Exhibit 99.2
MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis is dated March 5, 2010 and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2009. Our consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP). We use the United States dollar as our reporting currency.Except where otherwise noted, all dollar amounts are stated in United States dollars.
Canadian GAAP differs in some respects from accounting principles generally accepted in the United States (US GAAP). Significant differences between Canadian GAAP and US GAAP are described in note 19 to our consolidated financial statements.
At March 5, 2010 we had 92,127,192 common shares issued and outstanding and stock options exercisable for 3,334,037 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.
OVERVIEW OF THE BUSINESS
Methanol is a commodity liquid chemical that is predominantly produced from natural gas and also from coal, particularly in China. Approximately 70% of all methanol demand is used to produce 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 remainder of methanol demand comes from the energy sector. There are growing markets for using methanol in energy applications such as direct methanol blending into gasoline and dimethyl ether (DME) which can be blended with liquefied petroleum gas for use in household cooking and heating, and also as a substitute for diesel. Methanol is also used to produce biodiesel and methyl tertiary butyl ether (MTBE), a gasoline component.
We are the world’s largest supplier of methanol to the major international markets of North America, Asia Pacific, Europe and Latin America. We currently have total annual production capacity of 6.8 million tonnes from our production hubs in Chile, Trinidad and New Zealand. We also have a 60% interest in a 1.3 million tonne methanol project in Egypt, scheduled for start-up in mid-2010. Our production hubs in Chile and Trinidad represent 5.9 million tonnes of our total annual production capacity. The remainder of our total annual production capacity consists of our 0.9 million tonne per year Motunui plant in New Zealand. We also have 1.4 million tonnes of idled annual capacity in New Zealand (a second 0.9 million tonne per year Motunui plant and a 0.5 million tonne per year plant in nearby Waitara Valley) and 0.5 million tonnes of idled capacity in Canada. These idled facilities provide the potential to increase production in New Zealand and Canada depending primarily on the availability of economically priced natural gas feedstock and methanol supply and demand dynamics. In addition to the methanol we produce, we purchase methanol produced by others under methanol offtake contracts and on the spot market. This gives us flexibility and certainty in managing our supply chain while continuing to meet customer needs and support our marketing efforts.
2009 Industry Overview
2009 was a challenging year for the methanol industry as a result of the global economic recession that began in late 2008. As we entered 2009, we estimate global demand had declined by about 15% from pre-recession levels to an annualized level of about 36 million tonnes, with global demand for traditional methanol derivatives being most impacted and declining by approximately 20% from pre-recession levels. Global demand into energy-related derivatives remained relatively stable during this period, despite the global recession, with particularly strong demand for both direct blending into gasoline and DME. In response to the decline in overall global demand, higher cost capacity was shut in or was operated at lower rates as prices declined. This resulted in a period of lower methanol pricing, and our average non-discounted posted price for the first half of 2009 was $213 per tonne.
Global methanol demand continued to recover throughout 2009 and by the end of year we estimate global demand had recovered to above pre-recession levels, or to approximately 43 million tonnes measured on an annualized basis. Overall, global demand for methanol in 2009 is estimated at 40 million tonnes (similar to 2008 demand). Demand recovery in the first half of 2009 was mainly focused in Asia, particularly in China, while during the second half of the year we also saw some recovery in demand in other regions including Europe and North America. In addition to the improvement in demand in the latter half of 2009, there were significant supplier operating issues across the industry and feedstock costs for higher-cost producers escalated as a result of higher energy prices. These factors resulted in an increase in methanol prices through the latter half of 2009 and into 2010. At the beginning of 2010, our average non-discounted posted prices had recovered to approximately $350 per tonne.
2009 Company Focus
Given the challenging economic environment in 2009, our focus for the year was on sound financial management while continuing to invest to strengthen our low cost asset position. Our priorities for allocating capital were to continue progress towards completing the new methanol project in Egypt, providing continued support of natural gas development in Chile and investing to maintain the strength of our existing plants.
Strengthening our Asset Position
During 2009, we made significant progress in the construction of a new 1.3 million tonne per year methanol facility in Egypt. As we enter 2010, the project continues to be on-budget with capital spending almost complete, and we remain focused on a successful start-up, which we expect in mid-2010.
We also continued supporting natural gas development activities in southern Chile during 2009, investing in natural gas development with our two natural gas suppliers in Chile — Empresa Nacional del Petroleo (ENAP) and GeoPark Chile Limited (GeoPark). In 2009, continued success in natural gas development from these investments led to increased natural gas supply and we were able to start a second plant, albeit at reduced rates, in late 2009. We remain committed to supporting these investments and are actively pursuing other opportunities to invest in natural gas development in southern Chile.
In addition to our methanol project in Egypt and natural gas development in southern Chile, we also completed major maintenance activities at both our Atlas and Titan facilities in Trinidad in 2009. We expect this will result in increased production from these facilities over the next year.
Financial Management
Always a key area of focus for the Company, sound financial management was especially important given the economic environment in 2009. At the beginning of the year, we embarked on a broad corporate cost savings plan that included reducing our operating costs and cancelling or postponing almost all discretionary capital spending. We also improved our liquidity position by renewing and extending our undrawn credit facility in August 2009.
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We completed the year in a solid financial position with a strong balance sheet. At December 31, 2009, we had a cash balance of $170 million, no re-financing requirements until 2012 and an undrawn $200 million credit facility that expires in mid-2012.
Our priority for allocating capital continues to be strengthening our asset position. Capital spending is almost complete on the new methanol project in Egypt and we are committed to increasing production at our Chile facilities by supporting the acceleration of natural gas development in that country. In addition, we believe there may be other opportunities to increase production at our other sites at relatively low cost. We believe these initiatives and opportunities give us the ability to significantly increase our production over the next few years with relatively modest capital requirements and provide a sound basis for significantly improving our cash generation and earnings capability.
OUR STRATEGY
Our primary objective is to create value by maintaining and enhancing our leadership in the global production, marketing and delivery of methanol to our customers. The key elements of our strategy are global leadership, low cost, and operational excellence.
Global Leadership
We are the leading supplier of methanol to the major international markets of North America, Asia Pacific, Europe and Latin America. Our sales volumes in 2009 represented approximately 15% of total global methanol demand. Our leadership position has enabled us to play an important role in the industry, which includes publishing Methanex reference prices that are generally used in each major market as the basis of pricing for most of our customer contracts.
The strategic location of our Chile, Trinidad and New Zealand production sites — as well as the new methanol project in Egypt — allows us to deliver methanol cost-effectively to our customers in all major global markets, while our investments in global distribution and supply infrastructure enable us to enhance value to customers by providing reliable and secure supply.
Our current focus of making investments to increase production at our sites is an important element of our strategy of Global Leadership. The new methanol project in Egypt, which is expected to startup in mid-2010, is well located and will provide additional security of supply for our customers. We are also focused on increasing production at our Chile facilities by supporting the acceleration of natural gas development in southern Chile. Into 2010 we have been operating two plants, each at approximately 60% of capacity, and our goal is to return to operating all four of our plants in Chile over the next few years. These initiatives could enable us to increase our global production levels from 3.5 million tonnes in 2009 to over 7 million tonnes over the next few years. We also continue to pursue opportunities to increase supply by restarting idled capacity at our sites in New Zealand and Canada, with the decision to restart the sites depending primarily on our ability to source economically priced natural gas and methanol supply and demand dynamics. We believe our initiatives to increase production will enable us to grow our sales levels while continuing to provide reliable and secure supply to our customers and to further build on our leadership position in the industry.
Although we have experienced significantly reduced production from our assets in Chile since mid-2007 (refer to theProduction Summary — Chilesection on page 8), we have continued to meet our commitments to customers. We have achieved this by increasing the amount of methanol 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 infrastructure which allows us to purchase methanol in the most cost-effective region while still maintaining overall security of supply.
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The Asia Pacific region continues to lead global methanol demand growth and over the past few years, we have continued to invest in and develop our presence in this important region. We added additional storage capacity in Zhangjiagang, China and expanded our offices in Shanghai and Hong Kong. In addition, we recently opened an office in Beijing to enhance our customer service and industry positioning in this region. This enables us to participate in and improve our knowledge of the rapidly evolving and high growth methanol market 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. Finally, our office in Dubai, UAE enables us to enhance our corporate presence and capitalize on future opportunities in the Middle East.
Over the past few years, the demand for methanol for energy applications has been strong, particularly in China, and the country continues to demonstrate the viability of methanol into energy applications. For example, in December 2009, the Chinese government implemented national standards for M-85 (85% methanol blend). One of our key strategic initiatives is to continue supporting demand growth into energy applications globally. We have a 20% interest in a 200,000 tonne per year DME facility in China with the ENN Group, and we are the exclusive methanol supplier to this facility. We have also entered into a joint venture agreement to develop a similar DME facility in Egypt. The joint venture will include Methanex and the ENN Group as minority interests, with the Egyptian Ministry of Petroloeum, including its subsidiary Egyptian Petrochemicals Holding Company (EChem), holding the majority interest. EChem is also a partner in our new methanol project in Egypt.
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 all business decisions is guided by our drive to maintain and enhance our cost structure, expand margins and return value to shareholders. The most significant components of our costs are natural gas for feedstock and distribution costs associated with delivering methanol to customers.
Natural gas is the primary feedstock at our methanol production facilities and is the most significant component of our cost structure. An essential element of our strategy is to ensure long-term security of natural gas supply. As described above, our goal is to return to operating all four of our plants in Chile over the next few years with natural gas supply from Chile, and we are actively pursuing investment opportunities to accelerate natural gas development in areas of southern Chile that are relatively close to our plants (refer to theProduction Summary — Chile section on page 8 for more information).
Our production facilities in Trinidad represent 2.1 million tonnes per year of competitive cost production capacity. These facilities are underpinned by long-term take-or-pay natural gas purchase agreements where the gas price varies with methanol prices. During 2009, we completed turnaround activities at both our Atlas and Titan facilities in Trinidad and we expect increased production from these facilities over the next year.
We have positioned our facilities in New Zealand as flexible production assets. At the end of 2008, we added approximately 0.4 million tonnes of incremental annual capacity by restarting one of our 0.9 million tonne per year facilities at our Motunui site and idling the smaller-scale 0.5 million tonne per year Waitara Valley facility in New Zealand. We also have additional potential production capacity that is currently idled in New Zealand (refer to theProduction Summary — New Zealand section on page 9 for more information).
In 2009, we continued to advance our project to construct a 1.3 million tonne per year methanol facility in Egypt (located at Damietta on the Mediterranean Sea). This project is on budget and we expect this methanol facility to startup in mid-2010. We are developing the project with partners: we have a 60% interest in the project and hold 100% of the marketing rights for the production. We believe this methanol facility will further enhance our positioning with its competitive cost structure and excellent location to supply the European market.
The cost to distribute methanol from production facilities to customers is also a significant component of our 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 maximizing the use of our shipping fleet to reduce costs 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.
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Operational Excellence
We maintain a focus on operational excellence in all aspects of our business. This includes excellence in our manufacturing and supply chain processes, marketing and sales, human resources, corporate governance practices and financial management.
To differentiate ourselves from our competitors, we strive to be the best operator in all aspects of our business and to be the preferred supplier to our 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. In part due to our commitment to Responsible Care, a risk-minimization approach developed by the Chemistry Industry Association of Canada, we believe we have reduced the likelihood of unplanned shutdowns and lost-time incidents and have achieved an excellent overall environmental record.
