Canadian Oil Sands Announces 2011 First Quarter
Results and Capital Cost Estimates for Major Projects
All financial figures are unaudited and in Canadian
dollars unless otherwise noted.
Canadian Oil Sands Limited ("Canadian Oil
Sands", "COS" or "we") (TSX: COS) today announced
first quarter 2011 results. Cash flow from operations in the first quarter of
2011 more than doubled to $478 million ($0.99 per Share) compared with $225
million ($0.46 per Share) in the first quarter of 2010. Net income for the
first quarter of 2011 rose to $324 million ($0.67 per Share) compared with $176
million ($0.36 per Share) in the first quarter of 2010. The improvement in
financial results reflects an increase in production and higher crude oil
prices.
COS today declared a dividend of $0.30 per Share
payable on May 31, 2011 to shareholders of record on May 26, 2011. COS has a
variable dividend strategy; dividend amounts will vary over time depending
largely on crude oil prices and the investment cycle of Syncrude's capital
projects.
"Stronger crude oil prices combined with better
clarity on future Syncrude capital requirements have led us to increase the
dividend to $0.30 per Share for the second quarter of 2011," said Marcel
Coutu, President and Chief Executive Officer. "We also are encouraged by
the recent strong operational performance at Syncrude, with first quarter 2011
production being the best first quarter on record."
Sales volumes during the first quarter of 2011
averaged 121,000 barrels per day compared with 99,000 barrels per day for the
first quarter of 2010. Operations reflect improved capacity utilization in the
first quarter of 2011 compared with the first quarter of 2010, which was
impacted by the turnaround of the LC Finer and associated upgrading units.
Higher sales volumes resulted in lower per barrel
operating expenses for the first quarter of 2011, which averaged $35.53 per
barrel compared with $37.89 per barrel in the 2010 first quarter.
Syncrude's total recordable injury rate for the first
quarter of 2011 was 1.22 compared with a rate of 0.39 for the same period of
2010. Syncrude recently adopted ExxonMobil's Incident and Injury Reporting
Guidelines that capture more types of events, therefore the rates for 2010 and
2011 are not directly comparable.
"This quarter, we are following through with our
undertaking to provide investors with a multi-year capital cost profile for our
mine train replacements and relocations and other large projects. Although the
estimates are still variable because the detailed engineering has not been
completed, we are confident at this point that we can fund these projects from
our cash flow without any significant equity dilution," said Coutu.
Highlights
Three
Months Ended
March 31
(millions of Canadian dollars, except per
Share and
per barrel volume amounts)
2011
2010
----------------------------------------------------------------------------
Cash flow from operations (1)
$ 478 $ 225
Per Share
(2)
$ 0.99 $ 0.46
Net Income
$ 324 $ 176
Per Share,
Basic and Diluted
$ 0.67 $ 0.36
Sales Volumes (3)
Total
(MMbbls)
10.9
8.9
Daily
average (bbls)
120,894
99,286
Realized SCO Selling Price ($/bbl)
$ 93.04 $ 82.06
West Texas Intermediate (average $US/bbl) (4) $ 94.60 $ 78.88
Operating Expenses ($/bbl)
$ 35.53 $ 37.89
Capital Expenditures
$ 109 $ 112
Dividends
$
97
$ 170
Per
Share
$ 0.20 $ 0.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Cash flow from operations is a non-GAAP measure
and is defined on page 9
of the Management's
Discussion and Analysis
("MD&A") section of this report.
(2) Cash flow from operations per Share is a non-GAAP
measure and is defined
on page 9 of the
MD&A section of this report.
(3) The Corporation's sales volumes differ from its
production volumes due
to changes in
inventory, w hich are primarily in-transit pipeline
volumes. Sales volumes
are net of purchased crude oil volumes.
(4) Pricing obtained from Bloomberg.
Syncrude Major Capital Projects
Syncrude is investing in a number of major capital
projects in 2011 through 2014 to support strong, stable, long-life production
while achieving operational efficiencies and improving environmental
performance.
The early cost estimates for these projects, with the
exception of the Syncrude Emissions Reduction project, are variable (plus or
minus 25 per cent), which is appropriate for the current stage of definition.
Under the Management Services Agreement between Syncrude Canada and Imperial
Oil, Imperial Oil provides Syncrude Canada with project management expertise,
utilizing ExxonMobil's global best practices and processes. We believe having
Imperial Oil assist Syncrude in managing these projects provides the potential
for better project execution and cost management. Imperial Oil is a Syncrude
joint venture owner with a vested interest in the project's success, and
through ExxonMobil, their parent company, they are recognized as a global
leader in managing major projects.
Syncrude Emissions Reduction (SER) project
The SER project is an environmental project that
represents a significant commitment to reduce Syncrude's impact on the local
air shed. It is designed to contribute to a 60 per cent reduction in sulphur
compound emissions from current approved levels once the project is fully
operational. Emissions of particulate matter also are expected to decline
considerably. Construction of this project commenced in 2006 and is scheduled
to be in service in 2011. Once operational, all of Syncrude's cokers will be
equipped with technology to capture emissions of sulphur dioxide and
particulates.
Mine Train projects
Syncrude operates five mine trains on its active
leases, four of which will be relocated or rebuilt over the next few years.
Like all surface mining operations, this activity is necessary to support
Syncrude's mine plan for the placement of tailings material and eventual
reclamation. Plans are in place to coordinate these efforts such that
production should not be affected.
A mine train is a modular process for crushing and
mixing the oil sands with warm water to facilitate the extraction of bitumen
from the oil sands. It includes three components: a crusher, which breaks down
the bitumen ore after it has been mined; a surge bin that regulates the oil
sands' feed into the process; and a mix box in which warm water is added to the
oil sands to form a slurry suitable for pumping. The resulting slurry is then
pumped to extraction via a hydrotransport pipeline, a Syncrude technology that
conditions the oil sands for separation.
At Syncrude's Mildred Lake mine site, the two existing
mine trains will be dismantled and new mine trains will be constructed at a new
location. The construction of these mine trains will incorporate Syncrude's new
wet crushing technology, which is expected to improve bitumen recovery and
lower maintenance requirements.
At the Aurora North mine site, there are three mine
trains. These mine trains were designed to be moveable and two will be
relocated; the third train will not need to be relocated. This is a much less
capital intensive process than the new mine train construction required at
Mildred Lake where the older, more permanent design does not allow a similar
equipment move.
Basic engineering has been completed for these projects
and civil works has commenced. Once the relocations and rebuilds have been
completed, the mine trains are expected to be in operation in their new
locations until the Mildred Lake and Aurora North mines are fully depleted with
no further moves required.
Aurora North Tailings Management
Syncrude expects to begin site preparation for a
composite tails (CT) plant at its Aurora North mine in 2011 as part of the
original plan for this mine. Construction is scheduled to start in 2012 with an
anticipated in-service date of 2013. A CT plant currently operates at the
Mildred Lake mine. A CT plant mixes mature fine tailings (MFT) with gypsum and
coarse tailings sand to transform the MFT into solid reclamation material. The
CT plant at the Aurora North mine is expected to process more than half of the
MFT produced at that site.
Syncrude has a multi-pronged approach to managing its
tailings and meeting the requirements of the Alberta government's Tailings
Directive 074. In addition to CT, other tailings management infrastructure is
required by 2015 but cost estimates for this infrastructure are not yet
available.
Syncrude and its industry counterparts have the
opportunity to share each others' tailings technologies through a technology
sharing agreement announced in December 2010.
