Exhibit 2
Management’s Discussion & Analysis
INDEX
7 | Overview | |||
8 | Our Strategy | |||
10 | How We Analyze Our Business | |||
12 | Financial Highlights | |||
12 | Production Summary | |||
14 | Results of Operations | |||
19 | Liquidity & Capital Resources | |||
23 | Risk Factors and Risk Management | |||
28 | Outlook | |||
29 | Critical Accounting Estimates | |||
30 | New Canadian Accounting Standards Adopted in 2006 | |||
31 | Anticipated Changes to Canadian Generally Accepted Accounting Principles | |||
31 | Supplemental Non-GAAP Measures | |||
32 | Quarterly Financial Data (Unaudited) | |||
32 | Selected Annual Information | |||
33 | Controls and Procedures | |||
33 | Forward-Looking Statements |
This Management’s Discussion and Analysis is dated March 2, 2007 and should be read in conjunction with our consolidated financial statements and the accompanying notes for the year ended December 31, 2006. 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 18 to our consolidated financial statements.
At March 2, 2007 we had 104,718,367 common shares issued and outstanding and stock options exercisable for 528,800 additional common shares.
Additional information relating to Methanex, including our Annual Information Form, is available on SEDAR atwww.sedar.com and on EDGAR atwww.sec.gov.
OVERVIEW
Methanex is the world’s largest producer and marketer of methanol. Our core production hubs in Chile and Trinidad have an annual production capacity of 5.8 million tonnes and represent over 90% of our current annual production capacity. We also produce methanol from our flexible 0.5 million tonne per year production facility in Waitara Valley, New Zealand. In addition to the methanol we produce, we purchase methanol produced by others under methanol offtake contracts in order to meet customer requirements and support our marketing efforts. Our total sales volumes in 2006 were 7.0 million tonnes representing approximately 19% of estimated global demand for methanol. We believe our global positioning, including our extensive network of storage terminals, and expertise in the global distribution of methanol is a competitive advantage.
Methanol is a chemical produced primarily from natural gas. Approximately 80% of all methanol is used in the production of formaldehyde, acetic acid and a variety of other chemicals for which demand is influenced by levels of global economic activity. These chemical derivatives are used in the manufacture of a wide range of products including plywood, particleboard, foams, resins and plastics. The remainder of methanol demand is largely in the energy sector for the production of methyl tertiary-butyl ether (MTBE), a gasoline component, and as a direct fuel for motor vehicles. There are also developing markets for using methanol in bio-diesel, methanol for power generation, di-methyl ether (DME) and fuel blending.
Due to the diversity of the end products in which methanol is used, demand for methanol is influenced by a broad range of economic, industrial and environmental factors. The global demand for methanol in 2006 is estimated at approximately 38 million tonnes.
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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 low cost, global leadership and operational excellence.
Low Cost
Maintaining 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 low cost structure. 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. An important element of our strategy is to ensure long-term security of natural gas supply. Over time we have been reducing our reliance on high cost production. We have positioned our facilities in New Zealand as flexible production assets with future operations dependant upon methanol industry supply and demand and the availability of natural gas on commercially acceptable terms. With the permanent closure of our Kitimat facility in 2005, we have eliminated our exposure to high cost North American natural gas feedstock.
With the completion of the 840,000 tonne per year Chile IV expansion in 2005, our core production hubs in Chile and Trinidad have an annual production capacity of 5.8 million tonnes and represent over 90% of our current annual production capacity. These facilities are underpinned by long-termtake-or-pay natural gas purchase agreements with pricing terms that vary with methanol prices. The strategic location of our Chile and Trinidad production hubs allows us to deliver methanol cost-effectively to our customers in Asia Pacific, Europe, North America and Latin America.
Our production facilities in Chile currently source approximately 62% of their natural gas feedstock from Argentina. During 2006, the government of Argentina passed new legislation increasing the existing duty on natural gas exports paid by our natural gas suppliers. While our gas contracts provide that duties levied by the government of Argentina are payable by the natural gas suppliers, we are in continuing discussions with our suppliers from Argentina regarding the impact of the increased export duty — refer to theProduction Summary andRisk Factors and Risk Management sections for further information. We continue to seek alternative sources of natural gas supply to our Chile facilities to minimize the impact of the increased export duty on our operations. There is interest in natural gas exploration in areas of Southern Chile that are relatively close to our production facilities and we are optimistic that this activity will ultimately provide us with improvedlong-term gas supply security.
The cost to distribute methanol from our production facilities to our 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. We seek to use larger vessels where possible and to maximize the use of our shipping fleet to reduce costs. We take advantage of prevailing conditions in the shipping market by varying the type and length of term of our ocean vessel contracts. We are continuously investigating opportunities to further improve the efficiency and cost-effectiveness of distributing methanol from our production facilities to our customers. We also look for opportunities to leverage our global asset position by entering into product exchanges with other methanol producers to reduce our distribution costs.
Global Leadership
We are the leading supplier of methanol to the major international markets of North America, Asia Pacific and Europe, as well as Latin America. Our industry leadership has enabled us to play a role in industry pricing by establishing published Methanex reference prices in each major market.
Our global distribution and supply infrastructure allows us to provide unmatched security of supply to our customers. During the second half of 2006, the methanol industry experienced a supply shortage brought on by planned and unplanned supplier outages. Using our flexible global distribution and supply network we were able to adjust our operations and deliver on our commitments to customers during this period of high demand.
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We permanently closed the Kitimat production facility in 2005 and converted the site into a terminal for storing and transporting methanol as well as other products. During 2006, this site has allowed us to further enhance our distribution network and to cost-effectively supply methanol from our Chile facilities to customers in the Pacific Northwest region of North America.
We continue to actively investigate options to enhance our supply position over the long term and are developing a project to build a 1.3 million tonne per year methanol facility in Egypt. This project is being developed through a joint venture in which we have a 60% interest and the marketing rights for all of the production. We are in the final stages of developing the project and expect to be in a position to make a final investment decision by the middle of 2007.
We relocated our Asia Pacific marketing and logistics office from Auckland, New Zealand to Hong Kong and we have added staff to our office in Shanghai 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 countries in Asia. Our enhanced presence in Asia has also helped us to identify opportunities to develop applications for methanol to energy.
We continue to be in the forefront of the industry through our Responsible Care and Corporate Social Responsibility programs.
Operational Excellence
We maintain a focus on operational excellence in all aspects of our business. This includes excellence in our manufacturing and distribution processes, human resources, corporate governance practices and financial management.
In order 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 Canadian Chemical Producers’ Association, we believe we have reduced the likelihood of unplanned shutdowns and lost-time incidents and have achieved an excellent overall environmental and safety record.
We have a Corporate Social Responsibility (CSR) policy which is a natural extension of our Responsible Care ethic. Our CSR policy encompasses corporate governance, employee engagement and development, community involvement, social investment and many other activities that have long been a part of our culture.
We operate in a highly competitive and cyclical industry. Accordingly, we believe it is important to maintain financial flexibility throughout the methanol price cycle and we have adopted a prudent approach to financial management. Where there are opportunities to grow our position in the methanol industry we apply a disciplined approach, which includes target return criteria. We also believe that it is prudent to maintain a conservative balance sheet and we have established a track record of returning excess cash to shareholders.
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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 EBITDA (refer toSupplemental Non-GAAP Measureson page 31 for a reconciliation to the most comparable GAAP measure), depreciation and amortization, interest expense, interest and other income, unusual items and income taxes. In addition to the methanol that we produce at our facilities, we also purchase and re-sell methanol produced by others and sell methanol on a commission basis. In analyzing the changes in Adjusted EBITDA, we separately analyze the results of Company-produced methanol sales from purchased methanol sales as the margin characteristics of each are very different.
Company-Produced Methanol
Our level of Adjusted EBITDA is highly dependant on the margin earned from our Company-produced methanol. Sales volumes of Company-produced methanol will depend on the amount of production from our methanol facilities, which in turn is based on how well the plants operate, the timing of scheduled maintenance and other factors. The key drivers of changes in our Adjusted EBITDA for Company-produced methanol are average realized price, sales volume and cash costs. We provide separate discussion of the changes in Adjusted EBITDA related to our core Chile and Trinidad production hubs and the changes in Adjusted EBITDA related to our New Zealand and Kitimat facilities.
Our production hubs in Chile and Trinidad have an annual operating capacity of 5.8 million tonnes per year. These production hubs are underpinned by long-termtake-or-pay natural gas purchase agreements and the operating results for these facilities represent a substantial portion of our Adjusted EBITDA. Accordingly, in our analysis of Adjusted EBITDA for our facilities in Chile and Trinidad we separately discuss the impact of changes in average realized price, sales volume and cash costs.