Product stewardship is a vital component of our 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 our 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 (HSE) initiatives, and we work with industry colleagues to improve safety standards and regulatory compliance. We readily share our 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 our Responsible Care ethic, we have a Social Responsibility policy that aligns our corporate governance, employee engagement and development, community involvement and social investment strategies with our core values and corporate strategy.
Our strategy of operational excellence 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. As a result of the global economic recession, we embarked on a broad corporate cost savings plan that included reducing operating costs and cancelling or postponing almost all discretionary capital spending. At December 31, 2009, we had a strong balance sheet with a cash balance of $170 million, no re-financing requirements until 2012 and a $200 million undrawn credit facility that expires in mid-2012. We believe we are well positioned to meet our financial commitments and continue investing to grow our business.
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HOW WE ANALYZE OUR BUSINESS
Our operations consist of a single operating segment — the production and sale of methanol. We review our results of operations by analyzing changes in the components of our adjusted earnings before interest, taxes, depreciations and amortization (Adjusted EBITDA) (refer to theSupplemental Non-GAAP Measuressection on page 40 for a reconciliation to the most comparable GAAP measure), depreciation and amortization, interest expense, interest and other income, 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. The key drivers of change in our Adjusted EBITDA are average realized price, cash costs and sales volume.
The price, cash cost and volume variances included in our Adjusted EBITDA analysis are defined and calculated as follows:
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| 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. |
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| CASH COST | | The change in our 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 our 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 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 also sell methanol on a commission basis. Commission sales represent volumes marketed on a commission basis related to the 36.9% of the Atlas methanol facility in Trinidad that we do not own.
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FINANCIAL HIGHLIGHTS
| | | | | | | | | |
| ($ MILLIONS, EXCEPT WHERE NOTED) | | 2009 | | | 2008 | |
Sales volumes (thousands of tonnes): | | | | | | | | |
Produced methanol | | | 3,764 | | | | 3,363 | |
Purchased methanol | | | 1,546 | | | | 2,074 | |
Commission sales1 | | | 638 | | | | 617 | |
| | | | | | | |
| | | | 5,948 | | | | 6,054 | |
| | | | | | | | | |
Methanex average non-discounted posted price ($ per tonne)2 | | | 252 | | | | 526 | |
Average realized price ($ per tonne)3 | | | 225 | | | | 424 | |
Revenue | | | 1,198 | | | | 2,314 | |
Adjusted EBITDA4 | | | 142 | | | | 330 | |
Net income | | | 1 | | | | 169 | |
Basic net income per share ($ per share) | | | 0.01 | | | | 1.79 | |
Diluted net income per share ($ per share) | | | 0.01 | | | | 1.78 | |
Cash flows from operating activities | | | 110 | | | | 313 | |
Cash flows from operating activities before changes in non-cash working capital4 | | | 129 | | | | 235 | |
Common share information (millions of shares): | | | | | | | | |
Weighted average number of common shares outstanding | | | 92 | | | | 95 | |
Diluted weighted average number of common shares outstanding | | | 93 | | | | 95 | |
Number of common shares outstanding | | | 92 | | | | 92 | |
| | | | | | | |
| | | |
| 1 | | Commission sales represent volumes marketed on a commission basis. Commission income is included in revenue when earned. |
| |
| 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 on our website at www.methanex.com. |
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| 3 | | Average realized price is calculated as revenue, net of commission income, divided by total sales volumes of produced and purchased methanol. |
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| 4 | | These items are non-GAAP measures that do not have any standardized meaning prescribed by Canadian GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Refer tothe Supplemental Non-GAAP Measuressection on page 40 for a description of each non-GAAP measure and a reconciliation to the most comparable GAAP measure. |
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PRODUCTION SUMMARY
The following table details the annual production capacity and actual production of our facilities that operated in 2009 and 2008:
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| | | ANNUAL | | | | | | | |
| | | PRODUCTION | | | | | | | |
| (THOUSANDS OF TONNES) | | CAPACITY1 | | | 2009 | | | 2008 | |
| | | | | | | | | | | | | |
Chile I, II, III and IV (Chile) | | | 3,800 | | | | 942 | | | | 1,088 | |
Atlas (Trinidad) (63.1% interest) | | | 1,150 | | | | 1,015 | | | | 1,134 | |
Titan (Trinidad) | | | 900 | | | | 764 | | | | 871 | |
New Zealand2 | | | 900 | | | | 822 | | | | 570 | |
| | | | | | | | | | |
| | | | 6,750 | | | | 3,543 | | | | 3,663 | |
| | | | | | | | | | |
| | | |
| 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 only our 0.9 million tonne per year Motunui facility which we restarted in late 2008. Practical operating capacity will depend partially on the composition of natural gas feedstock and may differ from the stated capacity above. We also have additional potential production capacity that is currently idled in New Zealand (refer to theNew Zealandsection on page 9 for more information). |
Chile
Our methanol facilities in Chile produced 0.9 million tonnes of methanol in 2009 compared with 1.1 million tonnes in 2008. Production at our methanol facilities in Chile was lower in 2009 compared with 2008 primarily as a result of plant technical issues that led to unplanned outages. In mid-December 2009, based on improved availability of natural gas, we restarted a second plant in Chile.
Throughout 2008 and 2009, we operated our methanol facilities in Chile significantly below site capacity. This is primarily due to curtailments of natural gas supply from Argentina. 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. As a result of the Argentinean natural gas supply issues, all of the methanol production at our Chile facilities since June 2007 has been produced with natural gas from Chile.
Our goal is to return to operating all four plants in Chile 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. During 2007 and 2008, we provided GeoPark with $40 million (of which $10 million had been repaid at December 31, 2009) to support and accelerate GeoPark’s natural gas exploration and development activities in southern Chile. In October 2009 we signed an agreement to provide a further $18 million in financing to support GeoPark’s natural gas exploration and development activities in southern Chile of which $15 million had been provided to GeoPark at December 31, 2009. GeoPark has agreed to supply us with all natural gas sourced from the Fell block under a ten-year exclusive supply arrangement. In May 2008, we signed an agreement with ENAP to accelerate natural gas exploration and development in the Dorado Riquelme exploration block in southern Chile and to supply natural gas to our production facilities in Chile. Final government approvals were received in the third quarter of 2009. Under the arrangement, we fund a 50% participation in the block and as at December 31, 2009, we had contributed approximately $65 million. Approximately 55% of total production at our Chilean facilities is currently being produced with natural gas supplied from the Fell and Dorado Riquelme blocks. In mid-December 2009, based on the success of the natural gas development initiatives, we restarted a second plant in Chile and into 2010 we have been operating two plants, each at approximately 60% capacity. For 2010, we are estimating production of about 1.2 million tonnes in Chile. This assumes that we may return to operating only one plant at times during the year, such as during the southern hemisphere winter, when there is incremental seasonal growth in demand for natural gas for residential purposes.
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Other investment activities are also supporting the acceleration of natural gas exploration and development in areas of southern Chile. In late 2007, the government of Chile completed an international bidding round 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. The terms of the agreements from the bidding round require minimum investment commitments. In July 2008, we announced that under the international bidding round, the Otway exploration block in southern Chile was awarded to a consortium that includes Wintershall Chile Limitada (Wintershall), GeoPark and Methanex. We have recently agreed to participate in the Tranquilo exploration block, also located in southern Chile. The participation is part of a new ownership structure that involves both the Tranquilo block and the Otway block. In the new ownership structure, Wintershall, GeoPark, and Pluspetrol Chile S.A. (Pluspetrol) each have 25% participation and International Finance Corporation, member of the World Bank Group (IFC) and Methanex each have 12.5% participation. GeoPark will be the operator of both blocks. The arrangement is subject to approval by the government of Chile. In 2010, approved budgets by the consortium for the two blocks total $37 million.
We cannot provide assurance that we, ENAP, GeoPark or others will be successful in the exploration and development of natural gas or that we will obtain any additional natural gas from suppliers in Chile on commercially acceptable terms.
Refer to theRisk Factors and Risk Management — Chilesection on page 23 for more information.
Trinidad
Our equity ownership of methanol facilities in Trinidad represent approximately 2.1 million tonnes of competitive-cost annual capacity. In 2009, these facilities produced a total of 1.8 million tonnes compared with 2.0 million tonnes in 2008. Production was lower in 2009 compared with 2008 as a result of planned and unplanned downtime. We completed planned major maintenance activities at both the Atlas and Titan facilities in 2009 and we expect increased production from these facilities in 2010.
New Zealand
We have positioned our facilities in New Zealand as flexible production assets. In October 2008, we restarted one of our idled 0.9 million tonne per year Motunui methanol plants and idled our 0.5 million tonne per year Waitara Valley plant. We produced 822,000 tonnes at our facilities in New Zealand in 2009 compared with 570,000 tonnes in 2008. The increase in production in 2009 is due to additional production from the Motunui facility. We currently have 1.4 million tonnes per year of idled capacity in New Zealand, including a second 0.9 million tonne per year Motunui plant and the Waitara Valley plant. These facilities provide the potential to increase production in New Zealand depending on methanol supply and demand dynamics and the availability of economically priced natural gas feedstock.
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RESULTS OF OPERATIONS
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| ($ MILLIONS) | | 2009 | | | 2008 | |
Consolidated statements of income: | | | | | | | | |
Revenue | | $ | 1,198 | | | $ | 2,314 | |
Cost of sales and operating expenses | | | 1,056 | | | | 1,951 | |
Inventory writedown | | | — | | | | 33 | |
| | | | | | | |
Adjusted EBITDA1 | | | 142 | | | | 330 | |
Depreciation and amortization | | | 118 | | | | 107 | |
| | | | | | | |
Operating income1 | | | 24 | | | | 223 | |
Interest expense | | | (27 | ) | | | (38 | ) |
Interest and other income | | | — | | | | 11 | |
Income tax recovery (expense) | | | 4 | | | | (27 | ) |
| | | | | | | |
Net income | | $ | 1 | | | $ | 169 | |
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| 1 | | These items are non-GAAP measures that do not have any standardized meaning prescribed by Canadian GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. Refer to theSupplemental Non-GAAP Measures section on page 40for a description of each non-GAAP measure and a reconciliation to the most comparable GAAP measure. |
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, the value of energy and changes in general economic conditions, which can vary across the major international methanol markets.
Revenue for 2009 was $1.2 billion compared with $2.3 billion in 2008. The decrease in revenue was primarily due to lower methanol pricing in 2009 compared with 2008.
We entered 2008 in a tight methanol market condition due to industry supply constraints as a result of significant planned and unplanned supplier outages in the latter half of 2007. This, combined with high global energy prices and healthy demand, resulted in high methanol prices during the first quarter of 2008. As inventories recovered, methanol prices moderated into the second quarter of 2008 and pricing remained relatively stable until the end of the third quarter of the year. The global economic slowdown in the later part of 2008 led to a sudden and significant reduction in global methanol demand and an increase in global inventories. This resulted in a decrease in methanol pricing during the fourth quarter of 2008 and into 2009. During 2009, global methanol demand improved, and as a result of this improvement and some planned and unplanned plant outages across the industry, methanol prices increased in the latter half of 2009 and into 2010 (refer to theOutlooksection on page 30 for more information). Our average realized price for the year ended December 31, 2009 was $225 per tonne compared with $424 per tonne in 2008, and this decreased our revenues by $1.1 billion.
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The methanol industry is highly competitive and prices are affected by supply and demand fundamentals. We publish non-discounted reference prices for each major methanol market and offer discounts to customers based on various factors. Our average non-discounted published reference price for 2009 was $252 per tonne compared with $526 per tonne in 2008. Our average realized price was approximately 11% and 19% lower than our average non-discounted published reference price for 2009 and 2008, respectively.