The following tables provide cost and schedule
estimates for Syncrude's major capital projects that have reached a certain
stage of definition. In particular, they do not provide cost estimates for
Aurora South development, other tailings management infrastructure or
maintenance of business post 2011:
Major Capital Projects(1)
Total Project Cost and Schedule Estimates(2)
Spent to Total
Cost
Target
Dec 31, 2010
Estimate Estimated %
In-Service
Project
($ millions) ($ billions) Accuracy Date
----------------------------------------------------------------------------
Syncrude
Emissions
Reduction (SER) Syncrude $ 1,108 $ 1.6 +10%/-10% Q4 2011
Retrofit
COS share
407
0.6
technology
into
Syncrude's
original
two
cokers to
reduce
total
sulphur
dioxide
and other
emissions
Mildred Lake
Mine
Train
Replacement Syncrude
166
3.6
+25%/-25% Q4 2014
Reconstruct COS share
61
1.3
crushers,
surge
facilities,
and slurry
prep
facilities
to
support
tailings
storage
requirements
Aurora North
Mine Train
Relocation
Syncrude 51
0.9
+25%/-25% Q1 2014
Relocate
COS share
19
0.3
crushers,
surge
facilities,
and slurry
prep
facilities
to
support
tailings
storage
requirements
Aurora North
Tailings
Management
Syncrude
59
0.8
+25%/-25% Q4 2013
Construct COS
share
22
0.3
composite
tails
(CT) plant
at the
Aurora
North mine
----------------------------------------------------------------------------
Total
Syncrude $ 1,384 $ 6.9
COS share
509
2.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Major Capital Projects(1)
Annual Spending Profile(2)
Cost Estimate
Spent to --------------------------------------------------
Dec 31,
2010
2011
2012
2013
2014 Total
($ ($
($
($ ($ ($
millions) millions) billions) billions) billions) billions)
----------------------------------------------------------------------------
Syncrude
Major capital
projects
$ 1,384 $ 1,672 $ 1.9 $ 1.7 $ 0.3 $ 6.9
Regular
maintenance of
the
business
and other
projects
831
----------
Total capital
expenditures
$ 2,503
----------------------------------------------------------------------------
Canadian Oil
Sands
share
Major capital
projects
$ 509 $ 614 $ 0.7 $ 0.6 $ 0.1 $ 2.5
Regular
maintenance of
the
business
and other
projects
305
----------
Total direct
capital
expenditures
919
Capitalized
interest
60
----------
Total capital
expenditures
$ 979
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Major capital projects include the Syncrude
Emissions Reduction (SER),
Mildred Lake Mine Train Replacement, Aurora North Mine Train Relocation
and Aurora North Tailings Management. Major Capital Projects do not
include projects that have not reached sufficient design definition,
such as Aurora South and other tailings management infrastructure.
(2) Total project costs include both capital costs and
certain
non-production costs. Costs
exclude capitalized interest.
Canadian Oil Sands plans to finance these major
capital projects primarily through cash flow from operations.
Beyond 2014, Syncrude's capital program includes
development of a group of undeveloped leases called Aurora South aimed at
expanding bitumen production by approximately 50 per cent before 2020. Syncrude
is in the process of developing cost estimates for this expansion, which
expansion must also be approved by the Syncrude joint venture owners.
The major capital projects descriptions and tables and
the expectations regarding the development of Aurora South contain
forward-looking information and users of this information are cautioned that
the actual yearly and total capital expenditures, the actual in-service dates
for the major capital projects and the actual level and timing of bitumen
production growth expected from the development of Aurora South may vary from
the plans disclosed. The capital expenditure cost estimates, major capital
project target in-service dates and expectations regarding the development of
Aurora South are based on current capital spending plans. Please refer to the
"Forward-Looking Information Advisory" in the MD&A section of
this report for the risks and assumptions underlying this forward-looking
information. For a list of additional risk factors that could cause the actual
amount of the capital expenditures and the major capital project target
in-service dates and the level and timing of bitumen production growth expected
from the development of Aurora South to differ materially, please refer to the
Corporation's Annual Information Form dated March 10, 2011 which is available
on the Corporation's profile on SEDAR at www.sedar.com and on the Corporation's website at www.cdnoilsands.com.
2011 Outlook
The outlook for production remains unchanged from the
guidance provided on January 27, 2011. Canadian Oil Sands estimates 2011
Syncrude production of 110 million barrels (40.4 million barrels, net to COS),
with a production range of 102 to 115 million barrels. This is equivalent to
301,400 barrels per day (110,700 barrels per day net to COS). The 110 million
barrel single-point estimate includes one planned coker turnaround in the
second half of the year.
Other estimates have been revised from the January
guidance. The estimate for operating costs increased to $37.51 per barrel.
Capital expenditures are now estimated at $979 million, including $614 million
for major capital projects, $305 million for regular maintenance of the
business and other projects, and $60 million in capitalized interest. In
accordance with IFRS, a portion of interest costs are capitalized with an
offsetting reduction to interest expense. Excluding capitalized interest, the
forecast is largely unchanged.
The April 28, 2011 Outlook assumes an increased U.S.
$95 per barrel WTI oil price, an SCO premium to Cdn dollar WTI of $4.00 per
barrel, and a stronger U.S./Cdn foreign exchange rate of $1.03. These
assumptions result in estimated sales of $3,890 million, or $96 per barrel in
2011.
The increase in our forecasted SCO premium to Cdn
dollar WTI reflects recent operational upsets and maintenance at several oil
sands plants, which have reduced SCO supply and resulted in significant
premiums relative to WTI. These supply disruptions are expected to be resolved
over the course of the year, which will likely result in SCO premiums
decreasing in the second half of 2011.
We are estimating cash flow from operations of
approximately $1.9 billion, or $3.95 per Share, in 2011. After deducting
forecast 2011 capital expenditures, we estimate $936 million in remaining cash
flow from operations for the year, or $1.93 per Share.
More information on COS' outlook is provided in the
MD&A section of this report and the April 28, 2011 guidance document, which
is available on our web site at www.cdnoilsands.com under "Investor Information".
The 2011 Outlook contains forward-looking information
and users are cautioned that the actual amounts may vary from the estimates
disclosed. Please refer to the "Forward-Looking Information Advisory"
in the MD&A section of this report for the risks and assumptions underlying
this forward-looking information.
Corporate Governance
Effective April 28, 2011, Wayne Newhouse will retire
from Canadian Oil Sands' board of directors. Mr. Newhouse is one of the
original board members, and his commitment over our long history is deeply
appreciated. In particular, the board and management will miss his valuable
contribution as chair of the Reserves Committee.
Another member of COS' board, Ian Bourne, deserves
special recognition for receiving a fellowship award from the Institute of
Corporate Directors. This award is the highest distinction for corporate
directors in Canada and recognizes Mr. Bourne for his outstanding contributions
to corporate governance.
Annual General Meeting
Canadian Oil Sands' Annual General Meeting of
Shareholders will be held today, April 28, 2011 at 2:30 p.m. (Mountain Daylight
Time) in the Ballroom of The Metropolitan Conference Centre, 333 Fourth Avenue
SW, Calgary, Alberta. A live audio webcast of the meeting will be available on
our website at www.cdnoilsands.com. An archive of the webcast will be
available approximately one hour following the meeting.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis
("MD&A") was prepared as of April 28, 2011 and should be read in
conjunction with the unaudited interim consolidated financial statements of
Canadian Oil Sands Limited (the "Corporation") for the three months
ended March 31, 2011 and March 31, 2010, the audited consolidated financial statements
and MD&A of the Corporation for the year ended December 31, 2010 and the
Corporation's Annual Information Form ("AIF") dated March 10, 2011.
Additional information on the Corporation, including its AIF, is available on
SEDAR at www.sedar.com or on the Corporation's website at www.cdnoilsands.com. References to Canadian Oil Sands or COS include the Corporation, its subsidiaries
and partnership and, as applicable, Canadian Oil Sands Trust (the
"Trust") prior to its dissolution. The financial results of Canadian
Oil Sands have been prepared in accordance with Canadian Generally Accepted
Accounting Principles ("GAAP") and are reported in Canadian dollars,
unless stated otherwise.
As a result of our conversion from an income trust to
a corporate structure on December 31, 2010 pursuant to which all outstanding
trust units of the Trust were exchanged on a one-for-one basis for common
shares of the Corporation, the financial information of Canadian Oil Sands
refers to common shares or shares ("Shares"), shareholders and
dividends which were referred to as Units, Unitholders and distributions under
the trust structure.
