NEWS RELEASE

Production (thousands of tonnes)

 

Sales volumes (thousands of tonnes):

Produced methanol

Purchased methanol

Commission sales ¹

 

Total sales volumes

Methanex average non-discounted posted price ($  per tonne) ²

Average realized price ($  per tonne) ³

Adjusted EBITDA ⁴

Cash flows from operating activities

Cash flows from operating activities before changes in non-cash working capital ⁴

Operating income

Net income attributable to Methanex shareholders

Basic net income per common share attributable to Methanex shareholders

Diluted net income per common share attributable to Methanex shareholders

Common share information (millions of shares):

Weighted average number of common shares

Diluted weighted average number of common shares

Number of common shares outstanding, end of period

Chile I, II, III and IV

Atlas (Trinidad) (63.1% interest)

Titan (Trinidad)

New Zealand ²

Egypt (60% interest)³

Medicine Hat³

 

 

 

Average realized price

Sales volume

Total cash costs

 

 

 

Methanex average non-discounted posted price ¹

Methanex average realized price

Average discount

Produced methanol costs, primarily natural gas

Proportion of purchased methanol sales

Purchased methanol costs

Share-based compensation

Unabsorbed fixed costs

Other, net

 

Decrease in Adjusted EBITDA

 

Finance costs before capitalized interest

Less capitalized interest

 

 

 

United States

Europe ²

Asia

 

 

Revenue

Net income²

Net income before unusual item²

Basic net income per common share²

Basic net income per common share before unusual item²

Diluted net income per common share²

Diluted net income per common share before unusual item²

Revenue

Net income (loss)²

Net income (loss) before unusual item²

Basic net income (loss) per common share²

Basic net income (loss) per common share before unusual item²

Diluted net income (loss) per common share²

Diluted net income (loss) per common share before unusual item²

expected demand for methanol and its derivatives,

expected new methanol supply and timing for start-up of the same,

expected shut downs (either temporary or permanent) or re-starts of existing methanol supply (including our own facilities), including, without limitation, timing of planned maintenance outages,

expected methanol and energy prices,

expected levels and timing of natural gas supply to our plants, including without limitation, levels of natural gas supply from investments in natural gas exploration and development in Chile and New Zealand and availability of economically priced natural gas in Chile, New Zealand and Canada,

capital committed by third parties towards future natural gas exploration in Chile and New Zealand,

expected capital expenditures, including without limitation, those to support natural gas exploration and development in Chile and New Zealand and the restart of our idled methanol facilities,

anticipated production rates of our plants, including without limitation, our Chilean facilities, the new methanol plant in Egypt and the restart of our Medicine Hat facility which is currently in the commissioning phase,

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

expected tax rates or resolutions to tax disputes,

expected cash flows and earnings capability,

anticipated completion date of, and cost to complete, our Medicine Hat restart project,

ability to meet covenants associated with our long-term debt obligations, including without limitation, the Egypt limited recourse debt facilities which have conditions associated with operational completion of the plant and related mortgages which require actions by Egyptian governmental entities,

availability of committed credit facilities and other financing,

shareholder distribution strategy and anticipated distributions to shareholders,

commercial viability of, or ability to execute, future projects or capacity expansions,

financial strength and ability to meet future financial commitments,

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

expected actions of governments, gas suppliers, courts, tribunals or other third parties, and

expected impact on our results of operations in Egypt and our financial condition as a consequence of actions taken by the Government of Egypt and its agencies.

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

success of natural gas exploration in Chile and New Zealand and our ability to procure economically priced natural gas in Chile, New Zealand and Canada,

production rates of our facilities, including without limitation, our Chilean facilities, the new methanol plant in Egypt and the restart of our Medicine Hat facility which is currently in the commissioning phase,

receipt or issuance of third party consents or approvals, including without limitation, governmental registrations of land title and related mortgages in Egypt, governmental approvals related to natural gas exploration rights, rights to purchase natural gas or the establishment of new fuel standards,

operating costs including natural gas feedstock and logistics costs, capital costs, tax rates, cash flows, foreign exchange rates and interest rates,

timing of completion and cost of our Medicine Hat restart project,

ability to meet covenants associated with our long-term debt obligations, including without limitation, the Egypt limited recourse debt facilities which have conditions associated with operational completion of the plant and completion of certain land title registrations and related mortgages which require actions by Egyptian governmental entities,

availability of committed credit facilities and other financing,

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

absence of a material negative impact from major natural disasters,

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

enforcement of contractual arrangements and ability to perform contractual obligations by customers, suppliers and other third parties.