We have entered into long-term contracts for a portion of our production volume with certain global customers where prices are either fixed or linked to our costs plus a margin. Sales under these contracts represented approximately 19% of our total sales volumes in 2009 compared with 23% of our total sales volumes in 2008. The difference between our average non-discounted published reference price and our average realized price is expected to narrow during periods of lower pricing.
Distribution of Revenue
The distribution of revenue for 2009 and 2008 is as follows:
| | | | | | | | | | | | | | | | | |
| ($ MILLIONS, EXCEPT WHERE NOTED) | | 2009 | | | 2008 | |
Canada | | $ | 106 | | | | 9 | % | | $ | 237 | | | | 10 | % |
United States | | | 355 | | | | 30 | % | | | 737 | | | | 32 | % |
Europe | | | 198 | | | | 17 | % | | | 494 | | | | 21 | % |
China | | | 195 | | | | 16 | % | | | 135 | | | | 6 | % |
Korea | | | 136 | | | | 11 | % | | | 263 | | | | 11 | % |
Other Asia | | | 83 | | | | 7 | % | | | 209 | | | | 9 | % |
Latin America | | | 125 | | | | 10 | % | | | 239 | | | | 10 | % |
| | | | | | | | | | | | | |
| | | $ | 1,198 | | | | 100 | % | | $ | 2,314 | | | | 100 | % |
| | | | | | | | | | | | | |
Our revenue distribution for 2009 is relatively comparable to 2008 except for changes in China. Revenue in China increased as a proportion of our total revenue in 2009 compared with 2008 by 10%, primarily as a result of an increase in sales volumes. China continues to play an important role in the methanol industry as a substantial producer and consumer. A key part of our global leadership strategy is to increase our presence in China and the Asia Pacific region.
Adjusted EBITDA
We review our results of operations by analyzing changes in the components of Adjusted EBITDA. In addition to the methanol that we produce at our facilities, we also purchase and re-sell methanol produced by others and we sell methanol on a commission basis. We analyze the results of all methanol sales together. The key drivers of change in our Adjusted EBITDA are average realized price, sales volume and cash costs.
2009 Adjusted EBITDA was $142 million compared with $330 million in 2008. The decrease in Adjusted EBITDA of $188 million resulted from changes in the following:
| | | | | |
| ($ MILLIONS) | | 2009 VS. 2008 | |
Average realized price | | $ | (1,063 | ) |
Sales volume | | | (11 | ) |
Total cash costs1 | | | 886 | |
| | | | |
| | | | | |
Decrease in Adjusted EBITDA | | $ | (188 | ) |
| | | | |
| | | |
| 1 | | Includes cash costs related to both Methanex-produced methanol and purchased methanol, as well as consolidated selling, general and administrative expenses and fixed storage and handling costs (refer to theHow We Analyze Our Businesssection on page 6 for more information). |
11
Average Realized Price
Our average realized price for the year ended December 31, 2009 was $225 per tonne compared with $424 per tonne for 2008, and this decreased our revenues by $1,063 million (refer to theRevenue section on page 10 for more information).
Sales Volume
Total methanol sales volumes, excluding commission sales volumes, for the year ended December 31, 2009 were 127,000 tonnes lower than in 2008, which resulted in lower Adjusted EBITDA of $11 million.
Total Cash Costs
Cash costs for Methanex-produced methanol and purchased methanol were $886 million lower in 2009 than in 2008. The primary changes in cash costs were as follows:
| | | | | |
| ($ MILLIONS) | | 2009 vs. 2008 | |
| | | | | |
Lower natural gas and purchased methanol costs (impact of lower methanol prices) | | $ | 846 | |
| | | | | |
Inventory writedown recorded in 2008 | | | 33 | |
| | | | | |
Lower selling, general & administrative and other expenses | | | 7 | |
| | | | |
| | | | | |
Decrease in total cash costs | | $ | 886 | |
| | | | |
Lower Natural Gas and Purchased Methanol Costs (Impact of Lower Methanol Prices)
Natural gas is the primary feedstock at our methanol production facilities and is the most significant component of our cost structure. The natural gas supply contracts for our assets in Chile, Trinidad and New Zealand include base and variable price components 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. The lower average methanol prices in 2009 decreased our natural gas costs per tonne for Methanex-produced methanol and this lowered cash costs by approximately $275 million compared with 2008. For additional information regarding our natural gas agreements refer to theSummary of Contractual Obligations and Commercial Commitmentssection on page 19.
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 offtake agreements we look for opportunities that provide synergies with our existing supply chain and market position. Our strong global supply chain allows us to take advantage of unique opportunities to add value through logistics cost savings and 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 lower average methanol prices in 2009 decreased the cost of purchased methanol per tonne and this lowered cash costs by approximately $435 million compared with 2008.
As a result of the higher cost characteristics of purchased methanol than Methanex-produced methanol, changes in the proportion of purchased methanol in overall sales volumes will have an impact on our cost structure from period to period. For the year ended December 31, 2009, purchased methanol represented a lower proportion of our overall sales volumes compared with 2008, lowering cash costs by approximately $136 million.
Inventory Writedown Recorded in 2008
We record inventory at lower of cost and estimated net realizable value. The carrying value of inventory, for both Methanex-produced methanol as well as purchased methanol, will reflect methanol pricing at the time of production or purchase and this will differ from methanol pricing when sold. In the latter part of 2008, as a result of the global economic slowdown and the sharp decline in methanol prices in the fourth quarter, we recorded a pre-tax charge to earnings of $33 million to write down the carrying value of inventory to estimated net realizable value at December 31, 2008.
12
Lower Selling, General & Administrative and Other Expenses
Selling, general & administrative and other expenses were lower for the year ended December 31, 2009 compared with 2008 by approximately $7 million, which includes lower selling, general & administrative expenses of approximately $16 million as a result of cost-reduction initiatives, offset by higher stock-based compensation expense of approximately $9 million as a result of the impact of changes in our share price. Stock-based compensation expense for deferred, restricted and performance share units is impacted by changes in our share price, and these changes are recognized in earnings for the proportion of the service that has been rendered at each reporting date.
Depreciation and Amortization
Depreciation and amortization expense in 2009 was $118 million compared with $107 million in 2008. The $11 million increase in depreciation and amortization is primarily due to higher sales volumes of Methanex- produced methanol inventories in 2009, which includes depreciation charges and the commencement of depletion charges associated with our oil and gas investment in Chile. Once we received final approval from the government of Chile on August 24, 2009, we adopted the full cost methodology for accounting for oil and gas exploration costs associated with our 50% participation in the Dorado Riquelme block in southern Chile (refer to theProduction Summary — Chileand theNew Canadian Accounting Standards Adopted in 2009sections on pages 8 and 35, respectively, for more information). Under these accounting standards, cash investments in the block are initially capitalized and are recorded to earnings through non-cash depletion charges as natural gas is produced from the block. Depletion charges recorded in earnings for 2009 were approximately $4 million.
Interest Expense
| | | | | | | | | |
| ($ MILLIONS) | | 2009 | | | 2008 | |
| | | | | | | | | |
Interest expense before capitalized interest | | $ | 60 | | | $ | 56 | |
| | | | | | | | | |
Less capitalized interest related to Egypt plant under construction | | | (33 | ) | | | (18 | ) |
| | | | | | | |
| | | | | | | | | |
Interest expense | | $ | 27 | | | $ | 38 | |
| | | | | | | |
Interest expense before capitalized interest in 2009 was $60 million compared with $56 million in 2008. Interest expense before capitalized interest was higher in 2009 primarily as a result of higher debt balances related to our methanol project in Egypt, which is scheduled to startup in mid-2010. We have limited recourse debt facilities of $530 million for this 1.3 million tonne per year methanol facility that we are developing with partners. Interest costs related to the project are capitalized to the carrying value of the property, plant and equipment under construction.
Interest and Other Income
Interest and other income was nil in 2009 compared with $11 million in 2008. Interest and other income for 2009 compared with 2008 was lower by $11 million primarily as a result of lower interest income earned on cash balances in 2009, a $5 million gain on sale of ammonia production assets recorded in 2008 and the impact of changes in foreign exchange rates.
13
Income Taxes
We recorded an income tax recovery of $4.3 million with a loss before tax of $3.5 million for an effective tax rate of 121% in 2009. In periods of low income levels, the distribution of income and loss between jurisdictions can result in income tax rates that may not be indicative of the longer-term corporate tax rate. During 2008, we recorded income tax expense of $26.7 million with income before tax of $195.5 million for an effective tax rate of 13%. The effective tax rate for 2008 was impacted by the resolution of a tax position during the fourth quarter of 2008 that resulted in a reduction of $27 million to future income tax liabilities.
The statutory tax rate in Chile and Trinidad, where we earn a substantial portion of pre-tax earnings, is 35%. Our Atlas facility in Trinidad has partial relief from corporate income tax until 2014. In Chile, the tax rate consists of a first tier tax that is payable when income is earned and a second tier tax that is due when earnings are distributed from Chile. The second category tax is initially recorded as future income tax expense and is subsequently reclassified to current income tax expense when earnings are distributed. Accordingly, the ratio of current income tax expense to total income tax expense is highly dependent on the level of cash distributed from Chile.
For additional information regarding income taxes, refer to note 12 of our 2009 consolidated financial statements.
14
LIQUIDITY AND CAPITAL RESOURCES
| | | | | | | | | |
| ($ MILLIONS) | | 2009 | | | 2008 | |
| | | | | | | | | |
Cash flows from operating activities: | | | | | | | | |
Cash flows from operating activities1 | | $ | 128 | | | $ | 235 | |
Changes in non-cash working capital | | | (18 | ) | | | 78 | |
| | | | | | | |
| | | | 110 | | | | 313 | |
| | | | | | | | | |
Cash flows from investing activities: | | | | | | | | |
Property, plant and equipment | | | (61 | ) | | | (97 | ) |
Egypt plant under construction | | | (262 | ) | | | (382 | ) |
Oil and gas assets | | | (23 | ) | | | (42 | ) |
GeoPark financing, net | | | (9 | ) | | | (22 | ) |
Other, net | | | 3 | | | | (2 | ) |
Changes in non-cash working capital related to investing activities | | | (28 | ) | | | 27 | |
| | | | | | | |
| | | | (380 | ) | | | (518 | ) |
| | | | | | | | | |
Cash flows from financing activities: | | | | | | | | |
Dividend payments | | | (57 | ) | | | (57 | ) |
Payments for shares repurchased | | | — | | | | (150 | ) |
Proceeds on issue of long-term debt | | | 151 | | | | 204 | |
Equity contribution by non-controlling interest | | | 45 | | | | 65 | |
Repayment of long-term debt | | | (15 | ) | | | (15 | ) |
Other, net | | | (12 | ) | | | (2 | ) |
| | | | | | | |
| | | | 112 | | | | 45 | |
| | | | | | | |
Decrease in cash and cash equivalents | | | (158 | ) | | | (160 | ) |
Cash and cash equivalents, end of year | | $ | 170 | | | $ | 328 | |
| | | | | | | |
| | | |
| 1 | | Before changes in non-cash working capital. |
Cash Flow Highlights
Cash Flows from Operating Activities
Despite the difficult economic environment and lower methanol prices, we generated positive cash flows from operating activities in every quarter in 2009. Cash flows from operating activities before changes in non-cash working capital were $128 million in 2009 compared with $235 million in 2008. The decrease in cash flows from operating activities before changes in non-cash working capital is primarily the result of lower earnings in 2009 compared with 2008.
