Canadian Oil Sands Trust announces 2010 third quarter results All financial figures are unaudited and in Canadian dollars unless otherwise noted.
TSX - COS.UN
Calgary, Alberta (October 28, 2010) – Canadian Oil Sands Trust (“Canadian Oil Sands”, the “Trust” or “we”) today announced cash from operating activities of $330 million ($0.68 per Trust unit (“Unit”)) for the third quarter of 2010 compared with cash from operating activities of $213 million ($0.44 per Unit) for the same period last year. Lower revenues and higher operating costs were more than offset by a reduction in non-cash working capital in the 2010 versus 2009 period. Year-to-date cash from operating activities increased to $997 million ($2.06 per Unit) for 2010 from about $219 million ($0.45 per Unit) recorded for the same period of 2009. Higher revenues combined with a decrease in non-cash working capital were partially offset by higher operating expenses and Crown royalties.
Net income for the third quarter of 2010 was $171 million, or $0.35 per Unit, compared with net income of $247 million, or $0.51 per Unit, for the 2009 third quarter. The decrease reflects lower revenues combined with higher operating expenses and smaller foreign exchange gains on the U.S. dollar denominated longterm debt, partially offset by lower Crown royalties, lower depreciation, depletion and accretion expense, and a future income tax recovery.
Year-to-date, net income in 2010 totaled $575 million, or $1.19 per Unit, up from net income of $336 million, or $0.69 per Unit, in 2009. The increase reflects higher revenues partially offset by higher operating expenses, higher Crown royalties, smaller foreign exchange gains on the U.S. dollar denominated long-term debt, and a reduced future income tax recovery.
The Trust has declared a quarterly distribution amount of $0.50 per Unit for Unitholders of record on November 19, 2010, payable on November 30, 2010.
In 2010, the Trust has declared its distributions with the intention of achieving certain tax pool targets. Based on our October 28, 2010 Outlook, we expect to achieve our target with approximately $2 billion of tax pools at year end. This may result in slightly higher debt levels, although our balance sheet should remain strong. Optimizing tax pools in such a manner will no longer be applicable when we convert to a corporation.
Canadian Oil Sands Trust Third Quarter Report 2010 Following our conversion to a corporation and consistent with other corporations, beginning January 1, 2011 Canadian Oil Sands will be subject to corporate taxation. While tax pools will be available to shelter income from cash taxes, future cash from operating activities ultimately will be reduced by corporate taxation. We anticipate future dividend amounts also will be impacted by a projected rise in capital expenditures to fund Syncrude’s sustaining capital program and future expansion plans. Consistent with past practice, the Trust intends to use its cash from operating activities to help finance such expenditures. As a result of discontinuing our tax optimization strategy, the projected rise in capital expenditures and the eventual impact of taxation, we anticipate a reduction in distributions/dividends from the current 2010 level.
“Higher production and crude oil prices during the first nine months of 2010 resulted in improved financial results compared with the 2009 period. As we look forward to becoming a corporation later this year, we are in a solid position with a strong balance sheet and about $2 billion in tax pools to shelter future income,” said Marcel Coutu, President and Chief Executive Officer. “I continue to believe that, along with expansion plans into our Aurora South leases later this decade, our greatest near-term value opportunity resides in improving the operational reliability at Syncrude. While this has been challenging, we continue to work with Syncrude, Imperial Oil and Exxon Mobil in establishing a solid foundation for gradual and sustained increases in production levels.”
Sales volumes averaged 96,000 barrels per day during the third quarter of 2010 compared with 115,000 barrels per day during the same period of 2009. Unplanned maintenance in upgrading units reduced production in both quarters while the 2010 third quarter was further impacted by the planned turnaround of Coker 8-1.
Sales volumes during the first nine months of 2010 averaged 105,000 barrels per day compared with 98,000 barrels per day in 2009. The increase reflects less unplanned maintenance and the production impact of the Coker 8-1 turnaround affecting only part of the period in 2010, versus the full impact of the extensive Coker 8-3 turnaround in 2009.