Our 530,000 tonne per year Waitara Valley facility in New Zealand operated for most of 2006 and has been positioned as a flexible production asset. We permanently closed our Kitimat facility on November 1, 2005 and sold the remaining production from this facility in early 2006. These facilities incur higher production costs and their operating results represent a smaller proportion of our Adjusted EBITDA. Accordingly, the impact of changes in average realized price, sales volume and cash costs on the Adjusted EBITDA for our New Zealand and Kitimat facilities has been combined and presented as the change in cash margin.
The price, cash cost and volume variances included in our Adjusted EBITDA analysis for Company-produced methanol are defined and calculated as follows:
PRICE | The change in our Adjusted EBITDA as a result of changes in average realized price is calculated as the difference fromperiod-to-period in the selling price of produced methanol multiplied by the current period sales volume of produced methanol. Sales under long-term contracts where the prices are either fixed or linked to our costs plus a margin are included as sales of Company-produced methanol. Accordingly, the selling price of Company-produced methanol will differ from the selling price of purchased methanol. | |
CASH COST | The change in our Adjusted EBITDA as a result of changes in cash costs is calculated as the difference fromperiod-to-period in cash costs per tonne multiplied by the sales volume of Company-produced methanol in the current period plus the change in unabsorbed fixed cash costs. The change in consolidated selling, general and administrative expenses and fixed storage and handling costs are included in the analysis of methanol produced at our Chile and Trinidad facilities. | |
VOLUME | The change in our Adjusted EBITDA as a result of changes in sales volume is calculated as the difference fromperiod-to-period in the sales volume of Company-produced methanol multiplied by the margin per tonne for the prior period. The margin per tonne is calculated as the selling price per tonne of Company-produced methanol less absorbed fixed cash costs per tonne and variable cash costs per tonne. |
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Purchased Methanol
We augment our marketing operations by purchasing methanol from other producers. This provides flexibility in our supply chain to optimize shipping costs and respond to changes in our production levels and customer requirements. The amount of methanol we purchase from others will depend on these and other factors and consequently sales of purchased product vary from period to period. Sales of purchased methanol represent a lower proportion of our Adjusted EBITDA because 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. Accordingly, the analysis of purchased methanol and its impact on our Adjusted EBITDA is discussed on a net margin basis.
Commission Sales
We also sell methanol on a commission basis, where we do not take risk and title to the product. 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. The product that we sell on a commission basis from the Atlas facility is sold in the United States and Europe. The proportion of commission sales in a period will impact the level of revenue as only the commission is included in revenue.
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FINANCIAL HIGHLIGHTS
($ MILLIONS, EXCEPT AS NOTED) | 2006 | 2005 | ||||||
Sales volumes (thousands of tonnes): | ||||||||
Company-produced | ||||||||
Chile and Trinidad | 4,990 | 4,553 | ||||||
New Zealand and Kitimat | 320 | 788 | ||||||
5,310 | 5,341 | |||||||
Purchased methanol | 1,101 | 1,174 | ||||||
Commission sales1 | 584 | 537 | ||||||
6,995 | 7,052 | |||||||
Average realized price ($ per tonne)2 | 328 | 254 | ||||||
Methanex average non-discounted posted price ($ per tonne)3 | 396 | 301 | ||||||
Revenue | 2,108 | 1,658 | ||||||
Adjusted EBITDA4 | 800 | 452 | ||||||
Net income | 483 | 166 | ||||||
Income before unusual items (after-tax)4 | 457 | 224 | ||||||
Basic net income per share | 4.43 | 1.41 | ||||||
Diluted net income per share | 4.41 | 1.40 | ||||||
Diluted income before unusual items (after-tax) per share4 | 4.18 | 1.89 | ||||||
Cash flows from operating activities4 5 | 623 | 330 | ||||||
Common share information (millions of shares): | ||||||||
Weighted average number of common shares outstanding | 109 | 118 | ||||||
Diluted weighted average number of common shares outstanding | 109 | 118 | ||||||
Number of common shares outstanding, end of period | 106 | 114 | ||||||
1 | Commission sales represent volumes marketed on a commission basis. Commission income is included in revenue when earned. |
2 | Average realized price is calculated as revenue, net of commissions earned, divided by total sales volumes of produced and purchased methanol. |
3 | 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. |
4 | These items are non-GAAP measures that do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and therefore are unlikely to be comparable to similar measures presented by other companies. Refer to Supplemental Non-GAAP Measureson page 31 for a description of each non-GAAP measure and a reconciliation to the most comparable GAAP measure. |
5 | Cash flows from operating activities in the above table represents cash flows from operating activities before changes in non-cash working capital. |
PRODUCTION SUMMARY
The following table details the annual operating capacity and production for our facilities that operated in 2006 or 2005:
ANNUAL | ||||||||||||
OPERATING | ||||||||||||
(THOUSANDS OF TONNES) | CAPACITY1 | 2006 | 2005 | |||||||||
Chile and Trinidad: | ||||||||||||
Chile I, II, III and IV (Chile)2 | 3,840 | 3,186 | 3,029 | |||||||||
Atlas (Trinidad) (63.1% interest) | 1,073 | 1,057 | 895 | |||||||||
Titan (Trinidad) | 850 | 864 | 715 | |||||||||
5,763 | 5,107 | 4,639 | ||||||||||
Waitara Valley (New Zealand) | 530 | 404 | 343 | |||||||||
Kitimat (Canada)3 | — | — | 376 | |||||||||
6,293 | 5,511 | 5,358 | ||||||||||
1 | The annual operating capacities shown in the above table may be higher than the original design capacity as a result of efficiencies gained through improvements and experience at our plants. |
2 | Our 840,000 tonne per year Chile IV methanol facility commenced operations in June 2005. Total operating capacity for our Chile facilities in 2005, including Chile IV from the date ofstart-up, was approximately 3.5 million tonnes. |
3 | We permanently closed the 500,000 tonne per year Kitimat methanol facility on November 1, 2005. |
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Chile
We produced 3.2 million tonnes during 2006 at our production hub in Chile compared with 3.0 million tonnes during 2005 and compared with production capacity in 2006 of 3.8 million tonnes. During 2006, we performed planned maintenance at our Chile I facility resulting in lost production of approximately 60,000 tonnes. We experienced some unplanned outages at our Chile IV methanol facility, which commenced operations in the second half of 2005. We believe that we have addressed all of the major operational issues and we expect to achieve improved reliability at our Chile IV facility in 2007. These issues, combined with other technical issues experienced at our Chile facilities, resulted in lost production of approximately 220,000 tonnes during 2006. Our natural gas suppliers to our Chile facilities delivered less than contracted volumes due to technical failures and other issues during 2006 and this resulted in lost production of approximately 260,000 tonnes. Natural gas supply to our Chile facilities was also impacted by curtailments of natural gas supply as a result of redirection orders from the government of Argentina during 2006, resulting in lost production of approximately 50,000 tonnes. For the past three years, the government of Argentina has ordered natural gas suppliers to inject additional gas into the local grid during the winter period in the southern hemisphere (May through August). The remaining lost production of 64,000 tonnes during 2006 was primarily a result of disruptions in natural gas supply from Argentina as a result of curtailments by certain suppliers during negotiations related to export duties.
We currently source 62% of our natural gas requirements for our production facilities in Chile from natural gas suppliers in Argentina that are affiliates of international oil and gas companies. The remaining natural gas requirements are supplied from gas reserves in Chile, mainly by Empresa Nacional del Petroleo (ENAP), the Chilean state-owned energy company.
Effective July 25, 2006, the government of Argentina increased the duty on exports of natural gas from Argentina to Chile, which has been in place since May 2004, from approximately $0.30 per mmbtu to $2.25 per mmbtu. Exports of natural gas from the province of Tierra del Fuego were exempt from this duty until late October 2006 when the government of Argentina extended this duty to include this province at the same rates applicable to the other provinces. As a result, the increased duty on exports of natural gas is applicable to all of the natural gas feedstock that we source from Argentina. The total annual cost of the export duty to our natural gas suppliers from Argentina has increased to approximately $200 million. While our natural gas contracts provide that natural gas suppliers are to pay any duties levied by the government of Argentina, we are in continuing discussions with our natural gas suppliers from Argentina regarding the impact of the increased export duty.
During 2006, we reached interim agreements with all of our natural gas suppliers from Argentina. In principle, we have agreed to share the cost of duties based in part on prevailing methanol prices. We have gained some flexibility to take the natural gas depending on prevailing methanol market conditions, and to the extent that these arrangements are not economic, then we will not purchase the natural gas. While we are in continuing discussions to reach longer-term arrangements with our natural gas suppliers from Argentina regarding the impact of the increased export duty, we cannot provide assurance that we will be able to reach satisfactory longer-term arrangements with our natural gas supplies or that the impact of this export duty will not have an adverse effect on our results of operations and financial condition. As at December 31, 2006, we accrued $26 million to record the estimated cost of sharing export duties for natural gas consumed in 2006. Approximately $8 million was charged to earnings during the fourth quarter of 2006 and the remaining amount is included in the cost of our inventory and will be charged to earnings when the inventory is sold.
