Exhibit 99.2
Management’s Discussion & Analysis
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This Management’s Discussion and Analysis is dated March 15, 2012 and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2011. We use the United States dollar as our reporting currency. Except where otherwise noted, all currency amounts are stated in United States dollars.
The year ending December 31, 2011, with comparative results for 2010, is our first annual period reported under International Financial Reporting Standards (IFRS). All comparative figures have been restated to be in accordance with IFRS, unless specifically noted otherwise. For a description of the significant accounting policies the Company has adopted under IFRS, including the estimates and judgments we consider most significant in applying those accounting policies, please refer to note 2 of the consolidated financial statements.
Our financial statements were prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP) until December 31, 2010. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosures. The transition to IFRS had a cumulative impact on the Company’s shareholders’ equity of $25 million as of January 1, 2010, excluding the presentation reclassification of the non-controlling interests. To help users of the financial statements better understand the impact of the adoption of IFRS on the Company, we have provided reconciliations from Canadian GAAP to IFRS for total assets, liabilities and equity, as well as net income and comprehensive income, for the comparative reporting periods. Please refer to note 24 of the consolidated financial statements for the reconciliations between IFRS and Canadian GAAP.
At March 9, 2012 we had 93,522,155 common shares issued and outstanding and stock options exercisable for 4,239,460 additional common shares.
Additional information relating to Methanex, including our Annual Information Form, is available on 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 also, particularly in China, from coal. Approximately two-thirds 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 one-third of methanol demand comes from energy-related applications. There has been strong demand growth for direct methanol blending into gasoline, as a feedstock in the production of dimethyl ether (DME), which can be blended with liquefied petroleum gas for use in household cooking and heating, and in the production of biodiesel. Methanol is also used to produce methyl tertiary-butyl ether (MTBE), a gasoline component, and an emerging application is for methanol demand into olefins.
We are the world’s largest supplier of methanol to major international markets in Asia Pacific, North America, Europe and Latin America. Our total annual production capacity, including Methanex equity interests in jointly owned plants, is currently 9.3 million
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Management’s Discussion & Analysis
tonnes and is located in Chile, New Zealand, Trinidad, Egypt and Canada (refer to theProduction Summary section on page 15 for more information). We have marketing rights for 100% of the production from the jointly owned plants in Trinidad and Egypt and this provides us with an additional 1.2 million tonnes per year of methanol offtake supply when the plants are operating at full capacity. 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.
2011 Industry Overview & Outlook
Methanol is a global commodity and our earnings are significantly affected by fluctuations in the price of methanol, which is directly impacted by the balance of methanol supply and demand. Demand for methanol is driven primarily by levels of industrial production, energy prices and the strength of the global economy.
Despite concerns throughout 2011 regarding the health of the global economy, the methanol industry experienced demand growth of 7% compared with 2010, leading to total demand of approximately 49 million tonnes. Increases in demand have been driven by both traditional derivatives and energy-related applications in Asia, particularly in China.
The methanol industry added 1.7 million tonnes of capacity outside of China in 2011, consisting of the new 1.26 million tonne plant in Egypt and our 0.47 million tonne plant in Medicine Hat, Alberta; however, there were also a number of planned and unplanned outages. Overall industry conditions were balanced and this led to a stable methanol pricing environment throughout 2011. Our average realized price for 2011 was $374 per tonne.
The outlook for methanol demand growth continues to be strong. The wide disparity between the price of crude oil and that of natural gas and coal has resulted in increased use of methanol in energy applications, which now accounts for approximately one-third of global methanol demand. Led by China, methanol demand for gasoline blending and in the production of DME has been particularly strong and grew at high rates in 2011. We believe that future growth in these applications is supported by regulatory changes in that country as many provinces in China have implemented fuel blending standards, and M85 and M100 (or 85% methanol and 100% methanol respectively) national standards took effect in 2009. We believe demand potential into energy-related applications will be stronger in a high energy price environment.
China is also leading the commercialization of methanol demand into olefins (MTO), which is emerging as a significant methanol application. MTO, at current energy prices, is proving to be cost competitive relative to the traditional production of olefins from naphtha. The first MTO plant in China started up in 2010, and there are now four plants operating in China, consuming over five million tonnes of methanol annually. Three of these projects were not expected to impact the merchant methanol market as they are integrated projects – coal to methanol to olefins. However, over the past year, these plants have purchased methanol to supplement their own methanol production and the one non-integrated plant has been dependent on merchant methanol supply. A number of non-integrated projects are currently being planned in China, and these will depend on merchant methanol supply. If the projects go ahead, they could significantly impact the global supply and demand balance of methanol.
While methanol demand in energy applications is strongest in China, many other countries have projects in place or are considering adopting these derivatives on a wider scale. For example, methanol is being used in small quantities in gasoline in the United Kingdom and Korea, and there are fuel-blending trials under way in various countries around the world. DME projects are also under development in countries that include Indonesia, India, Sweden and Japan.
We increased production in 2011 and anticipate a further increase in production capacity over the next few years. In addition to our commitment to restart a second New Zealand facility in mid-2012, we are also focused on increasing the utilization of our Chile assets. We are pursuing investment opportunities to accelerate natural gas exploration and development in Chile, which we expect will allow us to increase production rates at our Chile site in the future. We are considering other projects to increase the utilization of our Chilean assets. We are planning to relocate one of the idle Chile methanol plants to Geismar, Louisiana, with a final investment decision expected in the third quarter of 2012,and we are also continuing to examine the viability of utilizing coal gasification as an alternative feedstock in Chile.
Beyond our own capacity additions, there is a modest level of new capacity expected to come on stream over the next few years. There is a 0.85 million tonne plant expected to restart in Beaumont, Texas in 2012, a 0.8 million tonne plant expected to restart in
METHANEX | | Annual Report 2011 | 11 |
Management’s Discussion & Analysis
Channelview, Texas in 2013, a 0.7 million tonne plant expected to start up in Azerbaijan in 2014, and a 0.8 million tonne plant expected to start up in Russia in 2015.
Despite continued concerns regarding the global economy, methanol demand continues to be stable, supported by a higher energy price environment. With few capacity additions expected to enter the market over the next few years relative to expected demand growth, we believe we are well positioned with anticipated production increases from our existing assets. As production from these assets comes on line, we believe our leadership position in the industry will be strengthened, the overall cost position of our assets will be improved and we will have significant upside potential to cash flows and earnings.
The methanol price will ultimately depend on the strength of the global economy, industry operating rates, global energy prices, the rate of industry restructuring 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 invest 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. Our simple, clearly defined strategy – global leadership, low cost and operational excellence – has helped us achieve this objective.
Global Leadership
Global leadership is a key element of our strategy, with a focus on maintaining and enhancing our position as the major supplier to the global methanol industry, enhancing our ability to cost-effectively deliver methanol supply to customers and supporting both traditional and energy-related global methanol demand growth.
We are the leading supplier of methanol to the major international markets of North America, Asia Pacific, Europe and Latin America. We grew sales volumes by 8% in 2011 to 7.5 million tonnes, representing approximately 15% of global demand. Our leadership position has enabled us to play an important role in the industry, which includes publishing Methanex reference prices that are generally used in each major market as the basis of pricing for most of our customer contracts.
The geographically diverse location of our production sites allows 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 a focus on strengthening our asset position and increasing production capability. We increased production in 2011 with the start-up of the new 1.26 million tonne per year methanol plant in Egypt and the restart of our 0.47 million tonne per year Medicine Hat, Alberta plant. We recently announced our commitment to restart a second facility in New Zealand in mid-2012 and this will provide an additional 0.65 million tonnes of methanol capacity. Our New Zealand facilities are ideally situated to supply the growing Asia Pacific market.
Our methanol facilities in Chile represent 3.8 million tonnes of annual production capacity and since 2007 we have operated the site significantly below capacity. This is primarily due to curtailments of natural gas supply from Argentina (refer to theRisk Factors and Risk Management – Chile section on page 30 for further information). Our primary goal is to progressively increase production at the Chile site with natural gas from suppliers in Chile by supporting the acceleration of natural gas development in southern Chile. Significant investments have been made in the last few years for natural gas exploration and development in southern Chile, and gas deliveries from these investments have allowed us to continue to operate one plant. However, the timelines for significant increases in gas production are much longer than we had originally anticipated and existing gas fields are experiencing declines. As a result, the short-term outlook for gas supply in Chile continues to be challenging and we are considering other projects to increase the utilization of our Chile assets. We are planning to relocate one of the idle Chile methanol plants with a capacity of approximately 1.0 million tonnes to Geismar, Louisiana, with a final investment decision expected in the third quarter of 2012. We are also continuing to examine the viability of utilizing coal gasification as an alternative feedstock in Chile.
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Management’s Discussion & Analysis
Another key component of our global leadership strategy is our ability to supplement methanol production with methanol purchased from others to give us flexibility in our supply chain and continue to meet customer commitments. We purchase 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. We grew sales and purchasing levels in 2011 in anticipation of increased production from the Egypt and Medicine Hat facilities. We expect purchased methanol will represent a lower proportion of overall sales volumes in 2012 compared to 2011 as a result of higher production from Egypt, Medicine Hat and New Zealand.
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 and Korea 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 sector.
Low Cost
A low cost structure is an important element of 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 production facilities in Trinidad and Egypt represent 2.8 million tonnes per year of competitive cost production capacity. These facilities are well located to supply markets in North America and Europe and are underpinned by take-or-pay natural gas purchase agreements where the gas price varies with methanol prices. This pricing relationship enables these facilities to be competitive throughout the methanol price cycle.
During 2011, we operated one Motunui facility in New Zealand and we recently announced our commitment to restart a second Motunui facility in mid-2012, which will add up to 0.65 million tonnes of incremental capacity per annum. In support of the restart, Methanex has entered into a ten-year natural gas purchase agreement that is expected to supply up to half of the 1.5 million tonnes of annual capacity at the Motunui site under terms that include base and variable price components.
Our 0.47 million tonne facility in Medicine Hat, Alberta is ideally situated to supply customers in North America. We have a program in place to purchase natural gas on the Alberta gas market and we believe that the long-term natural gas dynamics in North America will support the long-term operation of this 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.
Operational Excellence
We maintain a focus on operational excellence in all aspects of our business. This includes excellence in the 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
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Management’s Discussion & Analysis
to health, safety, the environment, community involvement, social responsibility, 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 shutdowns and safety incidents 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 and regulatory compliance. 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 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. At December 31, 2011, we had a strong balance sheet with a cash balance of $351 million and a $200 million undrawn credit facility. On February 21, 2012, we issued $250 million of notes due in 2022. We intend to repay the $200 million of notes due in August 2012 from cash on hand, cash generated from operations and proceeds from the 2012 offering. We believe we are well positioned to meet our financial commitments and continue investing to grow the business.
