CALGARY, ALBERTA -- (Marketwire) -- 07/29/10 -- All financial figures are unaudited and in Canadian dollars unless otherwise noted.
Canadian Oil Sands Trust (TSX: COS.UN) ("Canadian Oil Sands", the "Trust" or "we") today announced second quarter 2010 cash from operating activities of $358 million, or $0.74 per Unit, compared with cash used in operating activities of $44 million, or $0.09 per Unit, for the same quarter in 2009. The increase was due to higher revenues during the second quarter of 2010 compared with 2009, partially offset by higher Crown royalties. Year-to-date cash from operating activities increased to $667 million for 2010 from $6 million in 2009. The increase was mainly due to higher revenues, partially offset by higher Crown royalties.
Net income for the second quarter of 2010 was $237 million, or $0.49 per Unit, compared with $46 million, or $0.10 per Unit, recorded in the second quarter of 2009. Net income was also higher in the first six months of 2010 than in the same period of 2009, totaling $404 million, or $0.83 per Unit, versus $89 million, or $0.18 per Unit. The increases in net income primarily reflect higher revenues partially offset by higher Crown royalties and foreign exchange losses.
The Trust has declared a distribution of $0.50 per Unit payable on August 31, 2010 to Unitholders of record on August 23, 2010. The $0.50 per Unit third quarter distribution reflects the Trust's objective of increasing tax pools to approximately $2 billion by the end of 2010, which may raise debt levels if achieved. As a result of this strategy, in 2010 the Trust expects distributions to exceed cash from operating activities less its capital expenditures. Beyond 2010, the Trust will look to avoid significant increases in net debt in advance of a larger sustaining capital program and future expansion plans. As we have done in the past, we will use cash from operating activities as a source of investment financing. Our anticipation of an increase in capital expenditures, therefore, indicates a reduction in distributions in order to reinvest in our business post-2010. Further information about Canadian Oil Sands' approach to distribution/dividend payments is further described under "Unitholder Distributions" in the Management's Discussion and Analysis ("MD&A") section of this report.
"Production at Syncrude was strong during the second quarter of 2010, averaging 324,000 barrels per day," said Marcel Coutu, President and Chief Executive Officer. "We were expecting these robust rates to continue into the third quarter, however, unplanned outages, particularly recent outages in the upgrader during July, have led us to reduce our 2010 annual production outlook by five million barrels for Syncrude to 110 million barrels. While these outages have all been remedied, the resulting production impact illustrates why the current focus on reliability is paramount and key to achieving design capacity of 350,000 barrels per day."
During the second quarter of 2010, Canadian Oil Sands' sales volumes averaged approximately 119,000 barrels per day compared with 76,000 barrels per day for the second quarter of 2009. For the first half of 2010, sales volumes averaged about 109,000 barrels per day compared to an average of 89,000 barrels per day during the comparable period in 2009. Sales volumes for 2010 reflect: the turnaround of the LC Finer and associated upgrading units, unplanned maintenance on a hydrotreater in the first quarter, and unplanned repairs and maintenance on two diluent recovery units in the second quarter. By comparison, sales volumes for 2009 were impacted by: the Coker 8-3 turnaround, circulation issues in Coker 8-1, reliability issues in mining and upgrading operations, and constrained bitumen production during the first quarter.
Canadian Oil Sands' operating costs were $336 million, or $31.18 per barrel, in the second quarter of 2010, compared to $345 million, or $50.23 per barrel, in the same quarter of 2009. The decrease in operating costs was primarily due to lower turnaround costs and stock-based compensation expenses in the second quarter of 2010, partially offset by additional mining activities to support higher production levels and additional unplanned repairs and maintenance. Lower per barrel operating costs also reflect the increased sales volumes in 2010.
The Syncrude Joint Venture's ("Syncrude") total recordable injury rate year-to-date for 2010 was 0.40 compared with a rate of 0.37 for the same period of 2009. Strong safety performance for Syncrude is a priority with efforts focused on achieving an injury-free workplace.
CANADIAN OIL SANDS TRUST
Highlights
(millions of Canadian dollars, Three Months Ended Six Months Ended
except per Trust Unit and per June 30 June 30
barrel volume amounts) 2010 2009 2010 2009
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Net Income $ 237 $ 46 $ 404 $ 89
Per Trust Unit - Basic $ 0.49 $ 0.10 $ 0.83 $ 0.18
Cash from (used in) Operating
Activities $ 358 $ (44) $ 667 $ 6
Per Trust Unit $ 0.74 $ (0.09) $ 1.38 $ 0.01
Unitholder Distributions $ 242 $ 73 $ 412 $ 145
Per Trust Unit $ 0.50 $ 0.15 $ 0.85 $ 0.30
Sales Volumes (1)
Total (MMbbls) 10.8 6.8 19.7 16.1
Daily average (bbls) 118,569 75,553 108,980 89,114
Operating Costs ($/bbl) $ 31.18 $ 50.23 $ 34.99 $ 43.66
Net Realized SCO Selling Price
($/bbl) $ 78.07 $ 67.92 $ 79.87 $ 60.69
West Texas Intermediate (average
$US/bbl) (2) $ 78.05 $ 59.79 $ 78.46 $ 51.68
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(1) The Trust's sales volumes differ from its production volumes due to
changes in inventory, which are primarily in-transit pipeline volumes,
and are after purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.
Outlook
The Trust has revised its outlook for 2010. Syncrude production is now estimated to total 110 million barrels (40.4 million barrels net to the Trust), with a production range of 108 million to 113 million barrels. We are estimating operating costs of approximately $37 per barrel, and capital expenditures totaling $544 million. Based on the Trust's assumption of WTI crude oil averaging U.S. $75 per barrel in 2010, together with the other assumptions outlined in our outlook, we are estimating cash from operating activities of $1,098 million, or $2.27 per Unit in 2010.
More information on the Trust's outlook is provided in the MD&A section of this report and the July 29, 2010 guidance document, which is available on our web site at www.cos-trust.com under "Investor".
Corporate Conversion
Canadian Oil Sands is continuing with its plans to convert to a corporate structure on or about December 31, 2010. The arrangement to convert has been approved by Canadian Oil Sands' Board, its Unitholders and the Court of Queen's Bench of Alberta. Following conversion to a corporate structure, Canadian Oil Sands expects its approach to dividend payments to be very similar to its management of distribution payments as a Trust. See the "Unitholder Distributions" section of the MD&A below for discussion on the dividend approach following conversion.
Syncrude Sustainability Report
Syncrude's 2008/2009 Sustainability Report has been posted on Syncrude's website at www.syncrude.ca. The report describes Syncrude's economic, environmental and social performance in 2008 and 2009; highlights include:
- Cumulative land reclaimed now totals 4,567 hectares
- Landscape construction began on a 52-hectare wetland, including the industry's first reclaimed fen
- Cumulative spending of $1.4 billion with Aboriginal-owned businesses since 1992
- Community investment of $7.5 million during 2008/09
- $6.3 billion in procurement of goods and services across Canada during 2008/09
A copy of the report or a summary of the highlights can be requested by email to info@syncrude.com.
Syncrude Waterfowl Incident
In February 2009, Syncrude Canada Ltd. ("Syncrude Canada") was charged under the Federal Migratory Birds Convention Act and the Alberta Environmental Protection and Enhancement Act for a 2008 waterfowl incident. On June 25, 2010, a provincial court judge ruled in favour of the federal and provincial Crowns on the case involving this waterfowl incident. A further hearing on the matter is scheduled for August 20, 2010. Syncrude continues to review the basis of the conviction before determining if any further action, including any potential appeal, will be made.
Syncrude has always acknowledged its moral obligations for this waterfowl incident and has implemented new waterfowl deterrent systems. Syncrude and its owners remain committed to improving their environmental performance. More information on the environmental issues is contained in the Annual Information Form of the Trust dated March 22, 2010.
Syncrude Appoints New President and CEO
Scott Sullivan has been appointed to the role of President and Chief Executive Officer of Syncrude Canada effective August 1, 2010. Mr. Sullivan succeeds Tom Katinas, who was assigned to the position in May 2007 for a three-year term. Both are employees of ExxonMobil Corp. ("ExxonMobil") seconded to Syncrude under the Management Services Agreement ("MSA") between Syncrude and Imperial Oil Resources Ltd.
Mr. Sullivan brings extensive operating experience to Syncrude, having worked at a number of ExxonMobil refining facilities around the world. In his most recent assignment, he held the position of deputy general manager of the Fujian Refining and Petrochemical Co., a major refining and petrochemical joint venture among ExxonMobil, Sinopec, Saudi Aramco and the Chinese province of Fujian.
This press release contains forward-looking statements, which are qualified by the advisory in the MD&A section of this report.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis ("MD&A") was prepared as of July 29, 2010 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust") for the three and six months ended June 30, 2010 and June 30, 2009, the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2009 and the Trust's Annual Information Form ("AIF") dated March 22, 2010. Additional information on the Trust, including its AIF, is available on SEDAR at www.sedar.com or on the Trust's website at www.cos-trust.com. The Trust's financial results have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") and are reported in Canadian dollars, unless stated otherwise.
