EX-99.2

This Management’s Discussion and Analysis (“MD&A”) is dated March 9, 2015 and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2014. 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. We use the United States dollar as our reporting currency and, except where otherwise noted, all currency amounts are stated in United States dollars.

At March 9, 2015, we had 91,679,012 common shares issued and outstanding and stock options exercisable for 1,878,689 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 60% 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 40% of methanol demand comes from a range of energy-related applications. These include direct blending of methanol into gasoline (primarily in China), and using methanol as a feedstock in the production of dimethyl ether (“DME”) biodiesel, and methanol-to-olefins (“MTO”). Methanol is also used to produce methyl tertiary-butyl ether (“MTBE”), a gasoline component.

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 8.3 million tonnes and is located in New Zealand, Trinidad, the United States, Egypt, Canada, and Chile (refer to the Production Summary section on page 10 for more information). In 2014 we completed the relocation of a 1 million tonne plant from our site in Chile to Geismar, Louisiana (“Geismar 1”). We are in the process of completing construction on a second facility relocated from Chile to Geismar (“Geismar 2”), and this is expected to increase our annual operating capacity to 8 million tonnes by late in the first quarter of 2016. 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 4% or 2 million tonnes in 2014, leading to total demand in the year of approximately 58 million tonnes, excluding demand from integrated MTO facilities. The increase in demand was driven by relatively strong growth in energy-related applications (notably MTO and fuel blending) and steady growth in traditional derivatives, particularly formaldehyde.

MTO and methanol-to-propylene (“MTP”) demand grew in 2014. There were seven completed MTO and MTP plants in China at the end of 2014 which are dependent on merchant methanol supply and these have the capacity to consume just under 7 million tonnes of methanol annually. There are also a number of other plants at various stages of construction which are anticipated to be completed in the 2015-16 timeframe. Direct methanol blending into gasoline in China has remained strong and we believe that future growth in this application is supported by numerous provincial fuel-blending standards. Fuel blending continues to gain interest outside of China with several countries currently conducting demonstration programs to test the use of methanol-blended fuels. DME demand declined in 2014 as a number of producers came under pressure in the second half of the year amidst declining liquefied petroleum gas prices in China.

There was a modest level of new industry supply additions outside of China in 2014. A 0.7 million tonne plant in Azerbaijan began selling methanol in mid-2014 and we increased our annual operating capacity by 1.0 million tonnes with the completion of the Geismar 1 facility. New production from supply additions inside China was consumed in that country as China continued to be a significant net importer of methanol.

We commenced first methanol production from our new Geismar 1 plant in January 2015 and are targeting to be producing methanol from Geismar 2 late in the first quarter of 2016. Beyond our own capacity additions in Geismar, there is a modest level of new capacity expected to come on stream over the next few years outside of China. With respect to China, we estimate that approximately 6 million tonnes of net new capacity was added in 2014. This was higher than expected. Although the number of restarts in China was lower, we saw a higher than expected number of new builds, consisting of small coke oven plants. To the end of 2016, we anticipate that approximately 6 million tonnes of net new capacity (not including integrated MTO production) will be added to meet growing domestic methanol demand in China. We expect that production from new capacity in China will be consumed in that country and that higher-cost production capacity in China will need to operate in order to satisfy demand growth. As production from our Geismar project comes on line, we believe our leadership position in the industry will be strengthened and we will have significant upside potential to cash flows and earnings.

Over the past five to six years, methanol demand growth has been led by strong demand from energy-related 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. A steep drop in oil and related product prices late in 2014 lowered the affordability for methanol into certain of these energy-related applications and this pushed global methanol pricing lower at the end of the year. Some higher cost methanol plants ceased to operate and we believe that any sustained period of methanol pricing below the marginal cash cost of production should result in further rationalization of higher cost methanol supply.

While the impact of lower energy prices has created some short-term methanol market uncertainty, we believe the industry fundamentals underpinning our strategy are intact. We remain focused on developing longer-term opportunities for methanol to meet the world’s increasing need for clean-burning energy products. 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. We believe that our financial position and financial flexibility, outstanding global supply network and competitive-cost position will provide a sound basis for Methanex to continue to be the leader in the methanol industry and to grow the Company.

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. In September 2014 we launched a new brand differentiator: “The Power of Agility.^™” 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. This brand is a critical element of our strong global culture, and it inspires us to achieve our vision of global methanol leadership.

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 2014 sales volume of 8.5 million tonnes represented approximately 15% 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 most of 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 dedicated 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 to strengthen our asset position. Our Geismar project is expected to enable us to reach 8 million tonnes of operating capacity late in the first quarter of 2016. Our Chile operations are currently operating at less than full capacity and provide further potential upside to our operating capacity.

Another key component of our global leadership strategy is our ability to supplement methanol production with methanol purchased from third parties to give us flexibility in our supply chain 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, Beijing, Seoul and Tokyo 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 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 Geismar 1 facility and our production facilities in New Zealand, Trinidad and Egypt 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. This pricing relationship enables these facilities to be competitive throughout the methanol price cycle. Our Titan gas contract expired in 2014, and we recently signed a term sheet to extend that contract for an additional five years.

We have a 0.6 million tonne facility located in Medicine Hat, Alberta, and we recently locked in 80% of our gas requirements for that facility to the end of 2016. We continue to pursue opportunities to further solidify our gas costs for our Medicine Hat facility.

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. We are continuously investigating opportunities to further improve the efficiency and cost-effectiveness of distributing methanol from our production facilities to customers. 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 (a risk-minimization approach developed by the Chemistry Industry Association of Canada) and we use it as the umbrella under which we manage issues related to health, safety, the environment, community involvement, social responsibility, sustainability, security and emergency preparedness at each of our facilities and locations. 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 $400 million credit facility provided by highly rated financial institutions that expires in late-2019. At December 31, 2014, we had a strong balance sheet with a cash balance of over $900 million. We believe we are well-positioned to meet our financial commitments, continue investing 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 2014 and 2013:

In New Zealand, we produced 2.2 million tonnes of methanol in 2014 compared with 1.4 million tonnes in 2013. Since re-starting the Waitara Valley facility, completing debottlenecking projects at Motunui and completing a major refurbishment of the Motunui 2 facility in 2013, our New Zealand facilities are able to produce at annual production capacity of up to 2.4 million tonnes, 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.