($ MILLIONS, EXCEPT WHERE NOTED) | 2011 | 2010 | ||||||
Production (thousands of tonnes) (attributable to Methanex shareholders) | 3,847 | 3,540 | ||||||
Sales volumes (thousands of tonnes): | ||||||||
Methanex-produced methanol (attributable to Methanex shareholders) | 3,853 | 3,540 | ||||||
Purchased methanol | 2,815 | 2,880 | ||||||
Commission sales1 | 846 | 509 | ||||||
Total sale volumes | 7,514 | 6,929 | ||||||
Methanex average non-discounted posted price ($ per tonne)2 | 440 | 356 | ||||||
Average realized price ($ per tonne)3 | 374 | 306 | ||||||
Revenue | 2,608 | 1,967 | ||||||
Adjusted EBITDA (attributable to Methanex shareholders)4 | 427 | 291 | ||||||
Cash flows from operating activities | 480 | 183 | ||||||
Adjusted cash flows from operating activities (attributable to Methanex shareholders)4 | 392 | 303 | ||||||
Net income (attributable to Methanex shareholders) | 201 | 96 | ||||||
Net income before unusual item (attributable to Methanex shareholders)4 | 201 | 74 | ||||||
Basic net income per common share ($ per share) | 2.16 | 1.04 | ||||||
Diluted net income per common share ($ per share) 5 | 2.06 | 1.03 | ||||||
Diluted net income per common share before unusual item ($ per share)4 | 2.06 | 0.79 | ||||||
Common share information (millions of shares): | ||||||||
Weighted average number of common shares outstanding | 93 | 92 | ||||||
Diluted weighted average number of common shares outstanding | 94 | 94 | ||||||
Number of common shares outstanding | 93 | 93 |
1 | Commission sales represent volumes marketed on a commission basis related to the 36.9% of the Atlas methanol facility and 40% of the Egypt methanol facility that we do not own. |
2 | Methanex average non-discounted posted price represents the average of our non-discounted posted prices in North America, Europe and Asia Pacific weighted by sales volume. Current and historical pricing information is available at www.methanex.com. |
3 | Average realized price is calculated as revenue, excluding commissions earned and the Egypt non-controlling interest share of revenue, divided by the total sales volumes of Methanex-produced (attributable to Methanex shareholders) and purchased methanol. |
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Management’s Discussion & Analysis
4 | These items are non-GAAP measures that do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Refer to theSupplemental Non-GAAP Measures section on page 41 for a description of each non-GAAP measure and a reconciliation to the most comparable GAAP measure. |
5 | For the year ended December 31, 2011, diluted net income per common share is $0.10 lower than basic net income per common share. The large difference between diluted and basic net income per common share is due to the basis for the calculation of diluted net income per common share differing from the accounting treatment for certain types of share-based compensation. See note 13 of the Company’s consolidated financial statements for the calculation of diluted net income per common share. |
The following table details the annual production capacity and actual production of our facilities in 2011 and 2010:
(THOUSANDS OF TONNES) | ANNUAL PRODUCTION CAPACITY1 | 2011 | 2010 | |||||||||
Chile I, II, III and IV | 3,800 | 554 | 935 | |||||||||
New Zealand2 | 2,230 | 830 | 830 | |||||||||
Atlas (Trinidad) (63.1% interest) | 1,150 | 891 | 884 | |||||||||
Titan (Trinidad) | 900 | 711 | 891 | |||||||||
Egypt (60% interest)3 | 760 | 532 | – | |||||||||
Medicine Hat3 | 470 | 329 | – | |||||||||
9,310 | 3,847 | 3,540 |
1 | The annual production capacity of our production facilities may be higher than original nameplate capacity as, over time, these figures have been adjusted to reflect ongoing operating efficiencies at these facilities. |
2 | The annual production capacity of New Zealand represents the two 0.85 million tonne facilities at Motunui and the 0.5 million tonne facility at Waitara Valley. We recently committed to restart a second Motunui facility in mid-2012, which is supported by a new ten-year natural gas agreement (refer to theNew Zealand section on page 16 for more information). Due to current distillation capacity constraints at the Motunui site, the combined operating capacity of both plants is approximately 1.5 million tonnes, compared with the combined nameplate capacity of 1.7 million tonnes. |
3 | The Egypt methanol facility commenced commercial production in March 2011 and the Medicine Hat facility was restarted in April 2011. |
Chile
The methanol facilities in Chile produced 0.55 million tonnes of methanol in 2011 compared with 0.94 million tonnes in 2010. Since 2007, we have operated the methanol facilities in Chile significantly below site capacity, primarily due to curtailments of natural gas supply from Argentina. In June 2007, natural gas suppliers from Argentina curtailed all gas supply to our plants in Chile in response to various actions by the Argentinean government, including imposing a large increase to the duty on natural gas exports. Under the current circumstances, we do not expect to receive any further natural gas supply from Argentina. As a result of the Argentinean natural gas supply issues, all of the methanol production at the Chile facilities since June 2007 has been produced with natural gas from Chile.
Our primary goal is to progressively increase production at the Chile site with natural gas from suppliers in Chile. We are pursuing investment opportunities with the state-owned energy company Empresa Nacional del Petroleo (ENAP), GeoPark Chile Limited (GeoPark) and others to help accelerate natural gas exploration and development in southern Chile. We are working with ENAP to develop natural gas in the Dorado Riquelme block in southern Chile. Under the arrangement, we fund a 50% participation in the block and, as at December 31, 2011, we had contributed approximately $106 million. Over the past few years, we have also provided $57 million in financing to GeoPark (of which approximately $40 million had been repaid at December 31, 2011) to support and accelerate GeoPark’s natural gas exploration and development activities in southern Chile. GeoPark has agreed to supply us with all natural gas sourced from the Fell block in southern Chile under a ten-year exclusive supply arrangement that began in 2008.
Other investment activities are also supporting the acceleration of natural gas exploration and development in areas of southern Chile. Over the past few years, the Government of Chile has completed international bidding rounds to assign oil and natural gas exploration areas that lie close to our production facilities and announced the participation of several international oil and gas companies. For two of the exploration blocks, we are participating in a consortium with other international oil and gas companies with Geopark as the operator. We have approximately a 15% participation in the consortium and at December 31, 2011, we had contributed $9 million for our share of the exploration costs.
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Management’s Discussion & Analysis
During 2011, approximately 75% of total production at the Chilean facilities was produced with natural gas supplied from the Fell and Dorado Riquelme blocks, with the remaining natural gas supplied by ENAP. Lower production from the Chile facilities in 2011 compared with 2010 was primarily as a result of declines in the deliverability from existing fields. As we entered 2012, we were operating one plant at approximately 40% of capacity and were working closely with ENAP to manage through the seasonality of gas demand with the objective of maintaining operations through the winter season in 2012.
While significant investments have been made in the last few years for oil and natural gas exploration and development in southern Chile, the timelines for significant increases in gas production are much longer than we had originally anticipated and existing gas fields are experiencing declines. As a result, the short-term outlook for gas supply in Chile continues to be challenging and we are also considering other projects to increase the utilization of the Chilean assets. We are planning to relocate one of the idle Chile methanol plants with a capacity of approximately 1.0 million tonnes to Geismar, Louisiana and expect to make a final investment decision in the third quarter of 2012 with production in late 2014. We are also continuing to examine the viability of utilizing coal gasification as an alternative feedstock in Chile. Refer to theRisk Factors and Risk Management – Chile section on page 30 for more information.
New Zealand
During 2010 and 2011, we operated one methanol facility at the Motunui site in New Zealand and produced 0.83 million tonnes of methanol each year. We recently announced our commitment to restart a second Motunui facility in mid-2012 which will add up to 0.65 million tonnes of incremental annual capacity to our New Zealand operations. In support of the restart, we have entered into a ten-year gas supply agreement that is expected to supply up to half of the 1.5 million tonnes of annual capacity at the Motunui site. We have an additional 0.53 million tonne per year plant at the nearby Waitara Valley site which remains idle. This facility provides additional potential to increase New Zealand production depending on methanol supply and demand dynamics and the availability of competitively priced natural gas. We continue to pursue opportunities to contract additional natural gas supply to our plants in New Zealand and are also pursuing natural gas exploration and development opportunities in that country. We have an agreement with Kea Petroleum, an oil and gas exploration and development company, to explore areas of the Taranaki basin, which is close to our plants.
Trinidad
Our equity ownership of methanol facilities in Trinidad represents 2.05 million tonnes of competitive cost annual capacity. The Titan and Atlas facilities in Trinidad are well located to supply markets in North America and Europe and are underpinned by take-or-pay natural gas purchase agreements that expire in 2014 and 2024, respectively, where the gas price varies with methanol prices. These facilities produced a total of 1.60 million tonnes in 2011 compared with 1.78 million tonnes in 2010. As a result of an equipment failure in July 2011, the Atlas facility operated at approximately 70% of capacity until it was shut down in January 2012 for a maintenance outage to complete the repair.
In addition, production at the Titan facility was lower than capacity, primarily due to unplanned maintenance outages and lower gas deliveries. During 2011, we experienced some natural gas curtailments to the Titan facility due to a mismatch between upstream commitments to supply The National Gas Company in Trinidad (NGC) and downstream demand from NGC’s customers which becomes apparent when an upstream technical problem arises. 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 theRisk Factors and Risk Management – Trinidad on page 30 for more information.
Egypt
The new 1.26 million tonne per year methanol plant in Egypt commenced commercial operations in March 2011 and produced 0.89 million tonnes (0.53 million tonnes on a 60% basis) in 2011. We have a 60% interest in the facility and have marketing rights for 100% of the production. This facility is well located to supply the European market and is underpinned by a 25-year take-or-pay natural gas purchase agreement where the gas price varies with methanol prices.
During 2011, Egypt experienced periods of anti-government protests and civil unrest and in November 2011, for the safety and security of our employees, we took the decision to temporarily curtail operations of the methanol plant. Since restarting in December the plant has operated near capacity. Refer to theRisk Factors and Risk Management – Egyptsection on page 31 for more information.
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Management’s Discussion & Analysis
Medicine Hat
Our 0.47 million tonne per year facility in Medicine Hat, Alberta was restarted in April 2011 and has operated well since that time, producing 0.33 million tonnes of methanol in 2011. We have a program in place to purchase natural gas on the Alberta gas market and we believe that the long-term natural gas dynamics in North America will support the long-term operation of this facility.
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 theSupplemental Non-GAAP Measures section on page 41 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, 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 re-sell 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 volumes. The key drivers of change in Adjusted EBITDA are average realized price, cash costs and sales volume which are defined and calculated as follows:
PRICE | The change in Adjusted EBITDA as a result of changes in average realized price is calculated as the difference from period to period in the selling price of methanol multiplied by the current period total methanol sales volume excluding commission sales volume 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 volumes 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. |
We own 63.1% of the Atlas methanol facility and market the remaining 36.9% of its production through a commission offtake agreement. We account for this investment using proportionate consolidation, which results in 63.1% of its results being included in revenues and expenses with the remaining 36.9% portion included as commission income.
We own 60% of the 1.26 million tonne per year Egypt methanol facility and market the remaining 40% 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’ interest in the methanol facility being presented as “non-controlling interests”. For purposes of analyzing our business, Adjusted EBITDA and Adjusted cash flows from operating activities exclude the amounts associated with the other investors’ 40% non-controlling interest, which are included in commission income on a consistent basis with how we present the Atlas facility.