FORWARD-LOOKING INFORMATION ADVISORY- in the interest
of providing the Corporation's shareholders and potential investors with
information regarding the Corporation, including management's assessment of the
Corporation's future production and cost estimates, plans and operations,
certain statements throughout this MD&A and the related press release
contain "forward-looking statements" under applicable securities law.
Forward-looking statements are typically identified by words such as
"anticipate", "expect", "believe",
"plan", "intend" or similar words suggesting future
outcomes. Forward-looking statements in this MD&A include, but are not
limited to, statements with respect to: future dividends and any increase or
decrease from current payment amounts; the establishment of future dividend
levels with the intent of absorbing short-term market volatility over several
quarters; plans regarding crude oil hedges and currency hedges in the future;
the level of natural gas consumption in 2011 and beyond; the expected production,
revenues, operating costs and Crown royalties for 2011; the expected price for
crude oil and natural gas in 2011; the expected foreign exchange rates in 2011;
the expected realized selling price, which includes the anticipated
differential to WTI to be received in 2011 for Corporation's product; the
anticipated impact of increases or decreases in oil prices, production,
operating costs, foreign exchange rates and natural gas prices on the
Corporation's cash flow from operations; the expected amount of total capital
expenditures and anticipated target in-service dates for the Syncrude Emissions
Reduction ("SER") project, the Mildred Lake mine train replacements,
the Aurora North mine train relocations and the composite tails plant at the Aurora
North mine; the expectation that the SER project will significantly reduce
total sulphur dioxide and other emissions; the expectation that the Corporation
will finance the major capital projects primarily through cash flow from
operations; the expected improvement in bitumen recovery and lower maintenance
requirements from wet crushing technology; the expected timing of
site-preparation and construction of the Aurora North composite tails plant;
the cost estimates for 2011 total capital expenditures and post-2011 major
capital project spending and the expectation that the development of Aurora
South will expand bitumen production by approximately 50 per cent before 2020.
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 Corporation believes
that the expectations represented by such forward-looking statements are
reasonable and reflect the current views of Corporation with respect to future
events, there can be no assurance that such assumptions and expectations will
prove to be correct.
The factors or assumptions on which the
forward-looking information is based include, but are not limited to: the
assumptions outlined in the Corporation's guidance document as posted on the
Corporation's website at www.cdnoilsands.com as of the date hereof and as
subsequently amended or replaced from time to time, including without
limitation, the assumptions as to production, operating costs and oil prices;
the successful and timely implementation of capital projects; the ability to
obtain regulatory and Syncrude joint venture owner approval; our ability to
either generate sufficient cash flow from operations to meet our current and
future obligations or obtain external sources of debt and equity capital; the
continuation of assumed tax, royalty and regulatory regimes and the accuracy of
the estimates of our reserves volumes.
Some of the risks and other factors which could cause
actual results or events to differ materially from current expectations
expressed in the forward-looking statements contained in this MD&A and the
related press release include, but are not limited to: the impacts of
legislative or regulatory changes especially as such relate to royalties,
taxation, the environment and tailings; the impact of technology on operations
and processes and how new complex technology may not perform as expected;
skilled labour shortages and the productivity achieved from labour in the Fort
McMurray area; the supply and demand metrics for oil and natural gas; the
impact that pipeline capacity and refinery demand have on prices for our
products; the unanimous joint venture owner approval for major expansions and
changes in product types; the variances of stock market activities generally;
global economic conditions/volatility; normal risks associated with litigation,
general economic, business and market conditions; the impact of Syncrude being
unable to meet the conditions of its approval for its tailings management plan
under Directive 074, and such other risks and uncertainties described in the
Corporation's Annual Information Form dated March 10, 2011 and in the reports and
filings made with securities regulatory authorities from time to time by the
Corporation which are available on the Corporation's profile on SEDAR at www.sedar.com and on the Corporation's website at www.cdnoilsands.com.
You are cautioned that the foregoing list of important
factors is not exhaustive. 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 Corporation 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.
NON-GAAP FINANCIAL MEASURES - In this MD&A and the
related press release, 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 flow from
operations, cash flow from operations on a per Share basis, net debt, total
capitalization and net debt to total capitalization. These measures are
indicators of the Corporation's capacity to fund capital expenditures, other
investing activities, and dividends without incremental financing. In addition,
the Corporation refers to various per barrel figures, such as net realized
selling prices, operating costs and Crown royalties, which also are considered
non-GAAP measures. We derive per barrel figures by dividing the relevant sales
or cost figure by our sales volumes, which are net of purchased crude oil volumes
in a period. Non-GAAP financial measures provide additional information that we
believe is meaningful regarding the Corporation's operational performance, its
liquidity and its capacity to fund dividends, capital expenditures and other
investing activities. Users are cautioned that non-GAAP financial measures
presented by the Corporation may not be comparable with measures provided by
other entities.
Beginning this quarter, we are reporting cash flow
from operations in total and on a per Share basis. Previously, we reported cash
from operating activities. Cash flow from operations is calculated as cash from
operating activities, as reported on the Consolidated Statement of Cash Flows,
before changes in non-cash working capital. Cash flow from operations per Share
is calculated as cash flow from operations divided by the weighted-average
number of Shares outstanding in the period. We believe that cash flow from
operations, which is not impacted by fluctuations in non-cash working capital
balances, is more indicative of operational performance. The majority of our
non-cash working capital is liquid and typically settles within 30 days.
Cash flow from operations is reconciled to cash from
operating activities as
follows:
Three
Months Ended
March 31
($ millions)
2011
2010
----------------------------------------------------------------------------
Cash flow from operations
$ 478 $ 225
Change in non-cash working capital (1)
(19)
104
----------------------------------------------------------------------------
Cash from operating activities (1)
$ 459 $ 329
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) As reported on the Consolidated Statements of Cash
Flows
TRANSITION TO INTERNATIONAL FINANCIAL REPORTING
STANDARDS
Canadian GAAP has been revised to incorporate
International Financial Reporting Standards ("IFRS") and publicly
traded companies like the Corporation are required to apply such standards for
years beginning on or after January 1, 2011. Note 5 to the attached interim
unaudited consolidated financial statements discloses the impact of the
transition to IFRS on the Corporation's reported financial position, income and
cash flows, including the nature and effect of changes in accounting policies
from those used in the Corporation's Canadian GAAP audited consolidated
financial statements for the year ended December 31, 2010.
First quarter 2010 financial measures reported in this
MD&A as comparative figures have been adjusted to reflect the transition to
IFRS, as have the financial measures for all 2010 quarters reported in the
summary of quarterly results on page 12. The accounting policies applied in
these interim unaudited consolidated financial statements are based on IFRS
issued and outstanding as of April 28, 2011. Any subsequent changes to IFRS
that are given effect in the Corporation's annual consolidated financial
statements for the year ending December 31, 2011 could result in a restatement
of these interim consolidated financial statements, including the adjustments
recognized on transition to IFRS.
The January 1, 2010 and December 31, 2010 balance
sheets were adjusted to reflect the following:
-- The
deferred tax liability was re-measured on transition at January 1,
2010 using the 39 per cent individual tax rate applicable to earnings
not distributed to trust unitholders. On conversion from an income
trust to a corporate structure on December 31, 2010, the deferred tax
liability was re-measured using the 25 per cent corporate tax rate,
resulting in a deferred tax recovery in the fourth quarter of 2010.
Prior to the adoption of IFRS, deferred taxes were measured using the
25 per cent corporate tax rate.
-- The
asset retirement obligation liability and related property, plant
and equipment were re-measured on transition at January 1, 2010, and at
the end of each reporting period, to reflect the current risk free
interest rate. Prior to the adoption of
IFRS, these were measured using
a credit-adjusted interest rate and were not re-measured each reporting
period for changes to this rate.