Operating costs during the third quarter of 2010 were $39.99 per barrel compared with $27.80 per barrel in 2009; the increase is primarily attributable to the turnaround of Coker 8-1 combined with increased maintenance costs on other upgrading units. Year-to-date, operating costs were $36.54 per barrel in 2010 compared with $37.39 per barrel in 2009. While total operating costs actually increased year-to-date in 2010 compared with the same period in 2009, primarily as a result of higher maintenance and projectrelated costs, the higher production in 2010 resulted in lower per barrel operating costs.
Canadian Oil Sands Trust Third Quarter Report 2010 2 Capital expenditures year-to-date in 2010 were $343 million compared with $308 million in the same period of 2009. The Syncrude Emissions Reduction (“SER”) project accounted for $84 million and $87 million of the capital spent in 2010 and 2009, respectively. Mine train replacements and relocations accounted for $61 million and $15 million of the capital spent in 2010 and 2009, respectively, while the remaining expenditures related to other sustaining capital activities including the construction of tailings facilities, pipe replacements and other infrastructure projects. The SER project is an environmental project designed to substantially reduce sulphur dioxide emissions, and is expected to be completed in 2011.
CANADIAN OIL SANDS TRUST Highlights
Three Months Ended Nine Months Ended September 30 September 30
(millions of Canadian dollars, except per Trust Unit and per barrel volume amounts) 2010 2009 2010 2009
Net Income $ 171 $ 247 $ 575 $ Per Trust Unit - Basic $ 0.35 $ 0.51 $ 1.19 $ 0.69
$ 330 $ 213 $ 997 $
Cash from (used in) Operating Activities
Per Trust Unit $ 0.68 $ 0.44 $ 2.06 $ 0.45
Unitholder Distributions $ 242 $ 121 $ 654 $ Per Trust Unit $ 0.50 $ 0.25 $ 1.35 $ 0.55
Sales Volumes (1)
| Total (MMbbls) | 8.9 10.6 | 28.6 | 26.7 | ||
| Daily average (bbls) | 96,477 | 114,544 | 104,767 | 97,684 | |
| Operating Costs ($/bbl) | $39.99 | $27.80 | $36.54 | $37.39 | |
| Net Realized SCO Selling Price ($/bbl) | $77.94 | $73.31 | $79.28 | $65.67 | |
| West Texas Intermediate (average $US/bbl)(2) | $76.21 | $68.24 | $77.69 | $57.32 |
(1) The Trust's sales volumes differ from its production volumes due to changes in inventory, w hich are primarily in-transit pipeline volumes, and are after purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.
2010 Outlook
On September 23, 2010 Canadian Oil Sands lowered its single point 2010 production Outlook by five million barrels from the revised July 29, 2010 Outlook to reflect unplanned maintenance in certain upgrading units and an extension of the planned Coker 8-1 turnaround completed in late October. Canadian Oil Sands is estimating annual 2010 Syncrude production of 105 million barrels with a revised range of 102 million to 108 million barrels. The original 2010 budget estimate for Syncrude production was 115 million barrels.
The October 28, 2010 Outlook assumes an increased U.S. $78 per barrel WTI oil price, a smaller SCO discount to Cdn dollar WTI of $1.75 per barrel but a stronger $0.97 U.S./Cdn foreign exchange rate.
Canadian Oil Sands Trust Third Quarter Report 2010 3 These assumptions, combined with the revised production volumes, result in estimated revenues of $3,037 million, or $79 per barrel in 2010.
Our revised 2010 Outlook for cash from operating activities is $1,137 million, or $2.35 per Unit. After deducting forecast 2010 capital expenditures of $511 million, we are estimating $626 million of remaining cash from operating activities for the year, or $1.29 per Unit.
More information on the Trust’s Outlook is provided in the Management’s Discussion and Analysis (“MD&A”) section of this report and the October 28, 2010 guidance document, which is available on the Trust’s web site at www.cos-trust.com under “Investor”.
Syncrude Waterfowl Incident
On October 25, 2010, Syncrude reported that, during a freezing rain storm, a waterfowl incident occurred when waterfowl landed at various locations on the Syncrude site including roads, parking lots and the Mildred Lake and Aurora settling basins with the result that waterfowl that came in contact with bitumen on the settling basins were euthanized. Several other oil sands operators in the area reported waterfowl mortalities as well. Syncrude is cooperating fully with regulators in their investigation of this incident.
