Canadian Oil Sands Trust raises quarterly distribution to $1.25 per Trust unit
All financial figures are unaudited and in Canadian dollars unless
otherwise noted.
TSX - COS.UN
CALGARY, July 29 /CNW/ - Canadian Oil Sands Trust ("Canadian Oil Sands",
the "Trust" or "we") today announced that cash from operating activities in
the second quarter of 2008 increased 27 per cent to $413 million ($0.86 per
Trust unit ("Unit")), over the same 2007 period. Year-to-date, cash from
operating activities was up 62 per cent to $854 million ($1.78 per Unit)
compared with the 2007 six-month period. The increase in cash from operating
activities on both a quarter and year-to-date basis reflects a higher realized
selling price for our synthetic crude oil partially offset by lower sales
volumes and higher operating and Crown royalties expenses.
Net income for the second quarter 2008 was $497 million ($1.04 per Unit)
compared with a net loss of $395 million ($0.82 per Unit) for the 2007 period.
Year-to-date, net income totaled $795 million ($1.66 per Unit) in 2008
compared with a net loss of $133 million ($0.28 per Unit) for 2007. In the
second quarter of 2007 the Trust recorded a one time future income tax expense
of $701 million for the substantive enactment of trust taxation legislation,
resulting in net losses for the 2007 second quarter and year-to-date periods.
The Trust has declared a 25 per cent increase in the quarterly
distribution amount to $1.25 per Unit from $1.00 per Unit for Unitholders of
record on August 15, 2008, payable on August 29, 2008.
Sales volumes quarter-over-quarter and on a year-to-date basis were lower
in 2008 compared with 2007. In 2008, sales volumes averaged about
97,700 barrels per day and 98,500 barrels per day during the second quarter
and first half of the year, respectively. Second quarter 2008 sales volumes
were primarily impacted by a scheduled coker turnaround while the first
quarter was marked by a disruption in operations and reliability challenges in
bitumen production and extraction.
Operating costs in the second quarter of 2008 rose 39 per cent to
$41.92 per barrel from the comparative 2007 quarter. For the first half 2008,
operating costs were $38.90 per barrel, up 46 per cent from the same period
last year. The increase primarily reflects operational difficulties during the
first half of the year, higher bitumen production costs with more mining
activity, and the purchase of third-party bitumen to support the expanded
capacity of the upgrader. As well, purchased energy costs rose with higher
natural gas consumption and prices in 2008.
"As we entered the third quarter of 2008, operational reliability has
improved with Syncrude achieving near design capacity rates in June and July.
While the third quarter will also be impacted by a scheduled coker turnaround,
confidence in Syncrude's operations for the remainder of the year and buoyant
crude oil prices encourage us to once again increase our quarterly
distribution," said Marcel Coutu, President and Chief Executive Officer. "A
principle tenet of our financial plan is to provide investors with a fuller
payout of the cash generated by our business during periods of lower capital
investment in order to manage an efficient capital structure for the Trust."
In the second quarter of 2008, Syncrude's total recordable injury rate
was 0.59 for every 200,000 hours worked compared to a rate of 0.70 recorded
for the same period of 2007.
CANADIAN OIL SANDS TRUST
Highlights
(millions of Canadian Three Months Ended Six Months Ended
dollars, except Trust June 30 June 30
unit and volume amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Net Income $ 497 $ (395) $ 795 $ (133)
Per Trust unit- Basic $ 1.04 $ (0.82) $ 1.66 $ (0.28)
Per Trust unit- Diluted $ 1.04 $ (0.82) $ 1.65 $ (0.28)
Cash from Operating
Activities $ 413 $ 324 $ 854 $ 526
Per Trust unit $ 0.86 $ 0.68 $ 1.78 $ 1.10
Unitholder Distributions $ 481 $ 191 $ 841 $ 335
Per Trust unit $ 1.00 $ 0.40 $ 1.75 $ 0.70
Sales Volumes(1)
Total (MMbbls) 8.9 9.0 17.9 18.8
Daily average (bbls) 97,744 98,720 98,463 103,822
Operating Costs per barrel $ 41.92 $ 30.13 $ 38.90 $ 26.70
Net Realized SCO Selling
Price per barrel $ 131.32 $ 76.81 $ 115.76 $ 72.56
West Texas Intermediate
(average $US per barrel)(2) $ 123.80 $ 65.02 $ 111.12 $ 61.68
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
2008 Outlook
The Trust is estimating Syncrude production to be 106 million barrels in
2008 with a range of 103 to 109 million barrels (net to the Trust, equivalent
to 39 million barrels with a range of 38 to 40 million barrels). This
production estimate was slightly reduced from the one provided on April 28,
2008, to reflect actual production volumes in the first half of the year. The
Trust has increased its average annual operating cost estimate for 2008 to
$35.46 per barrel. Cash from operating activities is estimated to be $4.90 per
Unit, based on an average WTI price of US$120 per barrel in 2008.
More information on the Trust's Outlook is provided in the MD&A section
of this report and the July 29, 2008 guidance document, which is available on
the Trust's web site at www.cos-trust.com under "investor information".
Mining Association of Canada awards Syncrude for 2007 sustainability
performance
Syncrude received five 2007 performance awards from the Mining
Association of Canada ("MAC") under its Towards Sustainable Mining ("TSM")
initiative. TSM is a benchmarking program that assesses company performance in
the areas of Tailings Management, Energy and Greenhouse Gas ("GHG")
Management, Crisis Management, and External Outreach. Syncrude has
participated in this program since inception and had its results externally
verified in both 2006 and 2007. Syncrude received two awards for attaining the
highest level of performance in Crisis Management and External Outreach and
two for meeting MAC's established benchmark standard in Tailings Management
and Energy/GHG Management. Syncrude was also presented with a special award
for being the first MAC member to meet the established benchmark in all
categories.
Canada's oil sands: a different conversation
Canada's oil sands producers and developers have joined together to
engage Canadians and other interested individuals in an open discussion about
oil sands development, and to foster a collaborative process that will create
better understanding and solutions to the related environmental and social
issues.