ADVISORY- in the interest of providing the Trust's Unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future production and cost estimates, plans and operations, certain statements throughout this MD&A and the related press release contain "forward-looking statements" under applicable securities law. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to the cost estimate for the Sulphur Emissions Reduction ("SER") project and the expectation that the SER project will significantly reduce total sulphur dioxide and other emissions; the completion date for the SER project; future distributions and any increase or decrease from current payment amounts; the Trust's plans with regard to its net debt level by the end of 2010 and beyond; the expected impact on Syncrude Canada Ltd. ("Syncrude Canada") of being convicted under both federal and provincial charges related to the waterfowl incident; plans regarding crude oil hedges and currency hedges in the future; the expected production, revenues and operating costs for 2010; the expected level of sustaining capital for the next few years and longer term; the expectations regarding capital expenditures and operating costs; the plans and expected impact of converting to a corporate structure; the plans and expected impact of adopting International Financial Reporting Standards including, without limitation, its impact on the Trust's accounting policies, financial statement disclosure, information technology requirements, data systems, internal controls and business activities, and the results that the Syncrude Joint Venture ("Syncrude") reports to the Trust; the expected impact of any current and future environmental legislation, including without limitation, regulations relating to tailings; the expected funding increases in 2010 for the Trust's share of Syncrude's pension and reclamation funding; the expected realized selling price, which includes the anticipated differential to WTI to be received in 2010 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; the level of energy consumption in 2010 and beyond; capital expenditures for 2010; the level of natural gas consumption in 2010 and beyond; the expected price for crude oil and natural gas in 2010, and the anticipated impact that certain factors such as natural gas and oil prices, foreign exchange and operating costs have on the Trust's cash from operating activities and net income.
You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur.
Although the Trust believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A include, but are not limited to: the impacts of regulatory changes especially as such relate to royalties, taxation, and environmental charges; the impact of technology on operations and processes and how new complex technology may not perform as expected; skilled labour shortages and the productivity achieved from labour in the Fort McMurray area; the supply and demand metrics for oil and natural gas; the impact that pipeline capacity and refinery demand have on prices for our products; the unanimous joint venture owner approval for major expansions and changes in product types; the variances of stock market activities generally; global economic environment/volatility of markets; normal risks associated with litigation, general economic, business and market conditions; the impact of any decisions rendered by a court in relation to litigation including without limitation: the decision relating to the trial against Syncrude Canada regarding the 2008 waterfowl incident, regulatory change, the impact of Syncrude being unable to meet the conditions of its approval for its tailings management plan under Directive 074, and such other risks and uncertainties described from time to time in the Trust's Annual Information Form dated March 22, 2010 and in the reports and filings made with securities regulatory authorities by the Trust as well as those assumptions outlined in the Trust's guidance document being correct. You are cautioned that the foregoing list of important factors is not exhaustive. No assurance can be given that the final legislation implementing the federal tax changes regarding income trusts will not be further changed in a manner which adversely affects the Trust and its Unitholders. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and unless required by law, the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.
REVIEW OF SYNCRUDE OPERATIONS
During the second quarter of 2010, crude oil production from the Syncrude Joint Venture ("Syncrude") totaled 29.5 million barrels, or 324,000 barrels per day, compared with 18.8 million barrels, or 206,000 barrels per day, during the same period of 2009. Net to the Trust, production totaled 10.8 million barrels in the second quarter of 2010 compared with 6.9 million barrels in the second quarter of 2009, based on our 36.74 per cent working interest.
Production volumes in the second quarter of 2010 were stronger than the same period in the prior year. While the second quarter of 2010 was impacted by unplanned repairs and maintenance on two diluent recovery units, the second quarter of 2009 was impacted by a scheduled turnaround of Coker 8-3 and related units, circulation issues with Coker 8-1 and operational reliability issues.
Year-to-date, Syncrude produced 53.7 million barrels in 2010, or about 297,000 barrels per day, compared with 43.4 million barrels, or about 240,000 barrels per day in 2009. Production in 2010 reflects the first quarter turnaround of the LC Finer and associated upgrading units and unplanned repairs and maintenance on a hydrotreater and two diluent recovery units. Production volumes in the first half of 2009 were impacted by a coker turnaround, coker circulation and operational reliability issues as well as first quarter 2009 bitumen production constraints.
Canadian Oil Sands' operating costs were $336 million, or $31.18 per barrel, in the second quarter of 2010, compared to $345 million, or $50.23 per barrel, in the same quarter of 2009 (see the "Operating Costs" section of this MD&A for further discussion).
Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. Under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of operational and mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's facilities is approximately 350,000 barrels per day on average and is referred to as "barrels per calendar day". All references to Syncrudes' production capacity in this report refer to barrels per calendar day, unless stated otherwise. The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes.
SUMMARY OF QUARTERLY RESULTS
2010 2009
($ millions,
except per Trust
Unit and volume
amounts) Q2 Q1 Q4 Q3 Q2 Q1
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Revenues (1) $ 842 $ 734 $ 863 $ 773 $ 467 $ 512
Net income $ 237 $ 167 $ 96 $ 247 $ 46 $ 43
Per Trust Unit,
Basic &
Diluted $ 0.49 $ 0.35 $ 0.20 $ 0.51 $ 0.10 $ 0.09
Cash from
operating
activities $ 358 $ 309 $ 328 $ 213 $ (44) $ 50
Per Trust
Unit (2) $ 0.74 $ 0.64 $ 0.68 $ 0.44 $ (0.09) $ 0.10
Unitholder
distributions $ 242 $ 170 $ 169 $ 121 $ 73 $ 72
Per Trust Unit $ 0.50 $ 0.35 $ 0.35 $ 0.25 $ 0.15 $ 0.15
Daily average
sales volumes
(bbls) (3) 118,569 99,286 119,287 114,544 75,553 102,825
Net realized SCO
selling price
($/bbl) (4) $ 78.07 $ 82.06 $ 78.67 $ 73.31 $ 67.92 $ 55.32
Operating costs
($/bbl) (5) $ 31.18 $ 39.59 $ 30.18 $ 27.80 $ 50.23 $ 38.78
Purchased
natural gas
price ($/GJ) $ 3.68 $ 4.95 $ 4.33 $ 2.90 $ 3.09 $ 4.96
West Texas
Intermediate
(avg.
US$/bbl) (6) $ 78.05 $ 78.88 $ 76.13 $ 68.24 $ 59.79 $ 43.31
Foreign exchange
rates
(US$/Cdn$):
Average $ 0.97 $ 0.96 $ 0.95 $ 0.91 $ 0.86 $ 0.80
Quarter-end $ 0.94 $ 0.98 $ 0.96 $ 0.93 $ 0.86 $ 0.79
2008
($ millions, except per Trust Unit and volume
amounts) Q4 Q3
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Revenues (1) $ 704 $ 1,381
Net income $ 124 $ 604
Per Trust Unit, Basic & Diluted $ 0.26 $ 1.25
Cash from operating activities $ 466 $ 921
Per Trust Unit (2) $ 0.97 $ 1.91
Unitholder distributions $ 361 $ 602
Per Trust Unit $ 0.75 $ 1.25
Daily average sales volumes (bbls) (3) 110,197 116,656
Net realized SCO selling price ($/bbl) (4) $ 69.40 $ 127.55
Operating costs ($/bbl) (5) $ 32.10 $ 32.15
Purchased natural gas price ($/GJ) $ 6.41 $ 7.86
West Texas Intermediate (avg. US$/bbl) (6) $ 59.08 $ 118.22
Foreign exchange rates (US$/Cdn$):
Average $ 0.83 $ 0.96
Quarter-end $ 0.82 $ 0.94
(1) Revenues after crude oil purchases and transportation expense.
(2) Cash from operating activities per Trust Unit is a non-GAAP measure that
is derived from cash from operating activities reported on the Trust's
Consolidated Statements of Cash Flows divided by the weighted-average
number of Trust Units outstanding in the period, as used in the Trust's
net income per Unit calculations.
(3) Daily average sales volumes after crude oil purchases.
(4) Net realized SCO selling price after foreign currency hedging.
(5) Derived from operating costs, as reported on the Trust's Consolidated
Statements of Income and Comprehensive Income, divided by the sales
volumes during the period.
(6) Pricing obtained from Bloomberg.
During the last eight quarters, the following items have had a significant impact on the Trust's financial results:
- Fluctuations in U.S. dollar WTI oil prices have impacted the Trust's revenues, Crown royalties, net income and cash from operating activities;
- Net income was reduced in the fourth quarter of 2009 by $148 million due to an impairment charge and goodwill write-down on the Arctic natural gas assets;
- Planned and unplanned maintenance activities as well as turnarounds have impacted quarterly production volumes, sales revenue and operating costs;
- U.S. to Canadian dollar exchange rate fluctuations have resulted in foreign exchange gains and losses on the revaluation of U.S. dollar denominated debt and have impacted commodity pricing;
- Transition to a new Crown royalty framework effective January 1, 2009; and
- Tax rate reductions substantively enacted in the first quarter of 2009 resulted in additional future income tax recoveries of $63 million.
Quarterly variances in net income and cash from operating activities are caused mainly by fluctuations in crude oil prices, production and sales volumes, operating costs and natural gas prices. Net income also is impacted by unrealized foreign exchange gains and losses, impairment charges and future income tax amounts. While the supply/demand balance for crude oil affects selling prices, the impact of this equation is difficult to predict and quantify and has not displayed significant seasonality. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is influenced by weather conditions and North American natural gas inventory levels.
Syncrude production levels may not display seasonal patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages may occur. Maintenance and turnaround activities impact both production volumes and operating costs. In addition, a large proportion of operating costs are fixed and, as such, per barrel operating costs are variable to production volumes. The costs associated with these activities are expensed in the period they are incurred, which can lead to significant increases in operating costs. The effect on per barrel operating costs of these maintenance activities is amplified as the facility is generally producing at reduced rates when maintenance work is occurring.