This incident follows the settlement of a 2008 waterfowl incident, announced on October 22, 2010, under which Syncrude paid a total of $3 million comprised of fines and payments to fund research for improved waterfowl deterrent systems, to create a waterfowl habitat-conservation project, and to create a Wildlife Management Program at Keyano College focused on Aboriginal students.
More information on Syncrude’s environmental and social responsibility performance is available in its 2008/2009 Sustainability Report, which is located on Syncrude’s website at www.syncrude.ca.
This press release contains statements about the future. See the forward looking advisory in the attached MD&A.
Canadian Oil Sands Trust Third Quarter Report 2010 4
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following Management’s Discussion and Analysis (“MD&A”) was prepared as of October 28, 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 nine months ended September 30, 2010 and September 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 dividends and any increase or decrease from current payment amounts; the Trust’s plans with regard to its net debt level; Crown royalties payable in 2010 and beyond; 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 or regulation, 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; 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.
Canadian Oil Sands Trust Third Quarter Report 2010 5
REVIEW OF SYNCRUDE OPERATIONS
During the third quarter of 2010, crude oil production from the Syncrude Joint Venture (“Syncrude”) totalled 24.3 million barrels, or 264,000 barrels per day, compared with 28.7 million barrels, or 312,000 barrels per day, during the same period of 2009. Net to the Trust, production totalled 8.9 million barrels in the third quarter of 2010 compared with 10.5 million barrels in the third quarter of 2009, based on our 36.74 per cent working interest.
Production volumes in the third quarter of 2010 were impacted by the planned turnaround on Coker 8-1 and unplanned maintenance in other upgrading units while the third quarter of 2009 production volumes were impacted by unplanned maintenance on the vacuum distillation unit.
Syncrude produced 78 million barrels through the first nine months of 2010, or about 286,000 barrels per day, compared with 72 million barrels, or about 264,000 barrels per day during the same period in 2009. Higher production in 2010 reflected less unplanned maintenance than in 2009 and only a portion of the impact of the Coker 8-1 turnaround, which began in early September and continues until late October. In contrast, 2009 production reflected the full impact of the more extensive Coker 8-3 turnaround.
Canadian Oil Sands’ operating costs were $355 million, or $39.99 per barrel, in the third quarter of 2010, compared to $293 million, or $27.80 per barrel, in the same quarter of 2009 (see the “Operating Costs” section of this MD&A for further discussion).
The productive capacity of Syncrude’s facilities is approximately 350,000 barrels per day on average, including an allowance for downtime, and is referred to as “barrels per calendar day”. All references to Syncrude’s production capacity in this report refer to barrels per calendar day, unless stated otherwise. The Trust’s production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes.
Canadian Oil Sands Trust Third Quarter Report 2010 6
SUMMARY OF QUARTERLY RESULTS
| 2010 2009 | 2008 | ||
| ($ millions, except per Trust Unit and volume amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 | |||
| Revenues (1) Net income Per Trust Unit, Basic & Diluted Cash from operating activities Per Trust Unit (2) Unitholder distributions Per Trust Unit Daily average sales volumes (bbls) (3) Net realized SCO selling price ($/bbl) (4) Operating costs ($/bbl) (5) | $ 6 92 $ 842 $ 7 34 $ 1 71 $ 237 $ 167 $ 0 .35 $ 0 .49 $ 0.35 $ 3 30 $ 358 $ 3 09 $ 0 .68 $ 0.74 $ 0.64 $ 2 42 $ 242 $ 1 70 $ 0.50 $ 0.50 $ 0.35 96,477 118,569 99,286 $ 77.94 $ 78.07 $ 82.06 $ 39.99 $ 31.18 $ 39.59 $ 3 .44 $ 3.68 $ 4.95 $ 76.21 $ 78.05 $ 78.88 $ 0 .96 $ 0.97 $ 0.96 $ 0 .97 $ 0.94 $ 0.98 | $ 863 $ 773 $ 467 $ 512 $ 96 $ 247 $ 46 $ 43 $ 0.20 $ 0.51 $ 0.10 $ 0.09 $ 328 $ 213 $ ( 44) $ 50 $ 0.68 $ 0.44 $ (0.09) $ 0.10 $ 169 $ 121 $ 73 $ 72 $ 0.35 $ 0.25 $ 0.15 $ 0.15 119,287 114,544 75,553 102,825 $ 78.67 $ 73.31 $ 67.92 $ 55.32 $ 30.18 $ 27.80 $ 50.23 $ 38.78 $ 4.33 $ 2.90 $ 3.09 $ 4.96 $ 76.13 $ 68.24 $ 59.79 $ 43.31 $ 0.95 $ 0.91 $ 0.86 $ 0.80 $ 0.96 $ 0.93 $ 0.86 $ 0.79 | $ 704 $ 124 $ 0.26 $ 466 $ 0.97 $ 361 $ 0.75 110,197 $ 69.40 $ 32.10 |