A central component of this "different conversation" is a new website
(www.canadasoilsands.ca) that features a public discussion forum through which
Canadians and other interested parties can express their views regarding oil
sands development. Over time, producers intend to engage with interested
parties directly through the site, responding to issues and proposing
solutions.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis ("MD&A") was prepared
as of July 29, 2008 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 six months ended June 30, 2008
and June 30, 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 press
release accompanying it contain "forward-looking statements" under applicable
securities law. Forward-looking statements in this MD&A include, but are not
limited to, statements with respect to: the expectation that a target net debt
of $1.6 billion will allow the Trust to maintain a stable credit rating,
conserve tax deductions, remain unhedged and provide the capacity to fund
future growth; the expected structure to be assumed given the Federal
government's tax changes effective in 2011; distributing a fuller amount of
cash from operating activities; the belief that distributions will exceed net
income at times over the next several years; expectations regarding future
distribution levels; the expected tax rate by the federal government on the
Trust in 2011; 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 on the
Trust from announced changes by the Alberta government regarding its royalty
regime; any expectations regarding the enforceability of legal rights; the
expected impact of any current and future environmental legislation, including
without limitation, regulations relating to tailings, or changes to the Crown
royalties regime; the expectation that there will not be any material funding
increases relative to Syncrude's future reclamation costs or pension funding
for the next several years; improvements in operational reliability; the
belief that the Trust will not be restricted by its net debt to total
capitalization financial covenant; the expectation that no crude oil hedges
will be entered into in the future; the expected realized selling price, which
includes the anticipated differential to WTI, to be received in 2008 for
Canadian Oil Sands' product; 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 2008 and beyond; capital expenditures for
2008; the level of natural gas consumption in 2008 and beyond; the expected
price for crude oil and natural gas in 2008; the expected production, revenues
and operating costs for 2008; 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,
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; 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 second quarter of 2008, crude oil production from the Syncrude
Joint Venture ("Syncrude") totalled 24.1 million barrels, or about
265,000 barrels per day, compared with 23.9 million barrels, or about
263,000 barrels per day, during the same period of 2007. Net to the Trust,
production totalled 8.9 million barrels in the second quarter of 2008 based on
our 36.74 per cent working interest compared with 8.8 million barrels in 2007.
Production in the second quarter of 2008 was primarily impacted by a
scheduled 45-day turnaround on Coker 8-1, which began in April and was
completed in mid-May. Operational problems with two sulphur plants and an
extended hydrogen plant turnaround also constrained production in the quarter.
These issues were resolved in May, leading to strong performance for June with
volumes averaging about 361,000 barrels per day. In the second quarter of
2007, production was primarily impacted by maintenance on Coker 8-3 and a
planned turnaround of the LC-Finer.
Year-to-date, Syncrude produced 48.4 million barrels in 2008 or about
266,000 barrels per day, compared with 50.5 million barrels or about
279,000 barrels per day in 2007. In addition to the coker turnaround during
the second quarter, first half 2008 production was impacted by a disruption in
operations triggered by extremely cold weather during the first quarter. The
cold weather also affected bitumen production and extraction. By comparison,
production in the first half of 2007 was impacted by maintenance on Coker 8-3,
Coker 8-2 and other units.
Operating costs increased to $41.92 per barrel in the second quarter of
2008, up $11.79 per barrel from the same quarter last year. Year-to-date
operating costs were $38.90 per barrel in 2008 versus $26.70 per barrel in
2007 (see the "Operating costs" section of this MD&A for further discussion).
Syncrude's facilities have the design capability to produce approximately
375,000 barrels per day when operating at full capacity under optimal
conditions and with no downtime for maintenance or turnarounds. Under normal
operating conditions, scheduled downtime is required for maintenance and
turnaround activities and unscheduled downtime will occur as a result of
operational and mechanical problems, unanticipated repairs and other
slowdowns. When allowances for such downtime are included, the daily design
productive capacity of Syncrude's facilities is approximately 350,000 barrels
per day on average and is referred to as "barrels per calendar day". All
references to Syncrude's productive capacity in this report refer to barrels
per calendar day, unless stated otherwise.
The Trust's production volumes differ from its sales volumes due to
changes in inventory, which are primarily in-transit pipeline volumes that
vary with current production. The impact of Syncrude's 2008 operations on
Canadian Oil Sands' financial results is more fully discussed later in this
MD&A.
SUMMARY OF QUARTERLY RESULTS
($ millions, except
per Trust Unit and 2008 2007
volume amounts) Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Revenues(1) $ 1,177 $ 907 $ 950 $ 936 $ 690 $ 674
Net income (loss) $ 497 $ 298 $ 515 $ 361 $ (395) $ 262
Per Trust Unit,
Basic $ 1.04 $ 0.62 $ 1.07 $ 0.75 $ (0.82) $ 0.55
Per Trust Unit,
Diluted $ 1.04 $ 0.62 $ 1.07 $ 0.75 $ (0.82) $ 0.54
Cash from operating
activities $ 413 $ 441 $ 367 $ 484 $ 324 $ 202
Per Trust Unit(2) $ 0.86 $ 0.92 $ 0.77 $ 1.01 $ 0.68 $ 0.42
Unitholder
distributions $ 481 $ 360 $ 264 $ 192 $ 191 $ 144
Per Trust Unit $ 1.00 $ 0.75 $ 0.55 $ 0.40 $ 0.40 $ 0.30
Daily average sales
volumes (bbls) 97,744 99,181 116,368 124,904 98,720 108,981
Net realized SCO
selling price
($/bbl)(3) $131.32 $100.41 $ 88.73 $ 81.48 $ 76.81 $ 68.69
Operating costs
($/bbl)(4) $ 41.92 $ 35.93 $ 27.38 $ 20.84 $ 30.13 $ 23.56
Purchased natural
gas price ($/GJ) $ 9.38 $ 7.30 $ 5.84 $ 4.99 $ 6.78 $ 6.99
West Texas
Intermediate
(avg. US$/bbl)(5) $123.80 $ 97.82 $ 90.50 $ 75.15 $ 65.02 $ 58.23
Foreign exchange
rates (US$/Cdn$):
Average $ 0.99 $ 1.00 $ 1.02 $ 0.96 $ 0.91 $ 0.85
Quarter-end $ 0.98 $ 0.97 $ 1.01 $ 1.00 $ 0.94 $ 0.87
($ millions, except
per Trust Unit and 2006
volume amounts) Q4 Q3
-------------------------------------
Revenues(1) $ 646 $ 689
Net income (loss) $ 128 $ 278
Per Trust Unit,
Basic $ 0.27 $ 0.60
Per Trust Unit,
Diluted $ 0.27 $ 0.59
Cash from operating
activities $ 412 $ 334
Per Trust Unit(2) $ 0.88 $ 0.72
Unitholder
distributions $ 140 $ 140
Per Trust Unit $ 0.30 $ 0.30
Daily average sales
volumes (bbls) 110,185 95,438
Net realized SCO
selling price
($/bbl)(3) $ 63.71 $ 78.43
Operating costs
($/bbl)(4) $ 23.60 $ 19.68
Purchased natural
gas price ($/GJ) $ 6.51 $ 5.42
West Texas
Intermediate
(avg. US$/bbl)(5) $ 60.16 $ 70.60
Foreign exchange
rates (US$/Cdn$):
Average $ 0.88 $ 0.89
Quarter-end $ 0.86 $ 0.90
(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) Net realized SCO selling price after foreign currency hedging.
(4) 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.
(5) Pricing obtained from Bloomberg.
-------------------------------------------------------------------------
During the last eight quarters, the following items have had a significant
impact on the Trust's financial results:
- U.S. dollar West Texas Intermediate ("WTI") oil prices, which impact
the Trust's revenues, have increased significantly over the last six
quarters, reaching a high of approximately US$140 per barrel during
the second quarter of 2008.
- The substantive enactment of income tax legislation in June 2007 to
apply a new tax on distributions from Canadian public trusts starting
in 2011 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.