--
Employee future benefits and other liabilities were adjusted on
transition at January 1, 2010, and
at the end of each reporting period,
to record previously unrecognized actuarial losses on Syncrude Canada's
defined benefit pension plan.
Under IFRS, net income is adjusted to reflect the
following:
-- Revenues
are now reported net of Crown royalties; previously Crown
royalties were reported as an expense.
--
Operating expenses have decreased reflecting the capitalization of major
turnaround costs as property, plant and equipment; previously these
costs were expensed. Operating
expenses per barrel have likewise
decreased.
--
Interest costs relating to certain assets being constructed are now
capitalized; previously all interest costs were expensed.
-- Depreciation
and depletion has increased reflecting the depreciation of
capitalized turnaround costs partially offset by the reclassification of
accretion of the asset retirement obligation. Accretion is now presented
with interest as part of net finance expense.
-- Future
income taxes are now referred to as deferred taxes.
-- Other
less significant IFRS adjustments have impacted operating
expenses, administration expenses, depreciation and depletion, and net
finance expense.
While the IFRS adjustments do not impact the
Corporation's total cash flow, cash flow from operations and cash used in
investing activities have each been adjusted, by equal and offsetting amounts,
to reflect the capitalization of major turnaround costs and interest costs on
certain assets during construction.
REVIEW OF SYNCRUDE OPERATIONS
Synthetic crude oil ("SCO") production from
the Syncrude Joint Venture ("Syncrude") during the first quarter of
2011 was the highest of any first quarter on record, totaling 28.9 million
barrels, or 321,000 barrels per day, compared with 24.2 million barrels, or
269,000 barrels per day, during the first quarter of 2010. Net to the
Corporation, production totaled 10.6 million barrels in the first quarter of
2011 compared with 8.9 million barrels in the first quarter of 2010, based on
Canadian Oil Sands' 36.74 per cent working interest in Syncrude.
The increase in quarter-over-quarter production
volumes reflects improved reliability through most of the operations in the
first quarter of 2011 relative to the first quarter of 2010. First quarter 2010
volumes were impacted by the turnaround of the LC Finer and associated
upgrading units.
Canadian Oil Sands' operating expenses were $387
million, or $35.53 per barrel, in the first quarter of 2011, compared with $339
million, or $37.89 per barrel, in the same quarter of 2010. The decrease in per
barrel operating expenses was mainly due to higher sales volumes (see the
"Operating Expenses" section of this MD&A for further discussion).
The productive capacity of Syncrude's facilities is
approximately 350,000 barrels per day on average, including an allowance for
downtime, and is referred to as "barrels per calendar day". All
references to Syncrude's production capacity in this report refer to barrels
per calendar day, unless stated otherwise. Canadian Oil Sands' production
volumes differ from its sales volumes due to changes in inventory, which are
primarily in-transit pipeline volumes.
SUMMARY OF QUARTERLY RESULTS
($ millions, except per Share and
2011
2010
volume
amounts)
Q1
Q4
Q3 Q2
----------------------------------------------------------------------------
Sales (1)
$ 1,016 $ 912 $ 692 $ 842
Net income
$ 324 $ 572 $ 195 $ 244
Per Share,
Basic & Diluted
$ 0.67 $ 1.18 $ 0.40 $ 0.50
Cash flow from operations (2)
$ 478 $
398 $ 229 $ 380
Per Share
(2)
$ 0.99 $ 0.82 $ 0.47 $ 0.79
Dividends
$ 97 $ 242 $ 242 $ 242
Per
Share
$ 0.20 $ 0.50 $ 0.50 $ 0.50
Daily average sales volumes
(bbls)
(3)
120,894 114,739 96,477 118,569
Realized SCO selling price
($/bbl)
(4)
$ 93.04 $
83.97 $ 77.94 $
78.07
Operating expenses ($/bbl) (5) $ 35.53 $
35.81 $ 37.86 $
30.93
Purchased natural gas price ($/GJ) $ 3.59 $ 3.45 $ 3.44 $ 3.68
West Texas Intermediate (avg.
US$/bbl)
(6)
$ 94.60 $
85.24 $ 76.21 $
78.05
Foreign exchange rates (US$/Cdn$):
Average
$ 1.02 $ 0.99 $ 0.96 $ 0.97
Quarter-end
$ 1.03 $ 1.01 $ 0.97 $ 0.94
($ millions, except per Share and
2010
2009 (7)
volume
amounts)
Q1
Q4
Q3 Q2
----------------------------------------------------------------------------
Sales (1)
$ 734 $ 863 $ 773 $ 467
Net income
$ 176 $ 96 $ 247 $ 46
Per Share,
Basic & Diluted
$ 0.36 $ 0.20 $ 0.51 $ 0.10
Cash flow from operations (2)
$ 225 $
366 $ 296 $ 23
Per Share
(2)
$ 0.46 $ 0.76 $ 0.61 $ 0.05
Dividends
$ 170 $ 169 $ 121 $ 73
Per
Share
$ 0.35 $ 0.35 $ 0.25 $ 0.15
Daily average sales volumes
(bbls)
(3)
99,286 119,287 114,544 75,553
Realized SCO selling price
($/bbl)
(4)
$ 82.06 $
78.67 $ 73.31 $
67.92
Operating expenses ($/bbl) (5) $ 37.89 $
30.18 $ 27.80 $
50.23
Purchased natural gas price ($/GJ) $ 4.95 $ 4.33 $ 2.90 $ 3.09
West Texas Intermediate (avg.
US$/bbl)
(6)
$ 78.88 $
76.13 $ 68.24 $
59.79
Foreign exchange rates (US$/Cdn$):
Average
$ 0.96 $ 0.95 $ 0.91 $ 0.86
Quarter-end
$ 0.98 $ 0.96 $ 0.93 $ 0.86
(1) Sales after crude oil purchases and transportation
expense.
(2) Cash flow from operations and Cash flow from
operations per Share are a
non-GAAP measures and are defined on page 9 of this MD&A.
(3) Daily average sales volumes after crude oil
purchases.
(4) Realized SCO selling price after foreign currency
hedging.
(5) Derived from operating costs, as reported on the
Consolidated Statements
of Income and Comprehensive Income, divided by the sales volumes during
the period.
(6) Pricing obtained from Bloomberg.
(7) Not adjusted for IFRS.
During the last eight quarters, the following items
have had a significant
impact on the Corporation's financial results:
--
fluctuations in U.S. dollar WTI oil prices have impacted the
Corporation's sales, Crown royalties, net income and cash flow from
operations;
-- U.S. to
Canadian dollar exchange rate fluctuations have resulted in
foreign exchange gains and losses on the revaluation of U.S. dollar
denominated debt and have impacted commodity pricing;
-- fluctuations in the differential between
SCO and Canadian dollar WTI oil
prices have impacted the Corporation's sales, Crown royalties, net
income and cash flow from operations;
-- planned
and unplanned maintenance activities have impacted quarterly
production volumes, revenues and operating expenses;
-- net
income was increased in the fourth quarter of 2010 due to a $269
million deferred tax recovery resulting from measuring the deferred tax
liability at a lower tax rate upon conversion from an income trust to a
corporate structure on December 31, 2010 (this deferred tax recovery was
not recognized under Canadian GAAP before the adoption of IFRS);
--
depreciation and depletion expense was lower in 2010 and the first
quarter of 2011 as a result of changes to the estimation methodology
made in the first quarter of 2010; and
-- net
income was reduced in the fourth quarter of 2009 by $148 million due
to an impairment charge and goodwill write-down on the Arctic natural
gas assets.
Quarterly variances in net income and cash flow from
operations are caused mainly by fluctuations in crude oil prices, production
and sales volumes, operating expenses and natural gas prices. Net income is
also impacted by unrealized foreign exchange gains and losses, depreciation and
depletion, impairment charges and deferred tax amounts.
While the supply/demand balance for crude oil affects
selling prices, the impact of this relationship is difficult to predict and
quantify and has not displayed significant seasonality. Natural gas prices are
typically higher in winter months as heating demand rises, but this seasonality
is influenced by weather conditions and North American natural gas inventory
levels.