REVIEW OF FINANCIAL RESULTS
In the second quarter of 2010, the Trust reported net income of $237 million, or $0.49 per Unit, compared with $46 million, or $0.10 per Unit, recorded in the second quarter of 2009. The increase in net income reflects higher revenues partially offset by higher Crown royalties. In addition, the second quarter of 2010 included foreign exchange losses whereas the second quarter of 2009 included foreign exchange gains.
Net income for the first six months of 2010 totaled $404 million, or $0.83 per Unit compared with net income of $89 million, or $0.18 per Unit, recorded in 2009. The increase reflects higher revenues partially offset by higher Crown royalties. In addition, 2010 included foreign exchange losses whereas 2009 included foreign exchange gains.
Revenues after crude oil purchases and transportation costs totaled $842 million in the second quarter of 2010 versus $467 million in the second quarter of 2009. On a year-to-date basis, revenues after crude oil purchases and transportation costs totaled $1,576 million in 2010 versus $979 million for the first half of 2009. The increases in revenues were due mainly to higher crude oil prices and higher production volumes in 2010 (see the "Revenues after Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).
Cash from operating activities was $358 million, or $0.74 per Unit, for the second quarter of 2010. This compares with cash used in operating activities of $44 million, or $0.09 per Unit, for the second quarter of 2009. The increase was due to higher revenues during the second quarter of 2010 than in the same period of 2009, partially offset by higher Crown royalties. Year-to-date cash from operating activities increased to $667 million for 2010 from $6 million in 2009. The increase was due to higher revenues partially offset by higher Crown royalties. In addition, non-cash working capital decreased during the first half of 2010 versus an increase during the first half of 2009.
Non-cash working capital reduced cash from operating activities by $14 million in the second quarter of 2010, primarily as a result of lower accounts payable at June 30, 2010 relative to March 31, 2010. By comparison, non-cash working capital decreased cash from operating activities by $67 million in the second quarter of 2009, primarily as a result of higher accounts receivable, reflecting higher oil prices, as well as higher inventory levels and lower accounts payable at June 30, 2009 relative to March 31, 2009.
In the first six months of 2010, non-cash working capital increased cash from operating activities by $90 million, primarily as a result of higher accounts payable and lower accounts receivable at June 30, 2010 relative to December 31, 2009. In the same period of 2009, non-cash working capital decreased cash from operating activities by $86 million, primarily as a result of higher accounts receivable and higher inventory levels at June 30, 2009 relative to December 31, 2008.
Non-cash working capital and changes therein can vary significantly on a period-by-period basis as a result of the timing and settlements of accounts receivable and accounts payable balances, and are impacted by a number of factors including changes in: revenue, operating expenses, Crown royalties, capital expenditures, inventory fluctuations, and the timing of payments.
Non-GAAP Financial Measures
In this MD&A we refer to financial measures that do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). These non-GAAP financial measures include cash from operating activities on a per Unit basis, net debt, total capitalization, net debt to total capitalization, and certain per barrel measures. Cash from operating activities per Unit is calculated as cash from operating activities as reported on the Trust's Consolidated Statement of Cash Flows divided by the weighted-average number of Units outstanding in the period. This measure is an indicator of the Trust's capacity to fund capital expenditures, distributions, and other investing activities without incremental financing. In addition, the Trust refers to various per barrel figures, such as net realized selling prices, operating costs and Crown royalties, which also are considered non-GAAP measures. We derive per barrel figures by dividing the relevant revenue or cost figure by our sales volumes, which are after purchased crude oil volumes in a period.
Non-GAAP financial measures provide additional information that we believe is meaningful regarding the Trust's operational performance, its liquidity and its capacity to fund distributions, capital expenditures and other investing activities. Users are cautioned that non-GAAP financial measures presented by the Trust may not be comparable with measures provided by other entities.
Net Income per Barrel
Three Months Ended Six Months Ended
June 30 June 30
($ per bbl) (1) 2010 2009 Variance 2010 2009 Variance
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Revenues after crude
oil purchases and
transportation expense 78.12 67.92 10.20 79.92 60.69 19.23
Operating costs (31.18) (50.23) 19.05 (34.99) (43.66) 8.67
Crown royalties (7.88) (3.33) (4.55) (8.27) (1.69) (6.58)
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39.06 14.36 24.70 36.66 15.34 21.32
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Non-production costs (1.78) (5.65) 3.87 (2.80) (4.46) 1.66
Administration and
insurance (0.95) (1.15) 0.20 (1.04) (0.96) (0.08)
Interest, net (2.02) (3.64) 1.62 (2.44) (2.78) 0.34
Depreciation,
depletion and
accretion (8.74) (11.82) 3.08 (9.99) (11.60) 1.61
Loss on disposal of
assets (0.44) - (0.44) (0.24) - (0.24)
Foreign exchange gain
(loss) (3.59) 11.22 (14.81) (0.28) 2.96 (3.24)
Future income tax
recovery and other 0.47 3.37 (2.90) 0.60 6.99 (6.39)
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(17.05) (7.67) (9.38) (16.19) (9.85) (6.34)
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Net income per barrel 22.01 6.69 15.32 20.47 5.49 14.98
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Sales volumes (MMbbls)
(2) 10.8 6.8 4.0 19.7 16.1 3.6
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(1) Unless otherwise specified, net income and other per barrel measures in
this MD&A have been derived by dividing the relevant revenue or cost
item by the sales volumes in the period.
(2) Sales volumes, after purchased crude oil volumes.
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Revenues after Crude Oil Purchases and Transportation Expense
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2010 2009 Variance 2010 2009 Variance
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Sales revenue (1) $ 879 $ 525 $ 354 $ 1,777 $ 1,073 $ 704
Crude oil purchases (29) (52) 23 (188) (81) (107)
Transportation expense (9) (7) (2) (15) (15) -
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841 466 375 1,574 977 597
Currency hedging gains
(1) 1 1 - 2 2 -
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$ 842 $ 467 $ 375 $ 1,576 $ 979 $ 597
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Sales volumes (MMbbls)
(2) 10.8 6.8 4.0 19.7 16.1 3.6
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(1) The sum of sales revenue and currency hedging gains equals Revenues on
the Trust's Consolidated Statements of Income and Comprehensive Income.
Sales revenue includes revenue from the sale of purchased crude oil and
sulphur revenue.
(2) Sales volumes, after purchased crude oil volumes.
($ per barrel)
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Realized SCO selling
price before
hedging (3) $ 77.98 $ 67.79 $ 10.19 $ 79.78 $ 60.58 $ 19.20
Currency hedging
gains 0.09 0.13 (0.04) 0.09 0.11 (0.02)
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Net realized SCO
selling price $ 78.07 $ 67.92 $ 10.15 $ 79.87 $ 60.69 $ 19.18
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(3) SCO sales revenue after crude oil purchases and transportation expense
divided by sales volumes, after purchased crude oil volumes.
The increase in sales revenue after crude oil purchases and transportation expense in the second quarter of 2010 versus 2009 primarily reflects a higher realized selling price for our synthetic crude oil ("SCO") combined with higher sales volumes. During the second quarter of 2010, WTI averaged U.S. $78 per barrel compared to U.S. $60 per barrel in the second quarter of 2009. The impact of the higher U.S. dollar WTI price in the second quarter of 2010 was offset somewhat by a stronger Canadian dollar, which averaged $0.97 U.S./Cdn for the second quarter of 2010 versus $0.86 U.S./Cdn for the second quarter of 2009. Year-to-date, WTI averaged U.S. $78 per barrel in 2010 versus U.S. $52 per barrel in 2009 while the Canadian dollar averaged $0.97 U.S./Cdn in 2010 versus $0.83 U.S./Cdn in 2009.
The Trust's SCO price is also affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the second quarter of 2010, the Trust realized a weighted-average SCO discount of $2.04 per barrel versus a $2.59 per barrel discount for the same period of 2009. The differential is dependent upon the supply and demand for SCO and, accordingly, can change quickly depending upon the short-term supply and demand dynamics in the market and pipeline availability for transporting crude oil.
The Trust's second quarter sales volumes averaged 119,000 barrels per day and 76,000 barrels per day in 2010 and 2009, respectively. Year-to-date sales volumes averaged 109,000 barrels per day in 2010 versus an average of 89,000 barrels per day for the first half of 2009. Sales volumes for 2010 reflect the turnaround of the LC Finer and associated upgrading units, unplanned maintenance on a hydrotreater during the first quarter and unplanned repairs and maintenance on two diluent recovery units during the second quarter. By comparison, sale volumes for 2009 were impacted by the Coker 8-3 turnaround, circulation issues in Coker 8-1, reliability issues in mining and upgrading operations, and constrained bitumen production during the first quarter.
The Trust purchases crude oil from third parties to fulfill sales commitments with customers when there are shortfalls in Syncrude's production and to facilitate certain transportation and tankage arrangements and operations. Sales revenue includes the sale of purchased crude oil. Increased crude oil purchases in 2010 reflect additional activities to support unanticipated production shortfalls due to the advancement of the LC Finer turnaround and incremental purchases associated with tankage arrangements, as well as higher crude oil prices as compared to 2009.
Operating Costs
The following table breaks down operating costs into their major components and shows bitumen costs both on a per barrel of bitumen and a per barrel of SCO produced basis. The information allocates costs to bitumen production and upgrading based on deductibility for bitumen royalty purposes. The Syncrude Royalty Amending Agreement provides for allowed bitumen costs, before internal fuel allocation, to be 64.5 per cent of Syncrude total operating costs until December 31, 2010.