- Syncrude's Stage 3 expansion came on-line at the end of August 2006,
increasing Syncrude's productive design capacity by approximately
100,000 barrels per day with a corresponding pro-rata increase to the
Trust's sales volumes, revenues, operating costs, and depletion,
depreciation and accretion ("DD&A") expense.
- On January 2, 2007 the Trust acquired a 1.25 per cent working
interest in Syncrude from Talisman Energy Inc. Commencing in 2007,
the Trust's financial results reflect a 36.74 per cent working
interest in Syncrude while the 2006 financial results reflect the
Trust's previous ownership of 35.49 per cent.
- U.S. to Canadian dollar exchange rate fluctuations have impacted
commodity pricing and have resulted in significant unrealized foreign
exchange gains and losses on the revaluation of U.S. dollar
denominated debt.
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 second quarter of 2008, net income amounted to $497 million, or
$1.04 per Trust unit ("Unit"), compared with a net loss of $395 million, or
$0.82 per Unit, recorded in the comparable quarter in 2007. The loss in the
second quarter of 2007 was primarily the result of a one time $701 million
future income tax expense recorded on the substantive enactment of trust
taxation legislation. In the second quarter of 2008, revenues net of crude oil
purchases and transportation expense totalled approximately $1.2 billion, an
increase of approximately $490 million relative to the second quarter of 2007
as a result of higher crude oil prices. Operating costs increased from
$271 million in the second quarter of 2007 to $373 million in the second
quarter of 2008 as a result of increased contractor and employee costs,
additional mining material moved in the quarter, increased energy costs and
bitumen purchases. Operating costs in both the second quarters of 2008 and
2007 reflect coker maintenance and turnarounds.
Year-to-date net income totaled $795 million, or $1.66 per Unit in 2008
compared with a net loss of $133 million, or $0.28 per Unit, recorded in 2007.
The improvement in net income primarily was the result of higher revenues net
of higher operating costs and Crown royalties in 2008 without the impact of
the one time future income tax expense of $701 million that was recorded in
2007.
Cash from operating activities increased to $413 million for the second
quarter of 2008 versus $324 million for the second quarter of 2007.
Year-to-date cash from operating activities increased to $854 million for 2008
versus $526 million for 2007. The increase in cash from operating activities
was the result of the higher revenues net of increases in operating expenses,
Crown royalties and changes in non-cash working capital.
Changes in non-cash working capital decreased cash from operating
activities by $162 million in the second quarter of 2008, primarily as a
result of higher accounts receivable at June 30, 2008 from stronger sales
volumes and pricing in the month of June 2008 versus March 2008. In the second
quarter of 2007, changes in non-cash working capital increased cash from
operating activities by $57 million, primarily as a result of lower accounts
receivable at June 30, 2007 relative to March 31, 2007.
Year-to-date changes in non-cash working capital decreased cash from
operating activities by $136 million in 2008, primarily as a result of higher
accounts receivable net of higher accounts payable at June 30, 2008 relative
to December 31, 2007. In the same period of 2007, changes in non-cash working
capital decreased cash from operating activities by $37 million primarily as a
result of higher accounts receivable and lower accounts payable at June 30,
2007 relative to December 31, 2007.
Non-cash working capital and changes therein can vary on a
period-by-period basis as a result of the timing and settlements of accounts
receivable and accounts payable balances, and are impacted by a number of
factors including changes in revenue, operating expenses, Crown royalties, the
timing of capital expenditures, and inventory fluctuations.
Net Income (Loss) per Barrel
Three Months Ended Six Months Ended
June 30 June 30
($ per bbl)(1) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Revenues after crude
oil purchases and
transportation
expense 132.34 76.81 55.53 116.30 72.56 43.74
Operating costs (41.92) (30.13) (11.79) (38.90) (26.70) (12.20)
Crown royalties (19.94) (9.94) (10.00) (17.24) (9.75) (7.49)
-------------------------------------------------------------------------
70.48 36.74 33.74 60.16 36.11 24.05
-------------------------------------------------------------------------
Non-production costs (1.79) (1.72) (0.07) (1.83) (1.75) (0.08)
Administration and
insurance (0.97) (0.83) (0.14) (0.86) (0.74) (0.12)
Interest, net (1.87) (2.50) 0.63 (1.85) (2.49) 0.64
Depletion,
depreciation and
accretion (11.39) (8.51) (2.88) (11.37) (8.50) (2.87)
Foreign exchange
gain (loss) 0.51 6.98 (6.47) (1.17) 3.75 (4.92)
Future income tax
(expense) recovery
and other 1.12 (74.06) 75.18 1.34 (33.46) 34.80
-------------------------------------------------------------------------
(14.39) (80.64) 66.25 (15.74) (43.19) 27.45
-------------------------------------------------------------------------
Net income (loss)
per barrel 56.09 (43.90) 99.99 44.42 (7.08) 51.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sales volumes (MMbbls) 8.9 9.0 (0.1) 17.9 18.8 (0.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Unless otherwise specified, net income (loss) 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.
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 capital 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 Six Months Ended
June 30 June 30
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Sales revenue(1) $ 1,285 $ 804 $ 481 $ 2,310 $ 1,585 $ 725
Crude oil purchases (101) (109) 8 (210) (208) (2)
Transportation
expense (8) (9) 1 (18) (19) 1
-------------------------------------------------------------------------
1,176 686 490 2,082 1,358 724
Currency hedging
gains(1) 1 4 (3) 2 6 (4)
-------------------------------------------------------------------------
$ 1,177 $ 690 $ 487 $ 2,084 $ 1,364 $ 720
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sales volumes
(MMbbls)(2) 8.9 9.0 (0.1) 17.9 18.8 (0.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The sum of sales revenue and currency hedging gains equals Revenues
on the Trust's Consolidated Statements of Income and Comprehensive
Income. Sales revenue includes revenue from the sale of purchased
crude oil and sulphur revenue.
(2) Sales volumes, net of purchased crude oil volumes.
($ per barrel)
-------------------------------------------------------------------------
Realized SCO
selling price
before hedging(3) $131.22 $ 76.41 $ 54.81 $115.66 $ 72.26 $ 43.40
Currency hedging
gains 0.10 0.40 (0.30) 0.10 0.30 (0.20)
-------------------------------------------------------------------------
Net realized SCO
selling price $131.32 $ 76.81 $ 54.51 $115.76 $ 72.56 $ 43.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(3) SCO sales revenue after crude oil purchases and transportation
expense divided by sales volumes, net of purchased crude oil volumes.
The increase in sales revenue for 2008 versus 2007 on a quarterly and on
a year-to-date basis was due to a higher realized selling price for our
synthetic crude oil ("SCO") offset by a slight decline in sales volumes.
