<<
All financial figures are unaudited and in Canadian dollars unless
otherwise noted.
TSX - COS.UN
>>
CALGARY, Jan. 28 /CNW/ - Canadian Oil Sands Trust ("Canadian Oil Sands", the "Trust" or "we") recorded fourth quarter cash from operating activities of $466 million ($0.97 per Trust Unit ("Unit")) compared with $367 million ($0.77 per Unit) for the fourth quarter of 2007. Net income for the fourth quarter 2008 was $124 million ($0.26 per Unit) compared with net income of $515 million ($1.07 per Unit) for the same period in 2007. The decrease in net income is primarily a result of lower revenues, higher operating costs, unrealized foreign exchange losses on long-term debt and lower future income tax recoveries. The increase in quarter-over-quarter cash from operating activities reflects net income changes as well as changes in non-cash working capital. Annual cash from operating activities for 2008 amounted to $2.2 billion ($4.66 per Unit) compared with $1.4 billion ($2.87 per Unit) in 2007. Net income in 2008 was $1.5 billion ($3.17 per Unit) compared with $743 million ($1.55 per Unit) in 2007. The increase in cash from operating activities and net income in 2008 over the prior year is primarily a result of higher revenues during the first three quarters of the year net of increases in operating expenses and Crown royalties. As well, 2007 net income reflects a one-time future income tax expense of $701 million relating to trust taxation. The Trust's financial performance during the fourth quarter of 2008 reflects the impact of the significant decline in crude oil prices relative to the first nine months of the year. With crude oil prices continuing to decline into 2009 and the effect on the Trust's cash from operating activities, the Trust has reduced its distribution for the first quarter of 2009 to $0.15 per Unit. We believe this distribution cut is a prudent measure to manage liquidity in the current business environment. It is also consistent with our strategy of managing the Trust with a long-term view. The distribution will paid to Unitholders of record on February 9, 2009, payable on February 27, 2009. As well, the Trust is reinstating its Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP"). Eligible Unitholders may elect to participate in the DRIP for the February distribution; see details at the end of this release. "Crude oil prices have continued to decline since our third quarter release, significantly reducing earnings," said Marcel Coutu, President and Chief Executive Officer. "With an expectation that near-term crude oil prices will remain weak, we deemed it prudent to reduce the distribution to reflect this lower price environment and to preserve our financial flexibility. The re-activation of our DRIP should further support balance sheet equity and distributions, as we manage our business through this challenging economic period. It also offers significant benefits to participating Unitholders by allowing them to reinvest their distribution to receive new Canadian Oil Sands Units at a five per cent discount to a weighted average trading price, or a premium distribution amount." Added Mr. Coutu: "I believe Syncrude remains the best positioned oil sands operator. We are maintaining a capital program that addresses our needs to sustain our business infrastructure, as well as continuing the pre-engineering work for the Stage 3 debottleneck expansion." Sales volumes in the fourth quarter of 2008 totalled 10.1 million barrels (110,200 barrels per day) compared with 10.7 million barrels (116,400 barrels per day) in the equivalent 2007 period. Production volumes in the fourth quarter of 2008 were reduced by a scheduled coker turnaround and constrained bitumen production while the 2007 fourth quarter was impacted by a shorter, unplanned coker outage. Sales volumes in 2008 totalled 38.8 million barrels (106,000 barrels per day) compared with 41.0 million barrels (112,300 barrels per day) in 2007. The decline reflects more facility downtime in 2008 with two planned coker turnarounds and a disruption in operations during the first quarter. As well, reliability issues constrained bitumen production in 2008. Operating costs in 2008 were $35.26 per barrel, an increase of $10.03 per barrel from 2007. The increase primarily reflects: higher volumes of overburden removed in 2008 than 2007 and increased use of contractors to support this activity; inflationary cost increases; bitumen purchases during the first half of 2008; additional costs associated with the operational upset in the first quarter 2008; and higher natural gas consumption and prices in 2008. The lower production volumes in 2008 compared with 2007 also contributed to higher per barrel operating costs. On December 31, 2008, a Syncrude employee died on site while working in the hydroprocessing area. Occupational Health and Safety investigators have completed their initial investigation into the fatality and Syncrude is now conducting its own full investigation. Syncrude is committed to the safety of its employees and is deeply sorry that this tragic incident occurred. Our condolences are with the family. In 2008, Syncrude's total recordable injury rate was 0.59 for every 200,000 hours worked compared with a rate of 0.70 recorded in 2007.
<<
CANADIAN OIL SANDS TRUST
Highlights
(millions of Canadian Three Months Ended Twelve Months Ended
dollars, except Trust December 31 December 31
unit and volume amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Net Income $ 124 $ 515 $ 1,523 $ 743
Per Trust unit- Basic $ 0.26 $ 1.07 $ 3.17 $ 1.55
Per Trust unit- Diluted $ 0.26 $ 1.07 $ 3.16 $ 1.54
Cash from Operating
Activities $ 466 $ 367 $ 2,241 $ 1,377
Per Trust unit $ 0.97 $ 0.77 $ 4.66 $ 2.87
Unitholder Distributions $ 361 $ 264 $ 1,804 $ 791
Per Trust unit $ 0.75 $ 0.55 $ 3.75 $ 1.65
Sales Volumes(1)
Total (MMbbls) 10.1 10.7 38.8 41.0
Daily average (bbls) 110,197 116,368 105,986 112,298
Operating Costs per barrel $ 32.10 $ 27.38 $ 35.26 $ 25.23
Net Realized SCO Selling
Price per barrel $ 69.40 $ 88.73 $ 106.91 $ 79.29
West Texas Intermediate
(average $US per barrel)(2) $ 59.08 $ 90.50 $ 99.75 $ 72.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 net of purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.
>>
2009 Outlook The Trust is estimating annual Syncrude production of 115 million barrels (315,000 barrels per day) in 2009 with a range 110 to 120 million barrels. Net to the Trust, this is equivalent to 42.3 million barrels (115,800 barrels per day) with a range of 40 to 44 million barrels. This estimate includes a turnaround of Coker 8-3 in the second quarter of 2009 as well as other maintenance work. The Trust also estimates operating expenses of $30.76 per barrel and Syncrude capital expenditures of $1,197 million ($440 million net to the Trust) in 2009. Cash from operating activities is estimated to be $1.55 per Unit based on current assumptions, including an average West Texas Intermediate ("WTI") crude oil price of US$50 per barrel in 2009.
<<
Premium Distribution, Distribution Re-Investment and Optional Unit
Purchase Plan (DRIP)
>>
Canadian Oil Sands is reinstating its Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP"). The DRIP allows eligible Unitholders to direct their distributions to the purchase of additional units at 95 per cent of the average market price, as defined in the DRIP. Alternatively, eligible Unitholders may elect under the premium distribution component to have their distributions invested in new units and exchanged through the DRIP Broker for a premium distribution equal to 102 per cent of the amount that the Unitholder would otherwise have received on the distribution date (subject to proration and withholding tax reductions in certain circumstances). The DRIP allows those Unitholders who participate in either the regular distribution re-investment or premium distribution component of the DRIP to purchase additional Units from treasury at the average market price in minimum amounts of $1,000 per remittance and maximum amounts of $100,000, in a given quarter, all subject to an overall annual limit of two per cent of the outstanding trust units being offered for purchase in this manner. The DRIP provides Unitholders with several options to manage their distribution payments in a cost-effective, convenient manner. There are no brokerage fees or commissions payable by participants for the purchase of Units under the DRIP. Eligible Unitholders may elect to participate in the DRIP for the February distribution by enrolling in the plan by February 6, 2009 through Computershare Trust Company of Canada at 1-800-564-6253. More information on the DRIP is available on Canadian Oil Sands' website at www.cos-trust.com, or by contacting the Trust at (403) 218-6220 or Computershare. Only Canadian resident Unitholders are eligible to participate in the DRIP at this time. More information on the Trust's Outlook, including detailed analysis of 2009 cost estimates, is provided in the MD&A section of this report and the January 28, 2009 guidance document, which is available on the Trust's web site at www.cos-trust.com under "Investor". MANAGEMENT'S DISCUSSION AND ANALYSIS The following Management's Discussion and Analysis ("MD&A") was prepared as of January 28, 2009 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 twelve months ended December 31, 2008 and December 31, 2007, and the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2007 and the Trust's Annual Information Form ("AIF") dated March 15, 2008. 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. 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 expectations regarding the preservation of financial flexibility and the ability to meet operating and capital costs from the assumed cash from operating activities for 2009; future royalty rates under the New Royalty Framework post-2015; the expected increase in the Trust's depreciation and depletion rate; the expected impact on the Trust and distributions and the expected structure to be assumed given the Federal government's tax changes effective in 2011; the impact that continued credit market turmoil and low crude prices may have on distributions; the belief that debt covenants will not influence the Trust's liquidity in the foreseeable future or limit the Trust's ability to pay distributions; expectations regarding the sustainability of operations at certain levels of WTI prices; future distributions and any increase or decrease from current payment amounts; plans regarding refinancing of the 2009 debt maturities and views on future credit markets, accessibility of capital markets, and availability of financing and the impact on distributions; the belief that operational reliability will improve over time and with that improvement that operating costs will be reduced; the expected level of sustaining capital for the next few years and longer term; the expectations regarding bitumen purchases, capital expenditures and operating costs; the cost estimate for the 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; the expected impact of any current and future environmental legislation, including without limitation, regulations relating to tailings; the expectation that there will not be any material funding increases relative to Syncrude's future reclamation costs or pension funding for the next year; the belief that the Trust will not be restricted by its net debt to total capitalization financial covenant; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2009 for Canadian Oil Sands' product; the expectation that no crude oil hedges will be entered into in the future; the potential amount payable in respect of any future income tax liability; the plans regarding future expansions of the Syncrude project and in particular all plans regarding Stage 4 development; the level of energy consumption in 2009 and beyond; capital expenditures for 2009; the level of natural gas consumption in 2009 and beyond; the expected price for crude oil and natural gas in 2009; the expected production, revenues and operating costs for 2009; 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; 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, and such other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by the Trust. 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 fourth quarter of 2008, crude oil production from the Syncrude Joint Venture ("Syncrude") totalled 28.4 million barrels, or 308,000 barrels per day, compared with 28.8 million barrels, or 313,000 barrels per day, during the same period of 2007. Net to the Trust, production totalled 10.4 million barrels in the fourth quarter of 2008 compared with 10.6 million barrels in 2007, based on our 36.74 per cent working interest. Production volumes in the fourth quarter of 2008 were primarily impacted by a scheduled turnaround on Coker 8-2, which started in September and was completed during the first week of November. Production volumes during the fourth quarter were also impacted by constrained bitumen production, which was exacerbated by reliability issues. In comparison, fourth quarter 2007 production volumes were reduced by unplanned Coker 8-3 outages. On an annual basis, Syncrude produced 105.8 million barrels in 2008, or 289,000 barrels per day, compared with 111.3 million barrels, or 305,000 barrels per day in 2007. In addition to planned coker turnarounds during the second and fourth quarters, production in 2008 was impacted by constrained bitumen production and by a disruption in operations during the first quarter that was compounded by extremely cold weather. The cold weather during the first quarter of 2008 also affected bitumen production and extraction. By comparison, annual 2007 production was impacted by unplanned maintenance on Coker 8-3 and Coker 8-2, and planned maintenance on other units. Operating costs increased to $32.10 per barrel in the fourth quarter of 2008, up $4.72 per barrel from the same quarter last year. Year-to-date operating costs were $35.26 per barrel in 2008 versus $25.23 per barrel in 2007 (see the "Operating costs" section of this MD&A for further discussion). Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. Under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of operational and mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's facilities is approximately 350,000 barrels per day on average and is referred to as "barrels per calendar day". All references to Syncrude's productive capacity in this report refer to barrels per calendar day, unless stated otherwise. The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes that vary with current production. The impact of Syncrude's 2008 operations on Canadian Oil Sands' financial results is more fully discussed later in this MD&A.