Cash generated from changes in non-cash working capital related to operating activities is due to an increase in operating working capital of $18 million for the year ended December 31, 2009 and a decrease of $78 million for the year ended December 31, 2008. The changes in non-cash working capital are primarily driven by the impact of changes in methanol pricing on our non-cash working capital balances, changes in inventory and sales levels and timing of cash payments and collections.
Cash Flows from Investing Activities
In 2009, our priorities for allocating capital were to continue advancing the completion of the new methanol project in Egypt, supporting natural gas development in Chile and investing to maintain the strength of our existing plants.
During 2009, total capital expenditures were $262 million for the development and construction of the Egypt project. As we enter 2010, the project continues to be on budget with capital spending almost complete, and we expect the methanol facility to startup in mid-2010 (refer to theLiquidity and Capitalizationsection on page 17 for more information).
15
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. In 2009, we contributed $23 million and to December 31, 2009, we had made total contributions of approximately $65 million. We expect to make further contributions over the next few years to fully realize the potential of the block. These investments will be based on annual budgets established by ENAP and Methanex in accordance with the Joint Operating Agreement that governs this development.
We also have an agreement with GeoPark under which we provided $40 million in financing in 2007 and 2008 to support and accelerate GeoPark’s natural gas exploration and development activities in southern Chile. Approximately $6 million of this amount was repaid in 2009 and to December 31, 2009, a total of $10 million had been repaid. In 2009, we entered into an agreement to provide a further $18 million in financing to support GeoPark’s natural gas exploration and development activities in southern Chile, and we had provided $15 million to GeoPark under this new agreement at December 31, 2009.
Additions to property, plant and equipment, which include turnarounds, catalyst and other capital expenditures, were $61 million for 2009 compared with $97 million in 2008. In 2009, approximately $40 million of the total capital expenditures was incurred for major maintenance activities at our Trinidad facilities with the remaining capital expenditure of approximately $21 million relating primarily to maintenance costs at our plants in Chile and New Zealand. In 2008, approximately $70 million was incurred for the refurbishment and restart of the Motunui plant in New Zealand.
Cash Flows from Financing Activities
During 2009, we paid our regular quarterly dividend of $0.155 per share and made total dividend payments of $57 million, the same amount as in 2008. During 2008, we also repurchased a total of 6.5 million common shares at an average price of $23.04 per share, totalling $150 million.
In May 2007, we reached financial close and secured limited recourse debt of $530 million for a project to construct a 1.3 million tonne per year methanol facility in Egypt. We own 60% of Egyptian Methanex Methanol Company S.A.E. (EMethanex), which is the company that is developing the project. We account for our investment in EMethanex using consolidation accounting. This results in 100% of the assets and liabilities of EMethanex being included in our financial statements. The other investors’ interest in the project is presented as “non-controlling interest”. During 2009, a total of $151 million of this limited recourse debt was drawn for construction activities and to December 31, 2009, $472 million had been drawn under these facilities.
We repaid $15 million in principal on our Atlas and other limited recourse debt facilities in each of 2009 and 2008.
16
Liquidity and Capitalization
We maintain conservative financial policies and focus on maintaining our financial strength and flexibility through prudent financial management. Our objectives in managing liquidity and capital are to provide financial capacity and flexibility to meet our strategic objectives, to provide an adequate return to shareholders commensurate with the level of risk and to return excess cash through a combination of dividends and share repurchases.
The following table provides information on our liquidity and capitalization position as at December 31, 2009 and December 31, 2008, respectively:
| | | | | | | | | |
| ($ MILLIONS, EXCEPT WHERE NOTED) | | 2009 | | | 2008 | |
| | | | | | | | | |
Liquidity: | | | | | | | | |
Cash and cash equivalents | | $ | 170 | | | $ | 328 | |
Undrawn Egypt limited recourse debt facilities | | | 58 | | | | 209 | |
Undrawn credit facilities | | | 200 | | | | 250 | |
| | | | | | | |
Total liquidity | | $ | 428 | | | $ | 788 | |
| | | | | | | |
Capitalization: | | | | | | | | |
Unsecured notes | | $ | 347 | | | $ | 347 | |
Limited recourse debt facilities, including current portion | | | 567 | | | | 435 | |
| | | | | | | |
Total debt | | | 914 | | | | 782 | |
Non-controlling interest | | | 133 | | | | 89 | |
Shareholders’ equity | | | 1,236 | | | | 1,288 | |
| | | | | | | |
Total capitalization | | $ | 2,283 | | | $ | 2,159 | |
| | | | | | | |
Total debt to capitalization1 | | | 40 | % | | | 36 | % |
Net debt to capitalization2 | | | 35 | % | | | 25 | % |
| | | | | | | |
| | | |
| 1 | | Defined as total debt divided by total capitalization. |
| |
| 2 | | Defined as total debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents. |
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 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. This is particularly important in the current uncertain economic environment. We have excellent financial capacity and flexibility. Our cash balance at December 31, 2009 was $170 million and we have $58 million of undrawn capacity on the $530 million Egypt limited recourse debt facilities. Additionally, we have an undrawn credit facility in the amount of $200 million provided by highly rated financial institutions that expires in mid-2012. We invest cash only in highly rated instruments that have maturities of three months or less to ensure preservation of capital and appropriate liquidity.
Planned capital maintenance expenditures directed towards major maintenance, turnarounds and catalyst changes for current operations are estimated to be approximately $75 million for the period to the end of 2011.
17
We estimate total remaining capital expenditures of approximately $93 million to complete the construction of the Egypt methanol facility, including capitalized interest related to the project financing and excluding working capital. This excludes unpaid capital expenditures recorded in accounts payable at December 31, 2009 of approximately $28 million. These expenditures will be funded from cash generated from operations and cash on hand, cash contributed by the non-controlling shareholders and proceeds from the limited recourse debt facilities. At December 31, 2009, our 60% share of remaining cash equity contributions, including capitalized interest related to the project financing and excluding working capital, is estimated to be approximately $20 million.
As previously mentioned, 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 have contributed $65 million to date. We expect to make further contributions over the next few years to fully realize the potential of the block. These contributions will be based on annual budgets established by ENAP and Methanex in accordance with the Joint Operating Agreement that governs this development. In July 2008, we announced that under the international bidding round, the Otway exploration block in southern Chile was awarded to a consortium that included Wintershall, GeoPark, and Methanex. We have recently agreed to participate in the Tranquilo exploration block, also located in southern Chile. The participation is part of a new ownership structure that involves both the Tranquilo block and the Otway block. In the new ownership structure, Wintershall, GeoPark, and Pluspetrol each have 25% participation and IFC and Methanex each have 12.5% participation. GeoPark will be the operator of both blocks. The arrangement is subject to approval by the government of Chile. In 2010, approved budgets by the consortium for the two blocks total $37 million.
In addition to the above initiatives, we also recently entered into a $10 million funding arrangement with a new exploration company, Kea Exploration, to finance the drilling of a well in the Taranaki region in New Zealand near our methanol plants. There is a possibility that this could result in a gas discovery. However, it is probably more likely that this drilling will provide valuable data regarding the potential for this prospect and further exploration activity will be necessary. Other than the initial commitment, we have no further commitment to provide funding. However, as part of the arrangement, we have rights to the gas supply from this area at a price that is competitive to our other locations in Trinidad, Chile and Egypt.
We believe we are well positioned to meet our financial commitments in this time of economic uncertainty and continue to invest to grow our business.
The credit ratings for our unsecured notes at December 31, 2009 were as follows:
| | | |
| Standard & Poor’s Rating Services | | BBB- (negative) |
| Moody’s Investor Services | | Ba1 (stable) |
Credit ratings are not recommendations topurchase, hold or sell securities and do not comment on market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future.
18
Summary of Contractual Obligations and Commercial Commitments
A summary of the estimated amount and estimated timing of cash flows related to our contractual obligations and commercial commitments as at December 31, 2009 is as follows:
| | | | | | | | | | | | | | | | | | | | | |
| ($ MILLIONS) | | 2010 | | | 2011-2012 | | | 2013-2014 | | | After 2014 | | | TOTAL | |
Long-term debt repayments | | | 29 | | | | 291 | | | | 98 | | | | 511 | | | $ | 929 | |
Long-term debt interest obligations | | | 57 | | | | 101 | | | | 62 | | | | 81 | | | | 301 | |
Repayment of other long-term liabilities | | | 5 | | | | 11 | | | | 4 | | | | 38 | | | | 58 | |
Capital lease obligations | | | 9 | | | | 17 | | | | — | | | | — | | | | 26 | |
Natural gas and other | | | 177 | | | | 287 | | | | 301 | | | | 1,498 | | | | 2,263 | |
Operating lease commitments | | | 131 | | | | 236 | | | | 198 | | | | 467 | | | | 1,032 | |
Egypt plant under construction | | | 93 | | | | — | | | | — | | | | — | | | | 93 | |
| | | | | | | | | | | | | | | | |
| | | | 501 | | | | 943 | | | | 663 | | | | 2,595 | | | $ | 4,702 | |
| | | | | | | | | | | | | | | | |
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 with Argentinean suppliers for natural gas sourced from Argentina for a significant portion of the capacity of our facilities in Chile. These contracts have expiration dates between 2017 and 2025 and represent a total potential future commitment of approximately $1 billion at December 31, 2009. 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 (refer to theProduction Summary — Chilesection on page 8 for more information).
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 drawn as of December 31, 2009 and other limited recourse debt facilities, as well as our proportionate share of total expected principal repayments related to the Atlas limited recourse debt facilities. Interest obligations related to variable interest rate long-term debt were estimated using current interest rates in effect at December 31, 2009. For additional information, refer to note 7 of our 2009 consolidated financial statements.
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.
Capital Lease Obligations
We have entered into a capital lease agreement for an ocean-going vessel. The above table includes the future minimum lease payments related to this capital lease. For additional information, refer to note 8(b) of our 2009 consolidated financial statements.
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. Take-or-pay means that we are obliged to pay for the supplies regardless of whether we take delivery. Such commitments are typical 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 take-or-pay quantity.
19
Most of the natural gas supply contracts for our facilities in Chile, Trinidad and New Zealand and the natural gas supply contract for the methanol project under construction in Egypt are take-or-pay contracts denominated in United States dollars and include base and variable price components to reduce our commodity price risk exposure. The variable price component of each natural gas contract is adjusted by a formula related to methanol prices above a certain level. We believe this pricing relationship enables these facilities to be competitive 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.
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. Under these contracts with ENAP, we have the right to receive quantities of “make-up gas” if ENAP fails to deliver quantities of gas that it is obligated to deliver to us. Over the past few years, ENAP has delivered less than the full amount of natural gas that it was required to deliver under these contracts.
During 2008, we signed an agreement with ENAP to accelerate natural gas exploration and development in the Dorado Riquelme exploration block in southern Chile and to supply natural gas to our Chile production facilities. Final government approvals were received in the third quarter of 2009. Under the arrangement, we fund a 50% participation in the block and we have agreed to take all natural gas produced from the Dorado Riquelme block. We cannot determine the amount of natural gas that will be purchased under this arrangement, and accordingly, no amounts have been included in the above table.