Three Months Ended June 30
2010 2009
----------------------------------------------------------------------------
$/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO
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Bitumen production $ 17.60 $ 19.66 $ 26.97 $ 31.95
Internal fuel allocation (2) 2.31 2.58 2.64 3.13
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Total produced bitumen costs 19.91 22.24 29.61 35.08
Upgrading costs (1) 11.62 16.65
Less: Internal fuel allocation to
bitumen (2) (2.58) (3.13)
Bitumen purchases - 0.95
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Total Syncrude operating costs 31.28 49.55
Canadian Oil Sands' adjustments (3) (0.10) 0.68
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Total operating costs 31.18 50.23
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(thousands of barrels per day) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude production volumes (4) 362 324 245 206
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----------------------------------------------------------------------------
Six Months Ended June 30
2010 2009
----------------------------------------------------------------------------
$/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Bitumen production $ 19.76 $ 23.21 $ 23.74 $ 28.73
Internal fuel allocation (2) 2.77 3.26 2.45 2.97
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Total produced bitumen costs 22.53 26.47 26.19 31.70
Upgrading costs (1) 12.82 15.46
Less: Internal fuel allocation to
bitumen (2) (3.26) (2.97)
Bitumen purchases - 0.57
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Total Syncrude operating costs 36.03 44.76
Canadian Oil Sands' adjustments (3) (1.04) (1.10)
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Total operating costs 34.99 43.66
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----------------------------------------------------------------------------
(thousands of barrels per day) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude production volumes (4) 349 297 290 240
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(1) Upgrading costs include the production and ongoing maintenance costs
associated with processing and upgrading of bitumen to SCO. It also
includes the costs of major upgrading equipment turnarounds and catalyst
replacement, all of which are expensed as incurred.
(2) Natural gas prices averaged $3.68 per GJ and $4.31 per GJ for the three
and six months ended June 30, 2010, respectively and $3.09 per GJ and
$4.31 per GJ for the three and six months ended June 30, 2009,
respectively.
(3) Canadian Oil Sands' adjustments mainly pertain to actual reclamation
costs, Syncrude-related pension costs, as well as the inventory impact
of moving from production to sales as Syncrude reports per barrel costs
based on production volumes and the Trust reports based on sales
volumes.
(4) Syncrude SCO production volumes include the impact of processed
purchased bitumen volumes.
Three Months Ended Six Months Ended
June 30 June 30
($/bbl of SCO) 2010 2009 2010 2009
----------------------------------------------------------------------------
Production costs 27.67 46.30 $ 30.71 $ 38.75
Purchased energy 3.51 3.93 4.28 4.91
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Total operating costs 31.18 50.23 $ 34.99 $ 43.66
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----------------------------------------------------------------------------
(GJs/bbl of SCO)
----------------------------------------------------------------------------
Purchased energy consumption 0.95 1.27 0.99 1.14
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In the second quarter of 2010, operating costs were $336 million, averaging $31.18 per barrel, compared to $345 million, or $50.23 per barrel in the second quarter of 2009. Year-to-date operating costs were $690 million in 2010, averaging $34.99 per barrel, compared to $704 million, or $43.66 per barrel, in 2009.
The decrease in year-over-year operating costs was primarily due to the following:
- Lower turnaround costs in 2010; while the first quarter of 2010 reflected the turnaround of the LC Finer and related upgrading units, the second quarter of 2009 reflected the comprehensive and extended turnaround of Coker 8-3 and related units; and,
- Lower stock-based compensation expense in 2010; stock-based compensation expense for 2010 reflected a decrease in the fair market value of the Trust's Units and other Syncrude owners' public shares whereas 2009 reflected an increase.
The decrease in costs was partially offset by:
- Additional mining activities in 2010 relative to 2009 to support higher production levels; and,
- Additional unplanned repairs and maintenance activities in 2010 on two diluent recovery units and a hydrotreater.
Non-Production Costs
Non-production costs totaled $19 million and $39 million in the second quarters of 2010 and 2009, respectively. Year-to-date non-production costs totaled $55 million for 2010 and $72 million for 2009. The decrease in non-production costs was primarily due to the 2010 capitalization of costs relating to mine train replacements and relocations, and tailings initiatives. In 2009, costs relating to these activities were expensed as non-production costs.
Non-production costs consist primarily of development expenditures relating to capital programs, such as pre-feasibility engineering, technical and support services, research and development, and regulatory and stakeholder consultation expenditures. Non-production costs can vary on a periodic basis depending on the number of projects underway and the status of the projects.
Crown Royalties
In the second quarter of 2010, Crown royalties increased to $85 million, or $7.88 per barrel, from $23 million, or $3.33 per barrel, in the comparable 2009 quarter. Year-to-date Crown royalties increased to $163 million, or $8.27 per barrel, in 2010 from $27 million, or $1.69 per barrel in 2009. Crown royalties in the first half of 2009 were recorded at the minimum one per cent of deemed bitumen revenues, while Crown royalties in 2010 were accrued at 25 per cent of net revenues and reflect higher deemed bitumen revenues. Crown royalties in 2010 also reflect the additional royalty expense under the transition agreement with the Alberta government, which did not apply until January 1, 2010.
The Syncrude Amended Royalty Agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil price adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude's bitumen and the reference price of bitumen. The Alberta government, Syncrude, and the Syncrude owners are in discussions to determine the appropriate adjustments for quality, transportation and handling. For estimating and paying royalties, Syncrude has used a bitumen value based on Syncrude and its owners' interpretation of the Syncrude Amended Royalty Agreement, and their estimates of the appropriate quality, transportation and handling adjustments. These adjustments are different than those provided under the Alberta government's generic bitumen valuation methodology. Canadian Oil Sands' share of the royalties recognized for the period from January 1, 2009 to June 30, 2010 are estimated to be approximately $75 million less than the amount calculated under the generic bitumen valuation methodology. The Syncrude owners and the Alberta government continue to discuss the basis for these reasonable adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter.
Interest Expense, Net
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Interest expense on long-term debt $ 22 $ 25 $ 48 $ 46
Interest income and other - - - (1)
----------------------------------------------------------------------------
Interest expense, net $ 22 $ 25 $ 48 $ 45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest expense during the second quarter of 2010 was lower than in the second quarter of 2009, reflecting the 2009 refinancing of long-term debt that matured subsequently in that year. On a year-to-date basis, 2010 interest expense was higher than in the same period of 2009 due to consent solicitation fees recorded during the first quarter of 2010 for the Trust's corporate conversion plans.
Depreciation, Depletion and Accretion Expense
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Depreciation and depletion expense $ 87 $ 78 $ 184 $ 180
Accretion expense 7 3 13 7
----------------------------------------------------------------------------
$ 94 $ 81 $ 197 $ 187
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----------------------------------------------------------------------------
Oil sands assets are depreciated and depleted over their estimated remaining lives, which are reviewed by management on a regular basis. During the first quarter of 2010, management determined that the usage of certain tangible equipment would be most accurately represented by a straight-line calculation on an ongoing basis. Depreciation and depletion of the oil sands assets is now estimated based on a blend of both a unit-of-production and straight-line basis. Depreciation, depletion and accretion expense increased from 2009 to 2010 due to the effect of the change in accounting estimate and lower 2009 production.
The effect of this change in estimate for the three and six months ended June 30, 2010 is that approximately $35 million and $38 million less depreciation and depletion expense, respectively, was recorded using the new estimated remaining lives than would have been recorded using the previous estimates. Beyond 2010, it is not practical to calculate the effect of this change in estimate due to the long-life nature of the assets and the amounts and timing of estimated future development costs.
Foreign Exchange (Gain) Loss
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Foreign exchange (gain) loss-long
term debt $ 50 $ (83) $ 16 $ (52)
Foreign exchange (gain) loss-other (12) 6 (11) 4
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Total foreign exchange (gain) loss $ 38 $ (77) $ 5 $ (48)
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----------------------------------------------------------------------------
Foreign exchange ("FX") gains/losses are primarily the result of revaluations of our U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates.
The FX losses on long-term debt in 2010 were due to a weakening in the value of the Canadian dollar relative to the U.S. dollar to $0.94 U.S./Cdn at June 30, 2010 from $0.98 U.S./Cdn at March 31, 2010 and $0.96 U.S./Cdn at December 31, 2009. The FX gains in 2009 were due to a strengthening of the Canadian dollar relative to the U.S. dollar to $0.86 U.S./Cdn at June 30, 2009 from $0.79 U.S./Cdn at March 31, 2009 and $0.82 U.S./Cdn at December 31, 2008.
Future Income Tax and Other
In the second quarter of 2010, a future income tax recovery of $5 million was recorded versus a recovery of $23 million in the same period of 2009. On a year-to-date basis, a future income tax recovery of $12 million was recorded in 2010 versus a recovery of $113 million in 2009 as a result of decreases in temporary differences between accounting and tax values of Canadian Oil Sands' assets and liabilities in both years. In addition to the future income tax amounts recorded on changes in temporary differences, a future income tax recovery of $63 million was recorded during the first quarter of 2009 on the substantive enactment of tax rate reductions.
CAPITAL EXPENDITURES
In the second quarter of 2010, capital expenditures totaled $114 million compared with expenditures of $139 million in the same quarter of 2009. The Syncrude Emissions Reduction ("SER") project accounted for $27 million and $32 million of the capital spent in the second quarters of 2010 and 2009, respectively, with the remaining second quarter expenditures primarily related to other sustaining capital activities including: mine train replacements and relocations, construction of tailings facilities, pipe replacements and extensions, and other infrastructure projects. Capital expenditures on a per barrel basis were $10.57 and $20.07 in the second quarters of 2010 and 2009, respectively. Capital expenditures on a per barrel basis are affected by the Trust's sales volumes, which were higher in the second quarter of 2010 relative to the second quarter of 2009.