Our equity ownership of methanol facilities in Trinidad represents 2.0 million tonnes of cost-competitive 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. The Titan contract expired in 2014 and we recently signed a term sheet to renew that contract for an additional five years. These facilities produced a total of 1.6 million tonnes (Methanex share) in each of 2013 and 2014. For both 2013 and 2014, we operated these facilities at below operating capacity due to unplanned outages and natural gas restrictions.

During 2013 and 2014, we continued to experience some natural gas curtailments to our Trinidad facilities due to a mismatch between upstream commitments to supply the National Gas Company of Trinidad and Tobago Limited (“NGC”) and downstream demand from NGC’s customers, which becomes apparent when an upstream supplier has a technical issue or planned maintenance that reduces gas delivery. 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 the Trinidad site. Refer to the Risk Factors and Risk Management – Trinidad section on page 23 for more information.

In January 2015, the Geismar 1 plant commenced first methanol production. We continue to make excellent progress on the construction of Geismar 2 and we are targeting to be producing methanol late in the first quarter of 2016. The Geismar 2 facility will add an incremental one million tonnes to our annual operating capacity.

We have entered into a natural gas purchase agreement for our Geismar 1 facility that has base and variable components, where the gas price varies with methanol prices.

We operate a 1.26 million tonne per year methanol facility in Egypt and have marketing rights for 100% of the production. On December 9, 2013, we completed the sale of a 10% equity interest in the Egypt methanol facility to Arab Petroleum Investments Corporation (APICORP) for $110 million. Production from this facility attributable to Methanex reflects a 50% equity interest after December 9, 2013.

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. The facility produced 0.8 million tonnes in 2014 on a 100% basis (Methanex share 0.4 million tonnes) compared with 1.0 million tonnes (Methanex share 0.6 million tonnes) in 2013. Production from the Egypt facility during 2014 was lower than capacity, primarily due to natural gas supply restrictions. Refer to the Risk Factors and Risk Management – Egypt section on page 24 for more information.

The Medicine Hat facility produced 0.5 million tonnes in each of 2013 and 2014. An unplanned outage early in the year along with continuing production constraints resulted in lost production in 2014. We purchase natural gas on the Alberta gas market, and by the end of 2014 we had contracted sufficient natural gas volume to meet approximately 80% of our requirements for 2015 and 2016.

During 2013 and 2014, we operated our Chile methanol facilities significantly below annual production capacity due to insufficient natural gas feedstock.

In 2007, our natural gas suppliers from Argentina curtailed all gas supplied to our plants in Chile pursuant to long-term gas supply agreements. Under the existing circumstances, we do not expect to receive any further natural gas supply from Argentina under those long-term gas supply agreements. However, during 2013 and 2014 we received some natural gas from Argentina pursuant to a tolling agreement whereby the Company converts the natural gas into methanol and then re-delivers the methanol to Argentina. Approximately 60% of the Chile production during 2014 was produced using natural gas supplied from Argentina under this arrangement, compared to 45% in 2013.

In recent years, investments have been made by us and others to accelerate the exploration and development of natural gas in southern Chile. However, the potential for a significant increase in gas production remains challenging. We are continuing to work with gas suppliers in Chile and Argentina to secure sufficient natural gas to sustain our operations and, while the continued operation of the Chile plant through the 2015 southern hemisphere winter is possible based on the current projections of gas availability, it is unlikely. Refer to the Risk Factors and Risk Management – Chile section on page 25 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 (refer to the Supplemental Non-GAAP Measures section on page 34 for a description of Adjusted EBITDA and a reconciliation to the most comparable GAAP measure), mark-to-market impact of share-based compensation, depreciation and amortization, write-off of oil and gas rights, Geismar project relocation expenses and charges, Argentina gas settlement, asset impairment charges, finance costs, finance income and other expenses, and income taxes.

In addition to the methanol that we produce at our facilities (“Methanex-produced methanol”), we also purchase and resell methanol produced by others (“purchased methanol”) 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, respectively. For purposes of analyzing our business, Adjusted EBITDA, Adjusted net income and Adjusted net income per common share include an amount representing our 63.1% equity share in Atlas. Our analysis of depreciation and amortization, finance costs, finance income and other expenses and income taxes is consistent with the presentation of our consolidated statements of income and excludes amounts related to Atlas.

We own 50% of the 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 with the other investors’ interests in the methanol facility being presented as “non-controlling interests”. For purposes of analyzing our business, Adjusted EBITDA, Adjusted net income and Adjusted net income per common share exclude the amount associated with the other investors’ non-controlling interests.

For the year ended December 31, 2014, we reported Adjusted EBITDA of $702 million and Adjusted net income of $397 million ($4.12 per share on a diluted basis), compared with Adjusted EBITDA of $736 million and Adjusted net income of $471 million ($4.88 per share on a diluted basis) for the year ended December 31, 2013.

We calculate Adjusted EBITDA and Adjusted net income by including amounts related to our equity share of the Atlas (63.1% interest) and Egypt (50% interest as of December 9, 2013) facilities and by excluding 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. Adjusted EBITDA is a non-GAAP measure with no standardized meaning prescribed under IFRS. Refer to the Supplemental Non-GAAP Measures section on page 34 for further discussion on how we calculate these measures.

During 2014, we recorded a gain of $42 million ($27 million after-tax) after reaching a settlement with Total Austral S.A. (“Total”) in relation to Total’s natural gas delivery obligations pursuant to a long-term gas supply agreement in Chile. During 2013, we recorded a non-cash before-tax write-off of $25 million ($19 million after-tax) related to certain oil and gas exploration properties in New Zealand and Chile and a before-tax $34 million charge to earnings related to Geismar project relocation expenses ($22 million after-tax). Including these items and the mark-to-market impact of share-based compensation, we reported net income attributable to Methanex shareholders for the year ended December 31, 2014 of $455 million ($4.55 income per share on a diluted basis) compared with a net income attributable to Methanex shareholders for the year ended December 31, 2013 of $329 million ($3.41 income per share on a diluted basis).

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

A summary of our consolidated statements of income for 2014 and 2013 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. Our total sales volume increased while our average realized price slightly decreased in 2014 resulting in revenue of $3.2 billion for 2014 compared to revenue of $3.0 billion in 2013.