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

the price of natural gas, oil and oil derivatives,

the success of natural gas exploration and development activities in southern Chile and New Zealand and our ability to obtain any additional gas in Chile, New Zealand, and Canada on commercially acceptable terms,

the timing of start-up and cost to complete our Medicine Hat restart project,

the ability to successfully carry out corporate initiatives and strategies,

actions of competitors and suppliers,

actions of governments and governmental authorities, including without limitation, implementation of policies or other measures that could impact the supply or demand for methanol or its derivatives,

changes in laws or regulations,

import or export restrictions, anti-dumping measures, increases in duties, taxes and government royalties, and other actions by governments that may adversely affect our operations or existing contractual arrangements,

world-wide economic conditions, and

other risks described in our 2010 Management’s Discussion and Analysis and this First Quarter 2011 Management’s Discussion and Analysis.

The change in Adjusted EBITDA as a result of changes in average realized price is calculated as the difference from period to period in the selling price of methanol multiplied by the current period total methanol sales volume excluding commission sales volume plus the difference from period to period in commission revenue.

 

The change in our Adjusted EBITDA as a result of changes in cash costs is calculated as the difference from period to period in cash costs per tonne multiplied by the current period total methanol sales volume excluding commission sales volume in the current period. The cash costs per tonne is the weighted average of the cash cost per tonne of Methanex-produced methanol and the cash cost per tonne of purchased methanol. The cash cost per tonne of Methanex-produced methanol includes absorbed fixed cash costs per tonne and variable cash costs per tonne. The cash cost per tonne of purchased methanol consists principally of the cost of methanol itself. In addition, the change in our Adjusted EBITDA as a result of changes in cash costs includes the changes from period to period in unabsorbed fixed production costs, consolidated selling, general and administrative expenses and fixed storage and handling costs.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in fair value of forward exchange contracts, net of tax

Change in fair value of interest rate swap contracts, net of tax

Interest rate swap cash settlement reclassified to interest expense

Interest rate swap cash settlement reclassified to property, plant and equipment

 

 

 

 

Methanex Corporation shareholders

Non-controlling interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, January 1, 2010

Net income

Other comprehensive income

Compensation expense recorded for stock options

Issue of shares on exercise of stock options

Reclassification of grant date fair value on exercise of stock options

Dividend payments to Methanex Corporation shareholders

Capital contributions by non-controlling interests

 

Balance, March 31, 2010

Net income

Other comprehensive loss

Compensation expense recorded for stock options

Issue of shares on exercise of stock options

Reclassification of grant date fair value on exercise of stock options

Dividend payments to Methanex Corporation shareholders

Dividend payments to non-controlling interests

Capital contributions non-controlling interests

 

Balance, December 31, 2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Methanex Corporation (the Company) is an incorporated entity with corporate offices in Vancouver, Canada. The Company’s operations consist of the production and sale of methanol, a commodity chemical. The Company is the world’s largest supplier of methanol to the major international markets of Asia Pacific, North America, Europe and Latin America.

Functional currency is the currency of the primary economic environment in which an entity operates. The majority of the Company’s business is transacted in US dollars and, accordingly, these condensed consolidated interim financial statements have been measured and expressed in that currency. The Company translates foreign currency denominated monetary items at the rates of exchange prevailing at the balance sheet dates, foreign currency denominated non-monetary items at historic rates, and revenues and expenditures at the rates of exchange at the dates of the transactions. Foreign exchange gains and losses are included in earnings.

Cash equivalents include securities with maturities of three months or less when purchased.

The Company provides credit to its customers in the normal course of business. The Company performs ongoing credit evaluations of its customers and maintains reserves for potential credit losses. The Company records an allowance for doubtful accounts or writes down the receivable to estimated net realizable value if not collectible in full. Credit losses have historically been within the range of management’s expectations.