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Management’s Discussion & Analysis
($ MILLIONS) | 2011 | 2010 | ||||||
Consolidated statements of income: | ||||||||
Revenue | $ | 2,608 | $ | 1,967 | ||||
Cost of sales and operating expenses, excluding mark-to-market impact of share-based compensation | (2,128 | ) | (1,676 | ) | ||||
480 | 291 | |||||||
Comprised of: | ||||||||
Adjusted EBITDA (attributable to Methanex shareholders)1 | 427 | 291 | ||||||
Amounts attributable to non-controlling interests | 53 | – | ||||||
480 | 291 | |||||||
Mark-to-market impact of share-based compensation | 21 | (19 | ) | |||||
Gain on sale of Kitimat assets | – | 22 | ||||||
Depreciation and amortization | (157 | ) | (137 | ) | ||||
Operating income 1 | 344 | 157 | ||||||
Finance costs | (62 | ) | (31 | ) | ||||
Finance income and other expenses | 2 | 2 | ||||||
Income tax expense | (56 | ) | (34 | ) | ||||
Net income | $ | 228 | $ | 94 | ||||
Net income attributable to Methanex shareholders | $ | 201 | $ | 96 |
1 | These items are non-GAAP measures that do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Refer to theSupplemental Non-GAAP Measures section on page 41 for a description of the non-GAAP measures and a reconciliation to the most comparable GAAP measures. |
For the year ended December 31, 2011, we recorded Adjusted EBITDA (attributable to Methanex shareholders) of $427 million and net income attributable to Methanex Corporation shareholders of $201 million ($2.16 basic net income per common share and $2.06 per share on a diluted basis). This compares with Adjusted EBITDA (attributable to Methanex shareholders) of $291 million and net income attributable to Methanex Corporation shareholders of $96 million ($1.04 basic net income per common share and $1.03 per share on a diluted basis) for the year ended December 31, 2010. Included in our 2010 results was an unusual gain of $22 million from the sale of Kitimat assets. Refer to page 42 for a reconciliation of net income to net income before unusual item.
The following discussion provides a description of changes in revenue, Adjusted EBITDA, mark-to-market impact of share-based compensation, depreciation and amortization, finance costs, finance income and other expenses, and income taxes for 2011 compared with 2010.
Revenue
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.
18 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
Revenue for 2011 was $2.6 billion compared with $2.0 billion in 2010. The increase in revenue was primarily due to higher methanol pricing and increased sales volumes in 2011 compared with 2010.
Despite concerns throughout 2011 regarding the health of the global economy, we estimate that global methanol demand grew at approximately 7% in 2011 and is currently 49 million tonnes on an annualized basis. Increases in demand have been driven by both traditional derivatives and energy-related applications in Asia (particularly in China). We grew our total sales volumes, including commission sales volumes, by approximately 8% in 2011, primarily in anticipation of the start-up of the Egypt and Medicine Hat facilities.
The methanol industry added 1.7 million tonnes of capacity outside of China in 2011, consisting of the new 1.26 million tonne plant in Egypt and our 0.47 million tonne plant in Medicine Hat, Alberta; however, there were also a number of planned and unplanned outages. Overall market conditions were balanced and this led to a stable methanol pricing environment throughout 2011. Our average realized price for 2011 was $374 per tonne compared with $306 per tonne in 2010.
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 2011 was $440 per tonne compared with $356 per tonne in 2010, and our average realized prices were 15% and 14% lower, respectively, than the average non-discounted published prices.
Distribution of Revenue
The distribution of revenue for 2011 and 2010 is as follows:
($ MILLIONS, EXCEPT WHERE NOTED) | 2011 | 2010 | ||||||||||||||
Canada | $ | 176 | 7 | % | $ | 142 | 7 | % | ||||||||
United States | 632 | 24 | % | 470 | 24 | % | ||||||||||
Europe | 679 | 26 | % | 454 | 23 | % | ||||||||||
China | 431 | 17 | % | 351 | 18 | % | ||||||||||
Korea | 267 | 10 | % | 216 | 11 | % | ||||||||||
Other Asia | 155 | 6 | % | 127 | 6 | % | ||||||||||
Latin America | 268 | 10 | % | 207 | 11 | % | ||||||||||
$ | 2,608 | 100 | % | $ | 1,967 | 100 | % |
The geographic distribution in our revenue in 2011 was similar to 2010.
Adjusted EBITDA (Attributable to Methanex Shareholders)
We own 60% of the 1.26 million tonne per year Egypt methanol facility and 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’ interest in the methanol facility being presented as “non-controlling interests”. We analyze Adjusted EBITDA by excluding the amounts associated with the other investors’ 40% non-controlling interest and include these results in commission income on a consistent basis with how we present the Atlas facility.
METHANEX | | Annual Report 2011 | 19 |
Management’s Discussion & Analysis
Commencing in 2011, we have modified our definition of Adjusted EBITDA to exclude the mark-to-market impact of items that impact the comparability of our results from one period to another, which currently include only the mark-to-market impact of share-based compensation as a result of changes in our share price. We grant share-based awards as an element of compensation and, as more fully discussed on page 22, certain of these awards are marked to market each period with the changes in fair value recognized in earnings for the proportion of the service that has been rendered at the reporting date. We believe excluding the mark-to-market impact of share-based compensation as a result of changes in our share price will provide readers with a better measure of the Company’s underlying ability to generate cash from operations and improve the comparability of our results from one period to another. A reconciliation of the change in the definition of Adjusted EBITDA is as follows:
($ MILLIONS) | 2011 | 2010 | ||||||
Adjusted EBITDA, as previously defined | $ | 448 | $ | 272 | ||||
Mark-to-market impact of share-based compensation | (21 | ) | 19 | |||||
Adjusted EBITDA(attributable to Methanex shareholders) | $ | 427 | $ | 291 |
2011 Adjusted EBITDA was $136 million higher than 2010 Adjusted EBITDA. The key drivers of changes in our Adjusted EBITDA are average realized price, sales volume and cash costs as described below (refer to theHow We Analyze Our Business section on page 17 for more information).
($ MILLIONS) | 2011 VS. 2010 | |||
Average realized price | $ | 454 | ||
Sales volume | 17 | |||
Total cash costs | (335 | ) | ||
Increase in Adjusted EBITDA | $ | 136 |
Average Realized Price
Our average realized price for the year ended December 31, 2011 was $374 per tonne compared with $306 per tonne for 2010, and this increased our Adjusted EBITDA by $454 million (refer to theRevenue section on page 18 for more information).
Sales Volumes
Total methanol sales volumes, excluding commission sales volumes, for the year ended December 31, 2011 were 0.25 million tonnes higher than in 2010, and this increased Adjusted EBITDA by $17 million. We grew our sales volumes in 2011, primarily in anticipation of the start-up of the Egypt and Medicine Hat facilities.
Total Cash Costs
The primary drivers of changes in our total cash costs are changes in the cost of methanol we produce at our facilities (Methanex-produced methanol) and changes in the cost of methanol we purchase from others (purchased methanol). All of our production facilities except Medicine Hat are underpinned by 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 will depend on changes in methanol pricing and the timing of inventory flows.
20 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
Costs for Methanex-produced methanol and purchased methanol were $335 million higher in 2011 than 2010. The changes in our cash costs were due to the following:
($ MILLIONS) | 2011 VS. 2010 | |||
Methanex-produced methanol costs | $ | (144 | ) | |
Purchased methanol costs | (200 | ) | ||
Proportion of Methanex-produced methanol sales | 24 | |||
Other, net | (15 | ) | ||
Increase in total cash costs | $ | (335 | ) |
Methanex-Produced Methanol Costs
Natural gas is the primary feedstock at our methanol facilities and is the most significant component of Methanex-produced methanol costs. We purchase natural gas for the Chile, Trinidad, Egypt and New Zealand methanol facilities under natural gas purchase agreements where the terms 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 this pricing relationship enables these facilities to be competitive throughout the methanol price cycle. Methanex-produced methanol costs were higher in 2011 compared with 2010 by $144 million, primarily due to the impact of higher methanol prices on our natural gas costs and the timing of inventory flows. For additional information regarding our natural gas agreements refer to theSummary of Contractual Obligations and Commercial Commitments section on page 27.
Purchased Methanol Costs
A key element of our corporate strategy is global leadership, and as such we have built a leading market position in each of the 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 lowest-cost 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. The higher average methanol prices in 2011 increased the cost of purchased methanol per tonne and this decreased Adjusted EBITDA by $200 million compared with 2010.
Proportion of Methanex-Produced Methanol Sales
The cost of purchased methanol is directly linked to the selling price for methanol at the time of purchase and the cost of purchased methanol is generally higher than the cost of Methanex-produced methanol. Accordingly, an increase in the proportion of Methanex-produced methanol sales results in a decrease in our overall cost structure for a given period. The proportion of Methanex-produced methanol sales for the year ended 2011 was higher compared with 2010 and this increased Adjusted EBITDA by $24 million. We increased our production capacity in 2011 with the start-up of the new methanol plant in Egypt and the restart of our facility in Medicine Hat, Alberta. Higher sales volumes from these facilities in 2011 were partially offset by lower sales of methanol produced at our Chile and Titan facilities.
Other, net
We experienced an equipment failure at our Atlas facility in July 2011 and operated this facility at approximately 70% of capacity for the remainder of the year. Our operations are covered by business interruption insurance and we have recorded $17 million for the estimated insurance proceeds net of deductibles related to 2011 as a result of this event.
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. Due to the significant reduction of production levels in Chile since mid-2007, we have had excess shipping capacity that is subject to fixed time charter costs. We have been successful in mitigating some of these costs by entering into sub-charters and third-party
METHANEX | | Annual Report 2011 | 21 |
Management’s Discussion & Analysis
backhaul arrangements. However, excess capacity in the global tanker market over the last few years has made it more difficult to mitigate these costs. For the year ended December 31, 2011 compared with 2010, ocean freight and other logistics costs were higher by $15 million primarily as a result of fewer backhaul opportunities and higher bunker fuel costs.
Other cash costs in 2011 were $17 million higher than 2010 due primarily to the impact of a weaker US dollar on our cost structure and the timing of recognizing fixed manufacturing costs in earnings. We allocate fixed manufacturing costs to inventory based on the normal operating capacity of our manufacturing facilities. During 2011, primarily as a result of our facilities in Chile and Trinidad operating below capacity for certain periods, a portion of fixed manufacturing costs were charged directly to earnings rather than to inventory and this decreased Adjusted EBITDA in 2011.
Mark-to-Market Impact of Share-Based Compensation
We grant share-based awards as an element of compensation. Share-based compensation expense (recovery) includes an amount related to the grant-date fair value and a mark-to-market impact as a result of subsequent changes in the Company’s share price. The grant-date fair value amount is included in Adjusted EBITDA. The mark-to-market impact of share-based compensation as a result of changes in the share price is excluded from Adjusted EBITDA and analyzed separately.
($ MILLIONS, EXCEPT PER SHARE AMOUNTS) | 2011 | 2010 | ||||||
Methanex Corporation share price1 | $ | 22.82 | $ | 30.40 | ||||
Grant-date fair value expense included in Adjusted EBITDA | 16 | 17 | ||||||
Mark-to-market impact due to change in share price | (21 | ) | 19 | |||||
Total share-based compensation expense (recovery) | $ | (5 | ) | $ | 36 |
1 | US dollar share price of Methanex Corporation as quoted on NASDAQ Global Market on the last trading day of the respective period. |
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 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.
Commencing in 2010, we granted share appreciation rights (SARs) and tandem share appreciation rights (TSARs) to replace grants of stock options with the objective to reduce dilution to shareholders. SARs and 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 value of SARs and TSARs are re-measured each quarter using the Black-Scholes option pricing model, which considers the market value of the Company’s common shares on the last trading day of the quarter.
Deferred, restricted and performance share units are grants of notional common shares that are redeemable for cash upon vesting 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 deferred, restricted and performance share units, the fair 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.
For all the share-based awards, the grant-date fair value is recognized in earnings and Adjusted EBITDA over the related vesting period for the proportion of the service that has been rendered at each reporting date. Any mark-to-market impact as a result of subsequent changes in the share price are also recognized in earnings over the related vesting period for the proportion of the service that has been rendered at each reporting date but are excluded from Adjusted EBITDA.