Demand for methanol grew by 4% or 2 million tonnes in 2014, leading to total annual global methanol demand of approximately 58 million tonnes, excluding methanol demand from integrated methanol-to-olefins facilities. The increase in demand was driven by relatively strong growth in energy-related applications (notably MTO and fuel blending) and steady growth in traditional derivatives, particularly formaldehyde.

At the beginning of 2014, supply constraints primarily in Asia Pacific resulted in rising methanol prices which stabilized through the second quarter when several plants returned to operation. A steep drop in oil and related product prices in the second half of 2014 lowered the affordability for methanol into certain energy-related applications and this, along with sufficient industry supply, pushed global methanol pricing lower at the end of the year. Some higher cost capacity ceased to operate and we believe that any sustained period of methanol pricing below the marginal cash cost of production should result in further rationalization of higher cost supply. Our average realized price for 2014 was $437 per tonne compared with $441 per tonne in 2013.

The methanol industry is highly competitive and prices are affected by supply and demand fundamentals. 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 for both 2014 and 2013 was $507 per tonne.

The geographic distribution of revenue by customer location for 2014 was similar to 2013. Details are as follows:

2014 Adjusted EBITDA was $702 million compared with 2013 Adjusted EBITDA of $736 million, a decrease of $34 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 11 for more information).

Our average realized price for the year ended December 31, 2014 was $437 per tonne compared with $441 per tonne for 2013, and this decreased Adjusted EBITDA by $45 million (refer to the Revenue section on page 14 for more information).

Methanol sales volume, excluding commission sales volume, for the year ended December 31, 2014 was 544,000 tonnes higher than in 2013, and this increased Adjusted EBITDA by $69 million. Including commission sales volume from the Atlas and Egypt facilities, our total methanol sales volume was 8.5 million tonnes in 2014, 0.5 million tonnes higher than in 2013, primarily due to increased production volume from our New Zealand facilities.

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 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 2014 compared with 2013 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 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 higher in 2014 compared with 2013 by $63 million, primarily due to the impact of higher realized methanol prices on our natural gas costs in the first half of the year, 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 Summary of Contractual Obligations and Commercial Commitments section on page 21.

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. Sales of Methanex-produced methanol made up a higher proportion of our total sales and this increased Adjusted EBITDA by $48 million for 2014 compared with 2013.

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 2014 and the timing of inventory flows and purchases, the cost of purchased methanol per tonne increased and this decreased Adjusted EBITDA by $29 million compared with 2013.

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, 2014 compared with 2013, ocean freight and other logistics costs were higher, decreasing Adjusted EBITDA by $9 million related to increased production volume.

The remaining change in other, net relates to an insurance settlement recorded in 2013 and costs related to our Geismar project. Certain costs incurred for the Geismar project are related to organizational build-up and are not eligible for capitalization under IFRS. These costs are charged directly to earnings as incurred and were higher in 2014 compared with 2013.

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 the 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. The mark-to-market impact of share-based compensation as a result of changes in our share price is excluded from Adjusted EBITDA and Adjusted net income and 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”) and tandem share appreciation rights (“TSARs”) 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,

which is determined at the date of grant. 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 units that will ultimately vest will be in the range of 50% to 120% of the original grant for grants prior to 2014 and in the range of 25% to 150% for subsequent grants. 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 Market decreased from $59.24 per share at December 31, 2013 to $45.83 per share at December 31, 2014. As a result of the decrease in the share price and the resulting impact on the fair value of the outstanding units, we recorded a $38 million mark-to-market recovery related to share-based compensation during 2014.

Depreciation and amortization was $143 million for the year ended December 31, 2014 compared with $123 million for the same period in 2013. The increase in depreciation and amortization in 2014 compared with 2013 is primarily as a result of depreciation associated with capital projects to increase production completed late in 2013 in New Zealand.

In the second quarter of 2014, we entered into a settlement agreement with Total in relation to Total’s natural gas delivery obligations pursuant to a long-term supply agreement in Chile. Total paid the Company a lump sum payment of $42 million to terminate its obligations under the agreement.

Finance costs before capitalized interest primarily relate to interest expense on the unsecured notes and limited recourse debt facilities. Capitalized interest in 2014 and 2013 relate to interest costs capitalized for the Geismar project.

Finance income and other expenses was a loss of $7 million for the year ended December 31, 2014 compared to a gain of $5 million for the same period in 2013. The change in finance income and other expenses in 2014 compared with 2013 is primarily related to the impact of changes in foreign exchange rates.

The effective tax rate related to Adjusted net income was 24% for the year ended December 31, 2014 compared with 16% for the year ended December 31, 2013. Adjusted net income represents the amount that is attributable to Methanex shareholders and excludes the mark-to-market impact of share-based compensation and the impact of certain items associated with specific identified events. The effective tax rate on both net income and Adjusted net income in 2013 was lower compared to 2014 due to the recognition of previously unrecognized tax assets in Canada and New Zealand in 2013.

We earn the majority of our pre-tax earnings in Trinidad, Egypt, Chile, Canada and New Zealand. In Trinidad and Chile, the statutory tax rate is 35%. The statutory rates in Canada and New Zealand are 26% and 28%, respectively. During the year, there was a temporary change to the Egypt statutory tax rate to 30% from 25% for the years 2014 to 2016. 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. During 2014, Chile passed a tax reform which modifies how companies and shareholders will pay taxes on income. Effective 2017, a dual tax system will apply whereby companies will have to elect to be taxed at either 35% payable on accrued taxable income or 44% split over two periods: 27% payable on accrued taxable income and a further 17% tax payable on repatriation of taxed profits out of Chile. The tax reform did not have a significant impact on our effective tax rate for 2014.

For additional information regarding income taxes, refer to note 15 of our 2014 consolidated financial statements.

Cash flows from operating activities for the year ended December 31, 2014 were $801 million compared with $586 million for 2013. The increase in cash flows from operating activities is primarily due to higher net income, after excluding depreciation and amortization, share-based compensation expense (recovery), oil and gas write-offs, finance costs and changes in non-cash working capital. The following table provides a summary of these items for 2014 and 2013:

For a discussion of the changes in net income, depreciation and amortization, share-based compensation expense (recovery), oil and gas write-offs and finance costs, refer to the analysis of our financial results on page 12.