We continue to work on sourcing additional natural gas supply for our Chile facilities from alternative sources. There is renewed interest in natural gas exploration in the southern regions of Chile. As an example, our Chilean natural gas supplier, ENAP, and others are undertaking gas exploration and development programs in areas of Chile that are relatively close to our production facilities. If these programs are successful we believe that some additional gas could be available during 2007. In addition, the Government of Chile has announced its intention to assign exploration areas which lie close to our facilities in a bidding round during 2007. However, there can be no assurance that ENAP or others will be successful or that we would obtain any additional natural gas on economic terms. For further information on natural gas exploration in Chile refer to theRisk Factors and Risk Management section on page 23.
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Trinidad
During 2006, our Trinidad facilities operated well and produced a total of 1.9 million tonnes compared with 1.6 million tonnes during 2005 and compared with production capacity in 2006 of 1.9 million tonnes. Our facilities in Trinidad are capable of producing above design capacity and would have produced a further 90,000 tonnes if it were not for short-term delivery infrastructure constraints of our natural gas suppliers during 2006.
New Zealand
We produced 404,000 tonnes at our Waitara Valley facility in New Zealand during 2006 compared with 343,000 tonnes during 2005. We have secured sufficient natural gas supply that will allow us to produce at this facility at least until the end of 2007. This facility has been positioned as a flexible production asset with operations dependant upon methanol industry supply and demand and the availability of natural gas on commercially acceptable terms.
RESULTS OF OPERATIONS
($ MILLIONS) | 2006 | 2005 | ||||||
Condensed consolidated statements of income: | ||||||||
Revenue | 2,108 | 1,658 | ||||||
Cost of sales and operating expenses | 1,308 | 1,206 | ||||||
Adjusted EBITDA1 | 800 | 452 | ||||||
Depreciation and amortization | 107 | 91 | ||||||
Kitimat closure costs | — | 41 | ||||||
Operating income | 693 | 320 | ||||||
Interest expense | (45 | ) | (42 | ) | ||||
Interest and other income | 10 | 10 | ||||||
Income taxes | (175 | ) | (122 | ) | ||||
Net income | 483 | 166 | ||||||
Income before unusual items (after-tax)1 | 457 | 224 | ||||||
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 Supplemental Non-GAAP Measureson page 31 for 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 and changes in general economic conditions, which can vary across the major international methanol markets.
Methanex Average Realized Price 2005-2006
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Revenue for 2006 was $2.1 billion compared with $1.7 billion during 2005. Total sales volumes of produced and purchased methanol during 2006 were 6.4 million tonnes compared with 6.5 million tonnes in 2005. The increase in revenue was primarily due to our higher average realized price in 2006 compared with 2005. We entered 2006 with tight market conditions as a result of high global energy prices, industry supply constraints and healthy demand, which resulted in continued strong pricing for the first half of 2006. During the third quarter of 2006, planned and unplanned supplier outages significantly reduced global inventory levels. This led to a dramatic increase in pricing in September and again in October and these high prices continued throughout the remainder of 2006. Our average realized price for 2006 was $328 per tonne compared with $254 per tonne in 2005. Our higher average realized price during 2006 increased revenue by $480 million compared with 2005 while slightly lower sales volumes decreased revenue by $30 million.
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 2006 was $396 per tonne compared with $301 per tonne in 2005. Our average realized price in 2006 was approximately 17% lower than our average non-discounted published reference price compared with approximately 16% lower for 2005.
To reduce the impact of cyclical pricing on our earnings, we have entered into long-term contracts for a portion of our production volume with certain global customers where prices are either fixed or linked to our costs plus a margin. In 2006, sales under these contracts represented approximately 20% of our total sales volumes. The increase in the discount from our average non-discounted published reference price in 2006 compared with 2005 is primarily the result of higher methanol prices in 2006. The discount from our non-discounted published reference prices is expected to narrow during periods of lower pricing. We believe it is important to maintain financial flexibility throughout the methanol price cycle and these strategic contracts are a part of our balanced approach to managing cash flow and liquidity.
Distribution of Revenue
Due to the diversity of the end products in which methanol is used, demand for methanol largely depends upon levels of industrial production and changes in general economic conditions, which can vary across the major international methanol markets.
Our distribution of revenue for 2006 and 2005 was as follows:
($ MILLIONS, EXCEPT AS NOTED) | 2006 | 2005 | ||||||||||||||
Canada | 167 | 8% | 72 | 4% | ||||||||||||
United States | 679 | 32% | 586 | 35% | ||||||||||||
Europe | 494 | 23% | 353 | 21% | ||||||||||||
Korea | 213 | 10% | 178 | 11% | ||||||||||||
Japan | 158 | 8% | 175 | 11% | ||||||||||||
Other Asia | 203 | 10% | 163 | 10% | ||||||||||||
Latin America | 194 | 9% | 131 | 8% | ||||||||||||
2,108 | 100% | 1,658 | 100% | |||||||||||||
Our revenue distribution for 2006 is relatively comparable to 2005 except for changes in Canada, the United States and Japan. Revenue related to customers in Canada as a proportion of our total revenue increased as a result of our increased marketing efforts in the Pacific Northwest region of North America. We are able to leverage our ability to import methanol through the Kitimat terminal to supply this attractive market. Revenue in the United States decreased as a proportion of total sales revenue primarily due to lower sales volumes to customers using methanol in the production of MTBE for consumption in the United States. The production of MTBE for consumption in the United States was largely phased out by mid-2006 and the remaining production of MTBE in the United States is mainly destined for export markets. Revenue related to customers in Japan decreased as a proportion of our total revenue as a result of changes in our distribution channels in Japan.
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Adjusted EBITDA
We review our results of operations by analyzing changes in the components of our Adjusted EBITDA. In addition to the methanol that we produce at our facilities, we also purchase and re-sell methanol produced by others. In analyzing the changes in Adjusted EBITDA, we separately analyze the results of our Chile and Trinidad produced methanol sales, our New Zealand and Kitimat produced methanol sales, and our purchased methanol sales, as the margin characteristics of each are very different.
Our 2006 Adjusted EBITDA was $800 million compared with $452 million in 2005. The increase in Adjusted EBITDA of $348 million resulted from changes in the following:
($ MILLIONS) | 2006 VS. 2005 | |||
Chile and Trinidad facilities: | ||||
Average realized price | 357 | |||
Sales volumes | 60 | |||
Total cash costs1 | (141 | ) | ||
276 | ||||
Higher margin from New Zealand and Kitimat production | 53 | |||
Higher margin on the sale of purchased methanol | 19 | |||
Increase in Adjusted EBITDA | 348 | |||
1 | Includes cash costs related to methanol produced at our Chile and Trinidad facilities as well as consolidated selling, general and administrative expenses and fixed storage and handling costs. |
Average Realized Price — Chile and Trinidad facilities
The higher average realized price on sales of methanol produced at our Chile and Trinidad facilities increased Adjusted EBITDA by $357 million.
Sales Volumes — Chile and Trinidad facilities
The commencement of operations of Chile IV in June 2005 increased our total annual Chile and Trinidad production capacity to 5.8 million tonnes from 5.0 million tonnes. Sales volumes of methanol produced at our production hubs in Chile and Trinidad for the year ended December 31, 2006 were higher by 437,000 tonnes compared with 2005, and this increased Adjusted EBITDA by $60 million.
Total Cash Costs — Chile and Trinidad facilities
Our cash costs were higher in 2006 compared with 2005 and this decreased Adjusted EBITDA by $141 million. The primary changes in cash costs were as follows:
($ MILLIONS) | 2006 VS. 2005 | |||
Higher natural gas costs and other costs linked to higher methanol prices | 81 | |||
Impact of sharing Argentina export duties | 8 | |||
Higher distribution costs | 25 | |||
Higher selling, general and administrative expenses | 20 | |||
Other, net | 7 | |||
141 | ||||
Higher Natural Gas Costs and Other Costs Linked to Higher Methanol Prices
Natural gas supply contracts for our assets in Chile and Trinidad 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 higher average methanol prices in 2006 increased our natural gas and other costs linked to methanol prices and this decreased Adjusted EBITDA by approximately $81 million compared with 2005. For additional
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information regarding our natural gas agreements refer toSummary of Contractual Obligations and Commercial Commitments — Purchase Obligations on page 21.
Impact of Sharing Argentina Export Duties
During 2006, the government of Argentina increased the duty on exports of natural gas from Argentina to Chile — for more detail refer to theProduction Summary section on page 12. During the fourth quarter of 2006, we reached interim agreements with all of our natural gas suppliers from Argentina and in principle, we have agreed to share the cost of duties based in part on prevailing methanol prices. As a result of reaching these interim agreements we accrued an additional $26 million to record the estimated cost of sharing export duties for natural gas consumed in 2006. Approximately $8 million was charged to earnings during 2006 and the remaining amount is included in the cost of our inventory and will be charged to earnings when the inventory is sold.