During 2007, we reached an arrangement with GeoPark to purchase all natural gas produced by GeoPark from the Fell block in southern Chile for a 10-year period. The pricing under this arrangement has a base component and a variable component determined with reference to a 3-month trailing average of industry methanol prices. We cannot determine the amount of natural gas that will be purchased under this arrangement in the future, and accordingly, no amounts have been included in the above table.
In Trinidad, we also 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.
In New Zealand, we have take-or-pay supply contracts that have a variable pricing component and these are included in the above table. These contracts are with a number of suppliers, which, together with some spot purchases of natural gas, will enable us to continue operating our 900,000 tonne per year Motunui plant until near the end of 2010.
Our long-term take-or-pay natural gas supply contract for the methanol project under construction in Egypt is included in the above table. We expect this facility to startup in mid-2010. The pricing for natural gas under this contract includes base and variable price components. The variable component of the natural gas contract in Egypt begins in mid-2012 and is determined with reference to our average realized price of methanol each quarter. This contract expires 25 years from the start of the commercial operation of the facility.
At December 31, 2009, we have annual methanol purchase commitments under offtake contracts for approximately 450,000 tonnes for 2010, approximately 380,000 tonnes for each of 2011 and 2012, and approximately 200,000 tonnes for 2013. The pricing under these contracts is referenced to industry pricing at the time of purchase, and accordingly, no amounts have been included in the above table.
20
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.
Egypt Plant under Construction
Project under construction includes the estimated total remaining capital expenditures to complete the construction of the 1.3 million tonne methanol facility in Egypt, including capitalized interest related to the project financing and excluding working capital.
Off-Balance Sheet Arrangements
At December 31, 2009, 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.
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 unless exempted. Changes in fair value of derivative financial instruments are recorded in earnings unless the instruments are designated as cash flow hedges.
21
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, 2009 and December 31, 2008, respectively:
| | | | | | | | | |
| ($ MILLIONS) | | 2009 | | | 2008 | |
| | | | | | | | | |
Financial assets: | | | | | | | | |
Held for trading financial assets: | | | | | | | | |
Cash and cash equivalents | | $ | 170 | | | $ | 328 | |
Debt service reserve accounts included in other assets | | | 13 | | | | 18 | |
| | | | | | | | | |
Loans and receivables: | | | | | | | | |
Receivables, excluding current portion of GeoPark financing | | | 249 | | | | 208 | |
Dorado Riquelme investments included in other assets | | | — | | | | 42 | |
GeoPark financing, including current portion | | | 46 | | | | 37 | |
| | | | | | | |
| | | $ | 478 | | | $ | 633 | |
| | | | | | | |
| | | | | | | | | |
Financial liabilities: | | | | | | | | |
Other financial liabilities: | | | | | | | | |
Accounts payable and accrued liabilities | | $ | 233 | | | $ | 235 | |
Long-term debt, including current portion | | | 914 | | | | 782 | |
| | | | | | | | | |
Held for trading financial liabilities: | | | | | | | | |
Derivative instruments designated as cash flow hedges | | | 33 | | | | 38 | |
Derivative instruments | | | — | | | | 2 | |
| | | | | | | |
| | | $ | 1,180 | | | $ | 1,057 | |
| | | | | | | |
At December 31, 2009, all of the financial instruments were recorded on the balance sheet at amortized cost with the exception of cash and cash equivalents, derivative financial instruments and debt service reserve accounts included in other assets which were 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 of September 28, 2007 to March 31, 2015.
These interest rate swaps had outstanding notional amounts of $351 million as at December 31, 2009. Under the interest rate swap contracts, the maximum notional amount during the term is $368 million. The notional amount on the interest rate swap contracts increases over the period of expected drawdowns and decreases over the expected repayment period on the Egypt limited recourse debt. At December 31, 2009, these interest rate swap contracts had a negative fair value of $33.2 million (December 31, 2008 — negative $38.1 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.
At December 31, 2009, our derivative financial instruments that had not been designated as cash flow hedges included a floating-for-fixed interest rate swap contract with a negative fair value of $0.1 million (December 31, 2008 — $0.6 million) recorded in other long-term liabilities. For the year ended December 31, 2009, the total change in the fair value of this interest rate swap contract was an increase of $0.5 million, which has been recorded in earnings during the period.
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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 Estimatessection on page 31, to be among the most important for understanding the issues that face our business and our approach to risk management.
Security of Natural Gas Supply and Price
We use natural gas as 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 mid-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 at approximately 25-30% of total production 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.
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 8 of this document. We are pursuing investment opportunities with ENAP, GeoPark and others to help accelerate natural gas exploration and development in southern Chile. In addition, the government of Chile completed an international bidding round in 2007 to assign natural gas exploration areas that lie close to our production facilities and announced the participation of several international oil and gas companies.
We cannot provide assurance that we, ENAP, GeoPark or the other bidding round participants will complete all planned expenditures or be successful in the exploration and development of natural gas in Chile or that we will obtain any additional natural gas from suppliers in Chile on commercially acceptable terms.
As a result of the Argentinean natural gas supply issues discussed above, all of the methanol production at our Chile facilities has been produced with natural gas from suppliers in Chile since mid-June of 2007. Over the past few years, ENAP, our primary supplier in Chile, has delivered less than the full amount of natural gas that it was obligated to deliver to us due to ongoing deliverability and production issues. The shortfalls in natural gas deliveries are generally greater in the southern hemisphere winter due to the need to satisfy increased demand for residential uses in the region. We cannot provide assurance that the loss of natural gas supply to our plants in Chile as a result of such issues will not be greater than it has been in the past. Such losses could have an adverse effect 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 2.1 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 we could access 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.
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New Zealand
We have three plants in New Zealand with a total production capacity of up to 2.4 million tonnes per year. Two plants are located at Motunui and the third is located at Waitara Valley, seven kilometers away. In 2004 we idled our two Motunui plants but continued to operate the Waitara Valley plant until October 2008 to match natural gas supply availability. In October 2008, we restarted one 900,000 tonne per year plant in Motunui and idled the 530,000 tonner per year Waitara Valley plant. The Motunui plant produced 822,000 tonnes of methanol during 2009. Our second Motunui plant and our Waitara Valley plant provide the potential to increase production in New Zealand depending on methanol supply and demand dynamics and the availability of natural gas on commercially acceptable terms.
During the past few years, increased natural gas exploration and development activity in New Zealand has resulted in improved gas availability and deliverability. We have a range of gas suppliers with existing contracts expiring at various times during 2010. We currently have sufficient quantities of natural gas to operate the one Motunui plant until near the end of 2010. Our main priority is to secure more gas to extend the operation of this plant, and we are in the process of finalizing contracts with a number of suppliers. Based on the improved outlook for natural gas in New Zealand, we are optimistic that we can secure additional gas supply in New Zealand and potentially restart more capacity there in the future.
The future operation of each of our New Zealand facilities depends on methanol industry supply and demand and the availability of natural gas on commercially acceptable terms. There can be no assurance that the ongoing exploration and development activity in New Zealand will be successful or that we will be able to secure additional gas for our facilities on commercially acceptable terms.
Egypt
Natural gas for the 1.3 million tonne per year production facility that we are currently constructing in Egypt is supplied under a single long-term contract with the government-owned Egyptian Natural Gas Holding Company. The contract expires 25 years after the start of the commercial operation of the facility. We expect this facility to startup in mid-2010. Gas will be 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. Egypt manages its gas reserves to ensure that demand growth related to new industrial projects is compatible with Egyptian residential demand growth. Demand growth could be significant given Egypt’s demographics. As well, Egypt has a stated goal of increasing economic development. As a result, we cannot provide assurance that we will not experience curtailments of natural gas supply which could have an adverse impact on our results of operations and financial condition.
Canada
We have a 470,000 tonne plant at Medicine Hat, Alberta that was idled in 2001 due to high natural gas feedstock prices in North America. The plant remains in good mechanical condition and is capable of being restarted. During the past few years there have been natural gas supply improvements in North America from shale and conventional sources that could provide the opportunity to secure sufficient natural gas on commercially acceptable terms to enable a restart of our facility in Medicine Hat. However, we are in the very early stages of discussions with potential gas suppliers and it is too soon to determine whether or not it will be possible to restart this facility in the future.
The future operation of our Medicine Hat facility depends on 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 secure sufficient natural gas for our Medicine Hat facilities on commercially acceptable terms.
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 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.
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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 Financial Crisis and Related Economic Slowdown
The recent global financial crisis and related economic slowdown added significant risks and uncertainties for our business, including risks and uncertainties related to the impact on 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 global economy has improved and demand for methanol and methanol prices have recovered somewhat, there can be no assurance that any such recovery will be sustained.
Liquidity Risk
We have an undrawn $200 million credit facility that expires in mid-2012. 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. We cannot provide assurance that all of these financial institutions will have the financial ability to honour a draw under the credit facility or that we will be able to meet these financial covenants in the future.
In addition, as at December 31, 2009, we had $58 million of undrawn capacity on the $530 million limited recourse debt facilities for the new Egypt facility that we are constructing with partners. We cannot provide assurance that the lenders under this facility will have the financial ability to honour future draws.
If we are unable to draw on the existing facilities described above or if we are unable to access new financing in the future, this 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 and Supplier Risk
In recessionary periods, such as the recent global recession, the risk of trade credit losses increases. Most of our customers are large global or regional petrochemical manufacturers or distributors and a number are highly leveraged. Two of our customers filed for bankruptcy protection in 2008 and 2009. While the outstanding receivables from these customers were not material at the time of these filings, it is possible, particularly if global economic activity slows again, that other customers may seek protection from creditors in the future and our exposure to such customers’ receivables could be greater. Although we monitor our customers’ financial status closely, 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 historically significant, this risk still exists, particularly if global economic activity slows significantly again.
The recent recession also increased the risk that some of our suppliers would not be able to meet future supply commitments, which could have an adverse effect on our results of operations and financial condition.
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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 for revenues on 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 United States 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 that was released by the EPA in January 2010 classified methanol as “Likely to Be Carcinogenic to Humans”. The EPA is conducting its public comment and review process related to this draft assessment and a final report relating to the human health effects of methanol, including its potential carcinogenicity, is expected to be released in the second quarter of 2011. We are unable to determine at this time whether this 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, financial condition or our stock price.
Demand for Methanol in the Production of Formaldehyde
In 2009, methanol demand for the production of formaldehyde represented approximately 34% 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. The estimated date of completion for the formaldehyde review is unknown at this time.
In May 2009, the 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 International Agency for Research on Cancer also recently concluded that there is sufficient evidence in humans of a causal association of formaldehyde with leukemia.
The U.S. Department of Health and Human Services’ (HHS) National Toxicology Program (NTP) Report on Carcinogens currently lists formaldehyde as “reasonably anticipated to be a human carcinogen.” This classification is currently under review. The NTP is expected to issue a report in December 2010 which could raise the formaldehyde classification to “human carcinogen”. In addition, there are legislative initiatives underway in the United States related to new national emissions standards for formaldehyde.
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 2009, methanol for the production of MTBE represented approximately 13% of global methanol demand. 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.
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Several years ago, environmental concerns and legislative action related to gasoline leaking into water supplies from underground gasoline storage tanks in the United States have led to 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 since 2007 to make MTBE for use in domestic fuel blending. However, approximately 750,000 tonnes of methanol was used in the United States in 2009 (the same amount as in 2008) 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 2010 to remain steady or to decline slightly, it could decline materially as this demand is uncertain and will be determined by various factors, including export economics and changes to legislation or policies related to MTBE use in countries that import MTBE from the United States.
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 the third quarter of 2011.