<<
SUMMARY OF QUARTERLY RESULTS
($ millions, except
per Trust Unit and 2008
volume amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Revenues(1) $ 704 $ 1,381 $ 1,177 $ 907
Net income (loss) $ 124 $ 604 $ 497 $ 298
Per Trust Unit, Basic $ 0.26 $ 1.25 $ 1.04 $ 0.62
Per Trust Unit, Diluted $ 0.26 $ 1.25 $ 1.04 $ 0.62
Cash from operating
activities $ 466 $ 921 $ 413 $ 441
Per Trust Unit(2) $ 0.97 $ 1.91 $ 0.86 $ 0.92
Unitholder distributions $ 361 $ 602 $ 481 $ 360
Per Trust Unit $ 0.75 $ 1.25 $ 1.00 $ 0.75
Daily average sales
volumes (bbls)(3) 110,197 116,656 97,744 99,181
Net realized SCO selling
price ($/bbl)(4) $ 69.40 $ 127.55 $ 131.32 $ 100.41
Operating costs ($/bbl)(5) $ 32.10 $ 32.15 $ 41.92 $ 35.93
Purchased natural gas
price ($/GJ) $ 6.41 $ 7.86 $ 9.38 $ 7.30
West Texas Intermediate
(avg. US$/bbl)(6) $ 59.08 $ 118.22 $ 123.80 $ 97.82
Foreign exchange rates
(US$/Cdn$):
Average $ 0.83 $ 0.96 $ 0.99 $ 1.00
Quarter-end $ 0.82 $ 0.94 $ 0.98 $ 0.97
($ millions, except
per Trust Unit and 2007
volume amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Revenues(1) $ 950 $ 936 $ 690 $ 674
Net income (loss) $ 515 $ 361 $ (395) $ 262
Per Trust Unit, Basic $ 1.07 $ 0.75 $ (0.82) $ 0.55
Per Trust Unit, Diluted $ 1.07 $ 0.75 $ (0.82) $ 0.54
Cash from operating
activities $ 367 $ 484 $ 324 $ 202
Per Trust Unit(2) $ 0.77 $ 1.01 $ 0.68 $ 0.42
Unitholder distributions $ 264 $ 192 $ 191 $ 144
Per Trust Unit $ 0.55 $ 0.40 $ 0.40 $ 0.30
Daily average sales
volumes (bbls)(3) 116,368 124,904 98,720 108,981
Net realized SCO selling
price ($/bbl)(4) $ 88.73 $ 81.48 $ 76.81 $ 68.69
Operating costs ($/bbl)(5) $ 27.38 $ 20.84 $ 30.13 $ 23.56
Purchased natural gas
price ($/GJ) $ 5.84 $ 4.99 $ 6.78 $ 6.99
West Texas Intermediate
(avg. US$/bbl)(6) $ 90.50 $ 75.15 $ 65.02 $ 58.23
Foreign exchange rates
(US$/Cdn$):
Average $ 1.02 $ 0.96 $ 0.91 $ 0.85
Quarter-end $ 1.01 $ 1.00 $ 0.94 $ 0.87
(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 West Texas Intermediate ("WTI") oil
prices significantly impacted the Trust's revenues, Crown royalties
and net income.
- The substantive enactment of income tax legislation in June 2007
resulted in an additional future income tax expense of $701 million
in the second quarter of 2007. Other corporate tax rate reductions
substantively enacted in the fourth and second quarters of 2007
resulted in future income tax recoveries of $153 million and
$38 million in each quarter, respectively.
- U.S. to Canadian dollar exchange rate fluctuations have resulted in
significant unrealized foreign exchange gains and losses on the
revaluation of U.S. dollar denominated debt and have impacted
commodity pricing.
- Planned and unplanned maintenance activities have impacted quarterly
production volumes, sales revenues and operating costs.
>>
Quarterly variances in revenues, net income, and cash from operating activities are caused by fluctuations in crude oil prices, production and sales volumes, operating costs and natural gas prices. Net income also is impacted by foreign exchange gains and losses and by future income tax amounts. A large proportion of operating costs are fixed and, as such, per barrel operating costs are highly variable to production volumes. 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. Maintenance and turnaround activities are typically scheduled to avoid the winter months. However, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages may occur. Accordingly, production levels may not display reliable seasonality patterns or trends. Maintenance and turnaround costs are expensed in the period incurred and can lead to significant increases in operating costs and reductions in production in those periods. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is significantly influenced by weather conditions and North American natural gas inventory levels. REVIEW OF FINANCIAL RESULTS In the fourth quarter of 2008, net income amounted to $124 million, or $0.26 per Trust unit ("Unit"), compared with net income of $515 million, or $1.07 per Unit, recorded in the comparable quarter in 2007, primarily as a result of lower revenues and unrealized foreign exchange losses on long term debt. On an annual basis, net income totalled $1.5 billion, or $3.17 per Unit, in 2008 compared with net income of $743 million, or $1.55 per Unit, recorded in 2007. The improvement in net income was primarily the result of higher revenues reflecting higher crude oil prices during the first three quarters of 2008, net of higher operating costs and Crown royalties, without the impact of a one-time future income tax expense of $701 million that was recorded in the second quarter of 2007. Cash from operating activities increased to $466 million for the fourth quarter of 2008 versus $367 million for the fourth quarter of 2007. The change in quarter-over-quarter cash from operating activities primarily resulted from changes in non-cash working capital, which more than offset lower revenues and higher operating costs. Changes in non-cash working capital increased cash from operating activities by $174 million in the fourth quarter of 2008, primarily as a result of lower accounts receivable at December 31, 2008 versus September 30, 2008. The decline in accounts receivable reflected lower oil prices in December versus September 2008, offset slightly by higher sales volumes. In the fourth quarter of 2007, changes in non-cash working capital decreased cash from operating activities by $142 million, primarily as a result of higher accounts receivable and lower accounts payable at December 31, 2007 relative to September 30, 2007. Year-to-date cash from operating activities increased to $2.2 billion for 2008 versus $1.4 billion for 2007. The increase was due to higher revenues net of increases in operating expenses and Crown royalties as well as changes in non-cash working capital. Year-to-date changes in non-cash working capital increased cash from operating activities by $202 million in 2008, primarily as a result of lower accounts receivable, reflecting lower commodity prices at December 31, 2008 relative to December 31, 2007. In the same period of 2007, changes in non-cash working capital decreased cash from operating activities by $165 million, primarily as a result of higher accounts receivable offset by higher accounts payable at December 31, 2007 relative to December 31, 2006. Non-cash working capital and changes therein can vary on a period-by-period basis as a result of the timing and settlements of accounts receivable and accounts payable balances, and are impacted by a number of factors including changes in revenue, operating expenses, Crown royalties, the timing of capital expenditures, and inventory fluctuations.
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Net Income per Barrel
Three Months Ended Year Ended
December 31 December 31
($ per bbl)(1) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Revenues after crude
oil purchases and
transportation
expense 69.43 88.73 (19.30) 107.47 79.29 28.18
Operating costs (32.10) (27.38) (4.72) (35.26) (25.23) (10.03)
Crown royalties (5.84) (12.81) 6.97 (15.44) (11.83) (3.61)
-------------------------------------------------------------------------
31.49 48.54 (17.05) 56.77 42.23 14.54
-------------------------------------------------------------------------
Non-production costs (2.36) (1.33) (1.03) (2.00) (1.54) (0.46)
Administration and
insurance (0.35) (0.76) 0.41 (0.61) (0.69) 0.08
Interest, net (1.80) (1.63) (0.17) (1.75) (2.08) 0.33
Depletion,
depreciation and
accretion (11.73) (8.47) (3.26) (11.46) (8.56) (2.90)
Foreign exchange
gain (loss) (10.40) 0.53 (10.93) (4.09) 2.86 (6.95)
Future income tax
(expense) recovery
and other 7.33 11.00 (3.67) 2.39 (14.12) 16.51
-------------------------------------------------------------------------
(19.31) (0.66) (18.65) (17.52) (24.13) 6.61
-------------------------------------------------------------------------
Net income per
barrel 12.18 47.88 (35.70) 39.25 18.10 21.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sales volumes
(MMbbls)(2) 10.1 10.7 (0.6) 38.8 41.0 (2.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
>>
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 and certain per barrel measures. These 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.