Higher Distribution Costs
The cost to distribute methanol from our production facilities to customers is a significant component of our operating costs. Ocean shipping costs are the most significant component of our distribution costs and we have a dedicated fleet of ocean-going vessels under long-term time charter that contribute to our objective of cost-effectively delivering methanol to our customers. Our ocean shipping costs increased by $5 million in 2006 compared with 2005, primarily due to increased fuel costs resulting from higher global energy prices partially offset by higher margins earned on backhaul arrangements.
The remaining costs to distribute methanol from our production facilities to customers primarily consist of the cost of in-market storage facilities and in-market distribution. In-market distribution costs will vary depending on the location of the customer and we are able to recover a substantial amount of these costs from our customers. These costs increased during 2006 by $20 million, primarily due to an increase in sales volumes to customers in Asia Pacific and the Pacific Northwest region of North America. Most of these costs were recovered from our customers and this cost recovery has been included in revenue.
Higher Selling, General & Administrative Expenses
Our selling, general and administrative expenses increased by $20 million in 2006 compared with 2005 primarily as a result of an increase in our stock-based compensation expense. Our stock-based compensation expense for deferred, restricted and performance share units is impacted by changes in our share price as these changes are recognized in earnings for the proportion of the service that has been rendered at each reporting date. Our stock price increased by 46% during 2006, resulting in an increase to our stock-based compensation expense.
Margin from New Zealand and Kitimat Production
We permanently closed our Kitimat facility in 2005 and sold the remaining inventory from this facility in early 2006. Our New Zealand operations have been positioned as flexible assets and represent a lower proportion of our Adjusted EBITDA. Therefore, we analyze the results of these facilities on a cash margin basis. In 2006, our cash margin on the sale of New Zealand and Kitimat inventory was higher by $53 million compared with 2005. The increase in cash margin primarily relates to lower sales volumes of high cost Kitimat inventory and higher methanol prices during 2006.
Margin on the Sale of Purchased Methanol
We purchase methanol produced by others through long-term offtake contracts to meet customer needs and support our marketing efforts. Consequently, we realize holding gains or losses on the resale of this product depending on the methanol price at the time of resale. In 2006, our cash margin was $20 million on resale of 1.1 million tonnes of purchased methanol compared with a cash margin of $1 million on resale of 1.2 million tonnes during 2005. The increase in cash margin is primarily due to the impact of increased methanol pricing during 2006.
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Depreciation and Amortization
Our depreciation and amortization expense in 2006 was $107 million compared with $91 million in 2005. The increase in depreciation and amortization of $16 million is primarily related to the depreciation of the Chile IV methanol facility, which commenced operations in June 2005, and depreciation related to a capital lease for an ocean-going vessel that commenced during the fourth quarter of 2005.
Kitimat Closure Costs
During 2005, we permanently closed our Kitimat production facilities and converted the site into a terminal for storing and transporting methanol as well as other products. The total closure costs of $41 million (before and after-tax) include employee severance costs of $13 million and contract termination costs of $28 million. Contract termination costs include costs to terminate atake-or-pay natural gas transportation agreement and an ammonia supply agreement.
We have entered into an agreement with EnCana for their use of the Kitimat site as a condensate terminal operation. Under this agreement, we have the right to sell to EnCana, and EnCana has the right to purchase from us, the entire Kitimat site through the exercise of put and call options, respectively. If exercised, a sale of this site under the put or call option would allow us to offset some, or possibly all, of the Kitimat closure costs.
Interest Expense
($ MILLIONS) | 2006 | 2005 | ||||||
Interest expense before capitalized interest | 45 | 49 | ||||||
Less capitalized interest related to Chile IV | — | (8 | ) | |||||
45 | 41 | |||||||
Our interest expense before capitalized interest in 2006 was $45 million compared with $49 million in 2005. The decrease in interest expense before capitalized interest primarily relates to lower levels of debt during 2006.
Interest incurred during construction is capitalized to the cost of the asset until the asset is substantively complete and ready for productive use. During 2005, we capitalized interest costs of $8 million to property, plant and equipment related to the construction of Chile IV.
Interest and Other Income
Our interest and other income was $10 million in 2006 compared with $10 million in 2005. Interest and other income increased by $4 million due to higher interest rates and higher cash balances in 2006 compared with 2005. The higher interest income was offset by a charge to earnings of $4 million in 2006 related to the decrease in fair value of natural gas purchase option contracts.
During 2006, we entered into a methanol offtake agreement with Celanese Ltd., a methanol producer in Canada, for a three-month period commencing January 1, 2007. The contract price includes a fixed facility fee and a variable fee indexed to natural gas prices. We entered into natural gas purchase option contracts during the fourth quarter of 2006 to mitigate our exposure to increases in natural gas costs under the methanol offtake agreement. The natural gas purchase option contracts expire over the period to the end of March 2007. We believe these option contracts provide an economic hedge of our exposure to increases in natural gas costs; however, these arrangements do not meet the requirements for hedge accounting treatment under Canadian or US GAAP. Natural gas prices declined late in the fourth quarter of 2006 and the fair value of the natural gas purchase options decreased by $4 million. The change in fair value was charged to earnings resulting in a decrease to interest and other income.
Income Taxes
During 2005, the government of Trinidad and Tobago introduced new tax legislation retroactive to January 1, 2004. As a result, during 2005 we recorded a $17 million charge to increase future income tax expense to reflect the retroactive impact for the period January 1, 2004 to December 31, 2004. In February 2006, the
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government of Trinidad and Tobago passed an amendment to this legislation that changed the retroactive effective date to January 1, 2005. As a result of this amendment we recorded an adjustment to decrease future income tax expense by a total of $26 million during 2006. The adjustment includes a reversal of the previous charge to 2005 earnings and an additional adjustment to recognize the benefit of tax deductions that were reinstated as a result of the change in the implementation date.
Excluding the unusual items relating to the 2005 Kitimat closure costs and the Trinidad tax adjustments, the effective tax rate for 2006 was 31% compared with 32% for 2005. The statutory tax rate in Chile and Trinidad, where we earn a substantial portion of our pre-tax earnings, is 35%. Our Atlas facility in Trinidad has partial relief from corporation income tax until 2014.
In Chile, the tax rate consists of a first category tax that is payable when income is earned and a second category tax that is due when earnings are distributed from Chile. The second category tax is initially recorded as future income tax expense and is subsequently reclassified to current income tax expense when earnings are distributed. Accordingly, the ratio of current income tax expense to total income tax expense is highly dependent on the level of cash distributed from Chile.
For additional information regarding income taxes, refer to note 12 of our 2006 consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow Highlights
($ MILLIONS) | 2006 | 2005 | ||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
Cash flows from operating activities1 | 623 | 330 | ||||||
Changes in non-cash working capital | (154 | ) | 29 | |||||
469 | 359 | |||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
Payments for shares repurchased | (187 | ) | (131 | ) | ||||
Dividend payments | (53 | ) | (48 | ) | ||||
Proceeds on issue of shares on exercise of stock options | 8 | 11 | ||||||
Repayment of long-term debt | (14 | ) | (258 | ) | ||||
Proceeds on issue of long-term debt | — | 148 | ||||||
Other, net | (8 | ) | (18 | ) | ||||
(254 | ) | (296 | ) | |||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
Property, plant and equipment | (53 | ) | (60 | ) | ||||
Plant and equipment construction costs, net | — | (24 | ) | |||||
Changes in non-cash working capital related to investing activities | 34 | (30 | ) | |||||
(19 | ) | (114 | ) | |||||
Increase (decrease) in cash and cash equivalents | 196 | (51 | ) | |||||
Cash and cash equivalents, end of year | 355 | 159 | ||||||
1 | Cash flows from operating activities in the above table represents cash flows from operating activities before changes in non-cash working capital. This item is a non-GAAP measure — refer toSupplemental Non-GAAP Measuressection on page 31 for further information. |
Cash Flows from Operating Activities
Our cash flows from operating activities before changes in non-cash working capital were $623 million in 2006 compared with $330 million in 2005. The increase in cash flows from operating activities before changes in non-cash working capital are primarily the result of higher earnings in 2006 compared with 2005.
Our non-cash working capital related to operating activities at December 31, 2006 increased by $154 million compared with December 31, 2005. The increase is primarily a result of an increase in our inventories and accounts receivables balances, net of an increase in accounts payable and accrued liabilities. Our inventories balance increased by $105 million due to the impact of higher production costs and purchased methanol
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costs as well as higher inventory volumes. The increases in our accounts receivables and accounts payable and accrued liabilities balances of $70 million and $74 million, respectively, was primarily due to the impact of higher methanol pricing on our trade receivables and trade payables in 2006 compared with 2005.