Inventories are valued at the lower of cost and estimated net realizable value. Cost is determined by the first-in first-out basis and includes direct purchase costs, cost of production, allocation of production overhead based on normal operating capacity and transportation.

Property, plant and equipment are initially recorded at cost. Cost includes expenditure that is directly attributable to the acquisition of the asset. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to a working condition for their intended use, the costs of dismantling and removing the items and restoring the site on which they are located and borrowing costs on self-constructed assets that meet certain criteria. Borrowing costs, including the impact of related cash flow hedges, incurred during construction and commissioning are capitalized until the plant is operating in the manner intended by management.

Routine repairs and maintenance costs are expensed as incurred. At regular intervals, the Company conducts a planned shutdown and inspection (turnaround) at its plants to perform major maintenance and replacements of catalyst. Costs associated with these shutdowns are capitalized and amortized over the period until the next planned turnaround.

Depreciation and amortization is generally provided on a straight-line basis or on a unit-of-natural gas consumption basis, at rates calculated to amortize the cost of property, plant and equipment from the commencement of commercial operations over their estimated useful lives to estimated residual value. The estimated useful life of the Company’s buildings, plant installations and machinery is 5 to 25 years.

The Company reviews the depreciation and amortization rates of property, plant and equipment on an annual basis and, if necessary, changes are accounted for prospectively.

Assets under finance lease are depreciated to their estimated residual value based on the shorter of their useful lives and the lease term.

Costs incurred for oil and natural gas properties with proven reserves are capitalized to property, plant and equipment, including the reclassification of associated exploration costs. These costs are depreciated using a unit-of-production method, taking into consideration both estimated future costs in developing reserves and estimated proven reserves. Proven and probable reserves for oil and natural gas properties are estimated based on independent reserve reports and represent the estimated quantities of natural gas which are considered commercially feasible. These reserve estimates are used to determine depreciation and to assess the carrying value of oil and natural gas properties. The accounting for costs incurred for oil and natural gas exploration properties with unproven reserves are described in note 2(h).

The Company reviews the carrying value of property, plant and equipment for impairment when circumstances indicate an asset’s carrying value may not be recoverable. Examples of such events or changes in circumstances related to our long-lived assets include, but are not restricted to: a significant adverse change in the extent or manner in which the asset is being used or in its physical condition; a significant change in the price or availability of natural gas feedstock required to manufacture methanol; a significant adverse change in oil and gas reserve estimates; a significant adverse change in legal factors or in the business climate that could affect the asset’s value, including an adverse action or assessment by a foreign government that impacts the use of the asset; or a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the asset’s use. If any such indication of impairment exists, the Company makes an assessment of the recoverable amount, by comparing the carrying value to the higher of fair value and the asset’s value in use. The asset’s value in use is determined as the present value of the expected future cash flows less expected costs for the disposal of the asset. An impairment write-down is recorded for the difference between the carrying amount and the higher of fair value and the asset’s value in use. An impairment write-down recognized in prior periods for an asset is reversed if there has been a subsequent recovery in the value of the asset due to changes in events and circumstances.

Intangible assets are capitalized to other assets and amortized to depreciation and amortization expense on an appropriate basis to charge the cost of the assets against earnings.

Financing fees related to undrawn credit facilities are capitalized to other assets and amortized to interest expense over the term of the credit facility. Financing fees related to project debt facilities are capitalized to other assets until the project debt is fully drawn. Once the project debt is fully drawn, these fees are reclassified to long-term debt net of financing fees and amortized to interest expense over the repayment term on an effective interest basis.

Costs incurred for oil and natural gas exploration properties with unproven reserves are capitalized to other assets. Upon recognition of proved reserves and internal approval for development, these costs are transferred to property, plant and equipment and are depreciated using a unit-of-production method based on estimated proved reserves.

The Company reviews the carrying value of other assets for impairment when circumstances indicate that an asset’s carrying value may not be recoverable.