The increase in the SCO selling price primarily reflects the increase in
WTI prices in 2008. During the second quarter of 2008, WTI prices averaged
US$123.80 per barrel compared to US$65.02 per barrel for the second quarter of
2007. Year-to-date, WTI prices averaged US$111.12 per barrel in 2008 versus
US$61.68 per barrel in 2007. The increase in US dollar WTI prices was tempered
by a stronger Canadian dollar, which averaged $0.99 US/Cdn year-to-date in
2008 compared with $0.88 US/Cdn in 2007, and averaged $0.99 US/Cdn for the
second quarter of 2008 compared with $0.91 US/Cdn for the second quarter of
2007.
In addition to the increase in WTI prices, our SCO continued to receive a
premium to Canadian dollar WTI (the "differential") in 2008. In the second
quarter of 2008, the Trust's SCO realized a weighted-average premium of
$4.05 per barrel compared with the average Canadian dollar WTI price versus a
premium of $4.85 per barrel in the same period in 2007. Year-to-date in 2008,
the Trust's SCO realized a weighted-average premium of $2.87 per barrel
relative to the average Canadian dollar WTI price versus a premium of
$2.28 per barrel for 2007. We believe that the modest improvement in the
differential in 2008 on a year-to-date basis was due to a tighter
supply/demand balance for SCO.
The Trust's sales volumes for the second quarter of 2008 averaged about
97,700 barrels per day versus an average of about 98,700 barrels per day in
the second quarter of 2007. Year-to-date sales volumes averaged about
98,500 barrels per day in 2008 versus an average of about 103,800 barrels per
day for 2007. Sales volumes for 2008 were impacted by the scheduled turnaround
of Coker 8-1 during the second quarter and by operational difficulties during
the first quarter. Sales volumes in 2007 were impacted by maintenance on Coker
8-3, Coker 8-2 and other units.
Operating Costs
Three Months Ended Six Months Ended
June 30 June 30
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) 15.30 10.73 15.71 10.40
Purchased
energy(2),(4) 3.40 2.53 3.77 2.65
Purchased
bitumen 2.43 - 1.90 -
-------------------------------------------------------------------------
21.13 26.21 13.26 16.43 21.38 25.46 13.05 15.90
-------------------------------------------------------------------------
Upgrading Costs(3)
Bitumen processing
and upgrading(2) 6.27 5.26 6.06 5.04
Turnaround and
catalysts 3.54 2.90 2.08 1.91
Purchased energy(4) 4.47 2.32 3.83 2.59
-------------------------------------------------------------------------
14.28 10.48 11.97 9.54
-------------------------------------------------------------------------
Other and research(2) 3.05 2.39 2.18 1.15
Change in treated
and untreated
inventory (1.48) 0.14 (0.64) (0.22)
-------------------------------------------------------------------------
Total Syncrude
operating costs 42.06 29.44 38.97 26.37
Canadian Oil Sands
adjustments(5) (0.14) 0.69 (0.07) 0.33
-------------------------------------------------------------------------
Total operating costs 41.92 30.13 38.90 26.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(thousands
of barrels
per day) Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO
-------------------------------------------------------------------------
Syncrude
production
volumes(6) 327 265 325 263 323 266 339 279
-------------------------------------------------------------------------
(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 $9.38/GJ and $6.78/GJ in the second
quarter of 2008 and 2007, respectively. For the first six months of
the year, natural gas costs averaged $8.27/GJ and $6.90/GJ in 2008
and 2007, respectively.
(5) Canadian Oil Sands' adjustments mainly pertain to Syncrude-related
pension costs, as well as the inventory impact of moving from
production to sales as Syncrude reports per barrel costs based on
production volumes and the Trust reports based on sales volumes.
(6) Syncrude production volumes include the impact of processed purchased
bitumen volumes.
Three Months Ended Six Months Ended
June 30 June 30
($/bbl of SCO) 2008 2007 2008 2007
-------------------------------------------------------------------------
Production costs 33.23 24.68 30.58 20.88
Purchased energy 8.69 5.45 8.32 5.82
-------------------------------------------------------------------------
Total operating costs 41.92 30.13 38.90 26.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(GJs/bbl of SCO)
-------------------------------------------------------------------------
Purchased energy consumption 0.93 0.80 1.01 0.84
-------------------------------------------------------------------------
In the second quarter of 2008, operating costs were $373 million,
averaging $41.92 per barrel, an increase of $102 million, or $11.79 per
barrel, over the second quarter of 2007 operating costs of $271 million.
Operating costs in both the second quarters of 2008 and 2007 reflect coker
maintenance and turnarounds. Year-to-date operating costs were $697 million in
2008, averaging $38.90 per barrel, an increase of $195 million, or $12.20 per
barrel over 2007. The increase in costs for the reported periods is primarily
due to the following:
- Additional overburden material was moved during the first and
second quarters of 2008 versus 2007. Syncrude also increased its use
of contracted equipment and operators to supplement its own material
movement activities in 2008 in order to re-establish exposed mineable
ore inventory and meet operational requirements;
- 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;
- the purchase of incremental bitumen in 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
resuming shipments at Syncrude following the disruption of operations
early in the year;
- higher energy costs reflecting higher natural gas prices and
increased natural gas consumption on per barrel basis due to
operational inefficiencies during 2008; and
- an increase 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, the market performance of which was stronger in the
first half of 2008 relative to the same period in 2007.
Operating costs per barrel also have increased in 2008 on a year-to-date
basis as a result of reduced production volumes in 2008 versus 2007. A
significant portion of Syncrude's operating costs are fixed and as such, any
change in production impacts per unit operating costs. While inflationary
pressures are expected to persist, improvements in operational reliability
should help to reduce the costs related to the operational inefficiencies
experienced during 2008.
Non-Production Costs
Non-production costs totalled $16 million and $15 million in the second
quarters of 2008 and 2007, respectively. Year-to-date non-production costs
totalled $33 million for both 2008 and 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 second quarter of 2008, Crown royalties increased to $178 million,
or $19.94 per barrel, from $89 million, or $9.94 per barrel, in the comparable
2007 quarter. Year-to-date Crown royalties increased to $309 million, or
$17.24 per barrel, in 2008 from $183 million, or $9.75 per barrel in 2007. The
increase in royalties in 2008 on both a quarterly and a year-to-date basis was
primarily due to significantly increased revenues partially offset by higher
operating costs.
Potential changes to Crown royalty terms by the Alberta government are
discussed later in this MD&A.
Interest Expense, Net
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Interest expense on
long-term debt $ 18 $ 24 $ 38 $ 49
Interest income and other (2) (1) (5) (2)
-------------------------------------------------------------------------
Interest expense, net $ 16 $ 23 $ 33 $ 47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Trust's net interest expense in 2008 has decreased relative to the
comparable periods in 2007 due to reduced average net debt outstanding.
Depreciation, Depletion and Accretion Expense
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Depreciation and depletion
expense $ 98 $ 74 $ 197 $ 154
Accretion expense 4 3 7 5
-------------------------------------------------------------------------
$ 102 $ 77 $ 204 $ 159
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The increase in depreciation and depletion ("D&D") expense in 2008 on a
quarterly and on a 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 $8.31 in 2007 as a result of higher projected capital cost
estimates for Syncrude in the Trust's December 31, 2007 independent reserves
report.