Year-to-date capital expenditures totaled $206 million in 2010 versus $223 million in 2009. The SER project accounted for $54 million and $57 million of the capital spent in 2010 and 2009, respectively, with the remaining expenditures relating to other sustaining capital activities, including mine train replacements and relocations, construction of tailings facilities, pipe replacements and extensions and other infrastructure projects. Capital expenditures on a per barrel basis were approximately $10.46 and $13.78 on a year-to-date basis in 2010 and 2009, respectively. Capital expenditures on a per barrel basis are affected by the Trust's sales volumes, which were higher in 2010 relative to 2009.
Canadian Oil Sands' expansion-related capital expenditures have been relatively low in recent years and capital costs during 2010 and 2009 were mainly related to sustaining capital. Expansion-related capital expenditures are costs incurred to grow the productive capacity of the operation while sustaining capital expenditures are effectively all other capital expenditures. Capital expenditures may fluctuate considerably year-to-year due to the timing of expansions, equipment replacement and other factors.
Syncrude is undertaking the SER project, which commenced in 2006, to retrofit technology into the operation of Syncrude's original two cokers by the end of 2011 in order to reduce total sulphur dioxide and other emissions. The estimate of the total cost of the SER project remains at $1.6 billion ($590 million net to the Trust) and the Trust's share of SER expenditures to date is approximately $350 million.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
Contractual obligations are summarized in the Trust's 2009 annual MD&A and include future cash payments that the Trust is required to make under existing contractual arrangements that it has entered into directly or as a 36.74 per cent owner in Syncrude. During April 2010, an actuarial valuation of the pension obligation as at December 31, 2009 was completed. This resulted in additional funding requirements over the next 24 years of approximately $265 million, with the majority of the funding requirements due within the next five years. With the exception of the Trust's share of new Syncrude capital commitments of approximately $20 million related to purchases of new mining equipment, there have been no other significant new contractual obligations or commitments from our 2009 year-end disclosure.
UNITHOLDER DISTRIBUTIONS
Three Months Ended Six Months Ended
June 30 June 30
----------------------------------------------------------------------------
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash from operating activities $ 358 $ (44) $ 667 $ 6
Net income $ 237 $ 46 $ 404 $ 89
Unitholder distributions $ 242 $ 73 $ 412 $ 145
----------------------------------------------------------------------------
Excess (shortfall) of cash from
operating activities over
Unitholder distributions $ 116 $ (117) $ 255 $ (139)
Excess (shortfall) of net income
over Unitholder distributions $ (5) $ (27) $ (8) $ (56)
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During the first half of 2010, cash from operating activities exceeded Unitholder distributions by $255 million. Cash from operating activities was sufficient to fund the Trust's capital expenditures, reclamation trust fund contributions, and distributions.
Unitholder distributions exceeded net income by $8 million and $56 million in the first half of 2010 and 2009, respectively, primarily as a result of non-cash items included in the calculation of net income such as depletion, depreciation and accretion ("DD&A") and unrealized foreign exchange gains or losses. These non-cash items do not affect the Trust's cash from operating activities or ability to pay distributions over the near term.
The Trust uses debt and equity financing to the extent that cash from operating activities and existing cash balances are insufficient to fund capital expenditures, reclamation trust contributions, debt repayments, acquisitions, distributions and working capital changes from financing and investing activities. For further discussion, see the "Liquidity and Capital Resources" section of this MD&A.
On July 29, 2010 the Trust declared a quarterly distribution of $0.50 per Unit in respect of the third quarter of 2010 for a total distribution of approximately $242 million. The distribution will be paid on August 31, 2010 to Unitholders of record on August 23, 2010. Our quarterly distribution declarations consider the current and expected economic conditions, financing capacity for Canadian Oil Sands' capital requirements and the objective of maintaining an investment grade credit rating.
The $0.50 per Unit third quarter distribution reflects the Trust's objective of increasing tax pools to approximately $2 billion by the end of 2010, which may raise debt levels if achieved. As a result of this strategy, in 2010 the Trust expects distributions to exceed cash from operating activities less its capital expenditures.
Beyond 2010, the Trust will look to avoid significant increases in net debt in advance of a larger sustaining capital program and future expansion plans. As we have done in the past, we will use cash from operating activities as a source of investment financing. Our anticipation of an increase in capital expenditures, therefore, indicates a reduction in distributions in order to reinvest in our business post-2010.
Following the conversion to a corporate structure on or about December 31, 2010, Canadian Oil Sands expects its approach to dividend payments to be very similar to its management of distributions as a Trust. This means dividends will be determined on a quarterly basis in the context of current and expected crude oil prices, economic conditions, Syncrude's operating performance and financing capacity for operating and investing obligations. These factors can change significantly from period to period, causing fluctuations in cash from operating activities and net income. We will strive to reduce the impact of these fluctuations on dividends by taking a longer-term view of the factors influencing our business, and we may distribute more or less in a period than is generated in cash from operating activities or net income. However, the variable nature of cash from operating activities means Canadian Oil Sands' dividend amounts also are likely to be variable, and any expectations regarding the stability or sustainability of distributions/dividends are unwarranted and should not be implied.
In determining the Trust's distributions, Canadian Oil Sands also considers funding for its significant operating obligations, which are included in cash from operating activities. Such obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to $67 million and $42 million in the first half of 2010 and 2009, respectively. We anticipate these funding requirements for 2010 will rise to approximately $120 million from $69 million in 2009. The increase is due to additional reclamation activities, as well as the pension actuarial valuation completed in April 2010.
Debt covenants do not specifically limit the Trust's ability to pay distributions and are not expected to influence the Trust's liquidity in the foreseeable future. Aside from covenants relating to restrictions on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business, the most restrictive financial covenant limits total debt-to-total capitalization at less than 55 per cent. With a net debt-to-total capitalization of approximately 20 per cent at June 30, 2010, a significant increase in debt or decrease in equity would be required before covenants restrict the Trust's distributions or financial flexibility.
LIQUIDITY AND CAPITAL RESOURCES
June 30 December 31
($ millions) 2010 2009
----------------------------------------------------------------------------
Long-term debt $ 1,179 $ 1,163
Cash and cash equivalents (176) (122)
----------------------------------------------------------------------------
Net debt $ 1,003 $ 1,041
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Unitholders' equity $ 3,961 $ 3,969
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----------------------------------------------------------------------------
Total capitalization (1) $ 4,964 $ 5,010
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----------------------------------------------------------------------------
Net debt to total capitalization (%) 20 21
----------------------------------------------------------------------------
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(1) Net debt plus Unitholders' equity. Net debt, total capitalization, as
well as net debt to total capitalization are non-GAAP measures.
Net debt at June 30, 2010 decreased from December 31, 2009 primarily as a result of cash from operating activities exceeding capital expenditures and Unitholder distributions, partially offset by $16 million in foreign exchange losses on long-term debt.
We believe a slightly higher net debt level may provide a more efficient capital structure and will conserve tax pools prior to trust taxation; however, the Trust must also consider a prudent liquidity position, access to capital markets, and future investing and financing requirements. While we are comfortable in the current business environment paying distributions in excess of cash from operating activities less capital expenditures, future net debt will depend on actual operating results, crude oil prices, economic conditions, foreign exchange rates, and future investing activities, especially as our capital program increases beyond 2010.
In March 2010, the Trust's $70 million line of credit was increased to $100 million and the term on the Trust's $40 million bilateral credit facility was extended to April 21, 2011.
UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY
The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $13 billion with 484 million Units outstanding and a closing price of $26.99 per Unit on June 30, 2010.
Canadian Oil Sands Trust - Trading
Activity Second
Quarter June May April
2010 2010 2010 2010
----------------------------------------------------------------------------
Unit price
High $ 33.05 $ 29.66 $ 31.30 $ 33.05
Low $ 25.48 $ 26.55 $ 25.48 $ 29.51
Close $ 26.99 $ 26.99 $ 28.64 $ 30.75
Volume of Trust Units traded
(millions) 93.8 30.8 29.8 33.2
Weighted average Trust Units
outstanding (millions) 484.4 484.4 484.4 484.4
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FOREIGN OWNERSHIP
Based on information from the statutory declarations by Unitholders, we estimate that, as of May 20, 2010 approximately 73 per cent of our Units were held by Canadian residents with the remaining 27 per cent of Units being held by non-Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents.
The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of August 23, 2010. The Trust posts its foreign ownership levels on its web site at www.cos-trust.com under "Investor/Unit Information". The steps to manage foreign ownership levels are described in the Trust's AIF.
CORPORATE CONVERSION
On January 28, 2010, Canadian Oil Sands' Board approved converting to a corporate structure on or about December 31, 2010. At the Annual and Special Meeting on April 29, 2010, Canadian Oil Sands' Unitholders approved this arrangement and the Court of Queen's Bench of Alberta issued a final order on April 30, 2010. See the "Unitholder Distributions" section of this MD&A for discussion on the dividend approach following conversion.
TAILINGS MANAGEMENT
On April 23, 2010 the Energy Resources Conservation Board ("ERCB") approved, with conditions, Syncrude's revised tailings pond plans submitted in September 2009 under Tailings Directive 074. These plans outline a multi-pronged approach for meeting the long-term intent of Directive 074, and include the implementation of three main tailings technologies: water capping, composite tails and centrifuge technology. Issued by the ERCB in February 2009, Tailings Directive 074 and its Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes requires operators to prepare tailings plans and report on tailings ponds annually, reduce the solids content of fluid tailings through the capture of fine particles from the production process in dedicated disposal areas, and convert fines into trafficable deposits which are ready for reclamation five years after deposits have ceased.