22 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
Depreciation and Amortization
Depreciation and amortization was $157 million for the year ended December 31, 2011 compared with $137 million for 2010. The increase in depreciation and amortization for 2011 compared with 2010 was primarily a result of the commencement of depreciation associated with the methanol facilities in Egypt (100% basis) and Medicine Hat and due to a portion of depreciation being charged directly to earnings rather than to inventory due to lower production from our Titan and Chile facilities.
Finance Costs
($ MILLIONS) | 2011 | 2010 | ||||||
Finance costs before capitalized interest | $ | 69 | $ | 69 | ||||
Less capitalized interest related to Egypt plant under construction | (7 | ) | (38 | ) | ||||
Finance costs | $ | 62 | $ | 31 |
Finance costs before capitalized interest were $69 million for each of the years ended December 31, 2011 and 2010. Capitalized interest relates to interest costs capitalized during the construction of the 1.26 million tonne per year methanol facility in Egypt (100% basis). The Egypt methanol facility commenced production in mid-March 2011 and, accordingly, we ceased capitalization of interest costs from this date.
Finance Income and Other Expenses
Finance income and other expenses were $2 million for each of the years ended December 31, 2011 and 2010.
Income Taxes
We recorded income tax expense of $56 million for the year ended December 31, 2011 compared with $34 million for 2010. The effective tax rate for the year ended December 31, 2011 was approximately 20% compared with 27% for the same period in 2010. Included in income before tax for 2010 was a before- and after-tax gain of $22.2 million on the sale of our land and terminal assets in Kitimat, British Columbia. Excluding this item, the effective tax rate for 2010 was 32%.
We earn the majority of our pre-tax earnings in Trinidad, Egypt, Chile, Canada and New Zealand. In Chile and Trinidad, the statutory tax rate is 35%, and in Egypt, the statutory tax rate is 25%. Our Atlas facility in Trinidad has partial relief from corporate income tax until 2014. During the year ended December 31, 2011, we earned a higher proportion of our consolidated income from Egypt, Canada and New Zealand and a lower proportion of our consolidated income from Chile and this resulted in a lower effective tax rate in 2011 compared with 2010. We have loss carryforwards and other temporary differences in Canada and New Zealand of $304 million and $82 million, respectively, which have not been recognized for accounting purposes.
In Chile, the tax rate consists of a first-tier tax that is payable when income is earned and a second-tier tax that is due when earnings are distributed from Chile. The second category tax is initially recorded as future income tax expense and is subsequently reclassified to current income tax expense when earnings are distributed. Accordingly, the ratio of current income tax expense to total income tax expense is highly dependent on the level of cash distributed from Chile.
For additional information regarding income taxes, refer to note 16 of our 2011 consolidated financial statements.
METHANEX | | Annual Report 2011 | 23 |
Management’s Discussion & Analysis
LIQUIDITY AND CAPITAL RESOURCES
($ MILLIONS) | 2011 | 2010 | ||||||
Cash flows from operating activities: | ||||||||
Cash flows from operating activities before changes in non-cash working capital1 | $ | 444 | $ | 303 | ||||
Changes in non-cash working capital | 36 | (120 | ) | |||||
480 | 183 | |||||||
Cash flows from investing activities: | ||||||||
Property, plant and equipment | (128 | ) | (122 | ) | ||||
Oil and gas properties | (30 | ) | (24 | ) | ||||
GeoPark repayments | 8 | 20 | ||||||
Proceeds on sale of assets | – | 32 | ||||||
Other, net | – | (1 | ) | |||||
Changes in non-cash working capital relating to investing activities | 7 | (2 | ) | |||||
(143 | ) | (97 | ) | |||||
Cash flows from financing activities: | ||||||||
Dividend payments | (62 | ) | (57 | ) | ||||
Interest paid, including interest rate swap settlements | (60 | ) | (64 | ) | ||||
Proceeds from limited recourse debt | 3 | 68 | ||||||
Repayment of limited recourse debt | (50 | ) | (31 | ) | ||||
Change in project finance reserve accounts | (27 | ) | – | |||||
Equity contributions by non-controlling interests | 19 | 26 | ||||||
Distributions to non-controlling interests | (8 | ) | (1 | ) | ||||
Proceeds on issue of shares on exercise of stock options | 11 | 9 | ||||||
Repayment of finance leases and other long-term liabilities | (6 | ) | (12 | ) | ||||
(180 | ) | (62 | ) | |||||
Increase in cash and cash equivalents | 157 | 24 | ||||||
Cash and cash equivalents, end of year | $ | 351 | $ | 194 |
1 | This is a non-GAAP measure. Refer to page 41 for a reconciliation to the most comparable GAAP measure. |
Cash Flow Highlights
Cash Flows from Operating Activities
Cash flows from operating activities for the year ended December 31, 2011 were $480 million compared with $183 million for 2010. The increase in cash flows from operating activities is primarily explained by higher net income before unusual item, after excluding depreciation and amortization, share-based compensation expense and finance costs, and changes in non-cash working capital. The following table provides a summary of these items for 2011 and 2010:
($ MILLIONS) | 2011 | 2010 | ||||||
Net income before unusual item1 | $ | 228 | $ | 72 | ||||
Add (deduct) non-cash items: | ||||||||
Depreciation and amortization | 157 | 137 | ||||||
Share-based compensation expense | (5 | ) | 36 | |||||
Finance costs | 62 | 31 | ||||||
Other, net | 2 | 27 | ||||||
Cash flows from operating activities before changes in non-cash working capital1 | 444 | 303 | ||||||
Changes in non-cash working capital: | ||||||||
Trade and other receivables | (59 | ) | (64 | ) | ||||
Inventories | (44 | ) | (52 | ) | ||||
Prepaid expenses | 2 | (3 | ) | |||||
Accounts payable and accrued liabilities, including long-term payables | 137 | (1 | ) | |||||
36 | (120 | ) | ||||||
Cash flows from operating activities | $ | 480 | $ | 183 | ||||
Adjusted cash flows from operating activities (attributable to Methanex shareholders)1 | $ | 392 | $ | 303 |
1 | These are non-GAAP measures. Refer to page 41 for a reconciliation to the most directly comparable GAAP measure. |
24 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
For a discussion of the changes in net income before unusual item, depreciation and amortization, share-based compensation expense and finance costs, refer to the analysis of our financial results on page 18.
Changes in non-cash working capital increased cash flows from operating activities by $36 million for the year ended December 31, 2011 compared with decreasing cash flows from operating activities by $120 million for the year ended December 31, 2010. The most significant change in non-cash working capital for 2011 was an increase in accounts payable and accrued liabilities of $137 million as higher methanol pricing resulted in higher natural gas payables and purchased methanol payables. Trade and other receivables increased in both 2011 and 2010, primarily as a result of higher methanol pricing and higher sales volumes. Inventories also increased in both 2011 and 2010, primarily as a result of the impact of higher methanol pricing on Methanex-produced and purchased methanol.
Adjusted cash flows from operating activities, which exclude the amounts associated with the 40% non-controlling interest in the methanol facility in Egypt and changes in non-cash working capital, were $392 million and $303 million for 2011 and 2010, respectively (refer toSupplemental Non-GAAP Measures on page 41 for a reconciliation from cash flows from operating activities to adjusted cash flows from operating activities). The change in adjusted cash flows from operating activities between 2011 and 2010 was primarily due to higher Adjusted EBITDA of $136 million. Refer to page 19 for a discussion of the change in Adjusted EBITDA.
Cash Flows from Investing Activities
In 2011, our priorities for allocating capital were funding the completion of the methanol project in Egypt and the restart of the Medicine Hat methanol facility, supporting natural gas development in Chile and investing to maintain the reliability of our existing plants.
During 2011, additions to property, plant and equipment totaled $128 million. Capital expenditures were $34 million for the completion of the methanol project in Egypt and $40 million for the restart of our Medicine Hat, Alberta plant. The remaining $54 million of expenditures include $30 million associated with turnarounds, catalyst and maintenance activities, and $24 million of costs incurred in relation to the expected restart of a second Motunui facility in 2012.
In 2011, we incurred $18 million related to our share of Dorado Riquelme expenditures and $12 million related to other oil and gas initiatives in southern Chile. We have an agreement with ENAP to invest in natural gas exploration and development in the Dorado Riquelme exploration block in southern Chile. Under the arrangement, we fund a 50% participation in the block and receive 100% of the natural gas produced in the block.
We also have agreements with GeoPark under which we have provided $57 million in financing to support and accelerate GeoPark’s natural gas exploration and development activities in southern Chile. During 2011, GeoPark repaid approximately $8 million, bringing cumulative repayments for this financing to $40 million as at December 31, 2011. We have no further obligations to provide funding to GeoPark.
Cash Flows from Financing Activities
During 2011, we increased our regular quarterly dividend by 10% to $0.17 per share, beginning with the dividend payable on June 30, 2011. Total dividend payments in 2011 were $62 million compared with $57 million in 2010.
We have limited recourse debt facilities totaling $530 million (100% basis) for the methanol facility in Egypt that were fully drawn at December 31, 2010. During 2011, project finance reserve accounts related to the limited recourse debt facilities increased by $27 million.
During 2011, we repaid $32 million on our Egypt limited recourse debt facilities, $16 million on our Atlas limited recourse debt facilities and $2 million on our other limited recourse debt facilities compared with total repayments in 2010 of $31 million.
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 (refer to theFinancial Instruments section on page 29 for more information). The cash settlements associated with these interest rate swap contracts during 2011 and 2010 were approximately $16 million and $16 million, respectively, and are included in interest paid.
METHANEX | | Annual Report 2011 | 25 |
Management’s Discussion & Analysis
During 2011, we received proceeds of $11 million on the issue of 0.6 million common shares on the exercise of stock options.
Liquidity and Capitalization
We maintain conservative financial policies and focus on maintaining our financial strength and flexibility through prudent financial management. Our objectives in managing liquidity and capital are to provide financial capacity and flexibility to meet our strategic objectives, to provide an adequate return to shareholders commensurate with the level of risk and to return excess cash through a combination of dividends and share repurchases.
The following table provides information on our liquidity and capitalization position as at December 31, 2011 and December 31, 2010:
($ MILLIONS, EXCEPT WHERE NOTED) | 2011 | 2010 | ||||||
Liquidity: | ||||||||
Cash and cash equivalents | $ | 351 | $ | 194 | ||||
Undrawn credit facilities | 200 | 200 | ||||||
Total liquidity | 551 | 394 | ||||||
Capitalization: | ||||||||
Unsecured notes | 349 | 348 | ||||||
Limited recourse debt facilities, including current portion | 554 | 599 | ||||||
Total debt | 903 | 947 | ||||||
Non-controlling interest | 197 | 156 | ||||||
Shareholders’ equity | 1,405 | 1,253 | ||||||
Total capitalization | $ | 2,505 | $ | 2,356 | ||||
Total debt to capitalization1 | 36 | % | 40 | % | ||||
Net debt to capitalization2 | 26 | % | 35 | % |
1 | Defined as total debt divided by total capitalization (including 100% of debt related to the Egypt methanol facility). |
2 | Defined as total debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents (including 100% of debt related to the Egypt methanol facility). |
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 employ 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.
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, 2011, we had a strong balance sheet with a cash balance of $351 million, including $37 million relating to the Egypt non-controlling interest, and a $200 million undrawn credit facility. We invest cash only in highly rated instruments that have maturities of three months or less to ensure preservation of capital and appropriate liquidity.