Foreign Exchange Loss (Gain)
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Unrealized foreign exchange
loss (gain) $ (8) $ (76) $ 26 $ (87)
Realized foreign exchange
loss (gain) 3 13 (5) 17
-------------------------------------------------------------------------
Total foreign exchange
loss (gain) $ (5) $ (63) $ 21 $ (70)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized foreign exchange ("FX") gains and losses are the result of
revaluations of our U.S. dollar denominated long-term debt caused by
fluctuations in U.S. and Canadian dollar exchange rates. The unrealized FX
gains and losses reported in 2008 resulted from the change in the value of the
Canadian dollar relative to the U.S. dollar to $0.98 US/Cdn at June 30, 2008
from $0.97 US/Cdn at March 31, 2008 and $1.01 US/Cdn at December 31, 2007. The
unrealized FX gains in 2007 were due to the change in the value of the
Canadian dollar relative to the U.S. dollar to $0.94 US/Cdn at June 30, 2007
from $0.87 US/Cdn at March 31, 2008 and $0.86 US/Cdn at December 31, 2007.
Future Income Tax and Other
In the second quarter of 2008, a $10 million future income tax recovery
was recorded on the reduction of temporary differences versus a future income
tax expense of $665 million in the second quarter of 2007. On a year-to-date
basis, a future income tax recovery of $24 million was recorded in 2008 on the
reduction of temporary differences compared with a future income tax expense
of $628 million in 2007.
Prior to the substantive enactment of Bill C-52 in June 2007, the federal
government's legislation to tax distributions from income trusts commencing in
2011, Canadian Oil Sands' future income taxes reflected only those temporary
differences in the Trust's subsidiaries. Upon the substantive enactment of
Bill C-52, Canadian Oil Sands recorded a one-time $701 million future income
tax expense and a corresponding future income tax liability related to the
differences between the accounting and tax basis of the Trust's assets and
liabilities.
In June 2008, Bill C-50, which contains legislation to adjust the deemed
provincial component on the tax rate on distributions from income and royalty
trusts expected to apply to Canadian Oil Sands commencing in 2011, passed
third reading 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, however, the
adjustment to the provincial component of the tax is not considered
substantively enacted as the income tax regulations for the adjustment 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.
With the taxation of income trusts commencing January 1, 2011 Canadian
Oil Sands is evaluating alternatives as to the best structure for its
Unitholders in the future. On July 14, 2008, the Department of Finance
released proposed conversion rules for income and royalty trusts. The draft
rules, which are subject to comments by interested parties by September 15,
2008, are designed to permit income and royalty trusts to convert into public
corporations and wind up without triggering adverse tax consequences to the
income or royalty trust and its Unitholders. We are assessing the draft rules
and their implications to the Trust. However, until the draft legislation is
finalized and ultimately passed into law, we will not be able to complete our
evaluation. Subject to the finalization of the conversion rules, we plan to
retain the flow-through advantages of a trust structure until 2011 unless
circumstances arise that favour a faster transition to an alternate structure.
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 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:
- 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; 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 is 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
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.
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.
Canadian Oil Sands has commenced assessing the impact on our business of
adopting IFRS in 2011 and is preparing for the transition accordingly.
UNITHOLDER DISTRIBUTIONS
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash from operating activities $ 413 $ 324 $ 854 $ 526
Net income (loss) $ 497 $ (395) $ 795 $ (133)
Unitholder distributions $ 481 $ 191 $ 841 $ 335
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Excess (shortfall) of cash
from operating activities
over Unitholder distributions $ (68) $ 133 $ 13 $ 191
Excess (shortfall) of net
income over Unitholder
distributions $ 16 $ (586) $ (46) $ (468)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In the second quarter of 2008, Unitholder distributions exceeded cash
from operating activities by $68 million as a result of changes in non-cash
working capital. During the quarter, changes in non-cash working capital
reduced cash from operating activities by $162 million, primarily as a result
of a $198 million increase in accounts receivable at June 30, 2008 relative to
March 31, 2008. For the second quarter of 2008, cash from operating activities
along with opening cash balances at April 1, 2008 funded the Trust's
distributions, capital expenditures, and reclamation trust fund contributions.
Year-to-date cash from operating activities exceeded Unitholder
distributions by $13 million and, along with opening cash balances at
January 1, 2008, funded the Trust's distributions, capital expenditures, and
reclamation trust fund contributions.
Total distributions during 2008 exceeded net income on a year-to-date
basis primarily as a result of DD&A. DD&A is a non-cash item that does not
affect the Trust's cash from operating activities, balance sheet strength or
ability to pay distributions over the next several years.
The Trust uses debt and equity financing to the extent that cash from
operating activities is insufficient to fund distributions, capital
expenditures, reclamation trust contributions, acquisitions and working
capital changes from financing and investing activities.
On July 29, 2008 the Trust declared a quarterly distribution of $1.25 per
Unit in respect of the third quarter of 2008 for a total distribution of
$602 million. The distribution will be paid on August 29, 2008 to Unit holders
of record on August 15, 2008. 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.
The 25 per cent increase in the distribution over the previous quarter
reflects the Trust's financial plan of managing its capital structure in
anticipation of trust taxation in 2011. The Trust is distributing a fuller
amount of cash from operating activities unless capital investment or
acquisition opportunities arise that management believes offer Unitholders
enhanced value. Additionally, under current market conditions, the Trust plans
on raising its long-term net debt to about $1.6 billion by the end of 2010. We
believe this net debt target reflects efficient capital management and will
help conserve tax pools prior to trust taxation. The target is based on
Syncrude's existing productive capacity and we will reconsider this target in
light of Canadian Oil Sands future capital requirement plans.
In determining the Trust's distributions, Canadian Oil Sands 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 $20 million and
$18 million on a year-to-date basis in 2008 and 2007, respectively, and
approximated the related expense for both pension and reclamation of
$25 million and $22 million for each of the periods, respectively. While our
share of Syncrude's annual pension funding has increased modestly as a result
of the most recent actuarial valuation and our share of Syncrude's future
reclamation costs has increased, we currently do not anticipate any material
increases in funding related to these items for the next few years.
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-book capitalization at an amount less than 55 per cent. With a
current net debt-to-book 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 dramatically
from period to period reflecting, among other things, variability in
operational performance, WTI prices, SCO differentials to WTI and FX rates.
The Trust strives to smooth out the effect of this variability on
distributions by taking a longer-term view of our outlook for our operating
and business environment, our net debt level relative to our target, and our
capital expenditure and other commitments. In that regard, we may distribute
more or less in a period than we generate in cash from operating activities or
net income. Nonetheless, the highly variable nature of our cash from operating
activities introduces risk in our ability to sustain or provide stability in
distributions and any expectations regarding the stability or sustainability
of distributions are unwarranted and should not be implied.