Changes in non-cash working capital increased cash flows from operating activities by $58 million for the year ended December 31, 2014, compared with a decrease of $80 million for the year ended December 31, 2013. Trade and other receivables decreased in 2014 and this increased cash flows from operating activities by $130 million, primarily due to the impact on customer receivables from a lower average realized methanol price in the fourth quarter of 2014. Inventories decreased primarily due to the impact of a lower methanol price on Methanex-produced methanol costs and purchased product costs, and this increased cash flows from operating activities by $28 million. Accounts payable and accrued liabilities, including long-term payables, decreased cash flows from operating activities by $97 million, primarily due to the impact of lower methanol prices on natural gas supply payables and lower costs for purchased methanol.

During 2014, we increased our regular quarterly dividend by 25% to $0.25 per share, beginning with the dividend payable on June 30, 2014. Total dividend payments in 2014 were $90 million compared with $75 million in 2013 and total interest payments in 2014, including interest rate swap settlements, were $53 million compared with $55 million in 2013.

In 2014, we issued two separate tranches of unsecured notes for net proceeds of $592 million and repaid $42 million of unsecured notes and other limited recourse debt. Proceeds from the notes issued have been or will be used to repay limited recourse third party debt, to repay senior unsecured notes due in 2015, to fund capital expenditures and for working capital purposes.

During 2014, we incurred capital expenditures of $574 million related to our Geismar project. Other capital expenditures during 2014 of $84 million were primarily related to sustaining projects in New Zealand, Trinidad, Egypt and Medicine Hat.

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, 2014 and December 31, 2013:

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 issue of equity, 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 tandem share appreciation rights.

We operate in a highly competitive commodity industry and believe that it is appropriate to maintain a conservative balance sheet and retain financial flexibility. At December 31, 2014, we had a strong balance sheet with a cash balance of $952 million, including $69 million relating to the non-controlling interest in Egypt, and a $400 million undrawn credit facility. 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.

At December 31, 2014, 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 $110 million to the end of 2015. During 2014, capital expenditures related to the Geismar project were $574 million, excluding capitalized interest. The remaining capital expenditures related to the Geismar project are estimated to be $350 million, excluding capitalized interest.

We believe we are well positioned to meet our financial commitments, invest to grow the Company and continue to deliver on our commitment to 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, 2014 is as follows:

We have $150 million of unsecured notes that mature in 2015, $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 total expected principal repayments relating to the Egypt project debt and other limited recourse debt. Interest obligations related to variable interest rate long-term debt were estimated using current interest rates in effect at December 31, 2014. For additional information, refer to note 8 of our 2014 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 and to pay for transportation capacity related to this natural gas. We also have take-or-pay contracts to purchase oxygen and other feedstock requirements in Trinidad. 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 represent only the minimum take-or-pay quantity.

The natural gas supply contracts for our facilities in New Zealand, Trinidad, Egypt and the United States 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 at all points in the methanol price cycle and provides gas suppliers with attractive returns. The amounts disclosed in the table for these contracts represent only the base price component.

We have a program in place to purchase natural gas on the Alberta gas market to support the Medicine Hat facility and we believe that the long-term natural gas dynamics in North America will support the long-term operation of this facility. In the above table, we have included natural gas commitments 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.

We have supply contracts that expire between 2017 and 2025 with Argentinean suppliers for natural gas sourced from Argentina for a significant portion of the capacity of our facilities in Chile. We have excluded these potential purchase obligations from the table above. Since June 2007, our natural gas suppliers from Argentina have curtailed all gas supply to our plants in Chile under these arrangements. Under the current circumstances, we do not expect to receive any further natural gas supply from Argentina under these arrangements.

We also have contracts with Empresa Nacional del Petróleo (“ENAP”) to supply natural gas to produce approximately 0.8 million tonnes of methanol at our facilities in Chile. Over the last few years, deliveries from ENAP have been declining and ENAP has delivered significantly less than the full amount of natural gas that it was obligated to deliver under these contracts. We have excluded the potential purchase obligations 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. At December 31, 2014, we also have methanol purchase commitments with other suppliers under contracts for approximately 0.9 million tonnes for 2015 and a total of 1.0 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.

The majority of these commitments relate to time charter vessel agreements with terms of up to 15 years. Time charter vessels typically meet most of our ocean-shipping requirements. During 2014, we entered into one new time charter agreement in addition to the six time charter agreements entered into in 2013 relating to vessels that will be delivered in 2016; these commitments are included in the table above.

At December 31, 2014, 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. Held-to-maturity investments, loans and receivables and other financial liabilities are measured at amortized cost. Held-for-trading financial assets and liabilities and available-for-sale financial assets are measured on the balance sheet at fair value. From time to time, we enter into derivative financial instruments to limit our exposure to commodity price, foreign exchange and variable interest rate volatility and to contribute towards achieving cost structure and revenue targets. Until settled, the fair value of derivative financial instruments will fluctuate based on changes in commodity prices, foreign exchange rates and variable interest rates. Derivative financial instruments are classified as held-for-trading and are recorded on the consolidated statements of financial position at fair value unless exempted. Changes in fair value of held-for-trading derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges.

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, 2014 and December 31, 2013:

At December 31, 2014, all of the financial instruments were recorded on the consolidated statements of financial position at amortized cost with the exception of held-for-trading derivative financial instruments, which are recorded at fair value.

The Egypt limited recourse debt facilities bear interest at LIBOR plus a spread. We have entered into interest rate swap contracts to swap the LIBOR-based interest payments for an average aggregated fixed rate of 4.8% plus a spread on approximately 75% of the Egypt limited recourse debt facilities for the period to March 31, 2015. These interest rate swaps had outstanding notional amounts of $287 million as at December 31, 2014. At December 31, 2014, these interest rate swap contracts had a negative fair value of $6.5 million (December 31, 2013 – negative $20 million) recorded in other long-term liabilities.

The Company also designates as cash flow hedges forward exchange contracts to sell euros at a fixed U.S. dollar exchange rate. At December 31, 2014, the Company had outstanding forward exchange contracts designated as cash flow hedges to sell a notional amount of 25 million euros. The euro contracts had a positive fair value of $1.1 million (2013 – negative fair value of $0.6 million) recorded in current assets.

Changes in the fair value of derivative financial instruments designated as cash flow hedges have been recorded in other comprehensive income.