Cash Flows from Financing Activities
Over the past two years we have returned a total of $419 million of cash to shareholders through a combination of share repurchases of $318 million and regular quarterly dividend payments of $101 million.
In 2005, we commenced a normal course issuer bid that expired on May 16, 2006. On May 17, 2006, we commenced a new bid that expires on May 16, 2007. During 2006, we repurchased a total of 8.5 million common shares under these bids at an average price of US$21.91 per share, totaling $187 million. At December 31, 2006, we had repurchased a total of 3.8 million common shares under the current bid. During 2005, we repurchased a total of 7.7 million common shares at an average price of US$16.97 per share, totaling $131 million.
We increased our regular quarterly dividend by 14% to US$0.125 per share per quarter, beginning with the dividend payable on June 30, 2006. Total dividend payments in 2006 were $53 million compared with $48 million in 2005.
We received proceeds of $8 million and issued 0.7 million common shares on the exercise of stock options during 2006, compared with proceeds of $11 million on the issuance of 1.3 million common shares in 2005.
During 2005, we issued $150 million of 6.00% notes due August 15, 2015. The net proceeds, together with cash on hand, were used to repay $250 million of 7.75% notes at maturity on August 15, 2005. These transactions reduced our long-term debt by $100 million.
Cash Flows from Investing Activities
Additions to property, plant and equipment, which are comprised of turnarounds, catalyst and other capital expenditures, were $53 million for 2006 compared with $60 million in 2005. In 2006 we completed a major turnaround at our Chile facilities and invested $11 million in the joint venture methanol project in Egypt. In 2005, we completed turnarounds at our facilities in Chile and our Titan and Atlas facilities in Trinidad.
During 2005, we completed the construction of Chile IV, an 840,000 tonne per year expansion to our production facilities in Chile. During 2005, we recorded $30 million of incentive tax credits related to the construction of Chile IV and this decreased the total capital expenditures related to Chile IV to $247 million. The tax credits were recorded as a reduction to property, plant and equipment and an increase to receivables and this resulted in an increase to non-cash working capital related to investing activities of $30 million in 2005. In 2006, we collected $28 million of the tax credits and we collected the remaining balance in early 2007. The collection of incentive tax credits in 2006 resulted in a decrease to non-cash working capital related to investing activities of $28 million. The benefit of these tax credits will be recognized in earnings through lower depreciation in future periods.
Summary of Contractual Obligations and Commercial Commitments
A summary of the estimated amount and estimated timing of cash flows related to our contractual obligations and commercial commitments as at December 31, 2006 is as follows:
($ MILLIONS) | 2007 | 2008-2009 | 2010-2011 | After 2011 | TOTAL | ||||||||||||||||
Long-term debt repayments | 14 | 28 | 29 | 415 | 486 | ||||||||||||||||
Long-term debt interest obligations | 37 | 71 | 66 | 57 | 231 | ||||||||||||||||
Repayment of other long-term liabilities | 12 | 22 | 2 | 22 | 58 | ||||||||||||||||
Capital lease obligations | 9 | 18 | 17 | 9 | 53 | ||||||||||||||||
Purchase obligations | 223 | 370 | 383 | 2,058 | 3,034 | ||||||||||||||||
Operating lease commitments | 154 | 197 | 143 | 370 | 864 | ||||||||||||||||
449 | 706 | 640 | 2,931 | 4,726 | |||||||||||||||||
The above table does not include costs for planned capital maintenance expenditures or any obligations with original maturities of less than one year.
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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 are for the expected scheduled principal repayments relating to our proportionate share of the Atlas limited recourse long-term debt facilities. Interest obligations related to variable interest rate long-term debt have been estimated using current interest rates in effect at December 31, 2006. For additional information, refer to note 6 of our 2006 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 7 of our 2006 consolidated financial statements.
Purchase Obligations
We have commitments undertake-or-pay contracts to purchase annual quantities of natural gas supplies and to pay for transportation capacity related to these supplies. We also havetake-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 totake-or-pay terms that is lower than the maximum quantity that we are entitled to purchase. The amounts disclosed in the table represent only thetake-or-pay quantity.
Natural gas supply contracts for our assets in Chile and Trinidad are 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 gas contract is adjusted by a formula related to methanol prices above a certain level. We believe this pricing relationship enables these facilities to be competitive throughout the methanol price cycle. The amounts disclosed in the table represent only the base price component.
In Chile, we purchase all of our natural gas through long-termtake-or-pay supply agreements. Approximately 62% of the natural gas for our Chilean facilities is purchased from suppliers in Argentina with the remainder supplied from gas reserves in Chile, mainly by Empresa Nacional del Petroleo (ENAP), the Chilean state-owned energy company. Refer toProduction Summary andRisk Factors and Risk Management sections for further information regarding natural gas supply to our production facilities in Chile. Natural gas for the Chile I and IV plants is supplied under contracts terminating in 2025 and natural gas export permits, valid until 2025, are in place for the gas being supplied from Argentina for those plants. Natural gas for the Chile II and III plants is supplied under contracts terminating in 2017 and 2019 and gas export permits, valid until those dates, are in place for gas being supplied from Argentina for those plants. Agreements for ten-year extensions of these contracts, until 2027 and 2029 are in place. Natural gas export permits for the gas to be sourced from Argentina under these extensions have not yet been granted. Such permits are customarily only applied for a few years before the contractual agreement becomes effective. Accordingly, we have not included ten-year extension periods for the Chile II and III plants in the contractual obligations and commercial commitments summary above.
The variable price component of the natural gas agreements for our Chilean methanol facilities is determined with reference to12-month trailing average published industry methanol prices, except for Chile I, where the variable component until mid-2009 is related to our average realized price for the current calendar year. Commencing in mid-2009, the variable price component for Chile I will be calculated with reference to12-month trailing average published industry methanol prices. The base prices increase annually under the Chile IV contract and, commencing in mid-2009, for the Chile I contract.
In Trinidad, we also havetake-or-pay supply contracts for natural gas, oxygen and other feedstock requirements. The variable component of our natural gas contracts in Trinidad is determined with reference
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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.
Operating Lease Commitments
The majority of these commitments relate to time charter vessel agreements with terms of up to 15 years. Time charter vessels meet most of our ocean shipping requirements, with the remainder of our requirements secured under a mix of contracts with terms of one to two years and through spot arrangements. We believe this structure provides an appropriate mix of shipping capacity, reflecting factors such as the location of our production facilities, the location and restrictions of the destination ports, and the risks associated with production, customer requirements and the general shipping market.
Financial Instruments
From time to time we enter into derivative financial instruments to limit our exposure to foreign exchange volatility and changes in natural gas feedstock costs and to contribute towards achieving cost structure and revenue targets. At December 31, 2006, the fair value of our derivative financial instruments used to limit our exposure to foreign exchange volatility and changes in natural gas feedstock costs approximate their carrying value of negative $0.2 million. Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in foreign exchange rates and natural gas prices. These contracts are not subject to rating triggers or margin calls and rank equally with all our unsecured indebtedness.
Off-Balance Sheet Arrangements
At December 31, 2006, we do not have any off-balance sheet arrangements, as defined by applicable securities regulators in Canada and the United States, that have, or are reasonably likely to have, a current or future material effect on our results of operations or financial condition.
Liquidity and Capitalization
We maintain conservative financial policies that reflect the cyclical nature of methanol pricing. We focus on maintaining our financial strength and flexibility through prudent financial management.
($ MILLIONS, EXCEPT AS NOTED) | 2006 | 2005 | ||||||
LIQUIDITY | ||||||||
Cash and cash equivalents | 355 | 159 | ||||||
Undrawn credit facilities | 250 | 250 | ||||||
605 | 409 | |||||||
CAPITALIZATION | ||||||||
Unsecured notes | 350 | 350 | ||||||
Limited recourse debt facilities, including current portion | 137 | 151 | ||||||
Total debt | 487 | 501 | ||||||
Shareholders’ equity | 1,209 | 950 | ||||||
Total capitalization | 1,696 | 1,451 | ||||||
Total debt to capitalization1 | 29% | 35% | ||||||
Net debt to capitalization2 | 10% | 26% | ||||||
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. |
Our planned capital maintenance expenditures directed towards major maintenance, turnarounds and catalyst changes are estimated to be approximately $100 million for the period to the end of 2009. We are in the final stages in developing a methanol project in Egypt. This project is being developed through a joint venture in which we have a 60% interest and the marketing rights for all production. We expect to be in a position to make a final investment decision on this project by the middle of 2007. If a decision is made to proceed, we expect the joint venture will fund ongoing expenditures through a combination of project financing and equity contributions.
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Our cash balance at December 31, 2006 was $355 million and we have an undrawn $250 million credit facility that expires in 2010. We believe we are well positioned to meet our financial requirements related to the potential methanol project in Egypt, complete our capital maintenance spending program, pursue new opportunities to enhance our leadership position in the methanol industry, investigate opportunities related to new methanol demand for energy applications and continue to deliver on our commitment to return excess cash to shareholders.