Syncrude production levels may not display seasonal
patterns or trends. While maintenance and turnaround activities are typically
scheduled to avoid the winter months, the exact timing of unit shutdowns cannot
be precisely scheduled, and unplanned outages may occur. The costs of major turnarounds
have been capitalized as property, plant and equipment and depreciated over the
period until the next scheduled turnaround. The costs of all other turnarounds
and maintenance activities have been expensed in the period incurred, which can
result in volatility in quarterly operating costs. Because a large proportion
of operating costs are fixed, the effect on per barrel operating costs of the
non-major turnaround and maintenance activities is amplified as the facilities
are generally producing at reduced rates when this work is occurring.
REVIEW OF FINANCIAL RESULTS
Three Months Ended
(millions of Canadian dollars, except per
March 31
Share and
per barrel volume amounts)
2011
2010
----------------------------------------------------------------------------
Cash flow from operations (1)
$
478 $ 225
Per Share
(2)
$ 0.99 $ 0.46
Net Income
$
324 $ 176
Per Share,
Basic and Diluted
$
0.67 $ 0.36
Sales Volumes (3)
Total
(MMbbls)
10.9 8.9
Daily
average (bbls)
120,894
99,286
Realized SCO Selling Price ($/bbl)
$ 93.04 $ 82.06
West Texas Intermediate (average $US/bbl) (4) $ 94.60 $ 78.88
Operating Expenses ($/bbl)
$ 35.53 $ 37.89
Capital Expenditures
$
109 $ 112
Dividends
$
97 $ 170
Per
Share
$ 0.20 $ 0.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Cash flow from operations is a non-GAAP measure
and is defined on page 9
of this MD&A.
(2) Cash flow from operations per Share is a non-GAAP
measure and is defined
on page 9 of this MD&A.
(3) The Corporation's sales volumes differ from its
production volumes due
to changes in inventory, w hich are primarily in-transit pipeline
volumes. Sales volumes are net of purchased crude oil volumes.
(4) Pricing obtained from Bloomberg.
Net income per Barrel
Three Months Ended
March 31
($ per bbl) (1)
2011
2010
Variance
----------------------------------------------------------------------------
Sales net of crude oil
purchases and transportation
expense
93.36
82.10
11.26
Operating expenses
(35.53)
(37.89)
2.36
Crown royalties
(6.49)
(8.74)
2.25
----------------------------------------------------------------------------
51.34
35.47
15.87
----------------------------------------------------------------------------
Non-production expenses
(3.00)
(4.04)
1.04
Administration and insurance
expenses
(1.04)
(1.23)
0.19
Depreciation and depletion
(8.77)
(11.82)
3.05
Net finance expense
(1.27)
(2.91)
1.64
Foreign exchange gain (loss)
1.99
3.72
(1.73)
Deferred tax (expense) recovery
(9.43)
0.48
(9.91)
----------------------------------------------------------------------------
(21.52)
(15.80)
(5.72)
----------------------------------------------------------------------------
Net income per barrel
29.82
19.67
10.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales volumes (MMbbls) (2)
10.9
8.9
2.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Unless otherwise specified, the per barrel
measures in this MD&A have
been derived by dividing the relevant revenue or cost item by the sales
volumes in the period.
(2) Sales volumes, net of purchased crude oil volumes.
Cash flow from operations was $478 million, or $0.99
per Share, for the first quarter of 2011 compared with cash flow from
operations of $225 million, or $0.46 per Share, for the first quarter of 2010.
Higher sales in the first quarter of 2011 were partially offset by higher
operating expenses.
Sales net of crude oil purchases and transportation
costs totaled $1,016 million in the first quarter of 2011 compared with $734
million in the first quarter of 2010. The increase in quarter-over-quarter
sales reflects higher crude oil prices and sales volumes in the first quarter
of 2011 (see the "Sales net of Crude Oil Purchases and Transportation
Expense" section of this MD&A for further discussion).
Crown royalties totaled $71 million in the first
quarter of 2011 compared with $78 million in the first quarter of 2010. The
decrease in 2011 Crown royalties relative to 2010 was due to lower deemed
bitumen revenues and higher allowed costs (see the "Crown royalties"
section of this MD&A for further discussion of Crown royalties).
Operating expenses in the first quarter of 2011
totaled $387 million, or $35.53 per barrel, compared with $339 million, or
$37.89 per barrel, in the first quarter of 2010. The decrease in per barrel
operating expenses was due to higher sales volumes (see the "Operating
Expenses" section of this MD&A for further discussion).
Net income totaled $324 million, or $0.67 per Share,
in the first quarter of 2011, compared with $176 million, or $0.36 per Share,
for the first quarter of 2010. The variances in sales, Crown royalties, and
operating expenses described earlier impacted net income, as did variances in
foreign exchange gains, depreciation and depletion expense and deferred taxes.
Depreciation and depletion expense totaled $95 million
in the first quarter of 2011 compared with $106 million in the first quarter of
2010. The decrease is mainly due to changes in the estimated useful lives of
certain tangible equipment.
Foreign exchange gains on the revaluation of long-term
debt fell to $25 million in the first quarter of 2011 from $34 million in the
same period of 2010.
As a result of the conversion from an income trust to
a corporate structure on December 31, 2010, Canadian Oil Sands recorded a $103
million deferred tax expense in the first quarter of 2011 versus a $4 million
recovery in the first quarter of 2010.
Net debt, comprised of long-term debt less cash and
cash equivalents, decreased to $0.9 billion at March 31, 2011 from $1.2 billion
at December 31, 2010. The decrease is a result of cash flow from operations
exceeding capital expenditures, dividends and reclamation trust fund
contributions. A stronger Canadian dollar at March 31, 2011 relative to
December 31, 2010 further reduced the Canadian dollar equivalent value of the
U.S. dollar denominated long-term debt.
Capital expenditures in the first quarter of 2011 were
$109 million compared with $112 million in the first quarter of 2010.
Sales net of Crude Oil Purchases and Transportation
Expense
Three Months Ended
March 31
($ millions)
2011
2010
Variance
----------------------------------------------------------------------------
Sales (1)
$
1,083 $
899 $ 184
Crude oil purchases
(59)
(159)
100
Transportation expense
(8)
(6)
(2)
----------------------------------------------------------------------------
$
1,016 $
734 $ 282
Sales volumes (MMbbls) (2)
10.9 8.9
2.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Sales include sales of purchased crude oil and
sulphur and proceeds
from insurance claims.
(2) Sales volumes, net of purchased crude oil volumes.
----------------------------------------------------------------------------
Realized SCO selling price
(average
$Cdn/bbl) (3)
93.04
82.06
10.98
West Texas Intermediate
(average
$US/bbl)
94.60
78.88
15.72
SCO premium (discount)
(weighted-average $Cdn/bbl)
0.35
(0.05)
0.40
Average foreign exchange rates
(US$/Cdn$)
1.02
0.96
0.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(3) SCO sales net of crude oil purchases and transportation
expense divided
by sales volumes, net of purchased crude oil volumes.
The increase in sales net of crude oil purchases and
transportation expense in the first quarter of 2011 relative to the first
quarter of 2010 reflects a higher realized selling price for our SCO and higher
sales volumes.
During the first quarter of 2011, the West Texas
Intermediate ("WTI") crude oil price averaged U.S. $95 per barrel
compared with U.S. $79 per barrel in the first quarter of 2010. The impact of
the higher U.S. dollar WTI oil price was offset somewhat by a stronger Canadian
dollar, which averaged $1.02 U.S./Cdn for the first quarter of 2011 versus
$0.96 U.S./Cdn for the first quarter of 2010.
The Corporation's SCO price is also affected by the
premium or discount realized relative to Canadian dollar WTI (the
"differential"). In the first quarter of 2011, the Corporation
realized a weighted-average SCO premium of $0.35 per barrel versus a $0.05 per
barrel discount in the first quarter of 2010. The differential is dependent
upon the supply and demand for SCO and, accordingly, can change quickly
depending upon the short-term supply and demand dynamics in the market and
pipeline availability for transporting crude oil.