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

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 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 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 and that this will not 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 NGC. 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. The Titan contract expired in 2014 and we recently signed a term sheet to renew that contract for an additional five years. Titan gas costs will increase as a result of the renewed terms. We believe the supply and demand fundamentals for natural gas supply in Trinidad will support the continued operation of these facilities, however we cannot provide assurance that our contracted suppliers will be able to fully meet their commitments and that this will not have an adverse impact on our results of operations and financial condition.

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 commitments to supply NGC and downstream demand from NGC’s customers, which becomes apparent when an upstream supplier has a technical issue or planned maintenance that reduces gas delivery. 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 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 and that this would not have an adverse impact on our results of operations and financial condition.

In January 2015, the Geismar 1 plant commenced first methanol production. We continue to make excellent progress on the construction of Geismar 2 and we are targeting to be producing methanol late in the first quarter of 2016. The Geismar 1 and Geismar 2 facilities will each add an incremental 1.0 million tonnes to our annual operating capacity.

We have secured a 10-year take-or-pay agreement for the supply of all of the natural gas requirements for Geismar 1 and contractual deliveries and obligations commence on the first date of commercial operations. The price to be paid for the gas is based on a U.S. dollar base price plus a variable price component where the variable price component is adjusted by a formula related to methanol prices above a certain level.

While we believe that our estimates of project costs and anticipated completion for the Geismar 2 facility are reasonable, we cannot provide assurance that the cost estimates will not be exceeded or that the Geismar 2 facility will commence commercial operations within the anticipated schedule, if at all. We cannot provide assurance that we will be able to secure natural gas for the Geismar 2 plant on commercially acceptable terms. 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. 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.

The Egypt facility began experiencing periodic, and at times significant, natural gas supply constraints in mid-2012 and since that time has operated below full capacity. Over the past few years, Egypt’s government has been in a transition, which has resulted in ongoing civil unrest, including acts of sabotage, political uncertainty, and an adverse impact on the country’s economy. We believe that these factors are contributing to constraints in the development of new supplies of natural gas coming to market, the delivery of natural gas and an increase in the use of domestically-produced natural gas instead of more expensive imported energy for the purpose of generating domestic electricity, particularly during the summer months when electricity demand is at its peak. These factors have led to periodic natural gas supply restrictions to the Methanex Egypt facility which became more significant in 2014 and into early 2015. This situation 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 and we recently entered into fixed price contracts to supply 80% of our gas requirements for the facility for 2015 and 2016.

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 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. Under the current circumstances, we do not expect to receive any further natural gas supply from Argentina under those long-term gas supply agreements. We continue to receive some natural gas from Argentina pursuant to a tolling agreement whereby the natural gas received is converted into methanol and then the methanol is re-delivered to Argentina.

Since 2007, all of the methanol production at our Chile facilities, other than the natural gas received under the tolling arrangements in 2014 and 2013, has been produced from natural gas from Chile. While both Methanex and its natural gas suppliers have made significant investments in natural gas exploration and development in southern Chile and there have been new gas discoveries in the region, the potential for a significant increase in gas deliveries to our plants remains challenging.

Entering 2015, we were operating one of the two remaining plants at less than capacity and while the continued operation of the Chile plant through the 2015 southern hemisphere winter is possible, it is unlikely based on the current projections of gas availability.

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 operate our Chile operations and that this will not have an adverse impact on our results of operations or financial condition.

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. New methanol plants are expected to be built and this will increase overall production capacity. Additional methanol supply can also become available in the future by restarting idle methanol plants, carrying out major expansions of existing plants or debottlenecking existing plants to increase their production capacity. Historically, higher-cost plants have been shut down or idled when methanol prices are low, but there can be no assurance that this practice will occur in the future. Demand for methanol largely depends upon levels of global industrial production, changes in general economic conditions and the level of energy prices.

We are not able to predict future methanol supply and demand balances, market conditions, 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 would have an adverse effect on our results of operations and financial condition.

Volatile global economic conditions over the past few years have added significant risks and uncertainties to our business, including risks and uncertainties related to the global supply and demand for methanol, its impact on methanol prices, changes in capital markets and corresponding effects on our investments, our ability to access existing or future credit and increased risk of defaults by customers, suppliers, insurers and other counterparties. While the demand for methanol grew in 2014, there can be no assurance that future global economic conditions will not have an adverse impact on the methanol industry and that this will not have an adverse impact on our results of operations and financial condition.

Methanol is a global commodity and customers base their purchasing decisions principally on the delivered price of methanol and reliability of supply. Some of our competitors are not dependent on revenues from a single product and some have greater financial resources than we do. Our competitors also include state-owned enterprises. These competitors may be better able than we are to withstand price competition and volatile market conditions.

Changes in environmental, health and safety laws, regulations or requirements could impact methanol demand. The US 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. 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 2014, methanol demand for the production of formaldehyde represented approximately 30% of global demand. The largest use for formaldehyde is as a component of urea-formaldehyde and phenol-formaldehyde resins, which are used in adhesives for plywood, particleboard, oriented strand board, medium-density fibreboard and other reconstituted or engineered wood products. There is also demand for formaldehyde as a raw material for engineering plastics and in the manufacture of a variety of other products, including elastomers, paints, building products, foams, polyurethane and automotive products.

The current EPA IRIS carcinogenicity classification for formaldehyde is “Likely to Be Carcinogenic to Humans;” however, the EPA is reviewing this classification for formaldehyde as part of a standard review of chemicals. In 2010, the EPA released its draft formaldehyde assessment, proposing formaldehyde as “Known to be Carcinogenic to Humans.” The release of the final assessment of formaldehyde is expected in 2015.

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 is 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 US 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.

Approximately 40% of methanol demand is from energy related applications. Over the past five to six 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. Methanol can be substituted for petroleum products in energy-related applications with relative ease. For example, methanol can be blended directly with gasoline, and DME (a methanol derivative) can be blended with liquified petroleum gas (propane). Because of this substitutability, 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 energy product prices late in 2014 lowered the affordability for methanol into certain energy-related applications and this negatively impacted methanol pricing. We cannot provide assurance that energy pricing will recover from current levels or that methanol demand growth will not be affected. The future operating rates and methanol consumption from energy-related applications using methanol as a feedstock 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.