At December 31, 2011, our long-term debt obligations included $350 million in unsecured notes ($200 million that matures in 2012 and $150 million that matures in 2015), $483 million related to the Egypt limited recourse debt facilities and $65 million related to our Atlas limited recourse debt facilities. Subsequent to December 31, 2011, we issued $250 million of unsecured notes that mature in 2022.
We have covenant and default provisions on our long-term debt obligations and we also have certain covenants that could restrict access to the credit facility. The Egypt limited recourse debt facilities contain a covenant to complete by March 31, 2013 certain land title registrations and related mortgages that require action by Egyptian government entities. We do not believe that the finalization of these items is material. Refer to note 8 of the Company’s consolidated financial statements for further information.
26 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
At December 31, 2011, management believes the Company was in compliance with all of the covenants and default provisions related to its long-term debt obligations.
Our planned capital maintenance expenditures directed towards major maintenance, turnarounds and catalyst changes for current operations are estimated to be approximately $60 million for the period to the end of 2012. We also recently committed to restart a second facility in New Zealand with an estimated future capital cost of $60 million.
As previously discussed, we are focused on accessing natural gas to increase production at our existing sites in Chile and New Zealand. We are working with ENAP in the Dorado Riquelme block in southern Chile and with Kea in the Taranaki basin in New Zealand. For 2012, we expect our share of total contributions for strategic oil and gas exploration and development in Chile and New Zealand to be approximately $60 million.
We believe we are well positioned to meet our financial commitments and continue to invest to grow our business.
Summary of Contractual Obligations and Commercial Commitments
A summary of the estimated amount and estimated timing of cash flows related to our contractual obligations and commercial commitments as at December 31, 2011 is as follows:
($ MILLIONS) | 2012 | 2013-2014 | 2015-2016 | AFTER 2016 | TOTAL | |||||||||||||||
Long-term debt repayments | $ | 251 | $ | 115 | $ | 253 | $ | 299 | $ | 918 | ||||||||||
Long-term debt interest obligations | 49 | 66 | 35 | 38 | 188 | |||||||||||||||
Repayment of other long-term liabilities | 21 | 89 | 18 | 91 | 219 | |||||||||||||||
Natural gas and other | 248 | 323 | 204 | 1,233 | 2,008 | |||||||||||||||
Operating lease commitments | 136 | 200 | 137 | 340 | 813 | |||||||||||||||
$ | 705 | $ | 793 | $ | 647 | $ | 2,001 | $ | 4,146 |
The above table does not include costs for planned capital maintenance expenditures, costs for purchased methanol under offtake contracts 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 in response to various actions by the Argentinean government, including imposing a large increase to the duty on natural gas exports. Under the current circumstances, we do not expect to receive any further natural gas supply from Argentina.
Long-Term Debt Repayments and Interest Obligations
We have $200 million of unsecured notes that mature in 2012 and $150 million of unsecured notes that mature in 2015. The remaining debt repayments represent the total expected principal repayments relating to the Egypt project debt, our proportionate share of total expected principal repayments related to the Atlas limited recourse debt facilities 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, 2011. For additional information, refer to note 8 of our 2011 consolidated financial statements.
Subsequent to December 31, 2011, we issued $250 million of unsecured notes bearing an interest rate of 5.25% that mature in 2022 (effective yield 5.30%). These notes and the associated interest payments are excluded from the table above.
Repayments of Other Long-Term Liabilities
Repayments of other long-term liabilities represent contractual payment dates or, if the timing is not known, we have estimated the timing of repayment based on management’s expectations.
Natural Gas and Other
We have commitments under take-or-pay contracts to purchase annual quantities of 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.
METHANEX | | Annual Report 2011 | 27 |
Management’s Discussion & Analysis
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.
Most of the natural gas supply contracts for our facilities in Chile, Trinidad, Egypt and New Zealand 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 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 volumes and prices.
The natural gas commitments for our Chile facilities included in the above table relate to our natural gas contracts with ENAP, the Chilean state-owned energy company. These contracts represent approximately 20% of the natural gas requirements for our Chile facilities operating at capacity. These contracts have a base component and variable price component determined with reference to 12-month trailing average published industry methanol prices and have expiration dates that range from 2017 to 2025. Over the past few years, ENAP has delivered significantly less than the full amount of natural gas that it was required to deliver under these contracts.
We have an agreement with ENAP to accelerate natural gas exploration and development in the Dorado Riquelme exploration block in southern Chile. Under the arrangement, we fund a 50% participation in the block and take all natural gas produced from the block. We also have an arrangement with GeoPark to purchase all natural gas produced by GeoPark from the Fell block in southern Chile for a ten-year period. The pricing under this arrangement has a base component and a variable component determined with reference to a three-month trailing average of methanol prices. We cannot determine the amount of natural gas that will be purchased under these agreements in the future, and accordingly, no amounts have been included in the above table.
In Trinidad, we have take-or-pay supply contracts for natural gas, oxygen and other feedstock requirements and these are included in the above table. The variable component of our natural gas contracts in Trinidad is determined with reference to average published industry methanol prices each quarter and the base prices increase over time. The natural gas and oxygen supply contracts for Titan and Atlas expire in 2014 and 2024, respectively.
We have marketing rights for 100% of the production from our jointly owned plants (the Atlas plant in Trinidad in which we have a 63.1% interest and the new plant in Egypt in which we have a 60% interest), which results in purchase commitments of an additional 1.2 million tonnes per year of methanol offtake supply when these plants operate at capacity. At December 31, 2011, we also have methanol purchase commitments with other suppliers under offtake contracts for approximately 0.54 million tonnes for 2012. The pricing under the purchase commitments related to our 100% marketing rights from our jointly owned plants and the purchase commitments with other suppliers is referenced to pricing at the time of purchase or sale, and accordingly, no amounts have been included in the above table.
Operating Lease Commitments
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.
Off-Balance Sheet Arrangements
At December 31, 2011, 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.
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Management’s Discussion & Analysis
Financial Instruments
A financial instrument is any contract that gives rise to a financial asset of one party and a financial liability or equity instrument of another party. Financial instruments are either measured at amortized cost or fair value. 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 foreign exchange volatility and to 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 foreign exchange rates and variable interest rates. Derivative financial instruments are classified as held-for-trading and are recorded on the balance sheet at fair value. Changes in fair value of 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, 2011 and December 31, 2010:
($ MILLIONS) | 2011 | 2010 | ||||||
Financial assets: | ||||||||
Loans and receivables: | ||||||||
Cash and cash equivalents | $ | 351 | $ | 194 | ||||
Trade and other receivables, excluding current portion of GeoPark financing | 333 | 273 | ||||||
Project financing reserve accounts included in other assets | 40 | 12 | ||||||
GeoPark financing, including current portion | 18 | 26 | ||||||
Total financial assets1 | $ | 742 | $ | 505 | ||||
Financial liabilities: | ||||||||
Other financial liabilities: | ||||||||
Trade, other payables and accrued liabilities | $ | 306 | $ | 232 | ||||
Deferred gas payments included in other long-term liabilities | 51 | – | ||||||
Long-term debt, including current portion | 903 | 947 | ||||||
Financial liabilities held-for-trading: | ||||||||
Derivative instruments designated as cash flow hedges2 | 42 | 43 | ||||||
Total financial liabilities | $ | 1,302 | $ | 1,222 |
1 | The carrying amount of the financial assets represents the maximum exposure to credit risk at the respective reporting periods. |
2 | We have Egypt interest rate swaps designated as cash flow hedges and these are measured at fair value based on industry accepted valuation models and inputs obtained from active markets. |
At December 31, 2011, all of the financial instruments were recorded on the balance sheet at amortized cost with the exception of 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 $367 million as at December 31, 2011. The notional amount decreases over the expected repayment of the Egypt limited recourse debt facilities. At December 31, 2011, these interest rate swap contracts had a fair value of negative $42 million (December 31, 2010 – negative $43 million) recorded in other long-term liabilities. The fair value of these interest rate swap contracts will fluctuate until maturity. Changes in the fair value of derivative financial instruments designated as cash flow hedges have been recorded in other comprehensive income.
RISK FACTORS AND RISK MANAGEMENT
We are subject to risks that require prudent risk management. We believe the following risks, in addition to those described in theCritical Accounting Estimates section on page 38, to be among the most important for understanding the issues that face our business and our approach to risk management.
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Management’s Discussion & Analysis
Security of Natural Gas Supply and Price
Natural gas is the principal feedstock for producing methanol and it accounts for a significant portion of our operating costs. Accordingly, our results from operations depend in large part on the availability and security of supply and the price of natural gas. If, for any reason, we are unable to obtain sufficient natural gas for any of our plants on commercially acceptable terms or we experience interruptions in the supply of contracted natural gas, we could be forced to curtail production or close such plants, which could have an adverse effect on our results of operations and financial condition.
Chile
We have four methanol plants in Chile with a total production capacity of 3.8 million tonnes per year. Although we have long-term natural gas supply contracts in place that entitle us to receive a significant quantity of our total natural gas requirements in Chile from suppliers in Argentina, these suppliers have curtailed all gas supply to our plants in Chile since June 2007 in response to various actions by the Argentinean government that include imposing a large increase to the duty on natural gas exports from Argentina. Since then we have been operating our Chile facilities significantly below site capacity. We are not aware of any plans by the Government of Argentina to decrease or remove this duty. Under the current circumstances, we do not expect to receive any further natural gas supply from Argentina.
Over the past few years, ENAP, our primary supplier in Chile, has delivered significantly less than the full amount of natural gas that it was obligated to deliver to us primarily due to declines in the production rates of existing wells. The shortfalls in natural gas deliveries from ENAP are generally greater in the southern hemisphere winter due to the need to satisfy increased demand for residential uses in the region. We are focused on sourcing additional gas supply for our Chile facilities from suppliers in Chile as discussed in more detail in theProduction Summary – Chile section on page 15. We are pursuing investment opportunities with ENAP, GeoPark and others to help accelerate natural gas exploration and development in southern Chile. In addition, over the past few years, the Government of Chile has completed international bidding rounds to assign natural gas exploration areas that lie close to our production facilities and announced the participation of several international oil and gas companies.
As we entered 2012, we were operating one plant at approximately 40% capacity at our Chile site. We are working closely with ENAP to manage through the seasonality of gas demand with the objective of being able to maintain our operations throughout the southern hemisphere winter season in 2012. The future operating rate of our Chile site is primarily dependent on production rates from existing natural gas fields, the level of natural gas deliveries from future exploration and development activities in southern Chile, and demand for natural gas for residential purposes, which is higher in the southern hemisphere winter. We cannot provide assurance regarding the production rates from existing natural gas fields or that we, ENAP, GeoPark or others will be successful in the exploration and development of natural gas or that we will obtain any additional natural gas from suppliers in Chile on commercially acceptable terms. As a result, we cannot provide assurance about the level of natural gas supply or whether we will be able to source sufficient natural gas to operate any capacity in Chile or that we will have sufficient future cash flows from Chile to support the carrying value of our Chilean assets and that this will not have an adverse impact on our results of operations and financial condition.
Trinidad
Natural gas for our two methanol production facilities in Trinidad, with a total production capacity of 2.05 million tonnes per year, is supplied under long-term contracts with The National Gas Company of Trinidad and Tobago Limited. The contracts for Titan and Atlas expire in 2014 and 2024, respectively. Although Titan and Atlas are located close to other natural gas reserves in Trinidad, which we believe could be a source of supply after the expiration of these natural gas supply contracts, we cannot provide assurance that we would be able to secure access to such natural gas under long-term contracts on commercially acceptable terms and that this will not have an adverse impact on our results of operations and financial condition.