The Corporation's first quarter sales volumes averaged
121,000 barrels per day in 2011 and 99,000 barrels per day in 2010. The
increase in quarter-over-quarter sales volumes reflected improved reliability
in the first quarter of 2011. In addition, first quarter 2010 volumes were
impacted by the turnaround of the LC Finer and associated upgrading units.
The Corporation purchases crude oil from third
parties, from time to time, to fulfill sales commitments with customers when
there are shortfalls in Syncrude's production, and to facilitate certain
transportation and tankage arrangements and operations. Sales includes the sale
of purchased crude oil while the cost of these purchases are included in crude
oil purchases and transportation expense. Crude oil purchases were lower in the
first quarter of 2011, relative to the first quarter of 2010. Higher purchased
volumes in the first quarter of 2010, due to additional activities to support
unanticipated production shortfalls and incremental purchases associated with
tankage arrangements, were partially offset by higher prices on crude oil
purchases in the first quarter of 2011.
Crown Royalties
In the first quarter of 2011, Crown royalties
decreased to $71 million, or $6.49 per barrel, from $78 million, or $8.74 per
barrel, in the comparable 2010 quarter, reflecting lower deemed bitumen
revenues and higher allowed costs in 2011.
The Syncrude Royalty Amending Agreement requires that
bitumen be valued by a formula that references the value of bitumen based on a
Canadian heavy oil price adjusted for reasonable quality, transportation and
handling deductions (including diluent costs) to reflect the quality and
location differences between Syncrude's bitumen and the reference price of
bitumen. The Alberta government and the Syncrude owners are in discussions to
determine the appropriate adjustments for quality, transportation and handling.
In December 2010 the Alberta government provided a modified notice of a bitumen
value for Syncrude (the "Syncrude BVM"). For estimating and paying
royalties, Syncrude used a bitumen value based on Syncrude and its owners'
interpretation of the Syncrude Royalty Amending Agreement, which is different
than the Syncrude BVM. As a result, Canadian Oil Sands' share of the royalties
recognized for the period from January 1, 2009 to March 31, 2011 are estimated
to be approximately $35 million less than the amount calculated under the
Syncrude BVM. The Syncrude owners and the Alberta government continue to
discuss the basis for reasonable quality, transportation, and handling
adjustments but if such discussions do not result in an agreed upon solution,
either party may seek judicial determination of the matter. Should these
discussions or a judicial determination result in a deemed bitumen value
different than that used by Syncrude for estimating and paying royalties, the
cumulative impact on Canadian Oil Sands' share of royalties since January 1,
2009 will be recognized immediately and impact both net income and cash
royalties accordingly.
Operating Expenses
The following table breaks down operating expenses
into their major components and shows operating expenses per barrel of bitumen
and SCO. The information allocates costs to bitumen production and upgrading on
the basis used to determine bitumen royalties.
Three
Months Ended
March 31
2011
2010
----------------------------------------------------------------------------
$/bbl
$/bbl
$/bbl
$/bbl
Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Bitumen
production
$ 21.56 $
24.54 $ 21.83 $
27.19
Internal
fuel allocation (2)
2.58
2.93
3.27
4.07
----------------------------------------------------------------------------
Total
produced bitumen costs 24.14 27.47 25.10 31.26
Upgrading
costs (1)
13.59
14.09
Less:
Internal fuel allocation to
bitumen
(2)
(2.93)
(4.07)
Bitumen
purchases -
-
----------------------------------------------------------------------------
Total
Syncrude operating costs
38.13
41.28
Canadian
Oil Sands' adjustments (3)
(2.60)
(3.39)
----------------------------------------------------------------------------
Total operating expenses
35.53
37.89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(thousands of barrels per day)
Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude production volumes
366
321
336
269
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Upgrading costs include the production and ongoing
maintenance costs
associated with processing and upgrading of bitumen to SCO.
(2) Natural gas prices averaged $3.59 per GJ and $4.95
per GJ in the first
quarters of 2011 and 2010, respectively.
(3) Canadian Oil Sands' adjustments mainly pertain to
actual reclamation
costs, which Syncrude includes in operating expenses and Canadian Oil
Sands recognizes through its asset retirement obligation, and expenses
as depreciation and depletion and accretion.
Three
Months Ended
March 31
($/bbl of SCO)
2011
2010
----------------------------------------------------------------------------
Production costs
$
30.59 $ 32.66
Purchased energy
4.94
5.23
----------------------------------------------------------------------------
Total
operating expenses
$
35.53 $ 37.89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(GJs/bbl of SCO)
----------------------------------------------------------------------------
Purchased energy consumption
1.38
1.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the first quarter of 2011, operating expenses were
$387 million, averaging $35.53 per barrel, compared with $339 million, or
$37.89 per barrel, in the first quarter of 2010. The increase in operating expenses
for the first quarter of 2011 relative to the first quarter of 2010 was
primarily due:
-- a
larger increase in the value of Syncrude's long-term incentive plans
in 2011 compared with 2010. A portion of Syncrude's long-term incentive
plans is based on the market return performance of several Syncrude
owners' shares, which was stronger in 2011 than in 2010;
--
increased diesel costs due to higher prices and increased volumes
reflecting low sulphur diesel regulations; and -- higher maintenance
costs on mining equipment and tailings and slurry pipe, partially
offset by lower maintenance costs in upgrading.
While total operating expenses for the first quarter
of 2011 were higher than the same period in 2010, per barrel costs were lower
due to the increase in sales volumes.
Non-Production Expenses
Non-production expenses totaled $33 million in the
first quarter of 2011, slightly lower than $36 million in the first quarter of
2010.
Non-production expenses consist primarily of
development expenditures relating to capital programs, such as pre-feasibility
engineering, technical and support services, research and development,
evaluation drilling, and regulatory and stakeholder consultation expenditures.
Non-production expenses can vary on a periodic basis depending on the number of
projects underway and the development stage of the projects.
Net Finance Expense
Three Months Ended
March
31
($ millions)
2011
2010
----------------------------------------------------------------------------
Interest costs
$
21 $ 26
Less
capitalized interest
$
(11) $ (6)
----------------------------------------------------------------------------
Interest expense
$
10 $ 20
Accretion of asset retirement obligation
4
5
----------------------------------------------------------------------------
Net finance expense
$
14 $ 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest costs totaled $21 million in the first
quarter of 2011 compared with $26 million in the first quarter of 2010 mainly
because of 2010 consent solicitation fees relating to the conversion from an
income trust to a corporate structure. In addition, a higher portion of the
2011 interest costs were capitalized as cumulative capital expenditures on
qualifying assets rose. As such, net finance expense decreased to $14 million
in the first quarter of 2011 from $25 million in the comparable 2010 quarter.
Depreciation and Depletion Expense
Depreciation and depletion expense decreased to $95
million in the first quarter of 2011 from $106 million in the first quarter of
2010 due primarily to changes in the estimated useful lives of certain tangible
equipment.
Foreign Exchange (Gain) Loss
Three Months Ended
March
31
($ millions)
2011
2010
----------------------------------------------------------------------------
Foreign exchange (gain) loss - long-term debt $ (25) $ (34)
Foreign exchange (gain) loss - other
3
1
----------------------------------------------------------------------------
Total
foreign exchange (gain) loss
$
(22) $ (33)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign exchange gains/losses are primarily the result
of revaluations of our U.S. dollar denominated long-term debt caused by
fluctuations in U.S. and Canadian dollar exchange rates.
The foreign exchange gains on long-term debt in the
first quarter of 2011 were the result of a strengthening in the value of the
Canadian dollar relative to the U.S. dollar to $1.03 U.S./Cdn at March 31, 2011
from $1.01 U.S./Cdn at December 31, 2010. The foreign exchange gains in the
first quarter of 2010 were likewise the result of a strengthening in the value
of the Canadian dollar relative to the U.S. dollar to $0.98 U.S./Cdn at March
31, 2010 from $0.96 U.S./Cdn at December 31, 2009.