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, 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%. In 2010, the Chinese Ministry of Commerce investigated allegations made by domestic Chinese producers related to the dumping into China of imported methanol. In December 2010, the Ministry recommended that duties of approximately 9% be imposed on methanol imports from New Zealand, Malaysia and Indonesia for five years starting from December 24, 2010. However, citing special circumstances, the Customs Tariff Commission of the State Council, which is China’s chief administrative authority, suspended enforcement of the recommended dumping duties with the effect that methanol will continue to be allowed to be imported from these three countries without the imposition of additional duties. If the suspension is lifted, we do not expect there to be a significant impact on industry supply/demand fundamentals and we would realign our supply chain to minimize the payment of duties. Currently, the costs we incur in respect of duties are not significant. However, there can be no assurance that the duties that we are currently subject to will not increase, that the suspension of Chinese dumping duties will not be lifted, 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 won’t have material adverse 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.

At December 31, 2014, we had a cash balance of $952 million, including $69 million relating to the non-controlling interest in Egypt, and a $400 million undrawn 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 certain financial covenants, including an EBITDA to interest coverage ratio and a debt to capitalization ratio, as defined.

At December 31, 2014, our long-term debt obligations include $1,350 million in unsecured notes ($150 million that matures in 2015, $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), $369 million related to the Egypt limited recourse debt facilities (100% basis) and $20 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 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 2014 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 material adverse 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 of operations and financial condition.

Although we maintain operational and construction insurance, including business interruption insurance and delayed start-up insurance, we cannot provide assurance that we will not incur losses beyond the limits of, or outside the coverage of, such insurance or that insurers will be financially capable of honouring future claims. From time to time, various types of insurance for companies in the chemical and petrochemical industries have not been available on commercially acceptable terms or, in some cases, have been unavailable. We cannot provide assurance that in the future we will be able to maintain existing coverage or that premiums will not increase substantially.

We believe that our estimate for budgeted project costs and targeted completion date for our Geismar 2 project is reasonable. However, as we could be impacted by potential cost increases including the impact of costs due to labour shortages, we cannot provide any assurance that the cost estimates will not be exceeded or that the facility will begin commercial production within the targeted schedule, if at all, or that the facility will operate at its designed capacity or on a sustained basis. Any changes to the targeted timing of completion or estimated cost to complete the project or future ability to operate at production capacity could have an adverse impact on our results of operations and financial condition.

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

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

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

Carbon dioxide (“CO₂”) is a by-product of the methanol production process. The amount of CO₂ generated by the methanol production process depends on the production technology (and hence often the plant age), the feedstock and any export of the by-product hydrogen. Plant efficiency, and thus CO₂ emissions, is highly dependent on the design of the methanol plant, so the CO₂ emission figure may vary from year to year depending on the asset mix that is operating. We also recognize that CO₂ is generated from our marine operations, and in that regard we measure the consumption of fuel by our ocean vessels based on the volume of product transported.

We manufacture methanol in New Zealand, Trinidad, the United States, Egypt, Canada, and Chile. Except for the United States, all of these countries signed and ratified the Kyoto Protocol; however, Canada has since removed itself from that agreement. We are not currently required to reduce greenhouse gases (“GHGs”) in Trinidad, Egypt and Chile but our production in New Zealand and Canada is subject to GHG regulations. Today, there is no GHG legislation that requires GHG reductions in the United States, however we are required to track and report the quantity of GHG emissions from our site in Geismar, Louisiana.

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. The New Zealand government confirmed that the legislation will continue providing further moderation and the free emission allocation provisions will remain unchanged until at least 2015. Consequently, our ETS-related costs are not expected to be significant to the end of 2015. However, after this date, the moderating features may be removed and our eligibility for free allocation of emissions units may also be progressively reduced. As a consequence, we may incur increasing costs after 2015. It is impossible to accurately quantify the impact on our business of ETS-related costs after 2015 and therefore we cannot provide assurance that the ETS will not have a significant impact on our results of operations and financial condition.

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 intensities by up to 12% of their established emissions intensity baseline. “Emissions intensity” means the quantity of specified greenhouse gases released per unit of production. In order to meet the reduction obligation, a facility can choose to make emissions reduction improvements or it can purchase either offset credits or “technology fund” credits for CAD$15 per tonne of CO₂ equivalent. Financial obligations began in 2014, and to date the costs for us to purchase offset credits have not been material.

The federal government of Canada is in the process of developing a sector-by-sector approach to reduce GHG emissions in the chemical sector in support of its commitment to reduce GHGs from 2005 levels by 17% by 2020. Final proposed regulations are expected to be published by the fall of 2015. As the sole methanol producer in Canada, Methanex is engaged in a consultative process to ensure achievable performance standards are set and that these incorporate equivalency agreements to prevent the potential of paying for GHG emissions under both provincial and federal regimes.

In January 2015, the Geismar 1 plant commenced first methanol production and we are targeting to be producing methanol at Geismar 2 late in the first quarter of 2016. Today, there is no GHG legislation that requires GHG reductions in the United States, however we are required to track and report the quantity of GHG emissions from our site. We continue to monitor the development of potential legislation in the United States and Louisiana that would require GHG reductions to ensure compliance with any potential future requirements. At this time, it is unknown what impact potential new GHG legislation or regulations could have on our operations in Geismar.

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.

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 and 2008 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, 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. See note 2 to our 2014 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. At December 31, 2014, the net book value of our property, plant and equipment was $2,778 million.

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.

At December 31, 2014, we have accrued $24 million for site restoration costs relating to the decommissioning and reclamation of our methanol production sites and oil and gas properties. 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 indicate that the carrying amount may not be recoverable. Examples of such events or changes in circumstances 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 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.

As a consequence of the uncertain outlook for the future supply of natural gas feedstock to our Chile operations, we recorded an impairment charge at December 31, 2012 to reduce the carrying value of our Chile assets to their estimated recoverable amount. The post-impairment carrying value at December 31, 2012 of $245 million included the second methanol plant that management was then considering relocating to Geismar, Louisiana. During 2013, we made a final investment decision to relocate the second facility from Chile to Geismar, Louisiana and, as a result, the $75 million carrying value of this methanol plant (adjusted for 2013 year-to-date depreciation) was removed from the Chile cash-generating unit. At December 31, 2014, our Chile cash-generating unit consists primarily of the remaining two methanol plants in Chile with a carrying value of approximately $150 million.