Leasing contracts are classified as either financing or operating leases. Where the contracts are classified as operating leases, payments are charged to income in the year they are incurred. A lease is classified as a finance lease if it transfers substantially all of the risks and rewards of ownership of the leased asset. The asset and liability associated with a finance lease are recorded at the lower of fair value and the present value of the minimum lease payments, net of executory costs. Lease payments are apportioned between interest expense and repayments of the liability.

The Company recognizes a liability to dismantle and remove assets or to restore a site upon which the assets are located. The Company estimates the fair value of the liability by determining the current market cost required to settle the site restoration costs and adjusts for inflation through to the expected date of the expenditures and discounts this amount back to the date when the obligation was originally incurred. As the liability is initially recorded on a discounted basis, it is increased each period until the estimated date of settlement. The resulting expense is referred to as accretion expense and is included in finance costs. The Company reviews asset retirement obligations and adjusts the liability as necessary to reflect changes in the estimated future cash flows, timing, inflation and discount rates underlying the fair value measurement. Inherent uncertainties exist in the estimate of the obligations 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. Because of uncertainties related to estimating the cost and timing of future site restoration activities, future costs could differ materially from the amounts estimated.

The Company has non-contributory defined benefit pension plans covering certain employees and defined contribution pension plans. The Company does not provide any significant post-retirement benefits other than pension plan benefits. For defined benefit pension plans, the net of the present value of the defined benefit obligation and the fair value of plan assets is recorded to the statement of financial position. The determination of the defined benefit obligation and associated pension cost is based on certain actuarial assumptions including inflation rates, salary growth, longevity and expected return on plan assets. The present value of the defined benefit obligation is determined by discounting estimated future cash flows using current market bond yields which have terms to maturity approximating the terms of the obligation. Actuarial gains and losses arising from differences between these assumptions and actual results are recognized in other comprehensive income, and recorded in retained earnings. The cost for defined contribution benefit plans is recognized in net income as earned by the employees.

The Company calculates basic net income per common share by dividing net income by the weighted average number of common shares outstanding and calculates diluted net income per common share under the treasury stock method. Under the treasury stock method, the weighted average number of common shares outstanding for the calculation of diluted net income per share assumes that the total of the proceeds to be received on the exercise of dilutive stock options is applied to repurchase common shares at the average market price for the period. Stock options are dilutive only when the average market price of common shares during the period exceeds the exercise price of the stock option.

The Company grants share-based awards as an element of compensation. Share-based awards granted by the Company can include stock options, tandem share appreciation rights, share appreciation rights, deferred share units, restricted share units or performance share units.

For stock options granted by the Company, the cost of the service received as consideration is measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the related service period with a corresponding increase in contributed surplus. On the exercise of stock options, consideration received, together with the compensation expense previously recorded to contributed surplus, is credited to share capital. The Company uses the Black-Scholes option pricing model to estimate the fair value of each stock option tranche at the date of grant.

Share appreciation rights are units which grant the holder the right to receive a cash payment upon exercise for the difference between the market price of the Company’s common shares and the exercise price which is determined at the date of grant. Tandem share appreciation rights gives the holder the choice between exercising a regular stock option or share appreciation right. For share appreciation rights and tandem share appreciation rights, the cost of the service received as consideration is initially measured based on an estimate of the fair value at the date of grant. The grant-date fair value is recognized as compensation expense over the related service period with a corresponding increase in liabilities. For share appreciation rights and tandem share appreciation rights, the cost of the service is re-measured at each reporting date based on an estimate of the fair value with changes in fair value recognized as compensation expense for the proportion of the service that has been rendered at that date. The Company uses the Black-Scholes option pricing model to estimate the fair value for share appreciation rights and tandem share appreciation rights.

Deferred, restricted and performance share units are grants of notional common shares that are redeemable for cash based on the market value of the Company’s common shares and are non-dilutive to shareholders. Performance share units have an additional feature where the ultimate number of units that vest will be determined by the Company’s total shareholder return in relation to a predetermined target over the period to vesting. The number of units that will ultimately vest will be in the range of 50% to 120% of the original grant. For deferred, restricted and performance share units, the cost of the service received as consideration is initially measured based on the market value of the Company’s common shares at the date of grant. The grant-date fair value is recognized as compensation expense over the related service period with a corresponding increase in liabilities. Deferred, restricted and performance share units are re-measured at each reporting date based on the market value of the Company’s common shares with changes in fair value recognized as compensation expense for the proportion of the service that has been rendered at that date.