The credit ratings for our unsecured notes at December 31, 2006 were as follows:
Standard & Poor’s Rating Services | BBB- (negative) | |
Moody’s Investor Services | Ba1 (stable) | |
Fitch Ratings | BBB (stable) |
Credit ratings are not recommendations to purchase, 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.
RISK FACTORS AND RISK MANAGEMENT
We believe our strategy of creating value by maintaining and enhancing our leadership in the production, marketing and delivery of methanol to our customers provides us with strategic advantages. However, as with any business, we are subject to risks that require prudent risk management. We believe the following risks, in addition to those described underCritical Accounting Estimates on page 30, to be among the most important for understanding the issues that face our business and our approach to risk management.
Commodity Price Cyclicality
The methanol business is a highly competitive commodity industry and prices are affected by supply and demand fundamentals. Methanol prices have historically been, and are expected to continue to be, characterized by 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 trend will occur in the future. Demand for methanol largely depends upon levels of industrial production and changes in general economic conditions.
Changes in environmental, health and safety requirements could also lead to a decrease in methanol demand. The United States Environmental Protection Agency (EPA) is preparing internal reports relating to the human health effects of methanol including its potential carcinogenicity and their final report is expected to be released in mid-2008. Currently, the EPA does not classify methanol with respect to carcinogenicity. We are unable to determine at this time whether the EPA or any other body will reclassify methanol. Any reclassification could reduce future methanol demand which could have an adverse effect on our results of operations and financial condition.
We are not able to predict future methanol supply and demand balances, market conditions or prices, all of which are affected by numerous factors beyond our control. As a result, we cannot provide assurance that demand for methanol will increase at all, or increase sufficiently to absorb additional production, or that the price of methanol will not decline. 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. We also cannot provide assurance that high cost plants would be shut down or idled if the price of methanol were to decline.
Security of Natural Gas Supply and Price
Natural gas is the principal feedstock for methanol and accounts for a significant portion of our cost of sales and operating expenses. Accordingly, our results from operations depend in large part on the availability and security of supply and the price of natural gas. If we are unable to obtain continued access to sufficient natural gas for any of our plants on commercially acceptable terms, or if we experience
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interruptions in the supply of contracted natural gas, we could be forced to reduce production or close plants, which would have a material adverse effect on our results of operations and financial condition.
Chile
In Chile, we purchase all of our natural gas through long-termtake-or-pay supply agreements. Currently, approximately 62% of the natural gas for our Chilean facilities is purchased from suppliers in Argentina with the remainder supplied from gas reserves in Chile, mainly by Empresa Nacional del Petroleo (ENAP), the Chilean state-owned energy company. Under our current long-term natural gas purchase commitments for our Chile facilities, the percentage of natural gas supplied from Argentina would increase to approximately 80% in 2009. Over the past few years, Argentina has been experiencing energy shortages. To avoid these shortages, the government of Argentina passed regulations that require Argentinean gas suppliers to give priority to supplying the domestic market. This has resulted in curtailments of gas supply to Chile as a result of the government of Argentina ordering natural gas suppliers to inject additional gas into the local grid. Since 2004, our production facilities in Chile have been impacted by these curtailments, primarily during the winter period in the southern hemisphere. In 2004 and 2005, we lost approximately 50,000 tonnes and 100,000 tonnes of methanol production, respectively, due to these curtailments. In 2006, the curtailment period extended from May to November and we lost about 50,000 tonnes of production.
Our Chilean operations have been, and continue to be, somewhat isolated from this issue because of the location of our plants in the southernmost region of Chile and the pipeline transportation capacity to the population centers in Argentina. There is only one major pipeline that runs from the south to the central region of Argentina. In 2005, the capacity of this pipeline was increased by approximately 13%. Some additional investment in infrastructure was made by our Argentinean gas suppliers in 2005, which increased the supply of natural gas in the southern region where we source our gas. The government of Argentina is pursuing further pipeline expansion projects, although the timing around commencement and completion of these projects is uncertain. To date, we are not aware of any such projects receiving final approval from the government of Argentina.
In July 2006, the government of Argentina increased the duty on exports of natural gas from Argentina to Chile, which has been in place since May 2004, from approximately $0.30 per mmbtu to $2.25 per mmbtu. Exports of natural gas from the province of Tierra del Fuego were exempt from this duty until late October 2006 when the government of Argentina extended this duty to include this province at the same rates applicable to the other provinces. As a result, the increased duty on exports of natural gas is applicable to all of the natural gas feedstock that we source from Argentina. The total cost of the export duty to our natural gas suppliers on an annual basis has increased to approximately $200 million. While our gas contracts provide that gas suppliers are to pay any duties levied by the government of Argentina, we are in continuing discussions with our Argentinean natural gas suppliers regarding the impact of the increased export duty.
During the fourth quarter of 2006, we reached interim agreements with all of our natural gas suppliers from Argentina. In principle, we have agreed to share the cost of duties and we have gained some flexibility to take the natural gas depending on prevailing methanol market conditions. We are in continuing discussions with our natural gas suppliers to reach longer-term arrangements. However, there can be no assurance that we will be successful in entering into longer-term arrangements with our natural gas suppliers from Argentina. As well, there can be no assurance that the natural gas suppliers will not take the position that the imposition of such duties relieves them of the obligation to deliver natural gas under the contracts.
As a result, there are many variables beyond our control that could have an effect on whether we experience production losses as a result of the potential disruption of natural gas supply from Argentina and we are currently unable to provide a reasonable view as to the amount of production losses that we might experience in 2007. These variables include the actions of government, actions of our gas suppliers, claims of force majeure, outcomes of ongoing or future arbitration or other proceedings, weather and other variables that are currently unanticipated or beyond our control.
There is renewed interest in natural gas exploration in the southern regions of Chile and we are working on sourcing additional natural gas supply for our Chile facilities from alternative sources. As an example, our Chilean natural gas supplier, ENAP, and others are undertaking gas exploration and development programs
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in areas of Chile that are relatively close to our production facilities. If these programs are successful we believe that some additional gas could be available during 2007. In addition, the government of Chile has announced its intention to assign exploration areas which lie close to our facilities in a bidding round during 2007. However, there can be no assurance that ENAP or others will be successful or that we would obtain any additional natural gas on economic terms.
We are working with our natural gas suppliers and senior government officials in Chile and Argentina, and we continue to monitor this issue closely.
Trinidad
Natural gas for our Trinidad methanol production facilities 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.
Since late 2005, large industrial natural gas consumers in Trinidad, including Methanex, have experienced periodic curtailments in their natural gas supply. Curtailments have resulted from a number of different factors including difficulties encountered in bringing new offshore natural gas delivery systems on line and various mechanical problems in the existing pipeline and distribution systems. Also, the commissioning of new facilities consuming large amounts of natural gas has put stress on the natural gas delivery system. We are working with our natural gas supplier and other large natural gas consumers in Trinidad concerning this issue. However, we expect that these curtailments will continue in 2007 and there can be no assurance that production losses will not be materially worse than we have experienced in the recent past.
New Zealand
We have restructured our New Zealand operations over the past few years due to natural gas supply constraints in New Zealand. In 2004, we permanently closed the 1.9 million tonne per year Motunui facility. The 530,000 tonne per year Waitara Valley plant has been positioned as a flexible production asset with operations dependant upon methanol industry supply and demand and the availability of natural gas on commercially acceptable terms. In 2006, we produced about 400,000 tonnes of methanol at the Waitara Valley plant and in January 2007, we secured additional amounts of natural gas which, combined with our existing gas entitlements, are expected to enable this plant to operate at least until the end of 2007 and produce approximately 425,000 tonnes of methanol in 2007. We continue to seek other supplies of natural gas to supplement this production and to extend the life of our New Zealand operations; however, there can be no assurance that we will be able to secure additional gas on commercially acceptable terms.
Demand for Methanol in the Production of Formaldehyde
Approximately 39% of global methanol demand is used to produce formaldehyde. In 2004, the United States National Cancer Institute (NCI) published the results of a study that concluded there is a “possible causal association” between formaldehyde exposure and nasopharyngeal cancer. The NCI is updating its original study and this update is expected to be completed and released in the first half of 2007.
Based in part on the NCI study, the International Agency for Research on Cancer (IARC) upgraded formaldehyde from a “probable” to a “known” carcinogen in 2004. IARC, while not a regulatory body, is influential in setting standards and protocols for various regulatory bodies around the world.