<<
Revenues after Crude Oil Purchases and Transportation Expense
Three Months Ended Year Ended
December 31 December 31
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Sales revenue(1) $ 767 $ 1,004 $ (237) $ 4,539 $ 3,622 $ 917
Crude oil purchases (54) (49) (5) (337) (348) 11
Transportation
expense (10) (8) (2) (37) (35) (2)
-------------------------------------------------------------------------
703 947 (244) 4,165 3,239 926
Currency hedging
gains(1) 1 3 (2) 4 11 (7)
-------------------------------------------------------------------------
$ 704 $ 950 $ (246) $ 4,169 $ 3,250 $ 919
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sales volumes
(MMbbls)(2) 10.1 10.7 (0.6) 38.8 41.0 (2.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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) $ 69.31 $ 88.50 $(19.19) $106.81 $ 79.02 $ 27.79
Currency hedging
gains 0.09 0.23 (0.14) 0.10 0.27 (0.17)
-------------------------------------------------------------------------
Net realized SCO
selling price $ 69.40 $ 88.73 $(19.33) $106.91 $ 79.29 $ 27.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(3) SCO sales revenue after crude oil purchases and transportation
expense divided by sales volumes, net of purchased crude oil volumes.
>>
The decrease in fourth quarter sales revenue for 2008 versus 2007 was primarily due to a lower realized selling price for our synthetic crude oil ("SCO"). During the fourth quarter of 2008, WTI prices averaged US$59.08 per barrel compared to US$90.50 per barrel for the fourth quarter of 2007. The decrease in US dollar WTI prices during the fourth quarter of 2008 was tempered by a weaker Canadian dollar, which averaged $0.83 US/Cdn for the fourth quarter of 2008 versus $1.02 US/Cdn for the fourth quarter of 2007. The increase in sales revenue on an annual basis in 2008 versus 2007 was due to higher realized selling prices for SCO during the first three quarters of 2008 offset by a decline in sales volumes and lower selling prices during the fourth quarter of 2008. WTI prices averaged US$113.52 per barrel for the first nine months of 2008 compared to US$66.22 per barrel for the first nine months of 2007. On an annual basis, WTI prices averaged US$99.75 per barrel in 2008 versus US$72.36 per barrel in 2007. In addition to the impacts of changes in WTI prices, the Trust's SCO price is affected by a premium or discount relative to Canadian dollar WTI (the "differential"). In the fourth quarter of 2008, the Trust's SCO realized a weighted-average discount of $1.63 per barrel versus a discount of $0.54 per barrel for the same period of 2007. On an annual basis, the Trust's SCO realized a weighted-average premium of $1.94 per barrel in 2008 versus a premium of $1.63 per barrel for 2007. 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 sales volumes for the fourth quarter of 2008 averaged 110,000 barrels per day versus an average of 116,000 barrels per day in the fourth quarter of 2007. Sales volumes during the fourth quarter of 2008 were impacted by a scheduled coker turnaround and by constrained bitumen production. In comparison, fourth quarter 2007 sales were impacted by an unplanned Coker 8-3 outage. Year-to-date sales volumes averaged 106,000 barrels per day in 2008 versus an average of 112,000 barrels per day for 2007. Sales volumes for 2008 were impacted by the scheduled turnarounds of Cokers 8-2 and 8-1, operational difficulties during the first quarter and bitumen production constraints. Sales volumes in 2007 were impacted by maintenance on Coker 8-3, Coker 8-2 and other units.
<<
Operating Costs
Three Months Ended Year Ended
December 31 December 31
2008 2007 2008 2007
-------------------------------------------------------------------------
$/bbl $/bbl $/bbl $/bbl $/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO
-------------------------------------------------------------------------
Bitumen Costs(1)
Bitumen
production(2) 17.12 12.04 15.76 10.64
Purchased
energy(2),(4) 2.35 2.33 2.83 2.19
Purchased
bitumen - - 0.90 -
-------------------------------------------------------------------------
19.47 22.29 14.37 17.49 19.49 22.82 12.83 15.26
-------------------------------------------------------------------------
Upgrading Costs(3)
Bitumen
processing and
upgrading(2) 5.46 3.63 5.83 4.35
Turnaround and
catalysts 1.09 0.45 1.81 1.05
Purchased
energy(4) 3.52 2.77 3.94 2.55
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10.07 6.85 11.58 7.95
-------------------------------------------------------------------------
Other and
research(2) 0.34 2.54 1.04 1.43
Change in treated
and untreated
inventory 0.52 (0.37) 0.06 (0.02)
-------------------------------------------------------------------------
Total Syncrude
operating
costs 33.22 26.51 35.50 24.62
Canadian Oil
Sands
adjustments(5) (1.12) 0.87 (0.24) 0.61
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Total operating
costs 32.10 27.38 35.26 25.23
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(thousands of
barrels per
day) Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO
-------------------------------------------------------------------------
Syncrude
production
volumes(6) 353 308 380 313 338 289 363 305
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(1) Bitumen costs relate to the removal of overburden, oil sands mining,
bitumen extraction and tailings dyke construction and disposal costs.
The costs are expressed on a per barrel of bitumen production basis
and converted to a per barrel of SCO based on the effective yield of
SCO from the processing and upgrading of bitumen.
(2) Prior year information has been restated for comparative purposes to
conform to a revised presentation of costs.
(3) 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.
(4) Natural gas prices averaged $6.41/GJ and $5.84/GJ in the fourth
quarter of 2008 and 2007, respectively. For the first twelve months
of the year, natural gas costs averaged $7.66/GJ and $6.14/GJ in 2008
and 2007, respectively.
(5) Canadian Oil Sands' adjustments mainly pertain to Syncrude-related
pension costs, as well as the inventory impact of moving from
production to sales as Syncrude reports per barrel costs based on
production volumes and the Trust reports based on sales volumes.
(6) Syncrude production volumes include the impact of processed purchased
bitumen volumes.
Three Months Ended Year Ended
December 31 December 31
($/bbl of SCO) 2008 2007 2008 2007
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Production costs 25.89 21.77 28.01 20.08
Purchased energy 6.21 5.61 7.25 5.15
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Total operating costs 32.10 27.38 35.26 25.23
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-------------------------------------------------------------------------
(GJs/bbl of SCO)
-------------------------------------------------------------------------
Purchased energy consumption 0.97 0.96 0.95 0.84
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-------------------------------------------------------------------------
>>
In the fourth quarter of 2008, operating costs were $326 million, averaging $32.10 per barrel, an increase of $33 million, or $4.72 per barrel, over fourth quarter 2007 operating costs of $293 million. Year-to-date operating costs were approximately $1.4 billion in 2008, averaging $35.26 per barrel, an increase of $334 million, or $10.03 per barrel over 2007. The change in operating costs for the reported periods is primarily due to the following: - additional overburden material was moved during 2008 versus 2007 in order to increase exposed mineable ore inventory. Syncrude also increased its use of contracted equipment and operators to supplement its own material movement activities in 2008; - increased costs for contractors and wages for Syncrude staff on a quarterly and on a year-to-date basis as a result of inflationary pressures and contract settlements; - higher energy costs reflecting increases in natural gas prices and purchased energy consumption, which rose on a per barrel basis due to operational inefficiencies during 2008; - the purchase of incremental bitumen during the first half of 2008 to support production during times of internal bitumen supply shortfalls; - inflationary pressure for materials and consumables; - additional costs during the first quarter of 2008 associated with the disruption of operations; and - higher maintenance costs in 2008 relative to 2007. The increase in costs was partially offset by a decrease in the value of Syncrude's long term incentive plan in 2008 versus 2007. A portion of Syncrude's long-term incentive plans is based on the market return performance of several Syncrude owners' shares and units, of which performance was weaker in the 2008 fourth quarter and year relative to 2007. Operating costs per barrel also have increased in 2008 as a result of reduced production volumes in 2008 versus 2007 on a quarterly and year-to-date basis. A significant portion of Syncrude's operating costs are fixed and as such, any change in production impacts per unit operating costs. Non-Production Costs Non-production costs totalled $24 million and $14 million in the fourth quarters of 2008 and 2007, respectively. Year-to-date non-production costs totalled $78 million for 2008 and $63 million for 2007. Non-production costs consist primarily of development expenditures relating to capital programs, which are expensed, such as: commissioning costs, 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 fourth quarter of 2008, Crown royalties decreased to $59 million, or $5.84 per barrel, from $137 million, or $12.81 per barrel, in the comparable 2007 quarter. Year-to-date Crown royalties increased to $599 million, or $15.44 per barrel, in 2008 from $485 million, or $11.83 per barrel in 2007. The change in Crown royalties in 2008 versus 2007 on both a quarterly and a year-to-date basis was due to changes in revenues net of allowed operating costs, non-production costs and capital expenditures. In the fourth quarter of 2008, Canadian Oil Sands and the other Syncrude joint venture owners exercised their pre-existing option to convert to a bitumen-based Crown royalty. Effective January 1, 2009, Syncrude will calculate Crown royalties based on deemed bitumen revenues less allowed bitumen operating, non-production and capital costs, rather than paying Crown royalties based on the production of SCO. As part of the conversion to a bitumen-based royalty, only costs related to producing bitumen rather than the fully upgraded SCO can be deducted. In addition, deductible costs in calculating Crown royalties will be reduced in future years by approximately $5 billion ($1.8 billion net to the Trust) resulting in future Crown royalties of approximately $1.25 billion ($459 million net to the Trust) over a 25-year period. The cost reductions relate to capital expenditures that were deducted in computing Crown royalties on SCO in prior years and are no longer associated with the royalty base. Also in the fourth quarter of 2008, Canadian Oil Sands and the other Syncrude joint venture owners reached an agreement with the Alberta government on terms to transition the Syncrude project to Alberta's new generic royalty regime. Under the agreement, the Syncrude joint venture owners will pay the greater of 25 per cent of net deemed bitumen revenues, or one per cent of gross deemed bitumen-based revenues, plus an additional royalty of up to $975 million ($358 million net to the Trust) for the period January 1, 2010 to December 31, 2015. The additional royalty of $975 million is reduced proportionally on bitumen production less than 345,000 barrels per day over the period and is to be paid in six annual installments. After 2015, the Syncrude project will be subject to the New Royalty Framework that applies to the entire oil sands industry. Currently, this generic royalty regime is based on a sliding scale rate that responds to Canadian dollar equivalent WTI ("C$-WTI") price levels. The minimum royalty will start at one per cent of deemed bitumen revenue and increase when C$-WTI oil is priced above $55 per barrel, to nine per cent of deemed bitumen revenue at $120 per barrel or higher. The net royalty rate will start at 25 per cent of net deemed revenue and rise for every dollar of C$-WTI increase above $55 per barrel up to 40 per cent of net deemed bitumen revenue at $120 per barrel or higher.