Additional information related to the stock option plan, the assumptions used in the Black-Scholes option pricing model, tandem share appreciation rights, share appreciation rights and the deferred, restricted and performance share units of the Company are described in note 14.

Revenue is recognized based on individual contract terms when the title and risk of loss to the product transfers to the customer, which usually occurs at the time shipment is made. Revenue is recognized at the time of delivery to the customer’s location if the Company retains title and risk of loss during shipment. For methanol shipped on a consignment basis, revenue is recognized when the customer consumes the methanol. For methanol sold on a commission basis, the commission income is included in revenue when earned.

Financial instruments are classified into one of five categories and, depending on the category, will either be measured at amortized cost or fair value. Held-to-maturity investments, loans and receivables and other financial liabilities are measured at amortized cost. Financial assets and liabilities through profit and loss (held for trading category) and available-for-sale financial assets are measured on the balance sheet at fair value. Changes in the fair value of held-for-trading financial assets and liabilities are recognized in earnings and changes in the fair value of available-for-sale financial assets are recorded in other comprehensive income until the investment is derecognized or impaired at which time the amounts would be recorded in earnings. The Company classifies its cash and cash equivalents as held-for-trading. Trade and other receivables are classified as loans and receivables. Trade, other payables and accrued liabilities, long-term debt, net of financing costs, and other long-term liabilities are classified as other financial liabilities.

Under these standards, derivative financial instruments, including embedded derivatives, are classified as held for trading and are recorded on the balance sheet at fair value unless exempted. The valuation of derivative financial instruments is a critical accounting estimate due to the complex nature of these products, the degree of judgment required to appropriately value these products and the potential impact of such valuation on the Company’s financial statements. The Company records all changes in fair value of derivative financial instruments in earnings unless the instruments are designated as cash flow hedges. The Company enters into and designates as cash flow hedges certain forward exchange purchase and sales contracts to hedge foreign exchange exposure on anticipated sales. The Company also enters into and designates as cash flow hedges certain interest rate swap contracts to hedge variable interest rate exposure on its limited recourse debt. The Company assesses at inception and on an ongoing basis whether the hedges are and continue to be effective in offsetting changes in the cash flows of the hedged transactions. The effective portion of changes in the fair value of these hedging instruments is recognized in other comprehensive income. Any gain or loss in fair value relating to the ineffective portion is recognized immediately in earnings. Until settled, the fair value of the derivative financial instruments will fluctuate based on changes in variable interest rates.

Income tax expense represents current tax and deferred tax. The Company records current tax based on the taxable profits for the period which is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Deferred income taxes are accounted for using the liability method. The liability method requires that income taxes reflect the expected future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their tax bases. Deferred income tax assets and liabilities are determined for each temporary difference based on currently enacted or substantially enacted tax rates that are expected to be in effect when the underlying items of income or expense are expected to be realized. The effect of a change in tax rates or tax legislation is recognized in the period of substantive enactment. Deferred tax assets, such as non-capital loss carryforwards, are recognized to the extent it is probable that taxable profit will be available against which the asset can be utilized.

The Company accrues for taxes that will be incurred upon distributions from its subsidiaries when it is probable that the earnings will be repatriated.

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, the Company’s results of operations and financial position could be materially impacted.

Provisions are recognized where a legal or constructive obligation has been incurred as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation.

The Company’s operation consists of the production and sale of methanol, which constitutes a single operating segment.

 

 

 

Inventories are valued at the lower of cost, determined on a first-in first-out basis, and estimated net realizable value. The amount of inventories included in cost of sales and operating expenses and depreciation and amortization for the three months ended March 31, 2011 is $507 million (2010 — $362 million).

 

 

 

 

Cost at December 31, 2010

Accumulated depreciation at December 31, 2010

 

Net book value at December 31, 2010

 

 

Cost at January 1, 2010

Accumulated depreciation at January 1, 2010

 

Net book value at January 1, 2010