As a result of insufficient natural gas feedstock during the southern hemisphere winter, we temporarily idled our Chile operations in April 2014. We restarted one methanol plant in September 2014 and operated the plant at approximately 30% of capacity in the fourth quarter of 2014 supported by natural gas supplies from both Chile and Argentina. The idling of our operations and the restart were both anticipated in our December 31, 2012 recoverability test. While we continue to work with our natural gas suppliers to sustain our Chile operations over the medium term, there is no assurance that we will be able to maintain operations through the upcoming southern hemisphere winter.

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 was 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. The pre-tax discount rate used of 13% was derived from the Company’s estimated cost of capital. 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, future global methanol production capacity, 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.

Based on an update of our previous model for current period assumptions, the estimated recoverable amount of our Chile cash-generating unit is approximately 18% in excess of its $150 million carrying value. Our estimate of the recoverable amount was based on a long-term methanol price assumption that is materially consistent with our historical results. A 10% decrease in our long term methanol price assumption would result in a reduction in the estimated recoverable amount by $50 million. Our estimate of the

recoverable amount was also based on natural gas prices which are materially consistent with those currently being incurred in the region and our best estimate of future natural gas availability, considering current contracted terms as well as factors that we believe are relevant to supply under these contracts and supplemental natural gas sources. A 10% increase in the natural gas price would result in a reduction in the estimated recoverable amount by $50 million and a 10% decrease in the natural gas availability would result in a reduction in the estimated recoverable amount by $40 million.

We believe the estimated recoverable amount of all long-lived assets except our Chile cash-generating unit substantially exceeded their carrying value at December 31, 2014.

Deferred income tax assets and liabilities are determined using enacted or substantially enacted tax rates for the effects of net operating losses and temporary differences between the book and tax bases of assets and liabilities. We recognize deferred tax assets to the extent it is probable that taxable profit will be available against which the asset can be utilized. In making this determination, certain judgments are made relating to the level of expected future taxable income and to available tax-planning strategies and their impact on the use of existing loss carryforwards and other income tax deductions. We also consider historical profitability and volatility to assess whether we believe it is probable that the existing loss carryforwards and other income tax deductions will be used to offset future taxable income otherwise calculated. Our management routinely reviews these judgments. At December 31, 2014, we had recognized future tax assets of $105 million (presented as a reduction of our deferred tax liabilities) and had $458 million of deductible temporary differences in the United States that have not been recognized. The determination of income taxes requires the use of judgment and estimates. If certain judgments or estimates prove to be inaccurate, or if certain tax rates or laws change, our results of operations and financial position could be materially impacted.

We enter into derivative financial instruments from time to time to manage certain exposures to commodity price volatility, foreign exchange volatility and variable interest rate volatility, which contributes towards managing our cost structure. Derivative financial instruments are classified as held-for-trading and are recorded on the balance sheet at fair value unless exempted. Changes in the fair value of held-for-trading derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges, in which case the effective portion of any changes in fair value are recorded in other comprehensive income. Assessment of contracts as derivative instruments, 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.

At December 31, 2014, the fair value of our derivative financial instruments used to limit our exposure to variable interest rate volatility that have been designated as cash flow hedges is negative $6.5 million.

In May 2014, the International Accounting Standards Board (“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, 2017, with early adoption permitted. The Company is in the process of determining the impact of IFRS 15 on its consolidated financial statements.

In July 2014, the IASB issued the final version of IFRS 9, Financial Instruments (“IFRS 9”), which reflects all phases of the financial instruments project and replaces IAS 39, Financial Instruments: Recognition and Measurement (“IAS 39”), and all previous versions of IFRS 9. The standard introduces new requirements for classification and measurement, impairment, and hedge accounting. IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early application permitted. The Company has chosen to early adopt IFRS 9 commencing January 1, 2015. The adoption of IFRS 9 will have an effect on the classification of the Company’s financial assets, but no impact on the classification of the Company’s financial liabilities. Specifically, cash and cash equivalents and trade and other receivables previously classified as loans and receivables at amortized cost have been reclassified to financial assets

at amortized cost with no resulting change in carrying value. Upon adoption of IFRS 9, the Company’s existing hedging relationships that qualified for hedge accounting under IAS 39 were reassessed and will continue under the new hedge accounting requirements in IFRS 9.

The Company does not expect that any other new or amended standards or interpretations that are effective as of January 1, 2015 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, Adjusted net income per share, 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, 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 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, Geismar project relocation expenses and charges, write-off of oil and gas rights and the Argentina gas settlement. Adjusted EBITDA includes an amount representing our 63.1% share of the Atlas facility and our 50% share (60% share prior to December 9, 2013) of the Egypt facility.

Adjusted EBITDA and Adjusted net income exclude the mark-to-market impact of share-based compensation related to the impact of changes in our share price on share appreciation rights, tandem share appreciation rights, deferred share units, restricted share units and performance share units. The mark-to-market impact related to performance share units that is excluded from Adjusted EBITDA and Adjusted net income is calculated as the difference between the grant-date value determined using a Methanex total shareholder return factor of 100% and the fair value recorded at each period-end. As share-based awards will be settled in future periods, the ultimate value of the units is unknown at the date of grant and therefore the grant-date value recognized in Adjusted EBITDA and Adjusted net income may differ from the total settlement cost.

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

Adjusted Net Income and Adjusted Net Income per Common Share (Attributable to Methanex Shareholders)

Adjusted net income and Adjusted net income 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 Geismar project relocation charges and expenses, write-off of oil and gas rights, and the Argentina gas settlement. The following table shows a reconciliation from net income attributable to Methanex shareholders to Adjusted net income and the calculation of Adjusted diluted net income per common share:

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 2014 is set out in our fourth quarter of 2014 Management’s Discussion and Analysis filed with the Canadian Securities Administrators and the US Securities and Exchange Commission and 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 at December 31, 2014, 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.

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, 2014, 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, 2014. The attestation report is included in our consolidated financial statements on page 41.

There have been no changes during the year ended December 31, 2014 to internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.