<<
Interest Expense, Net
Three Months Ended Twelve Months Ended
December 31 December 31
2008 2007 2008 2007
-------------------------------------------------------------------------
Interest expense on
long-term debt $ 20 $ 20 $ 76 $ 91
Interest income and other (1) (3) (8) (6)
-------------------------------------------------------------------------
Interest expense, net $ 19 $ 17 $ 68 $ 85
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Trust's interest expense on its long-term debt decreased in 2008 as a
result of reduced average net debt outstanding.
Depreciation, Depletion and Accretion Expense
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------------------------------------------------------------
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Depreciation and depletion
expense $ 115 $ 88 $ 430 $ 340
Accretion expense 4 3 14 11
-------------------------------------------------------------------------
$ 119 $ 91 $ 444 $ 351
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>>
The increase in depreciation and depletion ("D&D") expense in 2008 on a quarterly and year-to-date basis versus 2007 was due to a higher per barrel D&D rate. In 2008 the D&D rate per barrel of production increased to $11.07 from $8.31 in 2007 as a result of higher projected capital cost estimates in the Trust's December 31, 2007 independent reserves report. Based on preliminary reserve reports, we are not expecting any significant changes in the Trust's 2009 D&D rate from 2008.
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Foreign Exchange Loss (Gain)
Three Months Ended Twelve Months Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Unrealized foreign exchange
loss (gain) $ 142 $ (7) $ 204 $ (153)
Realized foreign exchange
loss (gain) (36) 2 (45) 36
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Total foreign exchange
loss (gain) $ 106 $ (5) $ 159 $ (117)
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>>
Unrealized foreign exchange ("FX") losses and gains 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. During 2008, the unrealized FX loss resulted from the weakening of the Canadian dollar relative to the U.S. dollar to $0.82 US/Cdn at December 31, 2008 from $0.94 US/Cdn at September 30, 2008 and $1.01 US/Cdn at December 31, 2007. The unrealized FX gains in 2007 were due to the strengthening of the Canadian dollar relative to the U.S. dollar to $1.01 US/Cdn at December 31, 2007 from $1.00 US/Cdn at September 30, 2007 and $0.86 US/Cdn at December 31, 2006. Realized FX losses and gains are primarily the result of the repayment of U.S. dollar denominated debt, the settlement of U.S. dollar denominated receivables and the revaluation of U.S. dollar cash balances. During the fourth quarter of 2008, the trust recognized FX gains primarily on the settlement of U.S. dollar denominated accounts receivable. During 2007, the Trust realized an FX gain of $18 million on the settlement of long-term debt and realized FX losses of $54 million on the settlement of U.S. dollar denominated accounts receivable and cash balances. Future Income Tax and Other In the fourth quarter of 2008, a $75 million future income tax recovery was recorded on the decrease of temporary differences between the accounting and tax values of Canadian Oil Sands' assets and liabilities. In the fourth quarter of 2007, future income tax recoveries of $118 million resulted from a reduction in corporate tax rates offset by an increase in temporary differences. On an annual basis a future income tax recovery of $93 million was recorded in 2008 on the reduction of temporary differences compared with a future income tax expense of $579 million in 2007. The 2007 future tax expense was primarily the result of a one-time $701 million future income tax expense recorded in the second quarter on the enactment of federal legislation to tax income trusts and the fourth quarter future income tax recovery. In June 2008 legislation to adjust the deemed provincial component of the tax on distributions from income and royalty trusts commencing in 2011 was passed in the House of Commons. Under this legislation, we expect the provincial component of the tax applicable to Canadian Oil Sands will be reduced from 13 per cent to 10 per cent, as substantially all of Canadian Oil Sands' activities are in Alberta. For accounting purposes, the adjustment is not considered substantively enacted because the related income tax regulations have not been finalized. If the proposal becomes enacted, we expect to record a future income tax recovery based on the temporary differences at that time. On July 14, 2008, the Department of Finance released draft legislation for income and royalty trust conversions. The draft legislation is designed to permit income and royalty trusts to convert into public corporations without triggering adverse Canadian tax consequences to the income or royalty trust and its Unitholders (the "SIFT conversion rules"). On November 28, 2008, the Minister of Finance introduced changes in the House of Commons to the SIFT conversion rules and on December 4, 2008 issued explanatory notes on these changes. The effect of this proposed legislation is to allow a tax-free rollover of holdings in a trust as it converts to a corporate structure. It also accelerated the safe haven guidelines to immediately allow cumulative new equity issues of up to 100 per cent of an entity's October 31, 2006 market capitalization. As of December 31, 2008, this legislation was not enacted. With the taxation of income trusts commencing January 1, 2011, Canadian Oil Sands has evaluated alternatives as to the best structure for its Unitholders in the future. Based on current information and pending the enactment of the SIFT conversion rules, we will likely convert to a corporation. We plan to retain the flow-through advantages of a trust structure until 2011 unless circumstances arise that favor a faster transition. Canadian Oil Sands continues to be a long-term value investment in the oil sands and does not rely on the tax efficiency of a flow-through trust model to sustain its business. Our long-life reserves and virtually non-declining production profile provide a solid foundation to generate future cash from operating activities. CHANGES IN ACCOUNTING POLICIES In its audited consolidated financial statements for the year ended December 31, 2007 ("Audited 2007 Financial Statements"), Canadian Oil Sands adopted the requirements of the Canadian Institute of Chartered Accountants ("CICA") Section 3862 Financial Instruments - Disclosures, Section 3863 Financial Instruments - Presentation and Section 1535 - Capital Disclosures. These standards were effective January 1, 2008, however, early adoption was encouraged by the CICA. Additional disclosures required as a result of adopting the standards can be found in the Trust's Audited 2007 Financial Statements. In June 2007, the CICA issued a new accounting standard Section 3031 Inventories, which replaces the existing standard for inventories, Section 3030. The main features of the new section are as follows:
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- measurement of inventories at the lower of cost and net realizable
value;
- consistent use of either first-in, first-out or a weighted average
cost formula is to be used to measure cost; and
- reversal of previous write-downs to net realizable value when there
is a subsequent increase to the value of inventories.
The new inventory standard was effective for the Trust beginning January
1, 2008. Application of the new standard did not have an impact on the Trust's
financial statements.
NEW ACCOUNTING PRONOUNCEMENTS
Goodwill and Intangible Assets
>>
In February 2008, the CICA issued a new accounting standard, Section 3064 - Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and Other Intangible Assets, and Section 3450 - Research and Development costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The section is effective for the Trust beginning January 1, 2009. Application of the new section is not expected to have a material impact on the Trust's financial statements. IFRS On February 13, 2008, the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards ("IFRS") starting in 2011. IFRS will effectively replace Canadian GAAP for these issuers and comparative IFRS information for the 2010 fiscal year will be required. Canadian Oil Sands is assessing the impact on our business of adopting IFRS in 2011. As part of its assessment, the Trust is identifying potential differences between Canadian GAAP and existing IFRS at December 31, 2008 as well as proposed IFRS which may be in effect in 2011. Management is reviewing the impact that these differences will have on accounting policies, information technology and data systems, internal control over financial reporting, disclosure controls and procedures, financial reporting, and business activities. Management has not fully determined the impact of adopting IFRS on its financial statements, however, it should be noted that the current financial statements may be significantly different when presented in accordance with IFRS. The potential impacts on the consolidated financial statements from the adoption of IFRS will depend on the particular circumstances prevailing on January 1, 2011, as well as the accounting policy choices adopted by Canadian Oil Sands.