Deferred Tax
Deferred tax expense rose to $103 million in the first
quarter of 2011 relative to a $4 million recovery in the first quarter of 2010.
An increase in the temporary differences between the accounting and tax values
of Canadian Oil Sands' assets and liabilities reflects an estimated decrease in
tax pools used to shelter taxable income in the first quarter of 2011. Under
the trust structure in 2010, taxable income was sheltered with the payment of
distributions.
Asset Retirement Obligation
Canadian Oil Sands' asset retirement obligation
decreased to $462 million at March 31, 2011 from $500 million at December 31,
2010. The decrease reflects an increase in the risk free interest rate used to
discount future reclamation payments as well as $29 million of reclamation
spending during the first quarter of 2011. The $37 million current portion of
the asset retirement obligation is included in accounts payable and accrued
liabilities, while the $425 million non-current portion is separately presented
as an asset retirement obligation on the Consolidated Balance Sheet.
CAPITAL EXPENDITURES
In the first quarter of 2011 capital expenditures
totaled $109 million compared with expenditures of $112 million in the first
quarter of 2010.
The Syncrude Emissions Reduction ("SER")
project, which commenced in 2006 and involves retrofitting technology into the
operation of Syncrude's original two cokers by the end of 2011 in order to
reduce total sulphur dioxide and other emissions, accounted for $30 million and
$27 million of the capital spent in the first quarters of 2011 and 2010,
respectively.
Mine train replacements and relocations, which involve
reconstructing or relocating crushers, surge facilities and slurry preparation
equipment to support tailings storage, accounted for $22 million and $9 million
of the capital spent in the first quarters of 2011 and 2010, respectively.
The Aurora North Tailings Management project, which
involves the construction of a composite tails plant at the Aurora North mine,
accounted for $7 million and $3 million of the capital spent in the first
quarters of 2011 and 2010, respectively.
Interest costs of $11 million were capitalized in the
first quarter of 2011, compared with $6 million in the first quarter of 2010,
due to higher cumulative capital expenditures on qualifying assets in the first
quarter of 2011.
There were no turnaround costs capitalized in the
first quarter of 2011 whereas, in the first quarter of 2010, $14 million of
costs relating to the LC Finer turnaround were capitalized.
The remaining capital expenditures related to other
investment activities, including relocation of tailings facilities and other
infrastructure projects.
More information on Canadian Oil Sands' capital
projects is provided in the "Outlook" section of this MD&A.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
Contractual obligations are summarized in the
Corporation's 2010 annual MD&A and include future cash payments that the
Corporation is required to make under existing contractual arrangements that it
has entered into directly or as a 36.74 per cent owner in Syncrude. There have
been no significant new contractual obligations or commitments relative to the
2010 year-end disclosure.
DIVIDENDS
On April 28, 2011, the Corporation declared a
quarterly dividend of $0.30 per Share in respect of the second quarter of 2011
for a total dividend of approximately $145 million. The dividend will be paid
on May 31, 2011 to Shareholders of record on May 26, 2011.
The dividend increase reflects higher than estimated
cash flows in the first quarter of the year and our revised outlook for 2011
provided in this report. We intend to fund major capital projects with cash
flow from operations while maintaining our strong balance sheet to reduce the
risk of potential oil price declines, capital cost increases, or major
operational upsets.
Dividend payments will continue to be determined on a
quarterly basis in the context of current and expected crude oil prices,
economic conditions, Syncrude's operating performance, taxation, and the
Corporation's capacity to finance operating and investing obligations. Dividend
levels will be established with the intent of absorbing short-term market
volatility over several quarters; however, the variable nature of cash flow
from operations, net income and capital spending means Canadian Oil Sands'
dividend amounts are likely to be variable and any expectations regarding the
stability or sustainability of dividends are unwarranted and should not be
inferred.
LIQUIDITY AND CAPITAL RESOURCES
March 31
December 31
($ millions)
2011
2010
----------------------------------------------------------------------------
Long-term debt
$
1,081 $ 1,251
Cash and cash equivalents
(189)
(80)
----------------------------------------------------------------------------
Net
debt
$
892 $ 1,171
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Shareholders' equity
$
3,955 $ 3,725
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total capitalization (1)
$
4,847 $ 4,896
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net debt to total capitalization (%)
18
24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net debt plus Shareholders' equity. Net debt,
total capitalization, as
well as net debt to total capitalization are non-GAAP measures.
Net debt decreased to $0.9 billion at March 31, 2011
from $1.2 billion at December 31, 2010. Cash flow from operations exceeded
capital expenditures, dividends and reclamation trust fund contributions in the
first quarter of 2011 resulting in the decreased leverage. In addition, a
stronger Canadian dollar at March 31, 2011 relative to December 31, 2010
reduced the Canadian dollar equivalent value of the U.S. dollar denominated
long-term debt by $25 million.
Shareholders' equity increased to $4.0 billion at
March 31, 2011 from $3.7 billion at December 31, 2010 as net income exceeded
dividends in the first quarter of 2011.
Debt covenants restrict Canadian Oil Sands' ability to
sell all or substantially all of its assets or change the nature of its
business, and limit total debt-to-total capitalization to 55 per cent. With a
net debt-to-total capitalization of approximately 18 per cent at March 31,
2011, a significant increase in debt or decrease in Shareholders' equity would
be required before covenants restrict the Corporation's financial flexibility.
SHAREHOLDERS' CAPITAL AND TRADING ACTIVITY
The Corporation's shares trade on the Toronto Stock
Exchange under the symbol COS. The Corporation had a market capitalization of
approximately $16 billion with 485 million shares outstanding and a closing
price of $32.67 per Share on March 31, 2011. The following table reflects the
trading activity for the first quarter of 2011.
Canadian Oil Sands Limited -
First
Trading
Activity
Quarter
March February January
2011
2011
2011
2011
----------------------------------------------------------------------------
Share price
High
$ 33.94 $ 33.94 $ 30.95 $ 27.49
Low
$ 24.98 $ 28.50 $ 27.51 $ 24.98
Close $ 32.67 $ 32.67 $ 30.05 $ 27.49
Volume of Shares traded (millions) 167.1 47.6 61.2 58.3
Weighted average Shares outstanding
(millions)
484.5
484.5
484.4
484.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FINANCIAL RISK MANAGEMENT
The Corporation did not have any financial derivatives
outstanding at March 31, 2011.
Crude Oil Price Risk
Canadian Oil Sands' revenues are impacted by changes
in both the U.S. dollar denominated crude oil prices and U.S./Cdn FX rates.
Over the last three years, daily WTI prices have experienced significant
volatility, ranging from U.S.$145 per barrel to U.S.$34 per barrel. Also,
supply, demand, and other market factors can vary significantly between regions
and, as a result, the spreads between crude oil benchmarks, such as WTI and
European Brent Crude, can be volatile.
Canadian Oil Sands prefers to remain un-hedged on
crude oil prices; however, during periods of significant capital spending and
financing requirements, management may hedge prices and exchange rates to
reduce revenue and cash flow volatility. The Corporation did not have any crude
oil price hedges in place during the first quarters of 2011 or 2010; instead, a
strong balance sheet was used to mitigate the risk around crude oil price
movements. As at April 28, 2011, and based on current expectations, the
Corporation remains un-hedged on its crude oil price exposure.
Foreign Currency Risk
Canadian Oil Sands' results are affected by
fluctuations in the U.S./Cdn currency exchange rates, as revenues generated are
based on a U.S. dollar WTI benchmark price while operating expenses and capital
expenditures are denominated primarily in Canadian dollars. Our revenue
exposure is partially offset by U.S. dollar obligations, such as interest costs
on U.S. dollar denominated long-term debt (Senior Notes) and our share of
Syncrude's U.S. dollar vendor payments. In addition, when our U.S. dollar
Senior Notes mature, we have exposure to U.S. dollar exchange rates on the
principal repayment of the notes. This repayment of U.S. dollar debt acts as a
partial economic hedge against the U.S. dollar denominated revenue payments we
receive from our customers.