This 2014 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 registration 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 the Government of Egypt and its agencies,

our shareholder distribution strategy and anticipated distributions to shareholders,

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

our financial strength and ability to meet future financial commitments,

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

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

expected actions of governments, government 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,

timing of completion and cost of the Geismar project,

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

absence of a material negative impact from major natural disasters,

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

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

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

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

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

the ability to carry out corporate initiatives and strategies,

actions of competitors, suppliers and financial institutions,

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

our ability to meet timeline and budget targets for our Geismar project, including cost pressures arising from labour costs,

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 the 2014 Management’s Discussion and Analysis.

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


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


($ Millions, except as noted)	2014		2013
Production (thousands of tonnes) (attributable to Methanex shareholders)¹		4,853		4,344
Sales volume (thousands of tonnes):
Methanex-produced methanol (attributable to Methanex shareholders)		4,878		4,304
Purchased methanol		2,685		2,715
Commission sales		941		972
Total sales volume¹		8,504		7,991
Methanex average non-discounted posted price ($ per tonne)²		507		507
Average realized price ($ per tonne)³		437		441
Revenue		3,223		3,024
Adjusted EBITDA⁴		702		736
Cash flows from operating activities		801		586
Adjusted net income⁴		397		471
Net income (attributable to Methanex shareholders)		455		329
Adjusted net income per common share ($ per share)⁴		4.12		4.88
Basic net income per common share ($ per share)		4.79		3.46
Diluted net income per common share ($ per share)		4.55		3.41
Common share information (millions of shares):
Weighted average number of common shares		95		95
Diluted weighted average number of common shares		96		96
Number of common shares outstanding, end of period		92		96


(Thousands of tonnes)	Annual production capacity¹		Annual operating capacity²		2014		2013
New Zealand³		2,430		2,430		2,196		1,419
Atlas (Trinidad) (63.1% interest)		1,125		1,125		907		971
Titan (Trinidad)		875		875		664		651
Geismar 1 and 2, (Louisiana, USA)⁴		1,000		1,000		–		–
Egypt (50% interest)⁵		630		630		416		623
Medicine Hat (Canada)		560		560		505		476
Chile I and IV		1,720		400		165		204
		8,340		7,020		4,853		4,344


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, 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 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.
VOLUME		The change in Adjusted EBITDA as a result of changes in sales volume is calculated as the difference from period to period in total methanol sales volume, excluding commission sales volume, multiplied by the margin per tonne for the prior period. The margin per tonne for the prior period is the weighted average margin per tonne of Methanex-produced methanol and margin per tonne of purchased methanol. The margin per tonne for Methanex-produced methanol is calculated as the selling price per tonne of methanol less absorbed fixed cash costs per tonne and variable cash costs per tonne. The margin per tonne for purchased methanol is calculated as the selling price per tonne of methanol less the cost of purchased methanol per tonne.


($ Millions, except number of shares and per share amounts)	2014			2013
Net income attributable to Methanex shareholders	$	455		$	329
Mark-to-market impact of share-based compensation, net of tax		(31	)		101
Argentina gas settlement, net of tax		(27	)		–
Write-off of oil and gas rights, net of tax		–			19
Geismar project relocation expenses and charges, net of tax		–			22
Adjusted net income¹	$	397		$	471
Diluted weighted average shares outstanding (millions)		96			96
Adjusted net income per common share¹	$	4.12		$	4.88


($ Millions)	2014			2013
Consolidated statements of income:
Revenue	$	3,223		$	3,024
Cost of sales and operating expenses, excluding mark-to-market impact of share-based compensation		(2,464	)		(2,255	)
Adjusted EBITDA of associate (Atlas)¹		41			56
		800			825
Comprised of:
Adjusted EBITDA (attributable to Methanex shareholders)²		702			736
Amounts attributable to non-controlling interests		98			89
		800			825
Mark-to-market impact of share-based compensation		38			(110	)
Depreciation and amortization		(143	)		(123	)
Argentina gas settlement		42			–
Geismar project relocation expenses and charges		–			(34	)
Write-off of oil & gas rights		–			(25	)
Earnings of associate, excluding amount included in Adjusted EBITDA		(32	)		(34	)
Finance costs		(37	)		(57	)
Finance income and other expenses		(7	)		5
Income tax expense		(155	)		(70	)
Net income	$	506		$	377
Net income attributable to Methanex shareholders	$	455		$	329


($ Millions, except where noted)	2014				2013
Canada	$	248	8	%	$	214	7	%
United States		459	14	%		474	16	%
Europe		1,001	31	%		925	31	%
China		320	10	%		378	12	%
South Korea		447	14	%		397	13	%
Other Asia		340	10	%		249	8	%
Latin America		408	13	%		387	13	%
	$	3,223	100	%	$	3,024	100	%


($ Millions)	2014 vs. 2013
Average realized price	$	(45	)
Sales volume		69
Total cash costs		(58	)
Decrease in Adjusted EBITDA	$	(34	)


($ Millions)	2014 vs. 2013
Methanex-produced methanol costs	$	(63	)
Proportion of Methanex-produced methanol sales		48
Purchased methanol costs		(29	)
Other, net		(14	)
Increase in total cash costs	$	(58	)


($ Millions)	2015		2016-2017		2018-2019		After 2019		Total
Long-term debt repayments	$	194	$	103	$	453	$	996	$	1,746
Long-term debt interest obligations		70		125		124		530		849
Repayments of other long-term liabilities		56		87		6		51		200
Natural gas and other		394		720		469		1,300		2,883
Operating lease commitments		146		271		256		859		1,532
	$	860	$	1,306	$	1,308	$	3,736	$	7,210



	Three months ended
($ Millions, except per share amounts)	Dec 31		Sep 30		Jun 30		Mar 31
2014
Revenue	$	733	$	730	$	792	$	968
Adjusted EBITDA^{1 2}		150		137		160		255
Adjusted net income^{1 2}		80		66		91		160
Net income²		133		52		125		145
Adjusted net income per share^{1 2}		0.85		0.69		0.94		1.65
Basic net income per common share²		1.43		0.55		1.30		1.51
Diluted net income per common share²		1.11		0.54		1.24		1.50

2013
Revenue	$	881	$	758	$	733	$	652
Adjusted EBITDA^{1 2}		245		184		157		149
Adjusted net income^{1 2}		167		117		99		88
Net income²		128		87		54		60
Adjusted net income per share¹ ²		1.72		1.22		1.02		0.92
Basic net income per common share²		1.33		0.91		0.57		0.64
Diluted net income per common share²		1.32		0.90		0.56		0.63