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UNITHOLDER DISTRIBUTIONS
Three Months Ended Year Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash from operating
activities $ 466 $ 367 $ 2,241 $ 1,377
Net income $ 124 $ 515 $ 1,523 $ 743
Unitholder distributions $ 361 $ 264 $ 1,804 $ 791
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Excess (shortfall) of cash
from operating activities
over Unitholder
distributions $ 105 $ 103 $ 437 $ 586
Excess (shortfall) of net
income over Unitholder
distributions $ (237) $ 251 $ (281) $ (48)
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>>
Cash from operating activities in 2008 exceeded Unitholder distributions in the fourth quarter and on a year-to-date basis by $105 million and $437 million respectively. During 2008, cash from operating activities along with opening cash balances was sufficient to fund the Trust's distributions, capital expenditures, reclamation trust fund contributions and debt repayments. On both a quarterly and a year-to-date basis, Unitholder distributions in 2008 exceeded net income primarily as a result of DD&A and unrealized foreign exchange losses which are non-cash items that 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. On January 28, 2009 the Trust declared a quarterly distribution of $0.15 per Unit in respect of the first quarter of 2009 for a total distribution of $72 million. The distribution will be paid on February 27, 2009 to Unitholders of record on February 9, 2009. Quarterly distributions are approved by our Board of Directors after considering the current and expected economic conditions, ensuring financing capacity for Canadian Oil Sands' capital requirements and with the objective of maintaining an investment grade credit rating. In establishing the distribution amount for the current quarter, the Trust has considered the recent decrease in crude oil prices and the turmoil in worldwide credit markets. The price of WTI crude oil has declined from approximately US$68 per barrel when the last distribution was approved to an average of approximately US$42 per barrel in January 2009. If oil prices continue to decrease, cash from operating activities and our ability to internally fund distributions and capital expenditures will decline. In addition, as a result of ongoing credit market turmoil, there is heightened risk around the ability of the Trust to access the capital markets in a prudent and cost effective manner. During this period of heightened risk, we believe that it is prudent to reduce distributions in order to maintain liquidity and financial flexibility. The Trust also has approximately $500 million in debt maturities in 2009 that it plans on refinancing through its existing credit facilities or in the debt capital markets. Despite current WTI market prices of approximately US$42 per barrel, the Trust continues to generate cash from operating activities, is largely undrawn on its $840 million of credit facilities and is positioned to execute its financial and operating strategies. The current distribution reflects the Trust's plan of managing its capital structure in anticipation of trust taxation in 2011. The Trust has been distributing a fuller amount of its cash from operating activities, and targeting a long-term net debt of about $1.6 billion by the end of 2010. While we believe this net debt target reflects efficient capital management and will help conserve tax pools prior to trust taxation, achievement of that target must also consider a prudent liquidity position and capital market access. The target is based on Syncrude's existing productive capacity and will be reconsidered in light of Canadian Oil Sands' future capital requirement plans and any growth opportunities. 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 $55 million and $38 million on a year-to-date basis in 2008 and 2007, respectively. We do not anticipate significant increases in funding for pension or reclamation items in 2009. 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 an amount less than 55 per cent. With a current net debt-to-total capitalization of approximately 20 per cent, a significant increase in debt or decrease in equity would be required to restrict the Trust's financial flexibility. Cash from operating activities and net income can fluctuate from period to period reflecting, among other things, variability in operational performance, WTI prices, SCO differentials to WTI prices and FX rates. The Trust strives to smooth out the impacts of these fluctuations on distributions by taking a longer-term view of the operating and business environment, our net debt level relative to our target, and our capital expenditure and other commitments. In that regard, the Trust may distribute more or less in a period than is generated in cash from operating activities or net income. The variable nature of cash from operating activities introduces risk in the ability to sustain or provide stability in distributions. Expectations regarding the stability or sustainability of distributions are unwarranted and should not be implied. Further, the taxation of income trusts commencing January 1, 2011 likely will alter future cash from operating activities and distribution levels.
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Premium Distribution, Distribution Re-Investment and Optional Unit
Purchase Plan (DRIP)
>>
Effective February 2009, Canadian Oil Sands is reinstating its Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP"). The DRIP allows eligible Unitholders to direct their distributions to the purchase of additional units at 95 per cent of the average market price, as defined in the DRIP. Alternatively, eligible Unitholders may elect under the premium distribution component to have their distributions invested in new units and exchanged through the DRIP Broker for a premium distribution equal to 102 per cent of the amount that the Unitholder would otherwise have received on the distribution date (subject to proration and withholding tax reductions in certain circumstances). The DRIP allows those Unitholders who participate in either the regular distribution re-investment or premium distribution component of the DRIP to purchase additional Units from treasury at the average market price in minimum amounts of $1,000 per remittance and maximum amounts of $100,000, in a given quarter, all subject to an overall annual limit of two per cent of the outstanding trust units being offered for purchase in this manner. The Trust reinstated its DRIP to help build balance sheet equity during this period of lower crude oil prices and credit market risk. As well, the DRIP supports distributions while providing Unitholders with several options to manage their distribution payments in a cost-effective, convenient manner. There are no brokerage fees or commissions payable by participants for the purchase of units under the DRIP. Only Canadian resident Unitholders are eligible to participate in the DRIP at this time.
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LIQUIDITY AND CAPITAL RESOURCES
December 31 December 31
($ millions) 2008 2007
-------------------------------------------------------------------------
Long-term debt $ 1,258 $ 1,218
Cash and cash equivalents (279) (268)
-------------------------------------------------------------------------
Net debt(1) $ 979 $ 950
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Unitholders' equity $ 3,910 $ 4,172
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Total capitalization(2) $ 4,889 $ 5,122
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(1) Non-GAAP measure
(2) Net debt plus Unitholders' equity
Net debt to total capitalization (%) 20 19
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>>
As at December 31, 2008, the Trust had $840 million of unutilized and available credit facilities, and had $67 million in letters of credit issued against a separate line of credit. During the second quarter of 2008, the Trust repaid $150 million of medium term notes that had matured. Canadian Oil Sands has set a long-term net debt target of approximately $1.6 billion by the end of 2010. The Trust's actual net debt will fluctuate, however, as factors such as crude oil prices, Syncrude's operational performance, distributions, FX rates, and the ability to access capital markets in a prudent and cost effective manner vary from our assumptions, as outlined above under Unitholder Distributions. CAPITAL EXPENDITURES With the completion of Syncrude's Stage 3 project in 2006, Canadian Oil Sands' expansion capital expenditures have declined and capital costs for 2008 and 2007 were primarily related to sustaining capital. The Trust defines expansion capital expenditures as the costs incurred to grow the productive capacity of the operation, such as the Stage 3 project, while sustaining capital is effectively all other capital. Sustaining capital expenditures may fluctuate considerably year-to-year due to the timing of equipment replacement and other factors. The productive capacity of Syncrude's operations was previously described in the "Review of Syncrude Operations" section of this MD&A. In the fourth quarter of 2008, capital expenditures totalled $86 million compared with expenditures of $55 million in the same quarter of 2007. The Syncrude Emissions Reduction ("SER") project accounted for $17 million and $18 million of the capital spent in the fourth quarters of 2008 and 2007, respectively. The remaining amounts in each quarter pertained to other sustaining capital activities including replacement of trucks and shovels, as well as other infrastructure projects. Sustaining capital expenditures on a per barrel basis were approximately $8.51 and $5.00 in each of the fourth quarters of 2008 and 2007, respectively. On an annual basis, capital expenditures totalled $281 million in 2008 versus $183 million in 2007. The SER project accounted for $73 million and $69 million of the capital spent in 2008 and 2007, respectively, with the remaining expenditures relating to other sustaining capital activities. Sustaining capital expenditures on a per barrel basis were approximately $7.23 and $4.46 on a year-to-date basis in 2008 and 2007, respectively. Syncrude is undertaking the SER project to retrofit technology into the operation of Syncrude's original two cokers to reduce total sulphur dioxide and other emissions. After the completion of the SER project, stack emissions of sulphur compounds are anticipated to be about 60 per cent lower than current approved levels. In the third quarter of 2008, Syncrude completed its review of the SER project and revised its cost estimates for the project to $1.6 billion ($590 million net to the Trust) from $772 million ($284 million net to the Trust). The cost increase reflects a delay in the expected completion date and inflationary pressures. The Trust's share of the SER project expenditures incurred to date is approximately $181 million, with the majority of the remaining costs expected to be incurred over the next three years to coordinate with equipment turnaround schedules. Sustaining capital expenditures, including the SER project, are estimated to average approximately $10.41 per barrel for 2009 and over the next few years we expect to incur $10 to $15 per barrel for sustaining capital expenditures. The additional expenditures are a result of large environmental and infrastructure projects. Over the longer term, we expect sustaining capital expenditures to average approximately $6 per barrel excluding inflation. Our per barrel estimates are based on estimated annual Syncrude production increasing from 106 million barrels in 2008 to 129 million barrels at design capacity. Syncrude's next significant growth stage is anticipated to be the Stage 3 debottleneck, which is estimated to increase Syncrude's productive capacity by about 50,000 barrels per day. Following the debottleneck, the Stage 4 expansion is expected to grow Syncrude capacity by a further 100,000 barrels per day, post-2016; however, Syncrude is re-evaluating its plans to increase production well beyond the 500,000 barrels per day provided by the Stage 4 expansion. The objective is to develop an expansion plan that maintains an appropriate resource life of about 50 years based on an independent estimate of Syncrude's reserves and resources as of December 31, 2007. The scoping engineering work on the Stage 3 debottleneck and subsequent expansion stages has been approved by the joint venture owners and is being pursued. Spending will ramp up as the engineering work progresses. The timing of the expansions will depend on the engineering and construction execution plans. It is probable that the debottleneck will be delayed beyond our previously disclosed 2012 projected startup, as could other expansion timing. We plan to provide more information on timing over the next year or two as the scoping work progresses. No cost estimates have been provided for these projects nor have they been approved by the Syncrude owners as they are still in the early planning stages. The amount and timing of future capital expenditures is dependent upon the business environment and future projects may be delayed or cancelled in times of low commodity prices. 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 $10 billion with 482 million Units outstanding and a closing price of $21.10 per Unit on December 31, 2008.
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Canadian Oil Sands Trust -
Trading Activity Fourth
Quarter December November October
2008 2008 2008 2008
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Unit price
High $ 39.44 $ 25.00 $ 34.81 $ 39.44
Low $ 18.15 $ 18.15 $ 18.18 $ 21.50
Close $ 21.10 $ 21.10 $ 25.75 $ 32.34
Volume traded (millions) 169.2 48.7 46.0 74.5
Weighted average Trust units
outstanding (millions) 481.5 481.5 481.5 481.5
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CONTRACTUAL OBLIGATIONS AND COMMITMENTS The following table outlines the significant financial obligations that are known as of January 28, 2009, which represent future cash payments that the Trust is required to make under existing contractual agreements that it has entered into directly, or as a 36.74 per cent owner in the Syncrude Joint Venture.
