TSX: COS: 23.83  +0.44

Quotes delayed up to 20 minutes.

VIEW DETAILED SHARE PRICE

Canadian Oil Sands Limited 2000 First Canadian Centre 350–7th Avenue SW Calgary, Alberta T2P 3N9

Tel: 403 218 6200
Fax: 403 218 6201

VIEW CONTACT PAGE

Search for a word or look it up alphabetically on our glossary page.

VIEW FULL GLOSSARY
 
Investor Centre
Canadian Oil Sands converted from an income trust to a corporation on December 31, 2010.  The personal tax information below is applicable for the 2010 taxation year and prior. 

For post-conversion personal tax information for the 2011 tax year and beyond, please see Tax Information

Tax consequences prior to trust taxation.

Canadian Resident Tax Information

Canadian Oil Sands Trust (the “Trust”) was treated as a mutual fund trust for purposes of the Canadian Income Tax Act. Each year the Trust files an income tax return and allocates all its taxable income to its Unitholders with the result that its income is taxable in the hands of its Unitholders. Distributions paid by the Trust are both a return of capital (i.e. a repayment of a portion of your investment) and a return on investment (i.e. taxable income). The allocation between these two streams is dependent upon the tax deductions that the Trust is entitled to claim against the income it earns from royalties, interest and dividends received from Canadian Oil Sands Limited (the operating company) and income the Trust earns directly.

Each year the taxable income portion and return of capital, is calculated and reported in the Trust's T3 return and allocated to each Unitholder who received distributions in that taxation year on the T3 Summary Form, which is mailed out before March 31st. The T3 slip will report only taxable amounts, which are classified and shown as other income (royalty and interest) in box 26, or eligible dividends in box 49. Historically, the portion of the Trust's distributions that were considered taxable has all been classified as "other income".

The tax deferred, or return of capital, portion reduces a Unitholder's adjusted cost base ("ACB") of units and is reported in Box 42 of the T3 slip.

A summary of the distributions paid per Unit and the amount that is tax deferred is available at Canadian Summary of Distributions.

Units held within a RRSP, RRIF or DPSP

For trust units held in non-taxable accounts such as Registered Retirement Savings Plans (RRSP), Registered Retirement Income Funds (RRIF), or Deferred Profit Sharing Plans (DPSP), income earned on the trust units is generally not subject to taxation during the year. The amount of capital and any earnings in the plan are typically taxed only on withdrawal from the plan.

Units held outside an RRSP, RRIF or DPSP

Unitholders who hold trust units outside a RRSP, RRIF or DPSP and received one or more cash distributions during the calendar year will be issued a T3 Summary Form indicating the portion of cash distributions to be reported as taxable "Other Income" or “Eligible Dividends” and the portion which is a return of capital. T3 slips are mailed in the month of March. Unitholders will receive the T3 slip from their brokerage firm if the units are registered in street form and directly from Computershare Trust Company of Canada, the Trust’s registrar and transfer agent, if the Units are registered in the Unitholder’s name.

Adjusted Cost Base ("ACB") Reduction

ACB is used in calculating capital gains or losses in respect of trust units held as capital property by a Unitholder on the disposition of the Units. A Unitholder must generally average the cost of all Units to determine ACB. Unitholders are required to reduce the ACB of their Units by the amount of any distributions received as returns of capital (i.e. the tax-deferred portion of distributions received).

Capital gains from the disposition of Units will be equal to proceeds of the sale of the Units less the ACB of the Units and any reasonable costs of disposition. Additionally, should a taxpayer's ACB be reduced to below zero during a taxation year, an immediate disposition is deemed to have occurred and the negative amount is deemed to be a capital gain. The ACB is then reset to zero. Capital gains are reported by a Unitholder on schedule 3 of the T1 Income Tax Return.

Example:

An investor purchased a unit of the Trust for $50.00. During the time the investor held the unit, the  Trust paid distributions totalling $5.00. These distributions were comprised of $4.90 taxable income and $0.10 tax-deferred return of capital. The $4.90 taxable portion is taxable as other income in the year it was received whereas the $0.10 tax-deferred return of capital would not be taxable in that year. This amount reduced the ACB of the trust unit to $49.90.

If the investor then sold the Unit for $52.00, a capital gain of $2.10 would result ($52.00 -$49.90).