Over the past year, large industrial consumers in Trinidad, including our Titan facility, experienced periodic curtailments of natural gas supply due to a mismatch between upstream commitments to supply The National Gas Company in Trinidad (NGC) and downstream demand from NGC’s customers which becomes apparent when an upstream technical problem arises. We are engaged with key stakeholders to find a solution to this issue, but in the meantime expect to continue to experience some gas
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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.
New Zealand
We have three plants in New Zealand with a total production capacity of up to 2.23 million tonnes per year. Two plants are located at Motunui and the third is located at nearby Waitara Valley. In 2004, we idled our two Motunui plants and continued to operate the Waitara Valley plant. As a result of improvements to natural gas availability and deliverability, in 2008 we restarted one 0.85 million tonne per year plant in Motunui and idled the 0.53 million tonne per year Waitara Valley plant. We recently announced our commitment to restart a second Motunui facility in mid-2012 which will add up to 0.65 million tonnes of incremental annual capacity to our New Zealand operations. In support of the restart, we have entered into a ten-year gas supply agreement that is expected to supply up to half of the 1.5 million tonnes of annual capacity at the Motunui site. We have an additional 0.53 million tonne per year plant at the nearby Waitara Valley site which remains idle. This facility provides additional potential to increase New Zealand production depending on methanol supply and demand dynamics and the availability of competitively priced natural gas.
We continue to pursue opportunities to contract additional natural gas supply to our plants in New Zealand and are also pursuing natural gas exploration and development opportunities in that country. We have an agreement with Kea Petroleum, an oil and gas exploration and development company, to explore areas of the Taranaki basin, which is close to our plants.
The future operation of our New Zealand facilities depends on methanol industry supply and demand, the ability of our contracted suppliers to meet their commitments, the availability of natural gas on commercially acceptable terms, and the success of ongoing exploration and development activities. We cannot provide assurance that we will be able to secure additional gas for our facilities on commercially acceptable terms or that the ongoing exploration and development activities in New Zealand will be successful to enable our operations to operate at capacity.
Egypt
Natural gas for the 1.26 million tonne per year production facility in Egypt, which commenced commercial production in March 2011, is supplied under a single long-term contract with the government-owned Egyptian Natural Gas Holding Company (EGAS). 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 and, accordingly, the natural gas supplied under this long-term contract could be impacted by the supply and demand balance of natural gas in Egypt. There can be no assurance that we will not experience curtailments of natural gas supply, which would have an adverse impact on our results of operations and financial condition.
Refer also to theForeign Operations section on page 34.
Canada
We restarted our 0.47 million tonne per year facility in Medicine Hat, Alberta in April 2011. We have a program in place to purchase natural gas on the Alberta gas market and we believe that the long-term natural gas dynamics in North America will support the long-term operation of this facility.
The future operation of our Medicine Hat facility depends on methanol industry supply and demand and our ability to secure sufficient natural gas on commercially acceptable terms. There can be no assurance that we will be able to continue to secure sufficient natural gas for our Medicine Hat facilities on commercially acceptable terms and that this will not have an adverse impact on our results of operations and financial condition.
Methanol Price Cyclicality and Methanol Supply and Demand
The methanol business is a highly competitive commodity industry and prices are affected by supply and demand fundamentals and global energy prices. Methanol prices have historically been, and are expected to continue to be, characterized by significant 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
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Management’s Discussion & Analysis
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 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.
Global Economic Conditions
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 and insurers. While the demand for methanol grew in 2011 and methanol prices were relatively stable, 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 Demand
Demand for Methanol – General
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 carcinogenicity classification for methanol as part of a standard review of chemicals under its Integrated Risk Information System (IRIS). Methanol is currently unclassified under IRIS. A draft assessment for methanol was released by the EPA in January 2010 classifying methanol as “Likely to Be Carcinogenic to Humans”. As of June 2010, the EPA’s methanol assessment has been placed “on hold”. In April 2011, the EPA announced that it was dividing the draft assessment for methanol into carcinogenic and non-carcinogenic assessments. The timeline for the carcinogenic assessment remains unknown while the non-carcinogenic assessment is expected in 2012. We are unable to determine whether the current draft classification will be maintained in the final 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.
Demand for Methanol in the Production of Formaldehyde
In 2011, methanol demand for the production of formaldehyde represented approximately 33% of global demand. The largest use for formaldehyde is as a component of urea-formaldehyde and phenol-formaldehyde resins, which are used as wood 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 and in June 2010, the EPA released its draft formaldehyde assessment, proposing formaldehyde as “Known to be Carcinogenic to Humans”. The timeline for the release of the final assessment of formaldehyde is currently unknown.
In May 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
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Management’s Discussion & Analysis
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 NCI has not outlined its expected schedule with regards to the second portion of the study, which focuses on nasopharyngeal cancer and other cancers. The International Agency for Research on Cancer also concluded that there is sufficient evidence in humans of a causal association of formaldehyde with leukemia. Finally, in June 2011, the US Department of Health and Human Services’ (HHS) National Toxicology Program (NTP) 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.”
In 2010, the USFormaldehyde Standards for Composite Wood Products Act became effective. The legislation sets new national emissions standards for formaldehyde in various wood products. These standards require a reduction in the emissions standards for formaldehyde used in hardwood plywood, particleboard and medium-density fibreboard sold in the United States. However, most United States producers are believed to have the technology in place to meet the new emissions requirements and we do not expect a significant impact on the demand for methanol for formaldehyde in the United States.
We are unable to determine at this time if the EPA, the HHS 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.
Demand for Methanol in the Production of MTBE
In 2011, methanol demand for the production of MTBE represented approximately 12% of global methanol demand. Demand growth has been particularly strong in China. MTBE is used primarily as a source of octane and as an oxygenate for gasoline to reduce the amount of harmful exhaust emissions from motor vehicles.
Several years ago, environmental concerns and legislative action related to gasoline leaking into water supplies from underground gasoline storage tanks in the United States resulted in the phase-out of MTBE as a gasoline additive in the United States. We believe that methanol has not been used in the United States to make MTBE for use in domestic fuel blending since 2007. However, approximately 0.65 million tonnes of methanol was used in the United States in 2011 to produce MTBE for export markets, where demand for MTBE has continued at strong levels. While we currently expect demand for methanol for MTBE production in the United States for 2012 to remain steady, it could decline materially if export demand was impacted by legislation or policy changes.
Additionally, the EPA in the United States is preparing an IRIS review of the human health effects of MTBE, including its potential carcinogenicity, and its final report is expected to be released in 2012.
The European Union issued a final risk assessment report on MTBE in 2002 that permitted the continued use of MTBE, although several risk-reduction measures relating to the storage and handling of fuels were recommended. Governmental efforts in recent years in some countries, primarily in the European Union and Latin America, to promote biofuels and alternative fuels through legislation or tax policy are putting competitive pressures on the use of MTBE in gasoline in these countries. However, due to strong MTBE demand in other countries, we have observed methanol demand growth for MTBE production. We cannot provide assurance that this will continue.
Although MTBE demand has remained strong outside of the United States, we cannot provide assurance that further legislation banning or restricting the use of MTBE or promoting alternatives to MTBE will not be passed or that negative public perceptions will not develop outside of the United States, either of which would lead to a decrease in the global demand for methanol for use in MTBE. Declines in demand for methanol for use in MTBE could have an adverse effect on our results of operations and financial condition.
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Management’s Discussion & Analysis
Foreign Operations
The majority of our operations and investments are located outside of North America, in Chile, Trinidad, New Zealand, Egypt, 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.
During 2011, there were periods of anti-government protests and civil unrest in Egypt. For the safety and security of our employees, we took the decision to temporarily curtail the operations of the methanol plant in Damietta, Egypt in November 2011. The methanol plant is currently operating. We cannot provide assurance that future developments in Egypt, including changes in government or further civil unrest or other disturbances, would not have an adverse impact on the ongoing operations or on the terms or enforceability of our natural gas or other contracts and that this would not have an adverse impact on our results of operations and financial condition.
Because we derive the majority 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 and capital expenditures, 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 and the Egyptian pound. 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 and operating expenses and capital expenditures. A portion of our revenue is earned in euros, Canadian dollars and British pounds. 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.
In June 2009, the Chinese Ministry of Commerce (MOFCOM) began an investigation into domestic methanol producer allegations of the dumping of methanol from New Zealand, Saudi Arabia, Indonesia and Malaysia. In late December 2010, MOFCOM issued its Final Determination and recommended that duties of approximately 9% be imposed on imports from existing producers in New Zealand, Malaysia and Indonesia for five years starting from December 24, 2010. However, citing special circumstances, the Customs Tariff Commission of the Chinese State Council decided to suspend enforcement of the anti-dumping measures, which will allow methanol from all three countries to enter into China without the imposition of additional duties. In the event that the suspension is lifted, we do not expect there would be any significant impact on industry supply/demand fundamentals and we would realign our supply chain. However, we cannot provide assurance that the suspension will not be lifted or that the Chinese government will not impose duties or other measures in the future, which actions could have an adverse effect on our results of operations and financial condition.
Methanol is a globally traded commodity that is produced by many producers at facilities located in many countries 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
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Management’s Discussion & Analysis
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.
Liquidity Risk
We have an undrawn $200 million credit facility that expires in mid-2015. This facility is provided by highly rated financial institutions and our ability to access 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, 2011, our long-term debt obligations include $350 million in unsecured notes ($200 million that matures in 2012 and $150 million that matures in 2015), $483 million related to the Egypt limited recourse debt facilities, $65 million related to the Atlas limited recourse debt facilities 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 Atlas joint venture and Egypt entity (“limited recourse subsidiaries”) and include restrictions on liens and sale and lease-back transactions, or 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 Atlas and Egypt limited recourse debt facilities are described as limited recourse as they are secured only by the assets of the Atlas joint venture and the Egypt entity, respectively. Accordingly, the lenders to the limited recourse debt facilities have no recourse to the Company or its other subsidiaries. The Atlas and Egypt limited recourse debt facilities have customary covenants and default provisions that apply only to these entities, including restrictions on the incurrence of additional indebtedness, a requirement to fulfill certain conditions before the payment of cash or other distributions and a restriction on these distributions if there is a default subsisting.
The Egypt limited recourse debt facilities contain a covenant to complete by March 31, 2013 certain land title registrations and related mortgages that require action by Egyptian government entities. We do not believe that the finalization of these items is material. We cannot provide assurance that we will be able to obtain a waiver from the lenders.
For additional information regarding long-term debt, refer to note 8 of our 2011 consolidated financial statements.
Subsequent to December 31, 2011, we issued $250 million of unsecured notes that mature in 2022.
We cannot provide assurance that we will be able to access new financing in the future 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 and to accelerate the due date of the principal and accrued interest on any outstanding loans. 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.
Customer Credit Risk
Most of 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 of operations and financial condition. Although credit losses have not been significant in the past, this risk still exists.
Operational Risks
Production Risks
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 unforeseen 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
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Management’s Discussion & Analysis
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.
Purchased Product Price Risk
In addition to the sale of methanol produced at our plants, we also purchase methanol produced by others on the spot market and through purchase contracts to meet our customer commitments and support our marketing efforts. We have adopted the first-in, first-out method of accounting for inventories and it generally takes between 30 and 60 days to sell the methanol we purchase. Consequently, we have the risk of holding losses on the resale of this product to the extent that methanol prices decrease from the date of purchase to the date of sale. Holding losses, if any, on the resale of purchased methanol could have an adverse effect on our results of operations and financial condition.