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Payments due by period
less than 1 - 3 4 - 5 After
($ millions) Total 1 year years years 5 years
-------------------------------------------------------------------------
Long-term debt(1) 1,270 506 - 367 397
Capital expenditure
commitments(2) 456 202 254 - -
Pension plan solvency
deficiency payments(3) 107 14 36 17 40
Management services
agreement(4) 142 17 51 34 40
Pipeline commitments(5) 537 19 58 39 421
Asset retirement
obligations(6) 774 12 43 25 694
Other obligations(7) 238 152 42 12 32
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3,524 922 484 494 1,623
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(1) Actual payments differ from the carrying value, which is stated at
amortized cost. While there is approximately $500 million of debt
maturing in 2009, Canadian Oil Sands' intention is to refinance such
debt.
(2) Capital expenditure commitments are primarily comprised of our
36.74 per cent share of Syncrude's Emissions Reduction project.
(3) We are responsible for funding our 36.74 per cent share of Syncrude
Canada's registered pension plan solvency deficiency, which was
confirmed in the December 31, 2006 actuarial valuation that was
completed in 2007.
(4) Reflects our 36.74 per cent share of Syncrude Canada's annual fixed
service fees under the agreement.
(5) Reflects our 36.74 per cent share of the AOSPL pipeline commitment as
a Syncrude Joint Venture owner, and various other Canadian Oil Sands
pipeline commitments for transportation access beyond Edmonton.
(6) Reflects our 36.74 percent share of the undiscounted estimated cash
flows required to settle Syncrude's environmental obligations upon
the ultimate reclamation of the Syncrude Joint Venture properties.
(7) These obligations primarily include our 36.74 per cent share of the
minimum payments required under Syncrude's commitments for natural
gas purchases. Other items include, but are not limited to, annual
disposal fees for the flue gas desulphurization unit and tire supply
agreements.
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The Trust's commitments and obligations have increased by approximately $165 million relative to the prior year end, primarily as a result of increased cost estimates for the SER project, new natural gas purchase commitments, changes in the value of the Trust's long-term debt, less payments on 2008 commitments. Canadian Oil Sands accrues its obligations for Syncrude Canada's post-employment benefits utilizing actuarial and other assumptions to estimate the projected benefit obligation, the return on plan assets and the expense accrual related to the current period. During the last quarter of 2008 there was a significant decline in the actual return of Syncrude's defined benefit pension plan assets compared with the expected return as a result of market performance. There was also an offsetting decline in the value of Syncrude's accrued benefit obligation due to changes in corporate interest rates used to discount those obligations. Syncrude Canada's last actuarial valuation of its pension plan was completed during 2007, which established funding requirements until December 31, 2009. Syncrude's next required valuation for funding purposes will be as of December 31, 2009, however, Syncrude will assess the requirement for an earlier valuation when it files its 2008 pension results. FINANCIAL RISK MANAGEMENT The Trust did not have any financial derivatives outstanding at December 31, 2008. Crude Oil Price Risk Our cash flows are impacted by changes in both the U.S. dollar denominated crude oil prices and U.S./Canadian FX rates. Over the last two years, daily WTI prices have experienced significant volatility, ranging from US$145 per barrel in July 2008 to US$34 per barrel in December 2008. Prior to 2007, management had hedged oil prices and exchange rates to reduce revenue and cash flow volatility to the Trust during periods of significant financing requirements. Subsequent to 2006 Canadian Oil Sands' financing requirements declined along with net debt levels and expansion capital expenditures and Canadian Oil Sands chose to remain un-hedged and exposed to crude oil price fluctuations. Canadian Oil Sands did not have any crude oil price hedges in place for 2008 or 2007. Instead, a strong balance sheet has been used to mitigate the risk around crude oil price movements. As at January 28, 2009, and based on current expectations, the Trust remains un-hedged on its crude oil price exposure; however, it may hedge this exposure in the future depending on the business environment and our growth opportunities. In the past few years synthetic oil production from various oil sands projects has increased with additional projects under development or being contemplated. If other projects are completed, there may be an additional increase in the supply of synthetic crude oil in the market. There is no guarantee there will be sufficient demand or pipeline capacity to absorb the increased supply without eroding the selling price, which could result in a deterioration of the price differential that Canadian Oil Sands realizes compared to benchmark prices such as WTI. Based on the expected supply of, and demand for, light synthetic crude oil in 2009, we are forecasting a price discount for our product of $4.00 per barrel relative to Canadian dollar WTI prices. Foreign Currency Hedging Canadian Oil Sands' results are affected by fluctuations in the U.S./Canadian currency exchange rates as we generate revenue from oil sales based on a U.S. dollar WTI benchmark price, while operating costs and capital costs are denominated primarily in Canadian dollars. Over the last two years, the Canadian dollar has experienced significant volatility, ranging from $1.09 US/Cdn in November 2007 to $0.77 US/Cdn in December 2008. Our revenue exposure is partially offset by U.S. dollar obligations, such as interest costs on U.S. dollar denominated debt and our share of Syncrude's U.S. dollar vendor payments. In addition, when our U.S. Senior Notes mature, we have exposure to U.S. dollar exchange rates on the principal repayment of the notes. This repayment of U.S. dollar debt acts as a partial economic hedge against the U.S. dollar denominated revenue payments from our customers. In the past, the Trust has hedged foreign currency exchange rates by entering into fixed rate currency contracts, including US$20 million hedged during 2007. The Trust did not have any foreign currency hedges in place during 2008, and we currently do not 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. As at December 31, 2008, we did not have any debt outstanding bearing interest at floating market-based rates. 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 through cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through bank credit facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic hedging opportunities, and compliance with debt covenants. We are also exposed to liquidity risk to the extent we have financing requirements related to significant capital or operating commitments or debt repayments. Over the long-term, Canadian Oil Sands manages these risks by spreading out the maturities of its various debt tranches and maintaining a prudent capital structure. During the last half of 2008, global credit markets tightened with a decline in liquidity and higher borrowing costs. While Canadian Oil Sands continues to generate cash from operating activities and has $840 million of credit facilities to support liquidity, access to capital markets has become constrained and more expensive. During 2009, two tranches of Canadian Oil Sands' debt totalling approximately $500 million will mature. The Trust is considering the risk that financial markets do not improve during 2009 as part of its financing plan and has identified potential mitigating strategies. These may include further distribution cuts or accessing the capital markets prior to these maturities, depending on the circumstances and market conditions. Credit Risk Canadian Oil Sands is exposed to credit risk primarily through its trade accounts receivable balances with customers and with financial counterparties with whom the Trust has invested its cash and 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 policy also specifically limits the exposure to customers with a credit rating below investment grade to a maximum of 25 per cent of Canadian Oil Sands' consolidated accounts receivable. This credit risk concentration is monitored on a regular basis. Risk is further mitigated as accounts receivable with customers typically are settled in the month following the sale, and investments with financial counterparties are typically short-term in nature and are placed with institutions that have a credit rating of "A" or better. Despite these controls, risk of a credit related loss has risen in the current economic environment. At December 31, 2008, over 90 per cent of our accounts receivable balance was due from investment grade energy producers and refinery-based customers, and over 90 per cent of our cash and cash equivalents were invested in term deposits from a range of high-quality senior Canadian banks. At present, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults FOREIGN OWNERSHIP Based on information from the statutory declarations by Unitholders, we estimate that, as of November 14 2008, approximately 32 per cent of our Units were held by non-Canadian residents with the remaining 68 per cent of Units being held by 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 February 13, 2009. 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.
<<
SUSTAINABLE DEVELOPMENT
Waterfowl Incident at Syncrude's Aurora Mine Tailings Pond
>>
In April 2008, a flock of ducks landed and died on one of Syncrude's tailings ponds. Alberta Environment is continuing their investigation into why this occurred, and on improvements to help prevent it from happening again. Measures are in progress to ensure Syncrude is fully prepared for the 2009 spring migration. Greenhouse Gas Emissions Reduction Requirements In 2007, through the Specified Gas Emitters Regulation, Alberta became the first province in Canada to regulate greenhouse gases by establishing intensity targets for Large Final Emitters of carbon. Effectively, the regulation requires Syncrude, beginning in the second half of 2007, to reduce its per barrel emissions of greenhouse gases by 12 per cent from the average of its annual per barrel emissions between 2003 and 2005. If Syncrude is unable to meet this target directly, it must purchase offset credits or pay into a government fund dedicated to the development of emissions reduction technology. For 2007, Syncrude met 90 per cent of its reduction target under the new regulation and offset the remainder through the payment of approximately $1 million to the Alberta government's technology fund. Syncrude's emissions calculation method and its data were externally verified. For 2008, Syncrude accrued approximately $0.10 per barrel for compliance with the Specified Gas Emitters Regulation, which is reflected in the Trust's operating costs. The cost estimate remains preliminary pending Syncrude's actual carbon dioxide ("CO(2)") emission intensity level and clarification from the Alberta government regarding details of implementation. No cost estimates are available for future years. On March 10, 2008Canada's federal government provided further detail on its regulatory framework to reduce GHG and air pollutant emissions originally announced on April 26, 2007. The draft regulations are currently expected to be finalized in 2009 and take effect on January 1, 2010. The draft regulations for oil sands projects require existing projects to reduce emissions intensity by 18 per cent in 2010 from the 2006 level and two per cent thereafter. New oil sands facilities coming onstream over the period 2004 to 2011 also will be required to meet clean fuel standards and will be encouraged to implement mechanisms to capture CO(2) emissions. In addition to the reduction of existing GHG emissions, the capture and storage of CO(2) emissions ("CCS") will be a requirement for all oil sands projects coming onstream post 2012. The draft regulations are expected to impact both current Syncrude operations and its future expansion projects, however, the full impact of the regulations cannot be quantified until they are finalized. Syncrude continues to explore and implement measures to reduce energy intensity in its operations, which reduces both CO2 emissions and operating costs. Syncrude also is exploring the viability of developing a large scale CO(2) capture, transportation and storage network through participation in the integrated CO(2) Network ("ICON"). Reclamation In March 2008, the Alberta government certified a parcel of reclaimed land north of Fort McMurray. The 104 hectares, known as Gateway Hill, was submitted by Syncrude to the Alberta government in 2003 for certification. Alberta's Environmental Protection and Enhancement Act requires operators to conserve and reclaim specified land and obtain a reclamation certificate. These certificates are issued to operators when their site has been successfully reclaimed. Syncrude is the first in the oil sands industry to receive certification for land that has been reclaimed. Syncrude has reclaimed more than 4,500 hectares, representing the largest share in the oil sands industry. Tailings Management Syncrude's reclamation efforts also include tailings systems management. Tailings systems are designed to separate water from sand and clay to enable incorporation of solids into reclamation landscapes and recycling of water back into the operations. Syncrude and most other oil sands producers use a method called consolidated tails technology, however, additional tailings management technologies may be required in order to meet the approved closure and reclamation plan. Syncrude is exploring methods to improve and supplement the effectiveness of its tailings systems. On June 26, 2008, the Alberta Energy Resources Conservation Board ("ERCB") released a draft Directive on Tailings Criteria for public review and comment. This directive proposes to develop new industry-wide criteria to supplement existing regulations by requiring operators to:
<<
- prepare an operations and abandonment plan for every consolidated
tailings pond, which would be reviewed for the establishment of
performance measures by the ERCB;
- operate and abandon each consolidated tailings pond in accordance
with their applications or ERCB approvals;
- consume fine fluid tailings as proposed in their applications or as
approved by the ERCB; and
- specify dates for pond construction, pond use, pond closure, and
other milestones and file these dates with the ERCB.