 
Purchase price = $50.00
Total distributions received during the year = $5.00
      Distribution comprised of:
      Taxable income = $4.90
      (reflected as “Other Income” on T3 Summary Form) 
      Tax deferred return of capital = $0.10
      (tax-deferred and reported in box 42 of T3 Summary Form) 
      ACB Reduction
      Purchase price =       $50.00
      Tax deferred              ($0.10) 
                                    = $49.90
          
      Sales price =                $52.00
      ACB =                         ($49.90) 
      Capital Gain                = $2.10
      (must be reported on Schedule 3 of T1 Income Tax Return)

The above information is not intended to be, and should not be construed to be, legal or tax advice to any Unitholder. Unitholders should obtain independent advice regarding the income tax consequences of their investment.

U.S. and other Non-resident Tax Information

Unitholders who are non-residents of Canada for Canadian income tax purposes are encouraged to seek advice from a qualified tax advisor in your country of residence for the tax treatment of distributions. Distributions payable to non-residents of Canada are normally subject to a withholding tax of 25% as prescribed by the Income Tax Act of Canada. However, the withholding tax for residents of the United States is prescribed at 15% in accordance with a reciprocal tax treaty between Canada and the United States. U.S. taxpayers may be eligible for a foreign tax credit with respect to the Canadian withholding taxes paid. Other jurisdictions may also have reciprocal tax treaties that would reduce the withholding tax rate.

As Canadian Oil Sands Trust has not made an election to be treated as a partnership for U.S. tax purposes, we believe we are considered a corporation for U.S. tax purposes with a portion of the distributions paid by the Trust qualifying as dividends for U.S. tax purposes. In the instance of a U.S. Unitholder, the taxable portion of the distribution for U.S. tax purposes is determined by the Trust based upon current and accumulated earnings determined in accordance with U.S. tax law. Information detailing distributions paid and the taxable portion for U.S. purposes is posted on our Web site after the end of each year.

The non-taxable portion of the cash distribution is subject to a withholding tax of 15% but treated as a reduction of cost base for purposes of computing gains or losses on disposition of a Unit. Once the full amount of the cost base has been recovered, any additional non-taxable distributions should generally be reported as capital gains.

For U.S. residents, the income tax laws of the United States apply.

A summary of the distributions paid per Unit, the per cent taxable as Ordinary Income and the per cent taxable as Return of Capital or Capital Gain is available at U.S. Summary of Distributions.

The above information is not intended to be, and should not be construed to be, legal or tax advice to any Unitholder. Unitholders should obtain independent advice regarding the income tax consequences of their investment.

Canadian Federal Tax considerations for DRIP participants

The following information applies to Unitholders who participate in Canadian Oil Sands Trust's premium distribution, distribution reinvestment and optional unit purchase plan (“DRIP”).

Unitholders must consider the tax consequences of their participation in the DRIP. Information on the tax consequences is provided below.

Electing distribution reinvestment option

Where Participants elect to accumulate additional Units under the distribution reinvestment plan, the Participants reinvest their distributions in additional Units at 95% of the Average Market Price (as fully described in Canadian Oil Sands Trust's DRIP).

The Canada Revenue Agency (the "CRA") generally takes the position that under a DRIP, where the fair market value of the Units acquired exceeds the purchase price, the difference is a benefit and must be included in the Participant's income for tax purposes. The cost of the Units acquired under the DRIP is the amount reinvested plus the amount of the benefit. The units acquired under the DRIP must be averaged with the cost of all other Units the Participant holds for the purpose of determining the adjusted cost base of all the Participant's Units. Capital gains or losses arising on a disposition of the Participant's Units will be measured by reference to the adjusted cost base of all the Participant's Units.

Electing the premium distribution option (available only to Canadian resident Unitholders)

Where Participants elect to receive the Premium Distribution under the DRIP, the Agent will pre-sell, through the Plan Broker the number of Units to be purchased through the DRIP and such Participants, subject to proration, will receive a Premium Distribution in an amount up to 102% of the distribution that such Participants would have otherwise been entitled to receive on that distribution date (as fully described in Canadian Oil Sands Trust's DRIP).

Under the current assessing policies of the CRA, a Participant in the Premium Distribution is required to include in computing income any benefit and must also account for any gain or loss on the units sold on his or her behalf through the Premium Distribution DRIP.

The benefit is equal to the amount by which the closing price of Units acquired under the premium DRIP exceeds the cost of such Units. The benefit enjoyed pursuant to the participation in the DRIP may not be reported by the Trust on a Unitholder's T-3; however, a Participant will be required to report such benefit when preparing his or her tax return for the year in which the Units were acquired.

In addition to including the Benefit in income the Participant is also required to compute the profit (or loss) from the sale of the Units. However, as the amount of benefit is added to the cost of the units sold, the cost will generally equal the proceeds and no further gain or loss will result.