Distribution Risks
Excess capacity within our fleet of ocean vessels resulting from a prolonged plant shutdown or other event could also have an adverse effect on our results of operations and financial condition. Due to the significant reduction of production levels at our Chilean facilities since mid-2007, we have had excess shipping capacity that is subject to fixed time charter costs. We have been successful in mitigating some of these costs by entering into sub-charters and third-party backhaul arrangements, although there has been significant excess global shipping capacity over the last few years that has made it more difficult to mitigate these costs. If we are unable to mitigate these costs in the future, or if we suffer any other disruptions in our distribution system, this could have an adverse effect on our results of operations and financial condition.
Insurance Risks
Although we maintain operational and construction insurances, 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.
New Zealand Plant Restart
We believe that our estimates of project costs and anticipated completion for the restart of our second Motunui plant in New Zealand are reasonable. However, we cannot provide any assurance that the cost estimates will not be exceeded or that the facility will begin commercial production within the anticipated schedule, if at all, or that the facility will operate at its designed capacity or on a sustained basis. This could have an adverse impact on results of operations and financial condition.
New Capital Projects
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, developing and not exceeding acceptable project cost estimates, constructing and completing the projects within the contemplated 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.
Environmental Regulation
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
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Management’s Discussion & Analysis
environmental laws. Non-compliance with these laws and regulations may give rise to work orders, fines, injunctions, civil liability and criminal sanctions.
As a result of frequently scheduled external and internal audits, we believe that we materially comply with all existing environmental, health and safety laws and regulations to which our operations are subject. 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.
We believe that minimizing emissions and waste from our business activities is good business practice. Carbon dioxide (CO2) is a significant 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 by-product hydrogen. We continually strive to increase the energy efficiency of our plants, which not only reduces the use of energy but also minimizes CO2 emissions. We have reduced CO2 emission intensity in our manufacturing operations by 31% between 1994 and 2011 through asset turnover, improved plant reliability, and energy efficiency and emissions management. Plant efficiency, and thus CO2 emission, is highly dependent on a particular design of the methanol plant, so our level of CO2 emissions 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 fuels by our ocean vessels based on the volume of product transported. Between 2002 and 2011, we reduced our CO2 intensity (tonnes of CO2 from fuel burned per tonne of product moved) from marine operations by nearly 22%. We also actively support global industry efforts to voluntarily reduce both energy consumption and CO2 emissions.
We manufacture methanol in Chile, Trinidad, Egypt, New Zealand and Canada. All of these countries have signed and ratified the Kyoto Protocol; however, Canada has since removed itself from that Agreement. Under the Kyoto Protocol, the developing nations of Chile, Trinidad and Egypt are not currently required to reduce greenhouse gases (“GHGs”), whereas our production in New Zealand and Canada is subject to GHG reduction regulations. We cannot predict whether GHG reductions will be required in Chile, Trinidad or Egypt in the future, which could have a significant adverse impact on our results of operation and financial condition.
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, and the legislation provides further moderation of any residual cost exposure until the end of 2012. Consequently, we do not believe that these costs will be significant to the end of 2012. However, after this date the moderating features are expected to be removed and our eligibility for free allocation of emissions units will be progressively reduced. As a consequence, we will likely incur increased costs after 2012. It is impossible to accurately quantify the impact on our business after 2012 and therefore we cannot provide assurance that the ETS will not have a significant adverse impact on our results of operation and financial condition after 2012.
Medicine Hat is located in the Canadian province of Alberta, which has an established GHG reduction regulation that applies to our plant. The regulation requires facilities to reduce emissions intensities by up to 12% of their established emissions intensity baseline. “Emissions intensity” means the quantity of specified GHGs released per unit of production from that facility. In order to meet the reduction obligation, a facility can choose to make emissions reduction improvements or it can opt to purchase either offset credits or “technology fund” credits for CDN$15 per tonne of CO2 equivalent. Financial obligations are set to begin in 2014 and based on the expected GHG baseline intensity, we do not believe that, when applied, the cost will be significant.
METHANEX | | Annual Report 2011 | 37 |
Management’s Discussion & Analysis
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.
Legal Proceedings
The Board of Inland Revenue of Trinidad and Tobago issued an assessment in 2011 against our 63.1% owned joint venture, Atlas Methanol Company Unlimited (“Atlas”), in respect of the 2005 financial year. All subsequent tax years remain open to assessment. The assessment relates to the pricing arrangements of certain long-term fixed-price sales contracts that extend to 2014 and 2019 related to methanol produced by Atlas. The impact of the amount in dispute for the 2005 financial year is nominal as Atlas was not subject to corporation income tax in that year. Atlas has partial relief from corporation income tax until 2014.
The Company has lodged an objection to the assessment. Based on the merits of the case and legal interpretation, management believes its 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 2011 consolidated financial statements for our significant accounting policies.
Property, Plant and Equipment
Our business is capital intensive and has required, and will continue to require, significant investments in property, plant and equipment. At December 31, 2011, the net book value of our property, plant and equipment was $2,233 million.
Capitalization
Property, plant and equipment are initially recorded at cost. Cost includes expenditures that are directly attributable to the acquisition of the asset. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to a working 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, 2011, we have accrued $25.9 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 today’s 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
We estimate the useful lives of property, plant and equipment for our major assets, and this is used as the basis for recording depreciation and amortization. Depreciation and amortization is generally provided on a straight-line basis at rates calculated to amortize the cost of the asset from the beginning of commercial operations over their estimated useful lives to estimated residual value. The estimated useful lives of our buildings, plant installations and machinery is 5 to 25 years.
Oil and Gas Properties
Exploration and evaluation costs incurred for oil and natural gas exploration properties with unproven reserves are capitalized to other assets. Upon recognition of proven reserves and internal approval for development, these costs are transferred to property, plant and equipment. Costs associated with properties with no proven reserves are transferred to property, plant and equipment and become subject to depreciation when they have been deemed abandoned by management. Subsequent costs incurred for
38 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
oil and natural gas properties with proven reserves are capitalized to property, plant and equipment. Oil and gas costs included in property, plant and equipment are depreciated using a unit-of-production method, taking into consideration estimated proven reserves and estimated future development costs.
Proven and probable reserves for oil and natural gas properties are estimated based on independent reserve reports and represent the estimated quantities of natural gas that are considered commercially feasible. These reserve estimates are used to determine depreciation and to assess the carrying value of oil and natural gas properties.
Recoverability of Asset Carrying Values
Property, Plant and Equipment and Oil and Gas Properties
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 change 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.
Recoverability of long-lived assets is measured by comparing the carrying value of an asset or cash-generating unit to estimated pre-tax fair value, which is determined by measuring the pre-tax cash flows expected to be generated from the asset or cash-generating unit over their estimated useful life discounted by a pre-tax discount rate. An impairment writedown is recorded for the difference that the carrying value exceeds the pre-tax fair value. 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 purposes of recognition and measurement of an impairment writedown, 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: (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 asset impairment charges or by changes in depreciation and amortization rates related to property, plant and equipment.
The four methanol facilities at the Company’s Chile site, the Chile oil and gas properties included in Property, Plant and Equipment, and the Chile oil and gas assets accounted for as Other Assets are considered as a single cash-generating unit (“Chile cash-generating unit”). Production from the site was lower than expected in 2011 as a result of lower natural gas deliveries, and as a consequence, the carrying value of the Chile cash-generating unit, being $650 million on a pre-tax basis and $460 million on a post-tax basis, was tested for recoverability. The estimated future pre-tax cash flows were discounted to a present value using a pre-tax discount rate based on the Company’s weighted average cost of capital. Based on the test performed, the carrying value of the Company’s Chile cash-generating unit is recoverable.
METHANEX | | Annual Report 2011 | 39 |
Management’s Discussion & Analysis
Inventories
Inventories are valued at the lower of cost, determined on a first-in, first-out basis, and estimated net realizable value. The cost of our inventory, for both Methanex-produced methanol as well as methanol we purchase from others, is impacted by methanol prices at the time of production or purchase. The net realizable value of inventories will depend on methanol prices when sold. Inherent uncertainties exist in estimating future methanol prices and therefore the net realizable value of our inventory. Methanol prices are influenced by supply and demand fundamentals, industrial production, energy prices and the strength of the global economy.
Income Taxes
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, 2011, we had recognized future tax assets of $115 million and unrecognized future income tax assets of approximately $100 million. 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.
Financial Instruments
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. Changes in the fair value of derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges, in which case the 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, 2011, 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 approximated their carrying value of negative $42 million. Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in variable interest rates.
INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS)
Transition from Canadian Generally Accepted Accounting Principles (Canadian GAAP) to IFRS
The year ending December 31, 2011 with comparative results for 2010 is our first period reported under International Financial Reporting Standards (IFRS). All comparative figures have been restated to be in accordance with IFRS, unless specifically noted otherwise. For a description of the significant accounting policies the Company has adopted under IFRS, including the estimates and judgments we consider most significant in applying those accounting policies, please refer to note 2 of the consolidated financial statements.
Our financial statements were prepared in accordance with Canadian GAAP until December 31, 2010. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosures. The transition to IFRS had a cumulative impact on the Company’s shareholders’ equity of $25 million as of January 1, 2010, excluding the presentation reclassification of the non-controlling interests.
Adoption of IFRS requires the application of IFRS 1,First-time Adoption of International Financial Reporting Standards, which provides guidance for an entity’s initial adoption of IFRS. IFRS 1 gives entities adopting IFRS for the first time a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRS. To help users of the financial statements better understand the impact of the adoption of IFRS on the Company, we have provided
40 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
reconciliations from Canadian GAAP to IFRS for total assets, liabilities and equity, as well as net income and comprehensive income, for the comparative reporting periods. Please refer to note 24 of the consolidated financial statements for a detailed description of the IFRS 1 exemptions we elected to apply and reconciliations between IFRS and Canadian GAAP.
ANTICIPATED CHANGES TO INTERNATIONAL FINANCIAL REPORTING STANDARDS
Consolidation and Joint Arrangement Accounting
In May 2011, the IASB issued new accounting standards related to consolidation and joint arrangement accounting. The IASB has revised the definition of “control,” which is a criterion for consolidation accounting. In addition, changes to IFRS in the accounting for joint arrangements were issued that, under certain circumstances, removed the option for proportionate consolidation accounting so that the equity method of accounting for such interests would need to be applied. The impact of applying consolidation accounting or equity accounting does not result in any change to net earnings or shareholders’ equity, but would result in a significant presentation impact. We are currently assessing the impact on our financial statements. We currently account for our 63.1% interest in Atlas Methanol Company using proportionate consolidation accounting and this represents the most significant potential change under these new standards. The effective date for these standards is for periods commencing on or after January 1, 2013, with earlier adoption permitted.
Leases
As part of their global conversion project, the International Accounting Standards Board (IASB) and the US Financial Accounting Standards Board (“FASB”) issued a joint Exposure Draft in 2010 proposing that lessees would be required to recognize all leases on the statement of financial position. We have a fleet of ocean-going vessels under time charter agreements with terms of up to 15 years, which are currently accounted for as operating leases. The proposed rules would require these time charter agreements to be recorded on the Consolidated Statements of Financial Position, resulting in a material increase to total assets and liabilities. The IASB and FASB currently expect to issue a re-exposed draft in 2012.