SYNCRUDE WATERFOWL INCIDENT
In February 2009, Syncrude Canada Ltd. ("Syncrude Canada") was charged under the Federal Migratory Birds Convention Act and the Alberta Environmental Protection and Enhancement Act for a 2008 waterfowl incident. On June 25, 2010, a provincial court judge ruled in favour of the federal and provincial Crowns on the case involving this waterfowl incident. A further hearing on the matter is scheduled for August 20, 2010. Syncrude continues to review the basis of the conviction before determining if any further action, including any potential appeal, will be made. The long-term issues relating to this incident and the attention on this single event are likely to continue to impact the regulatory regime and public perception of not only Syncrude but the oil sands industry generally.
Syncrude has always acknowledged its moral obligations for the waterfowl incident and has implemented new waterfowl deterrent systems. Syncrude and its owners remain committed to improving their environmental performance. More information on the environmental issues is contained in the Annual Information Form of the Trust dated March 22, 2010.
FINANCIAL RISK MANAGEMENT
The Trust did not have any financial derivatives outstanding at June 30, 2010.
Crude Oil Price Risk
Canadian Oil Sands' revenues are impacted by changes in both the U.S. dollar denominated crude oil prices and U.S./Cdn FX rates. The Trust did not have any crude oil price hedges in place during the first half of 2010 and 2009, and does not currently intend to enter into any crude oil hedge positions. The Trust may hedge this exposure in the future, however, depending on the business environment and our growth opportunities.
Foreign Currency Risk
Canadian Oil Sands' results are affected by fluctuations in the U.S./Cdn currency exchange rates, as revenues generated are based on a U.S. dollar WTI benchmark price while certain obligations are denominated in Canadian dollars. The Trust did not have any foreign currency hedges in place during the first half of 2010 or 2009, and does not currently intend to enter into any new currency hedge positions. The Trust may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.
Interest Rate Risk
Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding or upon the refinancing of maturing long-term debt at prevailing interest rates. As at June 30, 2010 there was no floating interest rate debt outstanding, and the next long-term debt maturity is in 2013.
Liquidity Risk
Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they fall due. Canadian Oil Sands actively manages its liquidity risk through its cash, debt and equity strategies. The next long-term debt maturity is in 2013, and the $800 million credit facility does not expire until April 27, 2012.
Credit Risk
Canadian Oil Sands is exposed to credit risk primarily through customer accounts receivable balances and financial counterparties with whom the Trust has invested its cash or purchased term deposits from. The maximum exposure to any one customer or financial counterparty is controlled through a credit policy that limits exposure based on credit ratings.
The financial condition of some of our U.S. based refinery customers has continued to come under pressure during 2010, reflecting low refinery margins. Canadian Oil Sands carries credit insurance to help mitigate a portion of the impact should a loss occur and continues to transact primarily with investment grade customers; the vast majority of accounts receivable at June 30, 2010 was due from investment grade energy producers and refinery based customers.
At June 30, 2010, our cash and cash equivalents were invested mainly in term deposits with high-quality senior Canadian banks. As of July 29, 2010, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.
NEW ACCOUNTING PRONOUNCEMENTS
There were no new accounting pronouncements by the CICA during the first half of 2010 that are expected to have a material impact on the Trust.
International Financial Reporting Standards ("IFRS")
IFRS will replace Canadian GAAP for publicly accountable enterprises in Canada in 2011. The Trust will be required to adopt IFRS for interim and annual financial statements beginning on January 1, 2011 including comparative financial statements for 2010.
As part of its IFRS conversion project, the Trust has analyzed IFRS accounting standards and accounting policy alternatives and has prepared draft IFRS financial statements and disclosures.
a) IFRS 1 "First-Time Adoption of International Financial Reporting Standards"
IFRS 1 provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRS. The Trust has analyzed the choices available under IFRS 1 and has made preliminary decisions to utilize exemptions relating to employee future benefits, interest capitalization, asset retirement obligations, business combinations, and leases. Similarly, the Trust has made preliminary decisions to reject exemptions relating to the fair value measurement of property, plant and equipment and long-term debt.
i) Employee future benefits
Utilizing the employee future benefits exemption will result in the recognition of approximately $125 million of previously unrecognized actuarial losses (net of approximately $40 million in future income taxes) through January 1, 2010 retained earnings with a corresponding increase to the employee future benefits liability. The Trust's accounting policy under Canadian GAAP is to recognize these losses over the expected average remaining service life of active employees.
ii) Interest capitalization
By utilizing the interest capitalization exemption, the Trust will be exempted from capitalizing interest on assets already under construction at January 1, 2010. As described in the "Significant Accounting Policy Changes Post Conversion" section below, interest on certain future capital projects will be capitalized.
iii) Asset retirement obligations
The Trust intends to utilize the asset retirement obligation exemption which provides a method for adjusting the asset retirement obligations and the related property, plant and equipment assets to obtaan a January 1, 2010 value. The combined effect of utilizing this exemption and the related accouting policy change contemplated going forward is discussed in the "Significant Accounting Policy Changes Post Conversion" section below.
Current estimates suggest that the other IFRS 1 exemptions applied to the Trust will not materially impact its financial position or financial results at January 1, 2010.
b) Significant Accounting Policy Changes Post Conversion
Based on an analysis of differences between IFRS and Canadian GAAP, the amounts the Trust reports under IFRS may differ significantly from the amounts the Trust reports under Canadian GAAP for asset retirement obligations, future income taxes, employee future benefits, interest capitalization, stock-based compensation, and impairment of property, plant and equipment.
i) Asset retirement obligations
The Trust has made a preliminary decision to discount the estimated fair value of its asset retirement obligations and the related property, plant and equipment assets using a risk-free interest rate. Under Canadian GAAP, the Trust uses a credit-adjusted interest rate. The combined effect of utilizing the IFRS 1 exemption and changing the discount rate will increase the January 1, 2010 asset retirement obligations and the related property, plant and equipment assets by approximately $160 million and $30 million, respectively, with an offsetting $130 million charge to January 1, 2010 retained earnings.
In addition, IFRS requires that asset retirement obligations be re-measured each reporting period for changes in the discount rate with a corresponding adjustment to the cost of the related property, plant and equipment assets; whereas, under Canadian GAAP, changes in discount rates do not result in a re-measurement.
ii) Future income taxes
IFRS requires the Trust to measure future income taxes using the tax rate applicable to earnings not distributed to Unitholders whereas, under Canadian GAAP, future income taxes are measured using the tax rate applicable to distributed earnings. This difference will result in an approximate $300 million increase in the January 1, 2010 future income taxes liability with a corresponding charge to retained earnings. This charge is expected to subsequently reverse as a gain in net income in April 2010 reflecting the Unitholders' approval of the conversion from a trust to a corporation.
iii) Employee future benefits
The Trust has made a preliminary decision to recognize actuarial gains and losses on Syncrude's pension plans in other comprehensive income in the period in which they arise. The Trust's current accounting policy is to defer recognition of these gains and losses and to amortize the excess of any net actuarial gain or loss exceeding 10 per cent of the greater of the benefit obligation or fair value of the plan assets over the expected average remaining service life of active employees (approximately 12 years at December 31, 2009). IFRS currently allows the use of either method. The adoption of the new policy will result in the net pension asset or liability being fully reflected on the balance sheet each period. However, as valuation changes will flow through other comprehensive income, they will not impact net income.
iv) Interest capitalization
IFRS requires that interest costs relating to assets that take a substantial period of time to construct be capitalized and subsequently expensed as depreciation over the assets' expected useful lives. Currently, under Canadian GAAP, the Trust expenses all interest costs. During periods when significant capital expenditures are incurred, the IFRS accounting policy could result in a significant decrease in interest expense with an offsetting increase in depreciation and depletion over subsequent periods.
v) Impairment of property, plant and equipment
Under IFRS, the Trust will be required to recognize an impairment loss if the carrying amount of any property, plant and equipment exceeds its estimated future discounted cash flows. Under Canadian GAAP, estimated future cash flows used to assess impairments are not discounted. As such, impairment losses may be recognized earlier under IFRS than under Canadian GAAP. At January 1, 2010, the Trust is not anticipating any impairment of property, plant and equipment as a result of adopting IFRS.
Other post-conversion accounting policy choices and IFRS-Canadian GAAP differences are not expected to materially impact the financial position or financial results of the Trust. Although IFRS includes more explicit direction for componentization of property, plant and equipment for the purposes of calculating depreciation and depletion than is provided under Canadian GAAP, the Trust does not expect any material changes to the carrying value of its property, plant and equipment nor to its depreciation and depletion expense on adoption of IFRS.
IFRS will likely result in additional disclosures in Canadian Oil Sands' financial statements for items already disclosed in other security documents in Canada. As part of preparing draft IFRS disclosures, the Trust has analyzed and will continue to analyze the additional disclosures to ensure sufficient information is available upon adoption of IFRS.
c) Advisory
The preliminary decisions about IFRS 1 exemptions and accounting policy choices, and the assessments of the differences between IFRS and Canadian GAAP have not been finalized. Users are cautioned that the analysis will not be finalized until 2011 and that the preliminary decisions and estimated impacts of adopting IFRS may change. In addition, other differences may exist between amounts reported by the Trust under Canadian GAAP versus IFRS. New or revised IFRS standards are being developed by the International Accounting Standards Board ("IASB") that may impact the adoption of IFRS by the Trust in 2011 or thereafter. These standards include Joint Ventures, Income Taxes, Financial Instruments, Emissions Trading Schemes, Extractive Industries, Employee Future Benefits, Measurement of Liabilities and the IFRS 1 exemption relating to interest capitalization. The Trust continues to monitor these and other accounting standard developments within IFRS which might impact its IFRS conversion.
d) Conversion Project Update
The Trust's IFRS conversion is overseen by the Audit Committee with quarterly reports by management to that committee on the progress of the plan and any issues that may have arisen. The Trust's IFRS project will continue through 2010 and is on schedule for a January 1, 2011 implementation date.