For example for a holder with 10,000 units the net effect of the sale of Premium DRIP on income account would be:

Profit (or loss) = Sale price – Cost of Units Acquired under the DRIP
                       = (102% x distribution) – (Cost of Units)
                       = (1.02% x $0.30 x 10,000) - $3,000)
                       = $3,100 – $3,000
Total Income = $100

Although a Participant may hold existing Units as capital property, Units sold pursuant to the Premium Distribution option of the DRIP will generally constitute inventory. In circumstances where a Unitholder is considered to hold the Units acquired under the Premium DRIP as capital property, the calculations required are more complex as the holder must average the cost of the units acquired with the cost of all other units held. Unitholders should consult their own tax advisors with respect to such calculations.

The above information is not intended to be, and should not be construed to be, legal or tax advice to any Unitholder. Unitholders should obtain independent advice regarding the income tax consequences of their investment.

For the Average Market Price, Discounted Price and Closing Price for each distribution payment, please see the table below.

RECORD DATE PAYMENT DATE DISTRIBUTION AVERAGE MARKET PRICE 1 5% DISCOUNTED UNIT PRICE CLOSING PRICE ON PAYMENT DATE
May 11, 2009 May 29, 2009    $0.15 $26.0546 $24.7519  $       28.00 
Feb. 9, 2009 Feb. 27, 2009 $0.15 $20.5394 $19.5124  $       20.00
Nov. 3, 2006 Nov. 30, 2006 $0.30 $29.1296 $27.6731  $       29.99
Aug. 4, 2006 Aug. 31, 2006 $0.30 $36.2508 $34.4383  $       33.80
May 8, 2006 May 31, 2006 $0.30 $33.4226 $31.7515  $       35.50
Feb. 6, 2006 Feb. 28, 2006 $1.00 $148.0839 $140.6797  $     155.14
Nov. 4, 2005 Nov. 30, 2005 $1.00 $112.5061 $106.8808  $     126.00
Aug. 3, 2005 Aug. 31, 2005 $0.50 $113.3442 $107.6770  $     127.50
May 5, 2005 May 31, 2005 $0.50 $78.5461 $74.6188  $       80.01
Feb. 9, 2005 Feb. 28, 2005 $0.50 $79.9817 $75.9826  $       84.25
Nov. 2, 2004 Nov. 30, 2004 $0.50 $59.5352 $56.5584  $       64.15
Aug. 3, 2004 Aug. 31, 2004 $0.50 $48.4781 $46.0542  $       49.40
May 6, 2004 May 31, 2004 $0.50 $42.7260 $40.5897  $       42.45
Feb. 2, 2004 Feb. 27, 2004 $0.50 $48.4107 $45.9902  $       51.20
Oct. 31,2003 Nov. 28, 2003 $0.50 $39.8862 $37.8919  $       41.50
Aug. 1, 2003 Aug. 29, 2003 $0.50 $37.7795 $35.8905  $       37.10
May 2, 2003 May 30, 2003 $0.50 $34.4012 $32.6811  $       34.30
Jan. 31, 2003 Feb. 28, 2003 $0.50 $35.7083 $33.9228  $       38.90
Nov. 4, 2002 Nov. 29, 2002 $0.50 $35.2842 $33.5199  $       37.10
July 31, 2002 Aug. 30, 2002 $0.50 $38.8194 $36.8784  $       38.85
May 6, 2002 May 31, 2002 $0.50 $41.1520 $39.0944  $       41.20
Jan. 31, 2002 Feb. 28, 2002 $0.50 $38.1927 $36.2831  $       37.00






1 For the period commencing on the second business day after the distribution record date and ending on the second business day immediately prior to the distribution payment date.   
Please note all figures provided on or after the May 3, 2006 record date reflect the 5:1 split of Canadian Oil Sands Trust Units effective May 4, 2006.






A   B   C   D   E   F   G   H   I   J   K   L   M   N   O   P   Q   R   S   T   U   V   W   X   Y   Z  
A
Alberta Oil Sand(s) Deposits

The four deposits, Athabasca, Peace River, Cold Lake and Wabasca, have total resource in place estimated at 1.7 trillion to 2.5 trillion barrels. The Athabasca Oil Sands deposit, Alberta's largest and most accessible source of bitumen, contains more than one trillion barrels of bitumen over an area encompassing more than 30,000 square kilometers.

 
top of page


B
Bitumen
The molasses-like substance that comprises up to 18 per cent of oil sands. Bitumen, in its raw state, is black, asphalt-like oil. It requires upgrading or blending to make it transportable by pipeline and usable by conventional refineries.
 
Bitumen cracking
A process that breaks large, complex hydrocarbon molecules into smaller, simpler compounds by means of heat.
 
top of page


C
Carbon dioxide (CO2)
A non-toxic gas produced from decaying materials, respiration of animal life, and combustion of organic matter, including fossil fuels; carbon dioxide is the most common greenhouse gas produced by human activities.
 
