037



	Three months ended
($ Millions, except per share amounts)	Dec 31		Sep 30			Jun 30			Mar 31
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	)
2015
Revenue	$	484	$	527		$	638		$	577
Adjusted EBITDA		80		95			129			97
Adjusted net income		15		23			51			21
Net income (attributable to Methanex shareholders)		10		78			104			9
Adjusted net income per common share		0.16		0.26			0.56			0.23
Basic net income per common share		0.10		0.87			1.15			0.09
Diluted net income per common share		0.10		0.54			1.15			0.09