As the Trust executes its financial plan, investors should anticipate
increased variability in distributions and understand that current
distribution levels may not be sustainable once we have reached our net debt
target. As distributions comprise a larger percentage of cash from operating
activities, the distributions will necessarily be more reflective of business
performance and crude oil prices. Further, the taxation of income trusts
commencing January 1, 2011 likely will materially alter our cash from
operating activities, and consequently distribution levels.
LIQUIDITY AND CAPITAL RESOURCES
June 30 December 31
($ millions) 2008 2007
-------------------------------------------------------------------------
Long-term debt $ 1,079 $ 1,218
Cash and cash equivalents (32) (268)
-------------------------------------------------------------------------
Net debt(1) $ 1,047 $ 950
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unitholders' equity $ 4,147 $ 4,172
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total capitalization(2) $ 5,194 $ 5,122
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Non-GAAP measure
(2) Net debt plus Unitholders' equity
Net debt to total capitalization (%) 20 19
-------------------------------------------------------------------------
As at June 30, 2008 the Trust had $840 million of credit facilities
available and unutilized. In addition, the Trust 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 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 actual crude oil prices, Syncrude's operational
performance, distributions, and FX rates vary from our assumptions.
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 are 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 second quarter of 2008, capital expenditures totalled $54 million,
compared with expenditures of $50 million in the same quarter of 2007. The
Syncrude Emissions Reduction ("SER") project accounted for $21 million and
$19 million of the capital spent in the second quarters of 2008 and 2007,
respectively. The remaining amounts in each quarter pertained to other
sustaining capital activities. Sustaining capital expenditures on a per barrel
basis were approximately $6.00 and $5.35 in each of the second quarters of
2008 and 2007, respectively.
Year-to-date capital expenditures totalled $101 million in 2008 versus
$83 million in 2007. The SER project accounted for $38 million and $34 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 $5.63 and $4.40
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 significantly reduce total
sulphur dioxide and other emissions. While expenditures on the SER project are
estimated at approximately $772 million ($284 million net to the Trust based
on its 36.74 per cent working interest) there is upward cost pressure on the
project. Syncrude is currently performing a full review of the SER project and
will provide updates to cost estimates and timing after such review has been
completed. The Trust's share of the SER project expenditures incurred to date
is approximately $144 million, with the remaining costs expected to be
incurred in the next three years to coordinate with equipment turnaround
schedules.
Sustaining capital expenditures, including the SER project, are estimated
to average approximately $8 per barrel for 2008. Over the longer term, we
expect sustaining capital expenditures to average approximately $5 per barrel
before inflation; however, over the next few years we expect to incur an
additional $2 to $5 per barrel annually for large environmental and
infrastructure projects. These projects include the relocation of certain
mining trains and tailings systems, which are required as mining operations
progress across the active leases. Tailings system projects also include
initiatives to improve and supplement the effectiveness of systems used to
separate water from sand and clay so that the water can be recycled back to
the operation and solids can be incorporated into the final reclamation
landscapes. Our per barrel estimates are based on estimated annual Syncrude
production, which increases from 106 million barrels in 2008, or 39 million
barrels net to the Trust, to 129 million barrels, or 47 million barrels net to
the Trust, 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 was expected to grow Syncrude capacity by a further 100,000 barrels
per day, post-2016. 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 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 have been approved and are being
developed. 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 possible that the debottleneck will be delayed beyond
our current 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.
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 $26.5 billion
with 482 million Units outstanding and a closing price of $55 per Unit on
June 30, 2008.
Second
Canadian Oil Sands Trust - Quarter June May April
Trading Activity 2008 2008 2008 2008
-------------------------------------------------------------------------
Unit price
High $ 55.14 $ 55.00 $ 55.14 $ 48.30
Low $ 40.25 $ 48.64 $ 43.53 $ 40.25
Close $ 55.00 $ 55.00 $ 50.04 $ 45.23
Volume traded (millions) 88.1 28.7 33.9 25.5
Weighted average Trust units
outstanding (millions) 480.8 481.5 480.9 479.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
As of July 29, 2008 there have been no significant changes to the Trust's
contractual obligations and commitments in 2008 from our 2007 year-end
disclosure, other than the repayment of approximately $150 million in maturing
medium term notes on April 9, 2008.
FINANCIAL RISK MANAGEMENT
The Trust did not have any financial derivatives outstanding at June 30,
2008.
Crude Oil Price Risk
Canadian Oil Sands did not have any crude oil price hedges in place for
2008 or 2007. As at June 30, 2008 the Trust remains unhedged on its crude oil
price exposure and does not intend to introduce any crude oil hedge positions.
Canadian Oil Sands may, however, hedge its crude oil production in the future
depending on the business environment and growth opportunities.
Foreign Currency Hedging
As at June 30, 2008, we do not have any foreign currency hedges in place.
At the present time, we do not intend to introduce any currency hedge
positions. Canadian Oil Sands may, however, hedge foreign 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 June 30, 2008 we did not have any debt outstanding bearing
interest at floating market-based rates.
FOREIGN OWNERSHIP
Based on information from the statutory declarations by Unitholders, we
estimate that, as of May 16, 2008, approximately 34 percent of our Units are
held by non-Canadian residents with the remaining 66 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 August 15, 2008. The Trust posts its foreign ownership levels and describes
its steps for managing these levels on its web site (www.cos-trust.com) under
"Investor Information", "Frequently Asked Questions". These steps are also
described in the Trust's AIF.
CROWN ROYALTY CHANGES
In 2007, the Alberta government announced new Crown royalty terms,
effective January 1, 2009. For oil sands projects, the new terms are based on
a sliding scale royalty rate ranging from one to nine per cent pre-payout and
25 to 40 per cent post-payout that responds to Canadian dollar equivalent WTI
("C$-WTI") price levels. The pre-payout rate starts at one per cent of revenue
and increases for every dollar oil is priced above $55 C$-WTI per barrel, to a
maximum of nine per cent of revenue at $120 C$-WTI per barrel or higher. The
net royalty rate applied post-payout will start at 25 per cent of net revenue
and rises for every dollar of C$-WTI increase above $55 C$-WTI per barrel up
to a maximum of 40 per cent of net revenue at $120 C$-WTI per barrel or
higher.
The Syncrude Joint Venture owners have a Crown royalty agreement with the
Alberta government that codifies the current royalty terms of 25 per cent of
net SCO revenues to December 31, 2015. The Crown royalty agreement also
provides Syncrude with the option to convert to a bitumen-based royalty,
consistent with the rest of the industry, prior to 2010. Canadian Oil Sands,
as one of the Syncrude owners, is currently in discussions with the Alberta
government regarding both the conversion to a bitumen-based royalty and an
equitable solution to offset Syncrude's transition to the higher generic
royalty rate prior to 2016. Canadian Oil Sands remains of the view that any
transition to the new generic royalty terms must recognize our legal rights to
the embedded value in Syncrude's contract with the government.
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. Syncrude is cooperating with Alberta Environment and
Sustainable Resource Development officials in their investigation into why
this occurred. Previous to this event, Syncrude's waterfowl management
program, which includes the deployment of noise cannons and scarecrows, has
worked very well over decades of use. Syncrude and its owners are very
disappointed this occurred and are focused on understanding how to prevent
this from happening again.