Cokers
Vessels in which bitumen is cracked into its fractions and from which coke is withdrawn to start the process of converting bitumen to upgraded crude oil.
 
Conventional oil
Petroleum found in liquid form, flowing naturally, or capable of being pumped without further processing or dilution.
 
Cyclofeeder
Specialized equipment that receives oil sand feed and turns it into a slurry form for transport to the pump box.
 
top of page


D
Debottleneck
An undertaking to systematically remove plant capacity limitations through modifications of existing facilities and/or addition of capital facilities.
 
Diesel cetane count
A quality specification important in the production of diesel fuels.
 
top of page


E
Extraction
The process of separating bitumen from oil sand.
 
top of page


F
Feedstocks
Raw material supplied to refinery, oil sands upgrader, or petrochemical plant.
 
Flue gas scrubber/desulphurizer
Equipment that removes sulphur dioxide and other emissions.
 
Fluid coking
A major part of the upgrading process whereby high temperatures in a coker break down the complex bitumen molecules, reject carbon and cause bitumen molecules to reformulate into lighter fractions that become the main ingredients in upgraded crude oil.
 
top of page


G
Greenhouse gases
Any of the various gases that contribute to the greenhouse effect.
 
top of page


L
LC-Finer hydroprocessor
A major upgrading unit that breaks down bitumen by adding hydrogen with the aid of a catalyst to produce gas oil.
 
Line-out
The process of optimizing an operational unit or facility to reach its design capacity.
 
Low-energy extraction
A process for extracting bitumen that uses about one-third of the energy of the traditional process, bringing significant cost and environmental benefits.
 
top of page


M
Middle distillates
A classification of refined petroleum products that includes kerosene, diesel, and jet fuel.
 
Mine train
Modular units for crushing and mixing the oil sands with warm water to facilitate the extraction of bitumen from the oil sands.
 
top of page


N
Naphtha
A refined petroleum product in the lighter classification that is often used to make gasoline.
 
Netback
Average realized selling price, after hedging, less operating costs and Crown royalties.
 
top of page


O
Oil sand(s)
A composition of sand, bitumen, mineral-rich clays and water.
 
Oil sand(s) lease
A long-term agreement with the provincial government that permits the leaseholder to extract bitumen, other metals and minerals contained in the oil sands in the specified lease area.
 
Ore grade
The percentage of bitumen by weight in the oil sands.
 
Overburden
Layer of rocky, clay-like material that lies under muskeg and above oil sands deposits.
 
top of page


S
Strip ratio
The ratio of waste (overburden material that covers mineable ore) to ore; used to define the quality of an oil sands ore body.
 
Sulphur dioxide (SO2)
A compound of sulphur and oxygen produced by burning sulphur.
 
Synbit
Typically, a synbit blend is a ~50/50 mix of bitumen and synthetic crude oil.
 
Syncrude Project
Canadian Oil Sands is a pure investment opportunity in light, sweet crude oil. Through our 36.74% interest in the Syncrude project, we offer a solid, robust production stream of fully upgraded crude oil, exposure to future crude oil prices, potential growth through high-quality oil sands leases and an attractive dividend.
 
Synthetic crude oil (SCO)
A high-quality product resulting from the mining, extraction and upgrading of bitumen.
 
top of page


T
Tailings
A combination of water, sand, silt, fine clay particles and residual hydrocarbon that is a by-product of removing bitumen from oil sand.
 
Tailings systems
Separation of water from sand and clay to enable incorporation of solids into reclamation landscapes and recycling of water back into the operations.
 
Tar sands
Oil sands are also referred to as tar sands. Oil sands are a naturally occurring combination of clay, sands, water and bitumen (a heavy, black viscous oil), whereas tar is a man-made substance.
 
Total volume to bitumen in place (TV/BIP)
The ratio of total ore plus overburden volume to total bitumen in place.
 
Turnaround
A unit shutdown essential for good maintenance of the mining, producing and upgrading facilities. A turnaround reduces production but does not usually halt it entirely as the various operating units are often duplicated.
 
top of page


U
Upgrader
A facility that upgrades bitumen (extra heavy oil) into synthetic crude oil.
 
Upgrading
The conversion of heavy bitumen into a lighter crude oil by increasing the ratio of hydrogen to carbon, either by removing carbon (coking) or adding hydrogen (hydroprocessing).
 
top of page


V
Vacuum Distillation Unit (VDU)
Capable of processing 285,000 barrels of bitumen a day, the VDU pulls streams of light and heavy-gas oil from hot bitumen feed delivered by the diluents recovery unit.
 
top of page