>>
Syncrude is involved in both the review of the draft directive and submission of comments to the ERCB, as well as assessing the impact of the proposed directive on current and future operations. Until the directive is finalized, the impact, if any, of the new regulations on Syncrude cannot be fully determined, however, new requirements for tailings management that may be required under these draft regulations are likely to have an adverse impact on the costs for tailings management. Syncrude is filing an amendment to its regulatory approval to modify the design of the existing Southwest Sand Storage ("SWSS") facility, permitting interim storage of increased volumes of mature fine tailings and to incorporate supplemental technologies to reduce tailings inventories. Changes to the design of the SWSS facility will be required to increase its fluid storage capacity. The change in design would not increase the footprint of the structure but rather elevate the fluid level within it. Pending regulatory approval, Syncrude intends to make use of this increase in capacity in 2009. 2009 OUTLOOK
<<
(millions of Canadian dollars, January 28, December 9,
except volume and per barrel amounts) 2009 2008
-------------------------------------------------------------------------
Syncrude production (MMbbls) 115 115
Canadian Oil Sands Sales (MMbbls) 42.3 42.3
Revenues, net of crude oil purchases
and transportation 2,392 2,392
Operating costs 1,300 1,298
Operating costs per barrel 30.76 30.72
Crown royalties 65 66
Capital expenditures 440 440
Cash from operating activities 747 816
Business environment assumptions
--------------------------------
West Texas Intermediate (US$/bbl) $ 50 $ 50
Premium (Discount) to average C$ WTI
prices (C$/bbl) $ (4.00) $ (4.00)
Foreign exchange rate (US$/Cdn$) $ 0.83 $ 0.83
AECO natural gas (Cdn$/GJ) $ 6.00 $ 6.00
>>
On December 9, 2008, the Trust announced its 2009 budget with an estimate of Syncrude production totalling 115 million barrels and a range 110 million barrels to 120 million barrels. This estimate includes a turnaround of Coker 8-3 in the second quarter of 2009, a turnaround of the LC-Finer in the third quarter of 2009, a turnaround of the vacuum unit with the timing not yet determined, and an allowance for some unplanned outages. The production estimate also incorporates reliability issues in the mining and extraction processes that continue to limit progress towards design capacity. Syncrude is focusing resources to address this issue, including the use of contractor services to accelerate overburden removal and expose more oil sands ore to optimize blending and increase feed volumes to our extraction plants. While purchases of bitumen by Syncrude are not anticipated during 2009 to achieve the budgeted production levels, Syncrude continues to monitor bitumen prices and upgrading capacity and may purchase bitumen during 2009 to optimize its operations. We are maintaining the key assumptions of our December budget, including a production estimate for Syncrude of approximately 115 million barrels in our January 28, 2009 Outlook; however, we have incorporated changes to reflect actual 2008 year-end results.
<<
Cdn$ US$
2009 Cost Estimates Per Bbl Per Bbl(1)
-------------------------------------------------------------------------
Syncrude Costs
Operating expenses $ 30.76 $ 25.38
Non-production costs $ 3.37 $ 2.78
---------- ----------
$ 34.13 $ 28.16
Capital expenditures $ 10.41 $ 8.59
---------- ----------
Total Syncrude costs $ 44.54 $ 36.75
---------- ----------
Canadian Oil Sands Costs
Interest $ 1.73 $ 1.43
Administration, Insurance, and Other $ 0.78 $ 0.64
---------- ----------
Total Canadian Oil Sands costs $ 2.51 $ 2.07
---------- ----------
Total Syncrude and Canadian Oil Sands costs $ 47.05 $ 38.82
Crown Royalties $ 1.55 $ 1.28
---------- ----------
Total costs $ 48.60 $ 40.10
---------- ----------
---------- ----------
(1) Amounts have been converted to US$ at the 2009 Outlook foreign
exchange rate of $0.825 US/Cdn for convenience of the reader.
>>
Annual operating expenses in 2009 are estimated at $31 per barrel, consisting of $25 per barrel of production costs and $6 per barrel of purchased energy. Purchased energy costs assume a $6 per GJ natural gas price. When combined with Syncrude non-production costs and capital expenditures, total 2009 Syncrude costs are estimated at $44 per barrel. Canadian Oil Sands also expects to incur an additional $3 per barrel of costs to cover interest expense, administration, and insurance resulting in estimated 2009 Syncrude and Canadian Oil Sands costs of $47 per barrel. Crown Royalties are estimated at $1.55 per barrel based on the calculations as described in the "Crown Royalties" section. We also have assumed a US$50 per barrel WTI crude oil price, an $0.825 US/Cdn foreign exchange rate, and a $4.00 per barrel SCO discount to Cdn $ WTI, resulting in revenues of $57 per barrel. Based on the above assumptions, our estimate of 2009 cash from operating activities is $747 million or $1.55 per Unit. After deducting estimated 2009 capital expenditures of $440 million we are estimating $307 million of remaining cash from operating activities, or $0.64 per Unit, to repay debt or pay distributions. In order to preserve financial flexibility during the current period of heightened liquidity risk, we have lowered our quarterly distribution to $0.15 per Unit for the first quarter of 2009. While Syncrude's operating costs and capital expenditures are relatively fixed, the joint venture will continue to pursue opportunities to reduce or defer the timing of costs. We believe we have positioned the Trust prudently in light of the current business environment to maintain the momentum of our long-term growth strategy. Distributions paid in 2008 and 2009 are expected to be 100 per cent taxable as other income. The actual taxability of the distributions will be determined and reported to Unitholders prior to the end of the first quarters of 2009 and 2010, respectively. 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 the North American markets could impact the differential for SCO relative to crude benchmarks; however, these factors are difficult to predict.
<<
2009 Outlook Sensitivity Analysis
Cash from Operating Activities
Annual Increase
Variable(1) Sensitivity $ millions $/Trust unit
-------------------------------------------------------------------------
Syncrude operating costs
decrease C$1.00/bbl 35 0.07
Syncrude operating costs
decrease C$50 million 15 0.03
WTI crude oil price increase US$1.00/bbl 41 0.08
Syncrude production increase 2 million bbls 33 0.07
Canadian dollar weakening US$0.01/C$ 24 0.05
AECO natural gas price
decrease C$0.50/GJ 16 0.03
(1) An opposite change in each of these variables will result in the
opposite cash from operating activities impacts.
Canadian Oil Sands may become subject to minimum Crown royalties at a rate
of 1% of gross bitumen revenue.
This sensitivities presented herein assumes royalties are paid at 25% of
net bitumen revenue.