Greenhouse Gas Emissions Reduction Requirements
On March 31, 2008 Syncrude submitted its 2007 compliance report on
greenhouse gas ("GHG") emissions to the Alberta government for review by the
director of Alberta Environment. The submission of the compliance report meets
the regulatory deadline specified by the Alberta government as part of its
Bill 3 legislation introduced in 2007 to reduce GHG emission intensity. Bill 3
states that facilities emitting more than 100,000 tonnes of GHGs a year
("Large Emitters") must reduce their emissions intensity (emissions per unit
of production) by 12 per cent over the average emissions intensity levels of
2003, 2004 and 2005. If they are unable to do so, these facilities will be
required to pay $15 per tonne for every tonne above the 12 per cent target,
beginning July 1, 2007.
For 2008, Syncrude is accruing approximately $0.10 per barrel for
compliance with Bill 3, which is reflected in the Trust's operating costs. The
cost estimate remains preliminary pending Syncrude's actual carbon dioxide
("CO2") emission intensity level and clarification from the Alberta government
regarding details of the Bill 3 implementation. No cost estimates are
available for future years.
On March 10, 2008 Canada'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 CO2 emissions. In addition to the reduction of existing
GHG emissions, the capture and storage of CO2 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
CO2 capture, transportation and storage network through participation in the
integrated CO2 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 by December 31,
2009.
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. The regulation as presently drafted, however, is likely to
have an adverse impact on the current cost estimates for tailings management.
Syncrude has filed an amendment to its regulatory approval to modify the
design of the existing Southwest Sand Storage ("SWSS") facility to permit
interim storage of increased volumes of mature fine tailings. 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.
2008 OUTLOOK
(millions of Canadian dollars, July 29, April 28,
except volume and per barrel amounts) 2008 2008
-------------------------------------------------------------------------
Syncrude production (MMbbls) 106 108
Canadian Oil Sands Sales (MMbbls) 38.9 39.7
Revenues, net of crude oil purchases
and transportation 4,734 3,929
Operating costs 1,381 1,273
Operating costs per barrel 35.46 32.07
Crown royalties 742 575
Capital expenditures 294 265
Cash from operating activities 2,356 1,924
Business environment assumptions
--------------------------------
West Texas Intermediate (US$/bbl) $ 120 $ 100
Premium (Discount) to average C$ WTI
prices (C$/bbl) $ 1.50 $ (1.00)
Foreign exchange rate (US$/Cdn$) $ 1.00 $ 1.00
AECO natural gas (Cdn$/GJ) $ 9.50 $ 8.50
The Trust has lowered its 2008 Syncrude production estimate to
106 million barrels to reflect first half results. The estimate continues to
incorporate Syncrude's remaining 2008 maintenance program, including the
turnaround of Coker 8-2 in the third quarter, an allowance for unplanned
outages, and recognition that Syncrude is still working to establish reliable
Stage 3 design rates. The Syncrude production estimate is set within a range
of 103 to 109 million barrels for 2008.
We have increased our estimate of the Trust's 2008 revenues as a result
of increases in the realized SCO sales price. Operating costs estimates have
increased as a result of the year-to-date financial results, the expectation
of continuing high costs in mining and maintenance operations, increased
natural gas prices and the impact of reduced production volumes on the
calculation of per Unit costs. The Trust has not assumed any further bitumen
purchases in this current Outlook; however, Syncrude may purchase up to
10,000 barrels per day of additional bitumen during the remainder of 2008 to
provide for flexibility in SCO production. The increase in forecasted Crown
royalties is due to the increased revenues net of increased cost estimates.
As a result of current assumptions, our revised estimate of cash from
operating activities has increased to $2,356 million or $4.90 on a per Unit
basis. With the increase in the distribution to $1.25 per Unit in the third
quarter of 2008, we are estimating net debt levels will remain at
approximately $1 billion at the end of 2008.
Distributions paid in 2008 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 quarter of 2009.
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.
2008 Outlook Sensitivity Analysis
Cash from Operating Activities
Annual(2) Increase
Variable(1) Sensitivity $ millions $/Trust unit
-------------------------------------------------------------------------
Syncrude operating costs
decrease C$1.00/bbl 29 0.06
Syncrude operating costs
decrease C$50 million 14 0.03
WTI crude oil price increase US$1.00/bbl 24 0.05
Syncrude production increase 2 million bbls 59 0.12
Canadian dollar weakening US$0.01/C$ 29 0.06
AECO natural gas price
decrease C$0.50/GJ 13 0.03
(1) An opposite change in each of these variables will result in the
opposite cash from operating activities impacts.
(2) Sensitivities assume a larger change in unrealized quarters to result
in the annual impact.
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)
Three Months Ended Six Months Ended
($ millions, except per June 30 June 30
Unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues $ 1,286 $ 808 $ 2,312 $ 1,591
Crude oil purchases and
transportation expense (109) (118) (228) (227)
-------------------------------------------------------------------------
1,177 690 2,084 1,364
-------------------------------------------------------------------------
Expenses:
Operating 373 271 697 502
Non-production 16 15 33 33
Crown royalties 178 89 309 183
Administration 9 6 13 10
Insurance 1 1 3 4
Interest, net (Note 8) 16 23 33 47
Depreciation, depletion
and accretion 102 77 204 159
Foreign exchange loss (gain) (5) (63) 21 (70)
-------------------------------------------------------------------------
690 419 1,313 868
-------------------------------------------------------------------------
Earnings before taxes 487 271 771 496
Future income tax expense
(recovery) and other (10) 665 (24) 628
-------------------------------------------------------------------------
Net income (loss) from
continuing operations 497 (394) 795 (132)
Loss from discontinued
operations - (1) - (1)
-------------------------------------------------------------------------
Net income (loss) 497 (395) 795 (133)
Other comprehensive loss,
net of income taxes
Reclassification of
derivative gains to
net income - (2) (1) (4)
-------------------------------------------------------------------------
Comprehensive income (loss) $ 497 $ (397) $ 794 $ (137)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average Trust Units
(millions) 481 479 480 479
Trust Units, end of period
(millions) 482 479 482 479
Net income (loss) per
Trust Unit:
Basic $ 1.04 $ (0.82) $ 1.66 $ (0.28)
Diluted $ 1.04 $ (0.82) $ 1.65 $ (0.28)
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Retained earnings
Balance, beginning of period $ 1,581 $ 1,809 $ 1,643 $ 1,691
Net income (loss) 497 (395) 795 (133)
Unitholder distributions
(Note 9) (481) (191) (841) (335)
-------------------------------------------------------------------------
Balance, end of period 1,597 1,223 1,597 1,223
-------------------------------------------------------------------------
Accumulated other
comprehensive income
Balance, beginning of period 23 28 24 30
Other comprehensive loss - (2) (1) (4)
-------------------------------------------------------------------------
Balance, end of period 23 26 23 26
-------------------------------------------------------------------------
Unitholders' capital
Balance, beginning of period 2,500 2,498 2,500 2,260
Issuance of Trust Units
(Note 4) 24 1 24 239
-------------------------------------------------------------------------
Balance, end of period 2,524 2,499 2,524 2,499
-------------------------------------------------------------------------
Contributed surplus
Balance, beginning of period 5 4 5 4
Exercise of employee stock
options (3) - (3) -
Stock-based compensation 1 - 1 -
-------------------------------------------------------------------------
Balance, end of period 3 4 3 4