| Purchased natural gas price ($/GJ) | $ 6.41 | ||
| West Texas Intermediate (avg. US$/bbl) (6) Foreign exchange rates (US$/Cdn$): Average Quarter-end | $ 59.08 $ 0.83 $ 0.82 | ||
| (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 Flow s divided by the w eighted-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 expense, net income and cash from operating activities;
- Planned and unplanned maintenance activities as well as turnarounds have impacted quarterly production volumes, sales revenues 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;
- The transition to a new Crown royalty framework effective January 1, 2009 has impacted Crown royalties expense;
- 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; 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 is also impacted by unrealized foreign exchange gains and losses, impairment charges and future income tax amounts.
Canadian Oil Sands Trust Third Quarter Report 2010 7 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. The costs associated with these activities are expensed in the period they are incurred, which can lead to significant increases in quarterly operating costs. Because a large proportion of operating costs are fixed, 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 third quarter of 2010, the Trust reported net income of $171 million, or $0.35 per Unit, compared with $247 million, or $0.51 per Unit, recorded in the third quarter of 2009. The decrease in net income reflects lower revenues combined with higher operating expenses and smaller foreign exchange gains on the U.S. dollar denominated long-term debt, partially offset by lower Crown royalties, lower depreciation, depletion and accretion expense, and a future income tax recovery.
Net income for the first nine months of 2010 totalled $575 million, or $1.19 per Unit, compared with net income of $336 million, or $0.69 per Unit, for the same period in 2009. The increase reflects higher revenues partially offset by higher operating expenses, higher Crown royalties, smaller foreign exchange gains on the U.S. dollar denominated long-term debt, and a smaller future income tax recovery.
Revenues after crude oil purchases and transportation costs totalled $692 million in the third quarter of 2010 versus $773 million in the third quarter of 2009. On a year-to-date basis, revenues after crude oil purchases and transportation costs totalled $2,268 million in 2010 versus $1,752 million for the first nine months of 2009. The decrease in quarter-over-quarter revenues reflects lower production volumes partially offset by higher crude oil prices in the third quarter of 2010 while the increase in year-to-date revenues reflects 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 $330 million, or $0.68 per Unit, for the third quarter of 2010. This compares with cash from operating activities of $213 million, or $0.44 per Unit, for the third quarter of 2009. Despite decreases in quarter-over-quarter revenues and increases in quarter-over-quarter
Canadian Oil Sands Trust Third Quarter Report 2010 8 operating costs, cash from operating activities was higher due to a reduction in non-cash working capital during the third quarter of 2010. The third quarter 2010 non-cash working capital decrease was the result of lower accounts receivable and higher accounts payable at September 30, 2010 relative to June 30, 2010, mainly as a result of the Coker 8-1 turnaround.
Year-to-date cash from operating activities increased to $997 million for 2010 from $219 million in 2009. The increase was due to higher revenues partially offset by higher operating expenses and Crown royalties. In addition, non-cash working capital decreased during the first nine months of 2010 as a result of lower accounts receivable and higher accounts payable at September 30, 2010 relative to December 31, 2009 mainly as a result of the Coker 8-1 turnaround.
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 and inventory fluctuations.