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 and this has resulted in some MTBE producers switching production to ethyl tert-butyl ether (ETBE) to access biofuels incentives. However, due to strong MTBE demand in other countries, we have observed the opposite in 2009, with some ETBE producers switching back to 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 further 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.
Foreign Operations
The majority of our operations and investments are located outside of North America, including 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, 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.
In addition, because we derive substantially all 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 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.
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In June 2009, the Chinese government began an anti-dumping investigation against imports of methanol from New Zealand, Saudi Arabia, Indonesia and Malaysia. A preliminary determination is expected in the first half of 2010 and a final determination is expected later in 2010. No new duties or other measures have been imposed to date. As an importer of methanol from New Zealand into China, we have fully co-operated with this investigation. We have submitted documents and data supporting our argument that there is no correlation between the alleged injury suffered by the local industry and the imports from the targeted countries. However, we cannot predict the outcome of this investigation and it is possible that the Chinese government could impose duties or other measures that 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 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, our financial condition or our stock price.
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 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. In mid-2007, we experienced a significant reduction in our production levels at our plants in Chile as a result of the natural gas curtailments from Argentina. Accordingly, we have increased our purchasing levels of methanol since that time to continue to meet our customer commitments, which has increased our exposure to holding losses on the sale of purchased methanol. Holding losses could have an adverse effect on our results of operations and financial condition.
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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 the recent recession made it more difficult to mitigate these costs due to significant excess shipping capacity. As we enter 2010, the shipping market has not yet fully recovered from the recession. 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.
Egypt Plant under Construction
We are currently constructing a 1.3 million tonne per year methanol facility with partners in Egypt. While we believe that our estimates of project costs and anticipated completion for the Egyptian project are reasonable, 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.
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 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 have laws and regulations to which we are subject governing the environment and the management of natural resources as well as the handling, storage, transportation and disposal of hazardous or waste materials. We are also subject to laws and regulations governing emissions and the import, export, use, discharge, storage, disposal and transportation of toxic substances. The products we use and produce are subject to regulation under various health, safety and environmental laws. Non-compliance with any of these laws and regulations may give rise to work orders, fines, injunctions, civil liability and criminal sanctions.
As a result of periodic external and internal audits, we currently 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 that renders 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 material 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 material costs or liabilities.
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Carbon dioxide is a significant by-product of the methanol production process. We manufacture methanol in Chile, Trinidad and New Zealand and we are constructing a new facility in Egypt with partners. All of these countries have signed and ratified the Kyoto Protocol. Under the Kyoto Protocol, we are not currently required to reduce greenhouse gases (GHGs) in the developing nations of Chile, Trinidad and Egypt. However, as a developed nation, New Zealand does have obligations related to GHG emissions reduction under the Kyoto Protocol.
To meet its commitments under the Kyoto Protocol, New Zealand passed legislation to establish an Emission Trading Scheme (ETS) that will take effect from July 1, 2010. The ETS will impose a carbon price on producers of fossil fuels, including natural gas, which is expected in turn to increase the costs of natural gas that Methanex purchases in New Zealand. However, as a trade-exposed company, Methanex will be 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. After this date, the moderating features are expected to be removed, our eligibility for free allocation of emissions units will be progressively reduced and we will likely have to pay the increased costs. We currently believe that the ETS will not have a material adverse impact on our results of operations and financial condition to the end of 2012. However, at this time it is difficult to accurately quantify the impact on our business after 2012 and therefore we cannot provide assurance that the ETS will not have a material adverse impact on our results of operations and financial condition after 2012.
Legal Proceedings
In 2009, the Board of Inland Revenue of Trinidad and Tobago issued an assessment against our wholly owned subsidiary, Methanex Trinidad (Titan) Unlimited, in respect of the 2003 financial year. The assessment related to the deferral of tax depreciation deductions during a five-year tax holiday that ended in 2005. The amount in dispute as at December 31, 2009 is approximately $23 million in current taxes and $26 million in future taxes, exclusive of any interest charges. 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 sustainable. However, we cannot provide assurance that the final assessment will not have an adverse effect on our results of operations and financial condition.
OUTLOOK
Methanol is a global chemical 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.
As we entered 2009, the global financial crisis and weak economic environment caused a sharp reduction in global demand for most traditional methanol derivatives (which represent approximately 70% of global methanol demand), while demand for methanol in energy-related applications (30% of global methanol demand) remained healthy. Overall, we estimate that global demand had declined by about 15% from 2008 pre-recession levels to an annualized level of about 36 million tonnes. As a result, a significant amount of high cost capacity shut in or operated at lower rates for a period of time to bring supply and demand into balance. This resulted in a period of lower methanol prices, with contract pricing across global markets averaging about $213 per tonne over the first half of the year.
During 2009, global methanol demand recovered and by the end of the year it reached a level of approximately 43 million tonnes measured on an annualized basis. Demand recovery was mainly focused in in Asia, particularly in China. In Europe and North America, demand into chemical derivatives began to recover in the second half of 2009, but still lagged pre-recession levels. Methanol blending into gasoline in China has been particularly strong and we believe that future growth in this application is supported by recent regulatory changes in that country. For example, an M85 (or 85% methanol blend) national standard took effect on December 1, 2009, and we expect an M15 (or 15% methanol blend) national standard to be released later in 2010. Supported by an environment of strong energy prices, methanol demand into DME in China also increased in 2009.
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In addition to the improvement in demand, we have seen an escalation in feedstock costs for producers and significant supply challenges. There have been a number of planned and unplanned plant outages across the industry and we understand that two new-world scale methanol plants that began operations in the last 12 months have been operating at reduced rates. As a result of the improvement in demand, industry supply challenges and the increase in costs for many producers, methanol prices increased through the latter half of 2009 and into 2010. Our average non-discounted posted price in January was approximately $350 per tonne.
Over the two-year period to the end of 2011, it is expected that new capacity and expansions will add approximately four million tonnes of capacity to the global industry outside of China, including the 1.3 million tonne plant we are constructing in Egypt with partners. We believe that this new capacity could be offset by demand growth outside of China, import growth into China and further closures of high cost capacity in the industry.
There are significant capacity additions planned in China over the next few years. However, the Chinese methanol industry has historically operated at low rates and there has been increasing pressure on its cost structure as a result of escalating feedstock costs for both coal and natural gas based producers. At the beginning of 2009, as a result of the lower methanol price environment, we estimate about 6 million tonnes of annualized higher-cost or less-efficient methanol production in China was shut down and net imports into China increased by approximately 5 million tonnes on an annualized basis. During the second half of 2009, increasing methanol prices resulted in some higher-cost capacity restarting in China and, given the strong demand for methanol, import levels also remained high. In addition, the majority of the methanol produced in China is made from coal and is typically lower quality and not suitable for all customers. In a high global energy price environment, we believe that methanol demand in China should continue to grow at high rates and that this will more than offset increases of domestic production in China and imports of methanol into China will increase over time.
The methanol price will ultimately depend on the strength of the economic recovery, 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 low 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.
CRITICAL ACCOUNTING ESTIMATES
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 1 to our 2009 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, 2009, the net book value of our property, plant and equipment was $2,184 million. We estimate the useful lives of property, plant and equipment and this is used as the basis for recording depreciation and amortization. Recoverability of property, plant and equipment is measured by comparing the net book value of an asset to the undiscounted future net cash flows expected to be generated from the asset over its estimated useful life. An impairment charge is recognized in cases where the undiscounted expected future cash flows from an asset are less than the net book value of the asset. The impairment charge is equal to the amount by which the net book value of the asset exceeds its fair value. Fair value is based on quoted market values, if available, or alternatively using discounted expected future cash flows.
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We test our long-lived assets 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. For purposes of recognition and measurement of an impairment loss, we group our long-lived assets with other assets and liabilities to form an “asset group,” 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 moved 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.
Asset Retirement Obligations
We record asset retirement obligations at fair value when incurred for those sites where a reasonable estimate of the fair value can be determined. At December 31, 2009, we have accrued $16 million for asset retirement obligations. Inherent uncertainties exist 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.
Income Taxes
Future income tax assets and liabilities are determined using enacted tax rates for the effects of net operating losses and temporary differences between the book and tax bases of assets and liabilities. We record a valuation allowance on future tax assets, when appropriate, to reflect the uncertainty of realizing future tax benefits. In determining the appropriate valuation allowance, 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. In making this analysis, we consider historical profitability and volatility to assess whether we believe it to be more likely than not 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, 2009, we had future income tax assets of $218 million that are substantially offset by a valuation allowance of $163 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.
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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 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. At December 31, 2009, inventory is appropriately valued at cost.
Accounts Receivable and Allowance for Doubtful Accounts
We provide credit to our customers in the normal course of business. We perform ongoing credit evaluations of our customers and maintain reserves for potential credit losses. We record an allowance for doubtful accounts or write down the receivable to estimated net realizable value if not collectible in full. As at December 31, 2009, we had approximately $191 million in trade accounts receivable, and we believe that we have adequately provided for any credit losses. Historically, credit losses have been within the range of management’s expectations. However, in the current economic environment, there continues to be an increased risk of trade credit losses and because of uncertainties in estimated future credit losses, credit losses on trade receivables could be materially different from amounts estimated.
Oil and Gas Accounting
On August 24, 2009, the Company received final government approval of the agreement signed on May 5, 2008 with ENAP, the Chilean state-owned oil and gas company. The agreement with ENAP is to accelerate gas exploration and development in the Dorado Riquelme exploration block in southern Chile and supply new Chilean-sourced natural gas to the Company’s production facilities in Chile. Under the arrangement we fund a 50% participation in the block.
Upon receiving final government approval of the agreement, the Company adopted the CICA guideline on full cost accounting in the oil and gas industry to account for our investment in the Dorado Riquelme block. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, the exploration for, and the development of natural gas reserves are capitalized. Costs are then depleted and amortized using the unit-of-production method based on estimated proved reserves. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded from the costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or impairment has occurred. Costs that have been impaired are included in the costs subject to depletion and amortization.
Under the CICA guideline on full cost accounting, an impairment assessment (“ceiling test”) is performed on an annual basis for all oil and gas assets. An impairment loss is recognized in earnings when the carrying amount is not recoverable and the carrying amount exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is measured as the amount by which the carrying amount exceeds the sum of the discounted cash flows of proved and probable reserves.
As a result of the adoption of the full cost accounting methodology, the Company reclassified the cumulative oil and gas expenditures of $58.7 million from other assets to property, plant and equipment in the third quarter of 2009. The Company performed the annual ceiling test for its investment in the Dorado Riquelme block and concluded no impairment existed as at December 31, 2009. For the year ended December 31, 2009, the Company contributed $22.8 million (2008 — $41.8 million) to the Dorado Riquelme investment.
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Derivative Financial Instruments
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. The valuation of derivative financial instruments is a critical accounting estimate due to the complex nature of these products, the degree of judgment required to appropriately value these products and the potential impact of such valuation on our financial statements. 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. At December 31, 2009, the fair value of our derivative financial instruments used to limit our exposure to foreign exchange volatility and to variable interest rate volatility approximated their carrying value of negative $33.2 million. Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in foreign exchange rates and variable interest rates, which have been volatile in the current economic environment.