-------------------------------------------------------------------------
Total Unitholders' equity $ 4,147 $ 3,752 $ 4,147 $ 3,752
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED BALANCE SHEETS
AS AT
(unaudited)
June 30 December 31
($ millions) 2008 2007
-------------------------------------------------------------------------
ASSETS
Current assets:
Cash and cash equivalents $ 32 $ 268
Accounts receivable 588 379
Inventories 118 102
Prepaid expenses 2 6
-------------------------------------------------------------------------
740 755
Property, plant and equipment, net 6,321 6,427
Goodwill 52 52
Reclamation trust 39 37
-------------------------------------------------------------------------
$ 7,152 $ 7,271
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 368 $ 289
Current portion of employee future benefits 16 16
-------------------------------------------------------------------------
384 305
Employee future benefits and other liabilities 112 128
Long-term debt 1,079 1,218
Asset retirement obligation 232 226
Future income taxes 1,198 1,222
-------------------------------------------------------------------------
3,005 3,099
Unitholders' equity 4,147 4,172
-------------------------------------------------------------------------
$ 7,152 $ 7,271
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See Notes to Unaudited Consolidated Financial Statements
CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash from (used in) operating
activities
Net income (loss) $ 497 $ (395) $ 795 $ (133)
Items not requiring outlay
of cash:
Depreciation, depletion
and accretion 102 77 204 159
Unrealized foreign exchange
on long-term debt (8) (76) 26 (87)
Future income tax expense
(recovery) (10) 666 (24) 628
Other 5 (4) 5 (4)
Net change in deferred items (11) (1) (16) -
-------------------------------------------------------------------------
Funds from operations 575 267 990 563
Change in non-cash
working capital (162) 57 (136) (37)
-------------------------------------------------------------------------
Cash from operating
activities 413 324 854 526
-------------------------------------------------------------------------
Cash from (used in) financing
activities
Repayment of medium term
and Senior Notes (150) (77) (150) (272)
Net drawdown (repayment) of
bank credit facilities - (50) (16) 70
Unitholder distributions
(Note 9) (481) (191) (841) (335)
Issuance of Trust Units
(Note 4) 21 2 21 2
-------------------------------------------------------------------------
Cash used in financing
activities (610) (316) (986) (535)
-------------------------------------------------------------------------
Cash from (used in) investing
activities
Capital expenditures (54) (50) (101) (83)
Acquisition of additional
Syncrude working interest - - - (231)
Disposition of properties - 4 - 4
Reclamation trust funding (2) (2) (3) (3)
Change in non-cash
working capital - 8 - 2
-------------------------------------------------------------------------
Cash used in investing
activities (56) (40) (104) (311)
-------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents (253) (32) (236) (320)
Cash and cash equivalents
at beginning of period 285 65 268 353
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents
at end of period $ 32 $ 33 $ 32 $ 33
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents
consist of:
Cash $ 3 $ 1
Short-term investments 29 32
-------------------------------------------------------------------------
$ 32 $ 33
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Information (Note 10)
See Notes to Unaudited Consolidated Financial Statements
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED JUNE 30, 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 is effective for the Trust beginning January 1, 2008.
Application of the new Section did not have an 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 six months ended June 30, 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 six months ended
June 30, 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 Six Months Ended
June 30 June 30
2008 2007 2008 2007
---------------------------------------------------------------------
Defined benefit plans:
Pension benefits $ 7 $ 7 $ 15 $ 14
Other benefit plans 1 1 2 2
---------------------------------------------------------------------
$ 8 $ 8 $ 17 $ 16
Defined contribution plans - 1 1 1
---------------------------------------------------------------------
Total Benefit cost $ 8 $ 9 $ 18 $ 17
---------------------------------------------------------------------
---------------------------------------------------------------------
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.
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 June 30, 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 June 30, 2008,
no amounts were drawn on this facility.
7) LONG-TERM DEBT
On April 9, 2008, the Trust repaid $150 million of 5.75% medium term
notes.
8) INTEREST, NET
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
---------------------------------------------------------------------
Interest expense on
long-term debt $ 18 $ 24 $ 38 $ 49
Interest income and other (2) (1) (5) (2)
---------------------------------------------------------------------
Interest expense, net $ 16 $ 23 $ 33 $ 47
---------------------------------------------------------------------
---------------------------------------------------------------------
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 income received or receivable by the Trust in a
quarter less expenses and any other amounts required by law or under
the terms of the Trust Indenture. The Trust primarily receives income
by way of a royalty and interest on intercompany loans from its
operating subsidiary, Canadian Oil Sands Limited ("COSL"). The
royalty is designed to capture the cash generated by COSL, after the
deduction of all costs and expenses including operating and
administrative costs, income taxes, capital expenditures, debt
interest and principal repayments, working capital and reserves for
future obligations deemed appropriate. The amount of royalty income
that the Trust receives in any period has a considerable amount of
flexibility through the use of discretionary reserves and debt
borrowings or repayments (either intercompany or third party).
Quarterly distributions are determined by COSL's Board of Directors
after considering the current and expected economic and operating
conditions, ensuring financing capacity for Syncrude's expansion
projects and/or Canadian Oil Sands acquisitions, and with the
objective of maintaining an investment grade credit rating.
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
---------------------------------------------------------------------
Cash from operating
activities $ 413 $ 324 $ 854 $ 526
Add (Deduct):
Capital expenditures (54) (50) (101) (83)
Acquisition of additional
Syncrude working interest - - - (231)
Disposition of properties 4 4
Change in non-cash working
capital(1) - 8 - 2
Reclamation trust funding (2) (2) (3) (3)
Change in cash and cash
equivalents and
financing, net(2) 124 (93) 91 120
---------------------------------------------------------------------
Unitholder distributions $ 481 $ 191 $ 841 $ 335
---------------------------------------------------------------------
---------------------------------------------------------------------
Unitholder distributions
per Trust Unit $ 1.00 $ 0.40 $ 1.75 $ 0.70
---------------------------------------------------------------------
---------------------------------------------------------------------
(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) SUPPLEMENTARY INFORMATION
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
---------------------------------------------------------------------
Income tax paid $ - $ 1 $ - $ 1
---------------------------------------------------------------------
---------------------------------------------------------------------
Interest paid $ 13 $ 19 $ 38 $ 54
---------------------------------------------------------------------
---------------------------------------------------------------------
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
For further information: Siren Fisekci, Director, Investor Relations,
(403) 218-6228, investor_relations@cos-trust.com, web site: www.cos-trust.com
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