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 net of 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.
Canadian Oil Sands Trust Third Quarter Report 2010 9
Net Income per Barrel
| Three Months Ended Nine Months Ended September 30 September 30 ($ per bbl) 1 2010 2009 Variance 2010 2009 Variance | ||
|---|---|---|
| Revenues after crude oil purchases and transportation expense Operating costs Crown royalties | 77.94 73.31 4.63 79.28 65.67 (39.99) (27.80) (12.19) (36.54) (37.39) (7.66) (10.25) 2.59 (8.08) (5.07) | 13.61 0.85 (3.01) |
| 30.29 35.26 (4.97) 34.66 23.21 | 11.45 | |
| (2.88) (3.19) 0.31 (2.83) (3.95) (0.88) (0.83) (0.05) (0.99) (0.91) (2.44) (2.40) (0.04) (2.44) (2.63) (10.66) (11.62) 0.96 (10.20) (11.60) (0.62) - (0.62) (0.36) - 3.45 8.57 (5.12) 0.88 5.18 3.02 (2.35) 5.37 1.35 3.30 | ||
| Non-production costs Administration and insurance Interest, net Depreciation, depletion and accretion Loss on disposal of assets Foreign exchange gain Future income tax (expense) recovery | 1.12 (0.08) 0.19 1.40 (0.36) (4.30) (1.95) | |
| (11.01) (11.82) 0.81 (14.59) (10.61) | (3.98) | |
| Net income per barrel | 19.28 23.44 (4.16) 20.07 12.60 | 7.47 |
| 8.9 10.6 (1.7) 28.6 26.7 | ||
| Sales volumes (MMbbls) 2 | 1.9 | |
| 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, net of purchased crude oil volumes. |
Revenues after Crude Oil Purchases and Transportation Expense
| Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2010 2009 Variance 2010 2009 Variance | ||||
|---|---|---|---|---|
| Sales revenue 1 Crude oil purchases Transportation expense | $ 7 44 $ 8 08 $ ( 64) $ 2,521 (48) (28) (20) (236) (5) (8) 3 (20) | $ 1,881 $ 6 40 (109) (127) (23) 3 | ||
| Currency hedging gains 1 | 691 772 (81) 2,265 1 1 - 3 | 1,749 516 3 - | ||
| $ 6 92 $ 7 73 $ ( 81) $ 2,268 | $ 1,752 $ 5 16 | |||
| Sales volumes (MMbbls) 2 | 8.9 10.6 (1.7) 28.6 | 26.7 1.9 | ||
| 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, net of purchased crude oil volumes. ($ per barrel) | ||||
| Realized SCO selling price before hedging 3 Currency hedging gains | $ 77.84 $ 73.22 $ 4 .62 $ 79.18 0.10 0.09 0.01 0.10 | $ 65.57 $ 13.61 0.10 - | ||
| Net realized SCO selling price | $ 77.94 $ 73.31 $ 4 .63 $ 79.28 | $ 65.67 $ 13.61 | ||
| 3 SCO sales revenu | e net of crude oil purchases and transportation expense divided by sales volumes, net of purchased crude | oil volumes. |
The decrease in sales revenue after crude oil purchases and transportation expense in the third quarter of 2010 relative to 2009 reflects lower sales volumes partially offset by a higher realized selling price for our synthetic crude oil (“SCO”). During the third quarter of 2010, West Texas Intermediate (“WTI”) crude oil price averaged U.S. $76 per barrel compared to U.S. $68 per barrel in the third quarter of 2009. The impact of the higher U.S. dollar WTI oil price in the third quarter of 2010 was offset somewhat by a stronger Canadian dollar, which averaged $0.96 U.S./Cdn for the third quarter of 2010 versus $0.91 U.S./Cdn for the third quarter of 2009. Year-to-date, WTI averaged U.S. $78 per barrel in 2010 versus
Canadian Oil Sands Trust Third Quarter Report 2010 10 U.S. $57 per barrel in 2009 while the Canadian dollar averaged $0.97 U.S./Cdn in 2010 versus $0.85 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 third quarter of 2010, the Trust realized a weighted-average SCO discount of $1.46 per barrel versus a $1.66 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 third quarter sales volumes averaged 96,000 barrels per day and 115,000 barrels per day in 2010 and 2009, respectively. The decline in 2010 sales volumes reflects the Coker 8-1 turnaround, which began in early September and continues until late October, as well as unplanned maintenance in other upgrading units. Sales volumes for the first nine months of 2010 averaged 105,000 barrels per day versus 98,000 barrels per day for the first nine months of 2009. Sales volumes for 2010 reflected turnarounds of the LC Finer and Coker 8-1 and unplanned maintenance in other upgrading units. By comparison, sales volumes in 2009 were impacted by an extended turnaround and modifications on Coker 8-3 and related units, as well as unplanned outages in the mining operations and unplanned maintenance in upgrading.
