2008-07-29 16:06:00
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 /EMWNews/ - 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 http://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
(http://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 http://www.sedar.com or on the Trust's website at http://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
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