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NEW CANADIAN ACCOUNTING STANDARDS ADOPTED IN 2009
Goodwill and Intangible Assets
On January 1, 2009, the Company adopted CICA Handbook Section 3064,Goodwill and Intangible Assets. This new accounting standard replaces Section 3062,Goodwill and Other Intangible Assets. Section 3064 expands on the standards for the recognition, measurement and disclosure of intangible assets. The impact of the retroactive adoption of this standard on the Company’s consolidated balance sheet at January 1, 2009 is approximately $13 million recorded as a reduction to opening retained earnings and property, plant and equipment. The amount relates to certain pre-operating expenditures that have been capitalized to property, plant and equipment at December 31, 2008 that would have been required to be expensed under this new standard. The impact for the year ended December 31, 2009 was an increase to selling, general and administrative expenses of approximately $3.8 million (2008 — $3.5 million).
As a portion of these pre-operating expenditures were incurred in a non-whollyowned subsidiary, the Company has also adjusted the opening non-controlling interest (NCI) and retained earnings balances at December 31, 2008 for the NCI’s proportionate share of approximately $4 million.
Oil and Gas Accounting
On August 24, 2009, the Company received final government approval of the agreement signed on May 5, 2008 with Empresa Nacional del petroleo (ENAP), the Chilean state-owned oil and gas company. The agreement with ENAP is to accelerate gas exploration and development in the Dorado Riquelme exploration block in southern Chile and supply new Chilean-sourced natural gas to the Company’s production facilities in Chile. Under the arrangement we fund a 50% participation in the block. Upon receiving final government approval of the agreement, the Company adopted the CICA guideline on full cost accounting in the oil and gas industry to account for our investment in the Dorado Riquelme block (refer to theCritical Accounting Estimates — Oil and Gas Accountingsection on page 33 for more information).
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ANTICIPATED CHANGES TO CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
International Financial Reporting Standards
The Canadian Accounting Standards Board confirmed January 1, 2011 as the changeover date for Canadian publicly accountable enterprises to start using International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). IFRS uses a conceptual framework similar to Canadian GAAP, but there are significant differences in recognition, measurement and disclosures.
As a result of the IFRS transition, changes in accounting policies are likely and may materially impact our consolidated financial statements. The IASB will also continue to issue new accounting standards during the conversion period, and as a result, the final impact of IFRS on our consolidated financial statements will only be measured once all the IFRS applicable at the conversion date are known.
We have established a working team to manage the transition to IFRS. Additionally, we have established a formal project governance structure that includes the Audit, Finance and Risk Committee, senior management, and an IFRS steering committee to monitor progress and review and approve recommendations from the working team for the transition to IFRS. The working team provides regular updates to the IFRS steering committee and to the Audit, Finance and Risk Committee of the Board.
We have developed a plan to convert our consolidated financial statements to IFRS at the changeover date of January 1, 2011 with comparative financial results for 2010. The IFRS transition plan addresses the impact of IFRS on accounting policies and implementation decisions, infrastructure, business activities and control activities. We are progressing according to schedule and continue to be on track toward the transition to IFRS in 2011. We will continue to provide updates on the status of the project and its impact on financial reporting in our quarterly and annual Management’s Discussion and Analysis throughout the convergence period to January 1, 2011. A summary status of the key elements of the changeover plan is as follows:
Accounting policies and implementation decisions
| | • | | Identification of differences in Canadian GAAP and IFRS accounting policies |
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| | • | | Selection of ongoing IFRS policies |
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| | • | | Selection of IFRS 1,First-time Adoption of International Financial Reporting Standards (“IFRS 1”) choices |
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| | • | | Development of financial statement format |
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| | • | | Quantification of effects of change in initial IFRS 1 disclosures and 2010 financial statements |
| | • | | We have identified differences between accounting policies under Canadian GAAP and accounting policy choices under IFRS, both on an ongoing basis and with respect to certain choices available on conversion, in accordance with IFRS 1 |
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| | • | | We have addressed, on a priority basis, those areas that we believe may cause the most significant impact to our consolidated financial statements |
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| | • | | We have engaged the Company’s external auditors, KPMG LLP, to discuss our proposed IFRS accounting policies to ensure consistent interpretation of IFRS guidance in key areas as they are arrived at and agreed by the working team |
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| | • | | We continue to monitor changes in accounting policies issued by the IASB and the impact of those changes on our accounting policies under IFRS |
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| | • | | We continue to progress our selection of IFRS accounting policies and the quantification of identified differences which we anticipate to finalize in 2010 |
Infrastructure: Financial reporting expertise
| | • | | Development of IFRS expertise |
| | • | | We have provided training for key employees and senior management |
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| | • | | We have held an IFRS information session with the Audit, Risk and Finance Committee that included an in-depth review of differences between Canadian GAAP and IFRS, a review of the implementation timeline, an overview of the project activities to date and a preliminary discussion of the significant impact areas of IFRS |
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| | • | | We will provide additional training and updates for key employees, senior management, the Audit, Risk and Finance Committee, the Board and other stakeholders throughout the convergence period |
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| | • | | In 2010, all accounting policy changes arising from the transition to IFRS will be subject to review by senior management, the IFRS Steering Committee and ultimately final review and approval by the Audit, Finance and Risk Committee of the Board |
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Infrastructure: Information technology and data systems
| | • | | Identification of system requirements for the convergence and post-convergence periods |
| | • | | We have assessed the impact on system requirements for the convergence and post-convergence periods. These requirements are limited to the core general ledger system to facilitate the compilation of IFRS comparative results throughout 2010. We do not anticipate significant impact to other applications arising from the transition to IFRS |
Business activities: Financial covenants
| | • | | Identification of impact on financial covenants and financing relationships |
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| | • | | Completion of any required renegotiations/changes |
| | • | | The financial covenant requirements in our financing relationships are measured on the basis of Canadian GAAP in effect at the commencement of the various relationships, and the transition to IFRS will therefore have no impact on our current financial covenant requirements |
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| | • | | We are developing a process to compile our financial results on a historical Canadian GAAP basis and to monitor financial covenant requirements through to the conclusion of our current financing relationships |
Business activities: Compensation arrangements
| | • | | Identification of impact on compensation arrangements |
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| | • | | Assessment and implementation of required changes |
| | • | | We have identified compensation policies that rely on indicators derived from the financial statements |
| | • | | In 2010, we will work with the Company’s human resources department and the Human Resources Committee of the Board to ensure that compensation arrangements incorporate IFRS results in accordance with the Company’s overall compensation principles |
Control activities: Internal control over financial reporting
| | • | | For all accounting policy changes identified, assessing the design and effectiveness of respective changes to Internal Controls over Financial Reporting (“ICFR”) |
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| | • | | Implementation of appropriate changes |
| | • | | We have identified the required accounting process changes that result from the application of IFRS accounting policies; these changes are not anticipated to be significant |
| | • | | In 2010 we will complete the design, implementation and documentation of the accounting process changes that result from the application of IFRS accounting policies |
Control activities: Disclosure controls and procedures
| | • | | For all accounting policy changes identified, assessing the design and effectiveness of respective changes to Disclosure Controls and Procedures (“DC&P”) |
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| | • | | Implementation of appropriate changes |
| | • | | We continue to provide IFRS project updates in quarterly and annual disclosure documents |
| | • | | In 2010, all accounting policy changes arising from the transition to IFRS will be subject to review by senior management, the IFRS Steering Committee and ultimately final review and approval by the Audit, Finance and Risk Committee of the Board |
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Potential Significant Impacts on Transition to IFRS
The Company has completed its initial assessment of the impacts of the transition to IFRS. Based on an analysis of Canadian GAAP and IFRS in effect at December 31, 2009, we have identified several differences between the Company’s current accounting policies and those expected to apply in preparing IFRS consolidated financial statements. Information on those changes that management considers most significant to the Company are presented below.
Interest in Joint Ventures
Under Canadian GAAP, our 63.1% interest in Atlas Methanol Company (Atlas) is accounted for using proportionate consolidation in the accounting for joint ventures. Current IFRS allows a choice between proportionate consolidation and equity accounting in the accounting for joint ventures.
Future changes to IFRS in the accounting for joint ventures are expected and these changes may remove the option for proportionate consolidation and allow only the equity method of accounting for such interests. The impact of applying the equity method of accounting does not result in any change to net earnings or shareholders’ equity. There would be a significant presentation impact, however, in that Atlas’ net results and financial position would be presented on a single line of the Company’s income statement and statement of financial position, respectively.
The IASB is currently proceeding on projects related to consolidation and joint venture accounting. The impact these projects may have on the conclusions related to the accounting treatment of Atlas is currently unknown.
We continue to monitor changes in accounting policies issued by the IASB in this area. We have not yet selected our accounting policy under current IFRS between proportionate consolidation and equity accounting for Atlas.
Leases
Canadian GAAP requires an arrangement that at its inception can be fulfilled only through the use of a specific asset or assets, and which conveys a right to use that asset, may be a lease or contain a lease, and therefore should be accounted for as a lease, regardless of whether it takes the legal form of a lease. However, Canadian GAAP has grandfathering provisions that exempts contracts entered into before 2004 from these requirements.
IFRS has similar accounting requirements as Canadian GAAP for lease-like arrangements, with IFRS requiring full retrospective application. We have long-term oxygen supply contracts for our Atlas and Titan methanol plants in Trinidad, executed prior to 2004, which we believe would be regarded as capital leases under these standards. Accordingly, we believe our Trinidad oxygen supply contracts will be required to be accounted for as finance leases and therefore be recognized on the statement of financial position as an asset with a corresponding long-term liability obligation. Our analysis is ongoing and includes quantifying the impact of this accounting conclusion on transition to IFRS.
Impairment of Assets
If there is an indication that an asset may be impaired, an impairment test must be performed. Under Canadian GAAP, this is a two-step impairment test in which (1) undiscounted future cash flows are compared to the carrying value; and (2) if those undiscounted cash flows are less than the carrying value, the asset is written down to the fair value. Under IFRS, an entity is required to assess, at the end of each reporting period, whether there is any indication that an asset may be impaired. If such an indication exists, the entity shall estimate the recoverable amount of the asset by performing a one-step impairment test, which requires a comparison of the carrying value of the asset to the higher of value in use and fair value less costs to sell. Value in use is defined as the present value of future cash flows expected to be derived from the asset in its current state.
As a result of this difference, in principle, impairment writedowns may be more likely under IFRS than are currently identified and recorded under Canadian GAAP. The extent of any new write downs, however, may be partially offset by the requirement under IAS 36,Impairment of Assetsto reverse any previous impairment losses where circumstances have changed such that the impairments have been reduced. Canadian GAAP prohibits reversal of impairment losses. We do not anticipate that the adoption of these standards will result in an impairment of our assets on transition to IFRS.
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Provisions
Under Canadian GAAP, a provision is required to be recorded in the financial statements when required payment is considered “likely” and can be reasonably estimated. The threshold for recognition of provisions under IFRS is lower than that under Canadian GAAP as provisions must be recognized if required payment is “probable.” Therefore, in principle, it is possible that there may be some provisions which would meet the recognition criteria under IFRS that were not recognized under Canadian GAAP.
Other differences between IFRS and Canadian GAAP exist in relation to the measurement of provisions, such as the methodology for determining the best estimate where there is a range of equally possible outcomes (IFRS uses the mid-point of the range, whereas Canadian GAAP uses the low end of the range), and the requirement under IFRS for provisions to be discounted where material.
IFRS 1 First-Time Adoption of International Financial Reporting Standards
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. The following are the optional exemptions available under IFRS 1 that the Company currently intends to elect on transition to IFRS. The Company continues to review all IFRS 1 exemptions and will implement those determined to be most appropriate in our circumstances on transition to IFRS. The list below and comments should not be regarded as a complete list of IFRS 1 that are available to the Company as a result from the transition to IFRS.