Also in 2004, the EPA began the process of preparing an internal study that could lead to a reclassification of formaldehyde in its Integrated Risk Information System (IRIS), the EPA’s database on human health effects that may result from exposure to various chemicals in the environment. IRIS is also influential as it is used by other countries for setting their national chemical exposure limits. It is expected that the EPA will await the findings from the updated NCI study before finalizing its review. The EPA will also be reviewing data indicating a possible link between formaldehyde exposure and leukemia in animals. It is expected that the EPA review will be released in mid-2008. Currently, the EPA classifies formaldehyde as “a probable human carcinogen.”
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In 2005, the United States Department of Health and Human Services announced that formaldehyde has been nominated for reconsideration in the National Toxicology Program’s (NTP) 12th Report on Carcinogens. The NTP is an interagency program that evaluates agents of public health concern and currently lists formaldehyde as “reasonably anticipated to be a human carcinogen.” Also in the US, the California Air Resources Board (CARB) is proposing an airborne toxic control measure to limit formaldehyde emissions from composite wood panels. A draft regulation was released in October 2006 and a rulemaking board hearing is scheduled for April 2007.
There are proposals in a number of other countries to reclassify formaldehyde and reduce permitted formaldehyde exposure levels. We are unable to determine at this time whether any of these countries or any other bodies will reclassify formaldehyde, or whether these or any other regulatory proposals will come into effect. Any reclassification 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 2006, methanol for the production of MTBE represented approximately 16% of global methanol demand. MTBE is used primarily as a source of octane and as an oxygenate for gasoline. During the 1990s, environmental concerns and legislation in the US led to the imposition of a federal oxygenate standard for gasoline that resulted in increased demand for MTBE for use in gasoline to reduce automobile tailpipe emissions.
Over the last few years, concerns have been raised in the US regarding the use of MTBE in gasoline. Gasoline containing MTBE has leaked into groundwater in the US, principally from underground gasoline storage tanks, and has also been discharged directly into drinking water reservoirs. As a result, several states including California, New York, New Jersey and Connecticut banned the use of MTBE as a gasoline component and this reduced demand for methanol in the US.
In 2005, the United States federal government passed the Energy Policy Act (EPACT), which contains provisions that have had the effect of further reducing demand for MTBE in the US. While EPACT does not provide for a federal ban on the use of MTBE in gasoline, it does waive the federal oxygenate standard for gasoline effective May 2006 and does not provide MTBE producers and blenders with liability protection.
About two million tonnes of methanol was used in the production of MTBE in the US in 2005. This was reduced to about 1.1 million tonnes in 2006 and we expect that this will be further reduced to about 0.8 million tonnes in 2007. This production is mainly destined for the export market as MTBE is no longer being consumed in the US except for non-fuel use. However, the pace of decline of US methanol demand for MTBE is uncertain and will be determined by various factors including the decision of US-based MTBE producers to continue to make MTBE for export. Most US refiners have already stated that they will stop the production and blending of MTBE for gasoline at some point.
The EPA is preparing an IRIS review of the human health effects of MTBE including its potential carcinogenicity, and their final report is expected to be released in mid-2008. 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 MTBE-containing fuel were recommended. However, governmental efforts in some European Union countries to promote bio-fuels and alternative fuels through legislation and tax policy are putting competitive pressures on the use of MTBE in gasoline. Several European MTBE production facilities have commenced production of ethyl tertiary butyl ether (ETBE) to take advantage of these tax incentives to produce bio-fuels.
Elsewhere in the world, MTBE continues to be used as a source of octane, but with growing use for its clean air benefits. We believe that there is potential for continuing growth in MTBE use outside the United States and Europe. Our belief is based on actions being taken around the world to reduce lead, benzene and other aromatics content in gasoline and to improve the emissions performance of vehicles generally. A number of Asian countries, including China, have adopted European specifications for gasoline formulations. This is expected to lead to increased consumption of MTBE in these markets.
We cannot provide assurance that legislation banning or restricting the use of MTBE or promoting alternatives to MTBE will not be passed or that negative public perceptions outside of the United States
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may not develop, either of which would lead to a further decrease in the global demand for methanol for use in MTBE.
Foreign Operations
We currently have substantial operations outside of North America, including Chile, Trinidad, New Zealand, 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, nationalization, war, insurrection and other political risks; increases in duties, taxes and governmental royalties and renegotiation of contracts with governmental entities; as well as changes in laws and policies governing operations of foreign-based companies.
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 taxing 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 for feedstock and ocean shipping 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 and the euro. 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.
Operational Risks
Substantially all 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 feedstock, power failures, longer than anticipated planned maintenance activities, loss of port facilities or any other event, including unanticipated events beyond our control, which 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 materially affect our revenues and operating income. Additionally, disruptions in our distribution system could materially adversely affect our revenues and operating income. Although we maintain insurance, including business interruption insurance, we cannot provide assurance that we will not incur losses beyond the limits of, or outside the coverage of, such insurance. 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.
Our trade in methanol is subject to import duties in certain jurisdictions. We cannot provide assurance that the duties that we are currently subject to will not increase, that duties will not be levied in other jurisdictions in the future or that we will be able to mitigate the impact of current or future duties, if levied.
New Capital Projects
As part of our strategy to strengthen our position as a low cost global producer of methanol, we intend to continue to pursue new opportunities to enhance our strategic position in the methanol industry. For example, we are developing a new methanol project in Egypt, but, as noted below, have not yet made a final decision to proceed with this project.
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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 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 andstart-up of large complex industrial projects. We cannot assure you that we will be able to identify and develop new methanol projects or, if we decide to proceed with a project, that the anticipated cost of construction will not be exceeded or that it will commence commercial production within the anticipated schedule, if at all.
We expect to make a final decision to proceed with our proposed project in Egypt by mid-2007. As at December 31, 2006, we have incurred approximately $16 million in development costs for this project that have been capitalized to property, plant and equipment and we will incur further development costs before making a final decision. If the final decision is made not to proceed, it would result in a write-off of these development costs.
Competition
The methanol industry is highly competitive. 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.
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 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.
Laws and regulations protecting the environment have become more stringent in recent years and may, in certain circumstances, impose absolute liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. These laws and regulations may also expose us to liability for the conduct of, or conditions caused by, others, or for our own acts that complied with applicable laws at the time such acts were performed. The operation of chemical manufacturing plants and the distribution of 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.
OUTLOOK
Methanol is a global commodity and our earnings are primarily affected by fluctuations in the methanol price, which is directly impacted by the balance of methanol supply and demand. Demand growth for methanol is driven primarily by growth in industrial production, energy prices and the strength of the global economy.
During the second half of 2006 global inventory levels were very low as a result of planned and unplanned supplier outages and strong demand. As a result, methanol prices increased substantially in September and again in October and pricing remained at these high levels for the remainder of 2006.
We estimate that global demand for methanol in 2006 increased by approximately 6% over 2005 to a total of 38 million tonnes, despite the phasing out of MTBE in the US. The increase in demand was driven primarily by an increase in demand for methanol in China, strong global economies leading to strong global demand for methanol in the traditional chemical derivatives markets and an increase in demand for methanol in energy-related markets. During 2006, demand for methanol in China was very strong and grew at higher rates than we expected for both traditional uses and non-traditional uses such as gasoline fuel
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blending. During 2006, there were numerous smaller scale capacity additions in China representing approximately 3.5 million tonnes per year and one significant addition of a 600,000 tonne per year natural gas based plant located on Hainan Island. The only significant capacity addition outside of China was the 550,000 tonne per year Togliatti plant in Russia that commenced operations towards the end of 2006.
Over the two-year period to the end of 2008, it is expected that new capacity and expansions outside of China will add approximately 6.5 million tonnes of capacity to the global industry. It is expected that the next increment of world-scale capacity will be the 1.7 million tonne per year NPC facility in Iran, which is expected to commence operations during the first half of 2007. In addition, there is a 1.0 million tonne per year plant in Oman under construction and it is expected that product from this plant will be available to the market during the second half of 2007. In 2008, it is expected that approximately 3.4 million tonnes of new capacity may be added to the market from two world-scale plants in Iran and Saudi Arabia and other expansions. Over the same period, it is also expected that additional plants will be constructed in China. We continue to believe that under normal market conditions, substantially all methanol production in China will be consumed locally and that China will continue to require imports to satisfy demand. We also believe that demand for methanol in China, for traditional chemical applications and new energy-related applications, will continue to grow at high rates, which will require capacity expansion and good operating rates in China in order to satisfy the growth in its domestic demand.
Over the two-year period to the end of 2008, we believe approximately 3.3 million tonnes of capacity could shut down as a result of high feedstock prices. Methanex itself is supplying methanol from two plants with a combined annual capacity of approximately 1.4 million tonnes that may shut down over the next 12 months. This includes our 530,000 tonne Waitara Valley facility located in New Zealand, which we are operating as a flexible asset, and the 850,000 tonne Celanese facility located in Alberta, Canada. We are purchasing methanol from the Celanese facility under an offtake agreement with Celanese Ltd. that expires on March 31, 2007.