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)
Three Months Ended Year Ended
($ millions, except December 31 December 31
per Unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues $ 768 $ 1,007 $ 4,543 $ 3,633
Crude oil purchases and
transportation expense (64) (57) (374) (383)
-------------------------------------------------------------------------
704 950 4,169 3,250
-------------------------------------------------------------------------
Expenses:
Operating 326 293 1,368 1,034
Non-production 24 14 78 63
Crown royalties 59 137 599 485
Administration 1 6 17 20
Insurance 1 2 6 8
Interest, net (Note 8) 19 17 68 85
Depreciation, depletion and
accretion 119 91 444 351
Foreign exchange loss (gain) 106 (5) 159 (117)
-------------------------------------------------------------------------
655 555 2,739 1,929
-------------------------------------------------------------------------
Earnings before taxes 49 395 1,430 1,321
Future income tax expense
(recovery) and other (75) (118) (93) 579
-------------------------------------------------------------------------
Net income from continuing
operations 124 513 1,523 742
Loss from discontinued
operations - 2 - 1
-------------------------------------------------------------------------
Net income 124 515 1,523 743
Other comprehensive loss,
net of income taxes
Reclassification of
derivative gains to
net income (1) - (3) (6)
-------------------------------------------------------------------------
Comprehensive income $ 123 $ 515 $ 1,520 $ 737
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average Trust Units
(millions) 482 479 481 479
Trust Units, end of period
(millions) 482 479 482 479
Net income per Trust Unit:
Basic $ 0.26 $ 1.07 $ 3.17 $ 1.55
Diluted $ 0.26 $ 1.07 $ 3.16 $ 1.54
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
(unaudited)
Three Months Ended Year Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Retained earnings
Balance, beginning of period $ 1,599 $ 1,392 $ 1,643 $ 1,691
Net income 124 515 1,523 743
Unitholder distributions
(Note 9) (361) (264) (1,804) (791)
-------------------------------------------------------------------------
Balance, end of period 1,362 1,643 1,362 1,643
-------------------------------------------------------------------------
Accumulated other comprehensive
income
Balance, beginning of period 22 24 24 30
Other comprehensive loss (1) - (3) (6)
-------------------------------------------------------------------------
Balance, end of period 21 24 21 24
-------------------------------------------------------------------------
Unitholders' capital
Balance, beginning of period 2,524 2,499 2,500 2,260
Issuance of Trust Units
(Note 4) - 1 24 240
-------------------------------------------------------------------------
Balance, end of period 2,524 2,500 2,524 2,500
-------------------------------------------------------------------------
Contributed surplus
Balance, beginning of period 3 5 5 4
Exercise of employee stock
options - - (3) -
Stock-based compensation - - 1 1
-------------------------------------------------------------------------
Balance, end of period 3 5 3 5
-------------------------------------------------------------------------
Total Unitholders' equity $ 3,910 $ 4,172 $ 3,910 $ 4,172
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED BALANCE SHEETS
AS AT DECEMBER 31
(unaudited)
($ millions) 2008 2007
-------------------------------------------------------------------------
ASSETS
Current assets:
Cash and cash equivalents $ 279 $ 268
Accounts receivable 184 379
Inventories 93 102
Prepaid expenses 5 6
-------------------------------------------------------------------------
561 755
Property, plant and equipment, net 6,277 6,427
Goodwill 52 52
Reclamation trust 43 37
-------------------------------------------------------------------------
$ 6,933 $ 7,271
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 284 $ 289
Current portion of employee future benefits 17 16
-------------------------------------------------------------------------
301 305
Employee future benefits and other liabilities 99 128
Long-term debt 1,258 1,218
Asset retirement obligation 235 226
Future income taxes 1,130 1,222
-------------------------------------------------------------------------
3,023 3,099
Unitholders' equity 3,910 4,172
-------------------------------------------------------------------------
$ 6,933 $ 7,271
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments (Note 10)
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Ended Year Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash from (used in) operating
activities
Net income $ 124 $ 515 $ 1,523 $ 743
Items not requiring
outlay of cash:
Depreciation, depletion
and accretion 119 91 444 351
Unrealized foreign
exchange on long-term debt 142 (7) 204 (153)
Future income tax expense
(recovery) (75) (118) (93) 578
Other (2) - 2 (3)
Net change in deferred items (16) 28 (41) 26
-------------------------------------------------------------------------
292 509 2,039 1,542
Change in non-cash working
capital 174 (142) 202 (165)
-------------------------------------------------------------------------
Cash from operating
activities 466 367 2,241 1,377
-------------------------------------------------------------------------
Cash from (used in) financing
activities
Repayment of medium term and
Senior Notes - - (150) (272)
Net drawdown (repayment) of
bank credit facilities - 16 (16) 16
Unitholder distributions
(Note 9) (361) (264) (1,804) (791)
Issuance of Trust Units (Note 4) - 2 21 3
-------------------------------------------------------------------------
Cash used in financing
activities (361) (246) (1,949) (1,044)
-------------------------------------------------------------------------
Cash from (used in) investing
activities
Capital expenditures (86) (55) (281) (183)
Acquisition of additional
Syncrude working interest - - - (231)
Disposition of properties - - - 4
Reclamation trust funding (2) (3) (6) (7)
Change in non-cash working
capital (16) 4 6 (1)
-------------------------------------------------------------------------
Cash used in investing
activities (104) (54) (281) (418)
-------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 1 67 11 (85)
Cash and cash equivalents at
beginning of period 278 201 268 353
-------------------------------------------------------------------------
Cash and cash equivalents at
end of period $ 279 $ 268 $ 279 $ 268
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents
consist of:
Cash $ 18 $ 4
Short-term investments 261 264
-------------------------------------------------------------------------
$ 279 $ 268
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Information (Note 11)
See Notes to Unaudited Consolidated Financial Statements
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE TWELVE MONTHS ENDED December 31, 2008
(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,
2007, 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,
2007.
2) CHANGES IN ACCOUNTING POLICIES
In its consolidated financial statements for the year ended December
31, 2007, Canadian Oil Sands adopted the requirements of the Canadian
Institute of Chartered Accountants ("CICA") Section 3862 Financial
Instruments - Disclosures, Section 3863 Financial Instruments -
Presentation, and Section 1535 Capital Disclosures. The standards
were effective January 1, 2008, however early adoption was encouraged
by the CICA. Additional disclosures required as a result of adopting
the standards can be found in the Trust's consolidated financial
statements for the year ended December 31, 2007.
In June 2007, the CICA issued a new accounting standard - Section
3031 Inventories, which replaces the existing standard for
inventories, Section 3030. The main features of the new Section are
as follows:
- Measurement of inventories at the lower of cost and net
realizable value
- Consistent use of either first-in, first-out or a weighted
average cost formula to measure cost
- Reversal of previous write-downs to net realizable value when
there is a subsequent increase to the value of inventories
The new Section was effective for the Trust beginning January 1,
2008. Application of the new Section did not have a significant
impact on the financial statements.
3) FUTURE CHANGES IN ACCOUNTING POLICIES
In February 2008, the CICA issued a new accounting standard - Section
3064 Goodwill and Intangible Assets, which replaces Section 3062
Goodwill and Other Intangible Assets, and Section 3450 Research and
Development Costs. The new section establishes standards for the
recognition, measurement and disclosure of goodwill and intangible
assets. The section is effective for the Trust beginning January 1,
2009. Application of the new section is not expected to have a
material impact on the Trust's financial statements.
4) ISSUANCE OF TRUST UNITS
In the twelve months ended December 31, 2008, approximately 2.1
million Trust Units were issued for $24 million on the exercise of
employee stock options.
5) EMPLOYEE FUTURE BENEFITS
Syncrude Canada Ltd. ("Syncrude Canada"), the operator of the
Syncrude Joint Venture, has a defined benefit and two defined
contribution plans providing pension benefits, and other retirement
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 twelve months ended
December 31, 2008 and 2007 is based on its 36.74 per cent working
interest. The costs have been recorded in operating expense as
follows:
Three Months Ended Twelve Months Ended
December 31 December 31
2008 2007 2008 2007
---------------------------------------------------------------------
Defined benefit plans:
Pension benefits $ 6 $ 7 $ 29 $ 27
Other benefit plans 2 - 5 3
---------------------------------------------------------------------
$ 8 $ 7 $ 34 $ 30
Defined contribution
plans - 1 2 2
---------------------------------------------------------------------
Total benefit cost $ 8 $ 8 $ 36 $ 32
---------------------------------------------------------------------
6) BANK CREDIT FACILITIES
---------------------------------------------------------------------
Extendible revolving
term facility (a) $ 40
Line of credit (b) 67
Operating credit facility (c) 800
---------------------------------------------------------------------
$ 907
---------------------------------------------------------------------
---------------------------------------------------------------------
Each of the Trust's credit facilities is unsecured. These credit
agreements contain typical covenants relating to the restrictions on
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 23, 2009. 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 December 31, 2008, no amounts were drawn on this facility.
b) The $67 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 $67 million have been written
against the line of credit as at December 31, 2008.
c) The $800 million operating facility is a five-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 December 31,
2008, no amounts were drawn on this facility.
7) LONG-TERM DEBT
On April 9, 2008, the Trust repaid $150 million of 5.75 per cent
medium term notes.
Canadian Oil Sands intends to refinance on a long-term basis
approximately $500 million in notes that are maturing in 2009. The
Trust had $840 million of unutilized operating credit facilities at
December 31, 2008 to refinance these obligations, and $800 million of
these facilities do not expire until April 27, 2012. In accordance
with EIC-122 Balance Sheet Classification of Callable Debt
Obligations and Debt Obligations Expected to be Refinanced, debt
maturing in 2009 has not been reclassified to current liabilities.
8) INTEREST, NET
Three Months Ended Twelve Months Ended
December 31 December 31
2008 2007 2008 2007
---------------------------------------------------------------------
Interest expense on
long-term debt $ 20 $ 20 $ 76 $ 91
Interest income and other (1) (3) (8) (6)
---------------------------------------------------------------------
Interest expense, net $ 19 $ 17 $ 68 $ 85
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9) UNITHOLDER DISTRIBUTIONS
The Consolidated Statements of Unitholder Distributions is provided
to assist Unitholders in reconciling cash from operating activities
to Unitholder distributions.
Pursuant to Section 5.1 of the Trust Indenture, the Trust is required
to distribute 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 Year Ended
December 31 December 31
2008 2007 2008 2007
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Cash from operating
activities $ 466 $ 367 $ 2,241 $ 1,377
Add (Deduct):
Capital expenditures (86) (55) (281) (183)
Acquisition of additional
Syncrude working interest - - - (231)
Disposition of properties - 4
Change in non-cash
working capital(1) (16) 4 6 (1)
Reclamation trust funding (2) (3) (6) (7)
Change in cash and cash
equivalents and
financing, net(2) (1) (49) (156) (168)
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Unitholder distributions $ 361 $ 264 $ 1,804 $ 791
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Unitholder distributions
per Trust Unit $ 0.75 $ 0.55 $ 3.75 $ 1.65
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(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.
10) COMMITMENTS
During the third quarter of 2008, Canadian Oil Sands committed to
additional costs of approximately $304 million relating to its share
of the Syncrude Emissions Reduction project. The majority of
additional costs are expected to be incurred over the next three
years.
11) SUPPLEMENTARY INFORMATION
Three Months Ended Year Ended
December 31 December 31
2008 2007 2008 2007
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Income tax paid $ - $ - $ - $ 1
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Interest paid $ 18 $ 13 $ 74 $ 94
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Canadian Oil Sands Limited Canadian Oil Sands Trust
Marcel Coutu 2500 First Canadian Centre
President & Chief Executive Officer 350 - 7 Avenue S.W.
Calgary, Alberta T2P 3N9
Units Listed - Symbol: COS.UN Ph: (403) 218-6200
Toronto Stock Exchange Fax: (403) 218-6201
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