Business Combinations
Under IFRS 1 an entity has the option to retroactively apply IFRS 3,Business Combinationsto all business combinations or may elect to apply the standard prospectively only to those business combinations that occur after the date of transition. The Company currently intends to elect this exemption under IFRS 1, which removes the requirement to retrospectively restate all business combinations prior to the date of transition to IFRS.
Employee Benefits
IFRS 1 provides an option to recognize all cumulative actuarial gains and losses existing at the date of transition immediately in retained earnings, rather than continuing to defer and amortize into the results of operations. The Company currently intends to elect this exemption under IFRS 1. Our analysis is ongoing to quantify the impact of this election on transition to IFRS.
The discussion above on potential significant impacts on transition to IFRS is provided to allow readers to obtain a better understanding of our IFRS changeover plan and the resulting potential effects on our consolidated financial statements. Readers are cautioned, however, that it may not be appropriate to use such information for any other purpose. This discussion reflects our most recent assumptions and expectations; circumstances may arise, such as changes in IFRS, regulations or economic conditions, which could change these assumptions or expectations. We are still in the process of completing the selection of IFRS accounting policies and the quantification of identified differences. Once completed, this information will be subject to approval by the Audit, Finance and Risk Committee and audit by KPMG LLP, prior to being finalized. Accordingly, the discussion above is subject to change.
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SUPPLEMENTAL NON-GAAP MEASURES
In addition to providing measures prepared in accordance with Canadian GAAP, we present certain supplemental non-GAAP measures. These are Adjusted EBITDA, operating income and cash flows from operating activities before changes in non-cash working capital. These measures do not have any standardized meaning prescribed by Canadian GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. We believe these measures are useful in evaluating the operating performance and liquidity of our ongoing business. 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 Canadian GAAP.
Adjusted EBITDA
This supplemental non-GAAP measure is provided to help readers determine our ability to generate cash from operations. We believe this measure is useful in assessing performance and highlighting trends on an overall basis. We also believe Adjusted EBITDA is frequently used by securities analysts and investors when comparing our results with those of other companies. Adjusted EBITDA differs from the most comparable GAAP measure, cash flows from operating activities, primarily because it does not include changes in non-cash working capital, stock-based compensation expense and other non-cash items net of cash payments, interest expense, interest and other income, and current income taxes.
The following table shows a reconciliation of cash flows from operating activities to Adjusted EBITDA:
| | | | | | | | | |
| ($ MILLIONS) | | 2009 | | | 2008 | |
Cash flows from operating activities | | $ | 110 | | | $ | 313 | |
Add (deduct): | | | | | | | | |
Changes in non-cash working capital | | | 18 | | | | (78 | ) |
Other cash payments | | | 11 | | | | 7 | |
Stock-based compensation expense | | | (12 | ) | | | (3 | ) |
Other non-cash items | | | (7 | ) | | | (3 | ) |
Interest expense | | | 27 | | | | 38 | |
Interest and other income | | | — | | | | (10 | ) |
Income taxes — current | | | (5 | ) | | | 66 | |
| | | | | | | |
Adjusted EBITDA | | $ | 142 | | | $ | 330 | |
| | | | | | | |
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 Canadian GAAP measures in our consolidated statement of income and consolidated statement of cash flows, respectively.
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QUARTERLY FINANCIAL DATA (UNAUDITED)
| | | | | | | | | | | | | | | | | |
| | | THREE MONTHS ENDED | |
| ($ MILLIONS, EXCEPT WHERE NOTED) | | DEC 31 | | | SEP 30 | | | JUN 30 | | | MAR 31 | |
2009 | | | | | | | | | | | | | | | | |
| Revenue | | $ | 382 | | | $ | 317 | | | $ | 246 | | | $ | 254 | |
| Net income (loss) | | | 26 | | | | (1 | ) | | | (6 | ) | | | (18 | ) |
| Basic net income (loss) per share | | | 0.28 | | | | (0.01 | ) | | | (0.06 | ) | | | (0.20 | ) |
| Diluted net income (loss) per share | | | 0.28 | | | | (0.01 | ) | | | (0.06 | ) | | | (0.20 | ) |
| | | | | | | | | | | | | | | | | |
| 2008 | | | | | | | | | | | | | | | | |
| Revenue | | $ | 408 | | | $ | 570 | | | $ | 600 | | | $ | 736 | |
| Net income | | | (4 | ) | | | 70 | | | | 38 | | | | 65 | |
| Basic net income per share | | | (0.04 | ) | | | 0.75 | | | | 0.40 | | | | 0.66 | |
| Diluted net income per share | | | (0.04 | ) | | | 0.74 | | | | 0.40 | | | | 0.66 | |
| | | | | | | | | | | | | |
A discussion and analysis of our results for the fourth quarter of 2009 is set out in our fourth quarter of 2009 Management’s Discussion and Analysis filed with Canadian Securities Administrators and the U.S. Securities and Exchange Commission and incorporated herein by reference.
SELECTED ANNUAL INFORMATION
| | | | | | | | | | | | | |
| ($ MILLIONS, EXCEPT WHERE NOTED) | | 2009 | | | 2008 | | | 2007 | |
Revenue | | $ | 1,198 | | | $ | 2,314 | | | $ | 2,266 | |
Net income | | | 1 | | | | 169 | | | | 373 | |
Basic net income per share | | | 0.01 | | | | 1.79 | | | | 3.66 | |
Diluted net income per share | | | 0.01 | | | | 1.78 | | | | 3.65 | |
Cash dividends declared per share | | | 0.620 | | | | 0.605 | | | | 0.545 | |
Total assets | | | 2,923 | | | | 2,799 | | | | 2,862 | |
Total long-term financial liabilities | | | 982 | | | | 864 | | | | 656 | |
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CONTROLS AND PROCEDURES
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, 2009, 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 our disclosure controls and procedures are effective.
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, 2009, based on the framework set forth inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under this framework, management concluded that our internal control over financial reporting was effective as of that date.
KPMG LLP (“KPMG”), 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, 2009. The attestation report is included on page 1 of our consolidated financial statements.
Changes in Internal Control over Financial Reporting
There have been no changes during the year ended December 31, 2009 to internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
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FORWARD-LOOKING STATEMENTS
This 2009 Annual Report contains forward-looking statements with respect to us and the chemical industry. Statements that include the words “believes,” “expects,” “may,” “will,” “should,” “seeks,” “intends,” “plans,” “estimates,” “anticipates,” or the negative version of these words or other comparable terminology and similar statements of a future or forward-looking nature identify forward-looking statements.
More particularly and without limitation, any statements regarding the following are forward-looking statements:
| • | | expected demand for methanol and its derivatives, |
| • | | expected new methanol supply and timing for start-up of same, |
| • | | expected shutdowns (either temporary or permanent) or restarts of existing methanol supply (including our own facilities), including, without limitation, timing of planned maintenance outages, |
| • | | expected prices of methanol and methanol derivatives, |
| • | | expected energy prices (including prices for natural gas and coal feedstocks), |
| • | | anticipated production from, and production rates of, our plants, |
| • | | expected levels of natural gas supply to our plants, |
| • | | capital committed by third parties towards future natural gas exploration in southern Chile, |
| • | | anticipated results of natural gas exploration in southern Chile and New Zealand and timing of same, |
| • | | receipt of third-party consents or approvals, |
| • | | expected operating costs, including natural gas feedstock costs and logistics costs, |
| • | | expected cash flows or earnings capability, |
| • | | ability to enter into new, or renew existing, gas contracts on commercially acceptable terms, |
| • | | expected expenditures and future sources of funding for such expenditures, including expenditures to support natural gas exploration and development in southern Chile and New Zealand, |
| • | | capital expenditures to support natural gas exploration and development in southern Chile and New Zealand, |
| • | | anticipated start-up date of, and cost to complete, our methanol project in Egypt, |
| • | | availability of committed credit facilities and other financing, |
| • | | shareholder distribution strategy and anticipated distributions to shareholders, |
| • | | commercial viability of, success of, or ability to execute future projects, including capacity expansions, |
| • | | financial strength and ability to meet future financial commitments, |
| • | | expected impact of regulatory actions, including assessments of the carcinogenicity of methanol, formaldehyde and MTBE, the imposition of formaldehyde emission limits and legislation related to CO2 emissions in New Zealand, |
| • | | expected global or regional economic activity (including industrial production levels) and expectations regarding recovery from the current uncertain economic environment, |
| • | | expected financial statement and other impacts related to the Company’s transition to IFRS, |
| • | | expected outcome of legal proceedings, including the tax assessment recently issued by the Board of Inland Revenue of Trinidad and Tobago and |
| • | | expected actions of governments, gas suppliers, courts, tribunals and other third parties, including the establishment by the Chinese government of new fuel-blending standards and the outcome of the Chinese government’s anti-dumping investigation related to methanol imports from a number of countries including New Zealand. |
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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:
| • | | supply of, demand for, and price of methanol, methanol derivatives, natural gas, oil and oil derivatives, |
| • | | production rates of our facilities in accordance with plan, |
| • | | success of natural gas exploration in southern Chile and New Zealand leading to increased natural gas supply available for our plants in Chile and New Zealand on commercially acceptable terms, |
| • | | receipt or issuance of third-party consents or approvals, including, without limitation, governmental approvals related to natural gas exploration rights or the establishment of new fuel blending standards, |
| • | | operating costs, including natural gas feedstock and logistics costs, capital costs, tax rates, cash flows, foreign exchange rates and interest rates in accordance with plan, |
| • | | completion date and cost of our methanol project in Egypt, |
| • | | availability of committed credit facilities and other financing, |
| • | | availability of future natural gas supply on commercially acceptable terms in Chile, Trinidad, New Zealand, Canada and Egypt, |
| • | | global and regional economic activity (including industrial production levels), |
| • | | absence of a material negative impact from major natural disasters or global pandemics, |
| • | | absence of a material negative impact from changes in laws, regulations or standards, |
| • | | the renewal of committed credit facilities and other financing upon the expiry thereof, |
| • | | the legal opinions received in connection with ongoing legal proceedings and |
| • | | performance of 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:
| • | | conditions in the methanol and other industries, including fluctuations in the supply of, demand for and price of methanol and its derivatives, including demand for methanol for energy uses, |
| • | | significant decrease in energy prices (including prices for natural gas and coal feedstocks), |
| • | | the success of natural gas exploration and development activities in southern Chile, New Zealand and Canada, |
| • | | availability of future natural gas supply on commercially acceptable terms in Chile, Trinidad, New Zealand and Egypt, |
| • | | the timing of the start-up and the cost to complete our new methanol project in Egypt, |
| • | | the ability to successfully carry out corporate initiatives and strategies, |
| • | | unexpected technical issues with our production facilities, |
| • | | actions of competitors and suppliers, |
| • | | actions of governments and governmental authorities, including implementation of policies or other measures by the Chinese government, the United States government or other governments that could impact the demand for methanol or its derivatives, or the failure to obtain governmental approvals related to natural gas exploration rights in southern Chile, |
| • | | changes in laws or regulations, |
| |
| • | | import or export restrictions, anti-dumping measures, increases in duties, taxes and government royalties and other actions by governments that may adversely affect our operations, |
| • | | worldwide economic conditions and conditions in the global financial markets and |
| • | | other risks described in our 2009 MD&A. |
In addition to the foregoing risk factors, the current uncertain economic environment has added additional risks and uncertainties, including changes in capital markets and corresponding effects on the Company’s investments, our ability to access existing or future credit and defaults by customers, suppliers or insurers.
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.
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