Over the same period, we believe that the methanol industry will require new capacity outside of China to satisfy traditional demand driven by general economic growth. In addition, we believe there is considerable potential for demand growth in emerging applications for methanol. These emerging applications include biodiesel, methanol for power generation, di-methyl ether (DME) and fuel blending, with the latter two having the largest growth prospects in China.
Typical of most cyclical commodity chemicals, periods of high methanol prices encourage high cost production to operate at maximum rates, construction of new plants and expansion projects leading to the possibility of oversupply in the market. However, historically, not all announced capacity additions result in the completion of new plants. The construction of low-cost world-scale methanol facilities requires significant capital costs over a long lead time, a location with access to significant natural gas reserves with appropriate pricing and an ability to cost-effectively deliver methanol to customers. Obtaining access to gas supply is becoming more challenging as gas is increasingly being used for higher value uses such as domestic use, LNG or other chemical products. In addition, plant construction phases have been extended and capital costs have escalated due to strong demand for raw materials, equipment and labour caused by increased construction activity globally.
We entered 2007 with high prices, which in a normal demand and supply environment are unsustainable, and global inventory levels in the methanol industry are recovering in 2007. However, industry fundamentals continue to be favourable and are underpinned by healthy demand and high energy prices. The methanol price will ultimately depend on industry operating rates, the rate of industry restructuring and the strength of global demand. We believe that our excellent financial position and financial flexibility, outstanding global supply network and competitive cost position will provide a sound basis for Methanex continuing to be a leader in the methanol industry.
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
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statements and related notes. See note 1 of our 2006 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, 2006, the net book value of our property, plant and equipment was $1,353 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.
There are a number of uncertainties inherent in estimating future net cash flows to be generated by our production facilities. These include, among other things, assumptions regarding future supply and demand, methanol pricing, availability and pricing of natural gas supply, and production and distribution costs. Changes in these assumptions will impact our estimates of future net 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 materially and 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, 2006, we had 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 true 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 currently enacted or substantially enacted tax rates for the effects of net operating losses and temporary differences between the book and tax bases of assets and liabilities. We record a valuation allowance on future tax assets, when appropriate, to reflect the uncertainty of realization of 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, 2006, we had future income tax assets of $302 million that are substantially offset by a valuation allowance of $263 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.
NEW CANADIAN ACCOUNTING STANDARDS ADOPTED IN 2006
There were no new Canadian accounting standards adopted during 2006 that had a material impact on our consolidated financial statements.
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ANTICIPATED CHANGES TO CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
Financial Instruments — Recognition and Measurement, Hedges and Comprehensive Income
The Canadian Institute of Chartered Accountants has issued new accounting standards for financial instruments that are effective for the Company as of January 1, 2007. These standards address when an entity should recognize a financial instrument on its balance sheet and how it should measure the financial instrument once recognized. These standards also provide guidance on applying hedge accounting and provide alternative treatments for entities that choose to designate qualifying transactions as hedges for accounting purposes. Comprehensive income is also introduced as a concept in Canadian accounting with a requirement to present certain unrealized gains and losses outside net income. We are currently assessing the implications of these new standards on our consolidated financial statements.
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, income before unusual items (after-tax), diluted income before unusual items (after-tax) per share, 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 the Company’s 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.
Operating Income and Cash Flows from Operating Activities before 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 statements of income and consolidated statements of cash flows, respectively.
Income before Unusual Items (After-Tax) and Diluted Income before Unusual Items (After-Tax) per Share
These supplemental non-GAAP measures are provided to assist readers in comparing earnings from one period to another without the impact of unusual items that are considered by management to be non-operational and/or non-recurring. Diluted income before unusual items (after-tax) per share has been calculated by dividing income before unusual items (after-tax) by the diluted weighted average number of common shares outstanding.
The following table shows a reconciliation of net income to income before unusual items (after-tax) and the calculation of diluted income before unusual items (after-tax) per share:
($ MILLIONS, EXCEPT NUMBER OF SHARES AND PER SHARE AMOUNTS) | 2006 | 2005 | ||||||
Net income | $ | 483 | $ | 166 | ||||
Add (deduct) unusual items: | ||||||||
Kitimat closure costs | — | 41 | ||||||
Future income taxes related to change in tax legislation | (26 | ) | 17 | |||||
Income before unusual items (after-tax) | $ | 457 | $ | 224 | ||||
Diluted weighted average number of common shares outstanding (millions of shares) | 109 | 118 | ||||||
Diluted income before unusual items (after-tax) per share | $ | 4.18 | $ | 1.89 | ||||
Adjusted EBITDA
This supplemental non-GAAP measure is provided to assist readers in determining 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
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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, Kitimat closure costs, 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) | 2006 | 2005 | ||||||
Cash flows from operating activities | $ | 469 | $ | 359 | ||||
Add (deduct): | ||||||||
Changes in non-cash working capital | 154 | (29 | ) | |||||
Stock-based compensation, net | (13 | ) | (5 | ) | ||||
Other, net | 1 | (2 | ) | |||||
Kitimat closure costs | — | 41 | ||||||
Interest expense | 45 | 41 | ||||||
Interest and other income | (10 | ) | (10 | ) | ||||
Income taxes — current | 154 | 57 | ||||||
Adjusted EBITDA | $ | 800 | $ | 452 | ||||
QUARTERLY FINANCIAL DATA (UNAUDITED)
THREE MONTHS ENDED | ||||||||||||||||
($ MILLIONS, EXCEPT PER SHARE AMOUNTS) | DEC 31 | SEP 30 | JUN 30 | MAR 31 | ||||||||||||
2006 | ||||||||||||||||
Revenue | $ | 668 | $ | 520 | $ | 461 | $ | 460 | ||||||||
Net income | 172 | 113 | 82 | 115 | ||||||||||||
Basic net income per share | 1.62 | 1.05 | 0.75 | 1.02 | ||||||||||||
Diluted net income per share | 1.61 | 1.05 | 0.75 | 1.02 | ||||||||||||
2005 | ||||||||||||||||
Revenue | $ | 460 | $ | 349 | $ | 411 | $ | 438 | ||||||||
Net income (loss) | 49 | (22 | ) | 63 | 76 | |||||||||||
Basic net income (loss) per share | 0.42 | (0.19 | ) | 0.53 | 0.63 | |||||||||||
Diluted net income (loss) per share | 0.42 | (0.19 | ) | 0.53 | 0.63 | |||||||||||
SELECTED ANNUAL INFORMATION
($ MILLIONS, EXCEPT PER SHARE AMOUNTS) | 2006 | 2005 | 2004 | |||||||||
Revenue | $ | 2,108 | $ | 1,658 | $ | 1,719 | ||||||
Net income | 483 | 166 | 236 | |||||||||
Basic net income per share | 4.43 | 1.41 | 1.95 | |||||||||
Diluted net income per share | 4.41 | 1.40 | 1.92 | |||||||||
Cash dividends declared per share | 0.485 | 0.410 | 0.280 | |||||||||
Total assets | 2,443 | 2,106 | 2,125 | |||||||||
Total long-term financial liabilities | 542 | 566 | 411 | |||||||||
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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 filings under applicable securities regulations is recorded, processed, summarized and reported within the time periods specified. As at December 31, 2006, 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.
Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (Canadian GAAP) and the requirements of the Securities and Exchange Commission in the United States, as applicable. Management is responsible for establishing and maintaining adequate internal control over financial reporting. 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 our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2006.
Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, Chartered Accountants, and their opinion is included in the annual report on page 37.
There have been no changes during the year ended December 31, 2006 to our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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.
FORWARD-LOOKING STATEMENTS
Statements made in this document that are based on our current objectives, expectations, estimates and projections constitute forward-looking statements. These statements include forward-looking statements both with respect to us and the chemicals industry. Statements that include the words “believes,” “expects,” “may,” “will,” “should,” “seeks,” “intends,” “plans,” “estimates,” “anticipates,” or the negative version of those words or other comparable terminology and similar statements of a future or forward-looking nature identify forward-looking statements. Methanex believes that it has a reasonable basis for making such forward-looking statements. Forward-looking statements 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 which are included in these forward-looking statements.
Important factors that can cause stated outcomes to differ materially from actual outcomes include but are not limited to worldwide economic conditions; conditions in the methanol and other industries, including the supply of methanol; demand for methanol and its derivatives; actions of competitors; actions of governments including changes in laws or regulations; the ability to implement business strategies, pursue business opportunities and maintain and enhance our competitive advantages; risks attendant with methanol production and marketing, including operational disruption; risks attendant with carrying out capital expenditure projects, including the ability to obtain financing and completing the projects on time and on budget; availability and price of natural gas feedstock; foreign exchange risks; raw material and other production costs; transportation costs; the ability to attract and retain qualified personnel; risks associated with investments and operations in multiple jurisdictions; and other risks discussed under the headingRisk Factors and Risk Management in our 2006 Management’s Discussion and Analysis.
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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.
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