SUPPLEMENTAL NON-GAAP MEASURES
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 cash flows from operating activities, operating income, net income before unusual items and diluted net income before unusual items per share. 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 (Attributable to Methanex Shareholders)
Adjusted EBITDA differs from the most comparable GAAP measure, cash flows from operating activities, because it does not include changes in non-cash working capital, other cash payments related to operating activities, share-based compensation excluding mark-to-market impact, other non-cash items, taxes paid, finance income and other expenses, and amounts associated with the 40% non-controlling interest in the methanol facility in Egypt.
METHANEX | | Annual Report 2011 | 41 |
Management’s Discussion & Analysis
The following table shows a reconciliation of cash flows from operating activities to Adjusted EBITDA:
($ MILLIONS) | 2011 | 2010 | ||||||
Cash flows from operating activities | $ | 480 | $ | 183 | ||||
Add (deduct): | ||||||||
Changes in non-cash working capital | (36 | ) | 120 | |||||
Other cash payments, including share-based compensation | 10 | 6 | ||||||
Share-based compensation expense, excluding mark-to-market impact | (16 | ) | (17 | ) | ||||
Other non-cash items | (3 | ) | (8 | ) | ||||
Income taxes paid | 46 | 9 | ||||||
Finance income and other expenses | (2 | ) | (2 | ) | ||||
Net (income) loss attributable to non-controlling interests | (27 | ) | 2 | |||||
Non-controlling interests adjustments1 | (25 | ) | (2 | ) | ||||
Adjusted EBITDA (attributable to Methanex shareholders) | $ | 427 | $ | 291 |
1 | This adjustment represents finance costs, income tax expense, and depreciation and amortization associated with the 40% non-controlling interest in the methanol facility in Egypt. |
Adjusted Cash Flows from Operating Activities (Attributable to Methanex Shareholders)
Adjusted cash flows from operating activities differs from the most comparable GAAP measure, cash flows from operating activities, because it does not include changes in non-cash working capital and cash flows associated with the 40% non-controlling interest in the methanol facility in Egypt.
The following table shows a reconciliation of cash flows from operating activities to adjusted cash flows from operating activities:
($ MILLIONS) | 2011 | 2010 | ||||||
Cash flows from operating activities | $ | 480 | $ | 183 | ||||
Add (deduct) non-controlling interests adjustment: | ||||||||
Net (income) loss | (27 | ) | 2 | |||||
Non-cash items | (25 | ) | (2 | ) | ||||
Changes in non-cash working capital | (36 | ) | 120 | |||||
Adjusted cash flow from operating activities (attributable to Methanex shareholders) | $ | 392 | $ | 303 |
Net Income before Unusual Item and Diluted Net Income before Unusual Item per Share
These supplemental non-GAAP measures are provided to assist readers in comparing earnings from one period to another without the impact of unusual items that are considered by management to be non-operational and/or non-recurring. Diluted income before unusual items per share has been calculated by dividing net income before unusual item by the diluted weighted average number of common shares outstanding.
The following table shows a reconciliation of net income attributable to Methanex shareholders to net income before unusual item and the calculation of diluted net income before unusual item per share:
($ MILLIONS, EXCEPT SHARES OR PER SHARE AMOUNTS) | 2011 | 2010 | ||||||
Net income1 | $ | 201 | $ | 96 | ||||
Gain on sale of Kitimat assets | – | (22 | ) | |||||
Net income before unusual item1 | $ | 201 | $ | 74 | ||||
Diluted weighted average number of common shares (millions) | 94 | 94 | ||||||
Diluted net income per share before unusual item1 | $ | 2.06 | $ | 0.79 |
1 | Attributable to Methanex Corporation shareholders. |
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.
42 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
QUARTERLY FINANCIAL DATA (UNAUDITED)
($ MILLIONS, EXCEPT WHERE NOTED) | THREE MONTHS ENDED | |||||||||||||||
DEC 31 | SEP 30 | JUN 30 | MAR 31 | |||||||||||||
2011 | ||||||||||||||||
Revenue | $ | 696 | $ | 670 | $ | 623 | $ | 619 | ||||||||
Net income1 | 64 | 62 | 41 | 35 | ||||||||||||
Net income before unusual item1 | 64 | 62 | 41 | 35 | ||||||||||||
Basic net income per share1 | 0.69 | 0.67 | 0.44 | 0.37 | ||||||||||||
Diluted net income per share1 | 0.68 | 0.59 | 0.43 | 0.37 | ||||||||||||
Diluted net income per share before unusual item1 | 0.68 | 0.59 | 0.43 | 0.37 | ||||||||||||
2010 | ||||||||||||||||
Revenue | $ | 570 | $ | 481 | $ | 449 | $ | 467 | ||||||||
Net income1 | 26 | 29 | 15 | 27 | ||||||||||||
Net income before unusual item1 | 26 | 6 | 15 | 27 | ||||||||||||
Basic net income per share1 | 0.28 | 0.31 | 0.16 | 0.29 | ||||||||||||
Diluted net income per share1 | 0.28 | 0.31 | 0.15 | 0.29 | ||||||||||||
Diluted net income per share before unusual item1 | 0.27 | 0.07 | 0.15 | 0.29 |
1 | Attributable to Methanex Corporation shareholders. |
A discussion and analysis of our results for the fourth quarter of 2011 is set out in our fourth quarter of 2011 Management’s Discussion and Analysis filed with the Canadian Securities Administrators and the U.S. Securities and Exchange Commission and incorporated herein by reference.
($ MILLIONS, EXCEPT WHERE NOTED) | 2011 | 2010 | 20092 | |||||||||
Revenue | $ | 2,608 | $ | 1,967 | $ | 1,198 | ||||||
Net income1 | 201 | 96 | 1 | |||||||||
Net income before unusual item1 | 201 | 74 | 1 | |||||||||
Basic net income per share1 | 2.16 | 1.04 | 0.01 | |||||||||
Diluted net income per share1 | 2.06 | 1.03 | 0.01 | |||||||||
Diluted net income per share before unusual item1 | 2.06 | 0.79 | 0.01 | |||||||||
Cash dividends declared per share | 0.665 | 0.620 | 0.620 | |||||||||
Total assets | 3,394 | 3,141 | 2,923 | |||||||||
Total long-term financial liabilities | 886 | 1,105 | 982 |
1 | Attributable to Methanex Corporation shareholders. |
2 | The 2009 figures are reported in accordance with Canadian GAAP. The Company transitioned to IFRS on January 1, 2010 and the 2009 figures have not been restated to be in accordance with IFRS. |
Disclosure Controls and Procedures
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, 2011, 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.
METHANEX | | Annual Report 2011 | 43 |
Management’s Discussion & Analysis
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting 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, 2011, based on the framework set forth in Internal Control – Integrated Framework issued 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, 2011. The attestation report is included on the third page of our consolidated financial statements.
Changes in Internal Control over Financial Reporting
There have been no changes during the year ended December 31, 2011 to internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.
This 2011 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:
n | expected demand for methanol and its derivatives, |
n | expected new methanol supply and timing for start-up of the same, |
n | 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, |
n | expected methanol and energy prices, |
n | expected levels of methanol purchases from traders or other third parties, |
n | expected levels, timing and availability of economically-priced natural gas supply to each of our plants, including, without limitation, levels of natural gas supply from investments in natural gas exploration and development in Chile and New Zealand, |
n | commitments, capital or otherwise of third parties to future natural gas exploration and development in the vicinity of our plants, |
n | expected capital expenditures, including, without limitation, those to support natural gas exploration and development for our plants and the restart of our idled methanol facilities, |
n | anticipated production rates of our plants, including, without limitation, our Chilean facilities and the planned restart of the Motunui 1 facility in New Zealand, |
n | expected operating costs, including natural gas feedstock costs and logistics costs, |
44 METHANEX | | Annual Report 2011 |
Management’s Discussion & Analysis
n | ability to reduce CO2 emissions and other greenhouse gases from our operations, |
n | expected tax rates or resolutions to tax disputes, |
n | expected cash flows, earnings capability and share price, |
n | ability to meet covenants or obtain waivers associated with our long-term debt obligations, including, without limitation, the Egypt limited recourse debt facilities that have conditions associated with finalization of certain land title registration and related mortgages that require actions by Egyptian governmental entities, |
n | availability of committed credit facilities and other financing, |
n | shareholder distribution strategy and anticipated distributions to shareholders, |
n | commercial viability of, or ability to execute, future projects, plant restarts, capacity expansions, plant relocations or other business initiatives or opportunities, including the planned relocation of one of our idle Chile methanol plants to the United States Gulf Coast, |
n | financial strength and ability to meet future financial commitments, |
n | expected global or regional economic activity (including industrial production levels), |
n | expected outcomes of litigation or other disputes, claims and assessments, |
n | expected impact of regulatory actions, including assessments of carcinogenicity of methanol, formaldehyde and MTBE, the imposition of formaldehyde emission limits and legislation related to CO2 emissions, |
n | expected actions of governments, government agencies, gas suppliers, courts, tribunals or other third parties, and |
n | expected impact on our results of operations in Egypt and our financial condition as a consequence of actions taken by the Government of Egypt and its agencies. |
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:
n | supply of, demand for, and price of, methanol, methanol derivatives, natural gas, oil and oil derivatives, |
n | success of natural gas exploration in Chile and New Zealand and our ability to procure economically priced natural gas in Chile, New Zealand and Canada, |
n | production rates of our facilities, |
n | receipt or issuance of third-party consents or approvals, including, without limitation, governmental registrations of land title and related mortgages in Egypt, governmental approvals related to natural gas exploration rights, rights to purchase natural gas or the establishment of new fuel standards, |
n | operating costs including natural gas feedstock and logistics costs, capital costs, tax rates, cash flows, foreign exchange rates and interest rates, |
n | availability of committed credit facilities and other financing, |
n | timing of completion and cost of our Motunui 1 restart project in New Zealand, |
n | global and regional economic activity (including industrial production levels), |
n | absence of a material negative impact from major natural disasters, |
METHANEX | | Annual Report 2011 | 45 |
Management’s Discussion & Analysis
n | absence of a material negative impact from changes in laws or regulations, |
n | accuracy and sustainability of opinions provided by our legal, accounting and other professional advisors, |
n | absence of material negative impact from political instability in the countries in which we operate, and |
n | enforcement of contractual arrangements and ability to perform contractual obligations by customers, suppliers and other third parties. |
However, forward-looking statements, by their nature, involve risks and uncertainties that could cause actual results to differ materially from those contemplated by the forward-looking statements. The risks and uncertainties primarily include those attendant with producing and marketing methanol and successfully carrying out major capital expenditure projects in various jurisdictions, including, without limitation:
n | conditions in the methanol and other industries, including fluctuations in supply, demand and price for methanol and its derivatives, including demand for methanol for energy uses, |
n | the price of natural gas, oil and oil derivatives, |
n | the success of natural gas exploration and development activities in southern Chile and New Zealand and our ability to obtain any additional gas in Chile, New Zealand and Canada on commercially acceptable terms, |
n | the ability to successfully carry out corporate initiatives and strategies, |
n | actions of competitors, suppliers and financial institutions, |
n | actions of governments and governmental authorities, including, without limitation, the implementation of policies or other measures that could impact the supply or demand for methanol or its derivatives, |
n | changes in laws or regulations, |
n | 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, |
n | worldwide economic conditions, and |
n | other risks described in the 2011 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 anticipated in forward-looking statements may not occur and we do not undertake to update forward-looking statements except as required by applicable securities laws.
46 METHANEX | | Annual Report 2011 |