Specifically, the Trust has completed the analysis of its information technology needs, data systems and internal controls and has concluded that they do not require any significant modification to adopt IFRS. To ensure the appropriate level of IFRS expertise is available through transition, resources have been added to the project team and ongoing education is provided to the project team, accounting staff, investor relations staff, senior management, the Audit Committee and the Board of Directors. The effects of existing IFRS on the Trust's business activities have been reviewed and it is not expected that IFRS will result in any significant changes to the Trust's business activities.
The adoption of IFRS also impacts Syncrude's reporting of results to the Trust. Syncrude has an implementation project to manage its own transition to IFRS. Canadian Oil Sands and the other Syncrude owners are stewarding Syncrude's IFRS implementation to help ensure that information provided by Syncrude meets the owners' needs. Syncrude is not currently anticipating any significant modifications to its accounting systems or business activities as a result of adopting IFRS.
2010 OUTLOOK (millions of Canadian dollars, except volume July 29, April 29, and per barrel amounts) 2010 2010 ---------------------------------------------------------------------------- Syncrude production (MMbbls) 110 115 Canadian Oil Sands sales (MMbbls) 40.4 42.3 Revenues, net of crude oil purchases and transportation 3,111 3,320 Operating costs 1,503 1,487 Operating costs per barrel 37.19 35.20 Crown royalties 309 376 Capital expenditures 544 532 Cash from operating activities 1,098 1,273 Business environment assumptions --------------------------------- West Texas Intermediate (US$/bbl) $ 75 $ 80 Premium (Discount) to average C$ WTI prices (C$/bbl) $ (2.00) $ (2.25) Foreign exchange rate (US$/Cdn$) $ 0.95 $ 0.99 AECO natural gas (Cdn$/GJ) $ 4.75 $ 5.00
For 2010, Canadian Oil Sands is estimating Syncrude production of 110 million barrels with a revised range of 108 million to 113 million barrels. The single point Syncrude production outlook has been decreased by five million barrels to reflect unplanned outages of the vacuum distillation unit and sour water stripper in July following the actual first half results. This estimate also includes the Coker 8-1 turnaround, scheduled to begin in September for a period of 45 days.
The outlook assumes a reduced U.S. $75 per barrel WTI oil price, a weaker $0.95 U.S./Cdn foreign exchange rate, and a SCO discount to Cdn dollar WTI of $2.00 per barrel. These assumptions, combined with the revised production outlook, result in estimated revenues of $3,111 million, or $77 per barrel in 2010.
Operating costs are estimated at $1,503 million with higher production costs partially offset by lower natural gas costs, reflecting a natural gas price assumption of $4.75 per gigajoule. Estimated per barrel operating costs have risen to $37, mainly as a result of the reduced production estimate.
Capital expenditures are estimated at $544 million, including $120 million related to the SER project and $106 million related to mine train replacements and relocations. Lower than forecast actual capital expenditures in the first half of 2010 are anticipated to be offset by higher spending in the second half of the year.
The assumed bitumen value has been reduced to 68 per cent of Cdn dollar WTI from 70 per cent, reflecting actual results to date. Combined with lower revenues, estimated 2010 Crown royalties have fallen to $309 million.
Based on the above assumptions, our revised 2010 outlook for cash from operating activities is $1,098 million, or $2.27 per Unit. After deducting forecasted 2010 capital expenditures of $544 million, we are estimating $554 million of remaining cash from operating activities for the year, or $1.14 per Unit.
Distributions paid in 2010 are expected to be 100 per cent taxable as other income. The actual taxability of 2010 distributions will be determined and reported to Unitholders prior to the end of the first quarter of 2011.
Changes in certain factors and market conditions could potentially impact Canadian Oil Sands' outlook. The following table provides a sensitivity analysis of the key factors affecting the Trust's performance. In addition to the factors described in the table, the supply/demand equation and pipeline access for synthetic crude oil in North American markets could impact the differential for SCO relative to crude benchmarks; however, these factors are difficult to predict.
2010 Outlook Sensitivity Analysis (July 29, 2010)
Cash from Operating
Activities
Increase
Annual
Variable (1) Sensitivity $ millions $/Trust unit
----------------------------------------------------------------------------
Syncrude operating costs decrease C$1.00/bbl 34 0.07
Syncrude operating costs decrease C$50 million 15 0.03
WTI crude oil price increase US$1.00/bbl 32 0.07
Syncrude production increase 2 million bbls 42 0.09
Canadian dollar weakening US$0.01/C$ 24 0.05
AECO natural gas price decrease C$0.50/GJ 17 0.04
(1) An opposite change in each of these variables will result in the
opposite cash from operating activities impacts. Canadian Oil Sands may
become subject to minimum Crown royalties at a rate of one per cent of
gross bitumen revenue. The sensitivities presented herein assume
royalties are paid at 25 per cent of net bitumen revenue.
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
($ millions, except
per Unit amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues $ 880 $ 526 $ 1,779 $ 1,075
----------------------------------------------------------------------------
Expenses:
Operating 336 345 690 704
Non-production 19 39 55 72
Crude oil purchases
and transportation expense 38 59 203 96
Crown royalties (Note 10) 85 23 163 27
Administration 8 6 16 12
Insurance 3 2 5 4
Interest, net (Note 6) 22 25 48 45
Depreciation, depletion
and accretion (Note 2) 94 81 197 187
Loss on disposal of assets 5 - 5 -
Foreign exchange (gain) loss 38 (77) 5 (48)
----------------------------------------------------------------------------
648 503 1,387 1,099
----------------------------------------------------------------------------
Earnings (loss) before taxes 232 23 392 (24)
Future income tax recovery
and other (5) (23) (12) (113)
----------------------------------------------------------------------------
Net income 237 46 404 89
Other comprehensive loss,
net of income taxes
Reclassification of
derivative gains to
net income - - (1) (1)
----------------------------------------------------------------------------
Comprehensive income $ 237 $ 46 $ 403 $ 88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average Trust
Units (millions) 484 484 484 483
Trust Units, end of period
(millions) 484 484 484 484
Net income per Trust Unit:
Basic and diluted $ 0.49 $ 0.10 $ 0.83 $ 0.18
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Retained earnings
Balance, beginning of
period $ 1,356 $ 1,333 $ 1,359 $ 1,362
Net income 237 46 404 89
Unitholder distributions
(Note 8) (242) (73) (412) (145)
----------------------------------------------------------------------------
Balance, end of period 1,351 1,306 1,351 1,306
----------------------------------------------------------------------------
Accumulated other
comprehensive income
Balance, beginning of
period 17 20 18 21
Other comprehensive loss - - (1) (1)
----------------------------------------------------------------------------
Balance, end of period 17 20 17 20
----------------------------------------------------------------------------
Unitholders' capital
Balance, beginning of
period 2,587 2,557 2,587 2,524
Issuance of Trust Units - 30 - 63
----------------------------------------------------------------------------
Balance, end of period 2,587 2,587 2,587 2,587
----------------------------------------------------------------------------
Contributed surplus
Balance, beginning of
period 6 4 5 3
Stock-based compensation
(Note 7) - - 1 1
----------------------------------------------------------------------------
Balance, end of period 6 4 6 4
----------------------------------------------------------------------------
Total Unitholders' equity $ 3,961 $ 3,917 $ 3,961 $ 3,917
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED BALANCE SHEETS
AS AT
(unaudited)
June 30 December 31
($ millions) 2010 2009
----------------------------------------------------------------------------
ASSETS
Current assets:
Cash and cash equivalents $ 176 $ 122
Accounts receivable 300 354
Inventories 123 133
Prepaid expenses 4 7
----------------------------------------------------------------------------
603 616
Property, plant and equipment, net (Note 2) 6,306 6,289
Reclamation trust 50 48
----------------------------------------------------------------------------
$ 6,959 $ 6,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 362 $ 284
Current portion of employee future benefits
(Note 4) 51 17
----------------------------------------------------------------------------
413 301
Employee future benefits and other liabilities (Note 4) 65 104
Long-term debt 1,179 1,163
Asset retirement obligation 326 389
Future income taxes 1,015 1,027
----------------------------------------------------------------------------
2,998 2,984
Unitholders' equity 3,961 3,969
----------------------------------------------------------------------------
$ 6,959 $ 6,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash from (used in)
operating activities
Net income $ 237 $ 46 $ 404 $ 89
Items not requiring
outlay of cash:
Depreciation, depletion
and accretion (Note 2) 94 81 197 187
Loss on disposal of assets 5 - 5 -
Foreign exchange (gain)
loss on long-term debt 50 (83) 16 (52)
Future income tax recovery (5) (23) (12) (113)
Actual reclamation costs (5) - (28) (22)
Net change in deferred items
and other (4) 2 (5) 3
----------------------------------------------------------------------------
372 23 577 92
Change in non-cash working
capital (14) (67) 90 (86)
----------------------------------------------------------------------------
Cash from (used in)
operating activities 358 (44) 667 6
----------------------------------------------------------------------------
Cash from (used in)
financing activities
Issuance of Senior Notes - 574 - 574
Repayment of medium term
and Senior Notes - (200) - (200)
Net drawdown of bank credit
facilities - (25) - -
Unitholder distributions
(Note 8) (242) (43) (412) (82)
----------------------------------------------------------------------------
Cash from (used in)
financing activities (242) 306 (412) 292
----------------------------------------------------------------------------
Cash from (used in)
investing activities
Capital expenditures (114) (139) (206) (223)
Reclamation trust funding (2) (1) (3) (2)
Change in non-cash working
capital 1 3 8 14
----------------------------------------------------------------------------
Cash used in investing
activities (115) (137) (201) (211)
----------------------------------------------------------------------------
Increase in cash and cash
equivalents 1 125 54 87
Cash and cash equivalents
at beginning of period 175 241 122 279
----------------------------------------------------------------------------
Cash and cash equivalents
at end of period $ 176 $ 366 $ 176 $ 366
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents
consist of:
Cash $ 28 $ 6
Short-term investments 148 360
----------------------------------------------------------------------------
$ 176 $ 366
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information (Note 11)
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2010
(Tabular amounts expressed in millions of Canadian dollars, except where
otherwise noted.)