The Trust purchases crude oil from third parties, from time to time, 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 and incremental purchases associated with tankage arrangements, as well as higher crude oil prices compared with 2009.
Operating Costs
The following table breaks down operating costs into their major components and shows per barrel bitumen and SCO costs. 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.
Canadian Oil Sands Trust Third Quarter Report 2010 11
| Three Months Ended Nine Months Ended | |||||
| September 30 September 30 | |||||
| 2010 2009 2010 2009 | |||||
| $/bbl Bitumen | $/bbl SCO | $/bbl $/bbl $/bbl $/bbl $/bbl $/bbl Bitumen SCO Bitumen SCO Bitumen SCO | |||
| $ 20.99 $ 27.28 $ 15.26 $ 17.61 $ 20.17 $ 24.48 $ 20.46 $ 24.30 2.01 2.61 2.08 2.40 2.52 3.05 2.31 2.74 | |||||
| Bitumen production Internal fuel allocation 2 | |||||
| Total produced bitumen costs | |||||
| Upgrading costs 1 Less: Internal fuel allocation to bitumen 2 Bitumen purchases | |||||
| Total Syncrude operating costs Canadian Oil Sands' adjustments 3 | 40.07 27.66 37.29 37.95 (0.08) 0.14 (0.75) (0.56) | ||||
| Total operating costs | 39.99 27.80 36.54 37.39 | ||||
| (thousands of barrels per day) | Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO | ||||
| Syncrude production volumes 4 343 264 360 312 347 286 314 264 |
1Upgrading 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.
2Natural gas prices averaged $3.44 per GJ and $4.05 per GJ for the three and nine months ended September 30, 2010, respectively and $2.90 per GJ and $3.84 per GJ for the three and nine months ended September 30, 2009, respectively.
3Canadian Oil Sands’ adjustments mainly pertain to actual reclamation costs, Syncrude-related pension costs, as well as the inventory impact of moving from production to sales as Syncrude reports per barrel costs based on production volumes and the Trust reports based on sales volumes.
4Syncrude SCO production volumes include the impact of processed purchased bitumen volumes.
| Three Months Ended Nine Months Ended | |||
| Septem ($/bbl of SCO) 2010 | ber 30 2009 | September 30 2010 2009 | |
| Production costs Purchased energy | |||
| Total operating costs | 39.99 27.80 $ 36.54 $ 37.39 | ||
| (GJs/bbl of SCO) | |||
| Purchased energy consumption | 1.15 0.87 1.03 1.03 |
In the third quarter of 2010, operating costs were $355 million, averaging $39.99 per barrel, compared with $293 million, or $27.80 per barrel in the third quarter of 2009. Year-to-date operating costs were $1,045 million in 2010, averaging $36.54 per barrel, compared with $997 million, or $37.39 per barrel, in 2009.
The increase in total operating costs for the third quarter of 2010 relative to the third quarter of 2009 was primarily due to the turnaround of Coker 8-1 combined with increased maintenance costs on other upgrading units.
The increase in year-to-date total operating costs for 2010 relative to 2009 was primarily due to the following:
- Higher maintenance costs in 2010 in mining, extraction, and upgrading;
- Additional costs supporting large projects such as mine train relocations and tailings pond dam construction; and
- Increased diesel purchases to support mining equipment and supplement decreased diesel production.
Canadian Oil Sands Trust Third Quarter Report 2010 12