1) BASIS OF PRESENTATION
The interim consolidated financial statements include the accounts of Canadian Oil Sands Trust and its subsidiaries (collectively, the "Trust" or "Canadian Oil Sands"), and are presented in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2009, except as discussed in Note 2. Certain disclosures that are normally required to be included in the notes to the annual audited consolidated financial statements have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in the Trust's annual report for the year ended December 31, 2009.
2) CHANGE IN ACCOUNTING ESTIMATE
Oil sands assets are depreciated and depleted over their estimated remaining lives, which are reviewed by management on a regular basis. During the three months ended March 31, 2010, management determined that the usage of certain tangible equipment would be most accurately represented by a straight-line calculation on an ongoing basis. Depreciation and depletion of the oil sands assets is now estimated based on a blend of both the unit-of-production and straight-line basis. The effect of this change in estimate for the three and six months ended June 30, 2010 is that approximately $35 million and $38 million less depreciation, respectively, was recorded using the new estimated remaining lives. Beyond 2010, it is not practical to estimate the effect of this change in estimate due to the long-life nature of the assets and the amounts and timing of the estimated future development costs.
3) FUTURE CHANGES IN ACCOUNTING POLICIES
The Trust will be subject to International Financial Reporting Standards ("IFRS") commencing in 2011. The Trust is currently assessing the impact that conversion to IFRS may have on its financial statements.
4) EMPLOYEE FUTURE BENEFITS
Syncrude Canada Ltd. ("Syncrude Canada"), the operator of the Syncrude Joint Venture ("Syncrude"), has a defined benefit and two defined contribution plans providing pension benefits, and other post-employment benefit plans ("OPEB") covering most of its employees. Other post-employment benefits include certain health care and life insurance benefits for retirees, their beneficiaries and covered dependents. The OPEB plan is not funded.
Canadian Oil Sands accrues its obligations as a joint venture owner in respect of Syncrude Canada's employee benefit plans and the related costs, net of plan assets. The cost of employee pension and other retirement benefits is actuarially determined using the projected benefit method based on length of service and reflects Canadian Oil Sands' best estimate of the expected performance of the plan investment, salary escalation factors, retirement ages of employees and future health care costs. The expected return on plan assets is based on the fair value of those assets. Past service costs from plan amendments are amortized on a straight-line basis over the estimated average remaining service life of active employees ("EARSL") at the date of amendment. The excess of any net actuarial gain or loss exceeding 10 per cent of the greater of the benefit obligation and fair value of the plan assets is amortized over the EARSL.
Canadian Oil Sands' share of Syncrude Canada's net defined benefit and contribution plans expense for the three and six months ended June 30, 2010 and 2009 is based on its 36.74 per cent working interest. The costs have been recorded in operating expense as follows:
Three Months Ended Six Months Ended
June 30 June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Defined benefit plans:
Pension benefits $ 11 $ 9 $ 19 $ 17
Other benefit plans - 1 - 3
----------------------------------------------------------------------------
$ 11 $ 10 $ 19 $ 20
Defined contribution plans - - 1 1
----------------------------------------------------------------------------
Total benefit cost $ 11 $ 10 $ 20 $ 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5) BANK CREDIT FACILITIES
Extendible revolving term facility (a) $ 40
Line of credit (b) 100
Operating credit facility (c) 800
----------------------------------------------------------------------------
$ 940
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Each of the Trust's credit facilities is unsecured. These credit agreements contain covenants restricting Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business. In addition, Canadian Oil Sands has agreed to maintain its total debt-to-total book capitalization at an amount less than 60 per cent, or 65 per cent in certain circumstances involving acquisitions.
a) The $40 million extendible revolving term facility is a 364-day facility with a one-year term out, expiring April 21, 2011. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at June 30, 2010, no amounts were drawn on this facility ($nil - December 31, 2009).
b) The $100 million line of credit is a one-year revolving letter of credit facility. Letters of credit drawn on the facility mature April 30th each year and are automatically renewed, unless notification to cancel is provided by Canadian Oil Sands or the financial institution providing the facility at least 60 days prior to expiry. Letters of credit on this facility bear interest at a credit spread.
Letters of credit of approximately $75 million were written against the line of credit as at June 30, 2010.
c) The $800 million operating facility is a multi-year facility, expiring April 27, 2012. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at June 30, 2010, no amounts were drawn against this facility ($nil - December 31, 2009).
6) INTEREST, NET
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Interest expense on long-term debt $ 22 $ 25 $ 48 $ 46
Interest income and other - - - (1)
----------------------------------------------------------------------------
Interest expense, net $ 22 $ 25 $ 48 $ 45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7) STOCK BASED COMPENSATION
During the first half of 2010, 385,274 options were issued by the Trust to employees with an average exercise price of $28.22 pursuant to the Trust's Unit Incentive Option Plan. These options had an estimated value of $2 million at the time of issue.
8) UNITHOLDER DISTRIBUTIONS
Pursuant to the Trust Indenture, the Trust distributes all the Distributable Income, as defined by the Trust Indenture, received or receivable by the Trust in a quarter. The Trust's Distributable Income primarily consists of a royalty from its operating subsidiary, Canadian Oil Sands Limited ("COSL"). The royalty is designed to capture the cash generated by COSL, after the deduction of all costs and expenses, including: operating and administrative costs, income taxes, capital expenditures, debt interest and principal repayments, working capital and reserves for future obligations deemed appropriate. The amount of royalty income that the Trust receives in any period has a considerable amount of flexibility through the use of discretionary reserves and debt borrowings or repayments (either intercompany or third party). Quarterly distributions are determined by COSL's Board of Directors after considering the current and expected economic and operating conditions, ensuring financing capacity for Syncrude's expansion projects and/or Canadian Oil Sands acquisitions, and with the objective of maintaining an investment grade credit rating.
Three Months Ended Six Months Ended
June 30 June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Cash from operating
activities $ 358 $ (44) $ 667 $ 6
Add (Deduct):
Capital expenditures (114) (139) (206) (223)
Change in non-cash working
capital (1) 1 3 8 14
Reclamation trust funding (2) (1) (3) (2)
Change in cash and cash
equivalents and financing,
net(2) (1) 254 (54) 350
----------------------------------------------------------------------------
Unitholder distributions $ 242 $ 73 $ 412 $ 145
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Unitholder distributions
per Trust Unit $ 0.50 $ 0.15 $ 0.85 $0.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) From investing activities.
(2) Primarily represents the change in cash and cash equivalents and net
financing to fund the Trust's share of investing activities.
9) COMMITMENTS
During April 2010, an actuarial valuation of the pension obligation as at December 31, 2009 was completed. This resulted in additional funding requirements over the next 24 years of approximately $265 million, with the majority of the funding requirements due within the next five years.
During the first six months of 2010, Syncrude entered into new capital commitments, mainly for mining equipment, the Trust's share of which is approximately $20 million.
10) CONTINGENCY
Crown royalties for 2010 include amounts due under the Syncrude Amended Royalty Agreement with the Alberta government. This agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil price adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude's bitumen and the reference price of bitumen. The Alberta government, Syncrude, and the Syncrude owners are in discussions to determine the appropriate adjustments for quality, transportation and handling. For estimating and recognizing royalties, the Trust has used a bitumen value based on Syncrude and its owners' interpretation of the Syncrude Amended Royalty Agreement, and their estimates of the appropriate quality, transportation and handling adjustments. These adjustments are different than those provided under the Alberta government's generic bitumen valuation methodology. The royalties recognized for the period from January 1, 2009 to June 30, 2010 are estimated to be approximately $75 million less than the amount calculated under the generic bitumen valuation methodology. The Syncrude owners and the Alberta government continue to discuss the basis for these reasonable adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter.
11) SUPPLEMENTARY INFORMATION
Three Months Ended Six Months Ended
June 30 June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Income tax paid $ - $ - - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 24 $ 10 48 $ 41
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12) PRIOR PERIOD COMPARATIVES
Certain prior period comparative figures have been reclassified to conform to the current period's presentation.
Canadian Oil Sands Limited
Marcel Coutu, President & Chief Executive Officer
Units Listed - Symbol: COS.UN
Toronto Stock Exchange
Contacts:
Canadian Oil Sands Trust
Siren Fisekci
Vice President, Investor & Corporate Relations
(403) 218-6228
www.cos-trust.com
2500 First Canadian Centre
350 - 7 Avenue S.W.
Calgary, Alberta T2P 3N9
(403) 218-6200
(403) 218-6201 (FAX)
investor_relations@cos-trust.com
www.cos-trust.com