In the past, the Corporation has hedged foreign
currency exchange rates by entering into fixed rate currency contracts. The
Corporation did not have any foreign currency hedges in place during the first
quarter of 2011 or 2010, and does not currently intend to enter into any new
currency hedge positions. The Corporation may, however, hedge foreign currency
exchange rates in the future, depending on the business environment and growth
opportunities.
Interest Rate Risk
Canadian Oil Sands' net income and cash flow from
operations are impacted by U.S. and Canadian interest rate changes because our
credit facilities and investments are exposed to floating interest rates. In
addition, we are exposed to the refinancing of maturing long-term debt at
prevailing interest rates. As at March 31, 2011, there were no amounts drawn on
the credit facilities ($145 million - December 31, 2010) and the next long-term
debt maturity is in 2013. The Corporation did not have a significant exposure
to interest rate risk based on the amount of floating rate debt or investments
outstanding during the quarter.
Liquidity Risk
Liquidity risk is the risk that Canadian Oil Sands
will not be able to meet its financial obligations as they fall due. Canadian
Oil Sands actively manages its liquidity risk through its cash, debt and equity
strategies. The next long-term debt maturity is in August, 2013, and the $800
million credit facility does not expire until April, 2012.
Credit Risk
Canadian Oil Sands is exposed to credit risk primarily
through customer accounts receivable balances and financial counterparties with
whom the Corporation has invested its cash or from whom it has purchased its
term deposits, and with its insurance providers in the event of an outstanding
claim. The maximum exposure to any one customer or financial counterparty is
managed through a credit policy that limits exposure based on credit ratings.
Canadian Oil Sands carries credit insurance to help
mitigate a portion of the impact should a loss occur and continues to transact
primarily with investment grade customers. The vast majority of accounts
receivable at December 31, 2010 was due from investment grade energy producers,
financial institutions, and refinery-based customers.
At March 31, 2011, our cash and cash equivalents were
invested mainly in term deposits with high-quality senior banks. As of April
28, 2011, there are no financial assets that are past their maturity or
impaired due to credit risk-related defaults.
CHANGES IN ACCOUNTING POLICIES
Apart from the changes described in the
"Transition to International Financial Reporting Standards" section
of this MD&A, there were no new accounting policies adopted, nor any
changes to accounting policies, in the first quarter of 2011.
NEW ACCOUNTING PRONOUNCEMENTS
There were no new accounting pronouncements issued by
the CICA during the first quarter of 2011 that are expected to have a material
impact on the Corporation.
OUTLOOK
(millions of Canadian dollars, except volume January 27, April 28,
and per
barrel amounts)
2011
2011
----------------------------------------------------------------------------
Syncrude production (MMbbls)
110
110
Canadian Oil Sands sales (MMbbls)
40.4
40.4
Sales, net of crude oil purchases and
transportation
3,188
3,890
Operating expenses
1,487
1,516
Operating expenses per barrel
36.79
37.51
Crown royalties
181
252
Capital expenditures
927
979
Cash flow from operations
1,214
1,915
Business environment assumptions
West Texas Intermediate (US$/bbl)
$ 80 $ 95
Premium (Discount) to average C$ WTI prices
(C$/bbl)
$
(2.75) $ 4.00
Foreign exchange rate (US$/Cdn$)
$
0.98 $ 1.03
AECO natural gas (Cdn$/GJ)
$ 4.00 $ 4.00
The outlook for production remains unchanged from the
guidance provided on January 27, 2011. Canadian Oil Sands estimates 2011
Syncrude production of 110 million barrels (40.4 million barrels, net to COS),
with a production range of 102 to 115 million barrels. This is equivalent to
301,400 barrels per day (110,700 barrels per day net to COS). The 110 million
barrel single-point estimate includes one planned coker turnaround in the
second half of the year.
Other estimates have been revised from the January
guidance. The estimate for operating costs increased to $37.51 per barrel.
Capital expenditures are now estimated at $979 million, including $614 million
for major capital projects, $305 million for regular maintenance of the
business and other projects, and $60 million in capitalized interest. In
accordance with IFRS, a portion of interest costs are capitalized with an
offsetting reduction to interest expense. Excluding capitalized interest, the
forecast is largely unchanged.
The April 28, 2011 Outlook assumes an increased U.S.
$95 per barrel WTI oil price, an SCO premium to Cdn dollar WTI of $4.00 per
barrel, and a stronger U.S./Cdn foreign exchange rate of $1.03. These
assumptions result in estimated sales of $3,890 million, or $96 per barrel in
2011.
The increase in our forecasted SCO premium to Cdn
dollar WTI reflects recent operational upsets and maintenance at several oil
sands plants, which have reduced SCO supply and resulted in significant premiums
relative to WTI. These supply disruptions are expected to be resolved over the
course of the year, which will likely result in SCO premiums decreasing in the
second half of 2011.
We are estimating cash flow from operations of
approximately $1.9 billion, or $3.95 per Share, in 2011. After deducting
forecast 2011 capital expenditures, we estimate $936 million in remaining cash
flow from operations for the year, or $1.93 per Share.
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 Corporation's
performance.
2011 Outlook Sensitivity Analysis (April 28, 2011)
Cash flow from Operations
Increase
Annual
Variable (1)
Sensitivity $
millions
$/Share
----------------------------------------------------------------------------
Syncrude operating costs decrease C$1.00/bbl
$33
$0.07
Syncrude operating costs decrease C$50 million
$15
$0.03
WTI crude oil price increase
US$1.00/bbl
$33
$0.07
Syncrude production increase 2 million
bbls
$59
$0.12
Canadian dollar weakening
US$0.01/C$
$30
$0.06
AECO natural gas price decrease
C$0.50/GJ
$19
$0.04
----------------------------------------------------------------------------
(1) An opposite change in each of these variables will
result in the
opposite cash flow from operations impacts. Canadian Oil Sands
anticipates $nil current taxes in 2011. As such, the sensitivities in
the table above do not reflect any impact for current taxes.
The 2011 Outlook contains forward-looking information
and users are cautioned that the actual amounts may vary from the estimates
disclosed. Please refer to the "Forward-Looking Information Advisory"
section of this MD&A for the risks and assumptions underlying this
forward-looking information.
Major Capital Projects
The following tables provide cost and schedule
estimates for Syncrude's major capital projects that have reached a certain
stage of definition. In particular, they do not provide cost estimates for
Aurora South development, other tailings management infrastructure or
maintenance of business post 2011:
Major Capital Projects(1)
Total Project Cost and Schedule Estimates(2)
Spent to Total
Cost
Target
Dec 31, 2010
Estimate Estimated %
In-Service
Project
($ millions) ($ billions)
Accuracy Date
----------------------------------------------------------------------------
Syncrude
Emissions
Reduction (SER) Syncrude $ 1,108 $ 1.6 +10%/-10% Q4 2011
Retrofit
COS share
407
0.6
technology
into
Syncrude's
original
two
cokers to
reduce
total
sulphur
dioxide
and other
emissions
Mildred Lake
Mine
Train
Replacement Syncrude
166
3.6
+25%/-25% Q4 2014
Reconstruct COS share
61
1.3
crushers,
surge
facilities,
and slurry
prep
facilities
to
support
tailings
storage
requirements
Aurora North
Mine Train
Relocation
Syncrude
51
0.9
+25%/-25% Q1 2014
Relocate
COS share
19
0.3
crushers,
surge
facilities,
and slurry
prep
facilities
to
support
tailings
storage
requirements
Aurora North
Tailings
Management
Syncrude
59
0.8
+25%/-25% Q4 2013
Construct COS
share
22
0.3
composite
tails
(CT) plant
at the
Aurora
North mine
----------------------------------------------------------------------------
Total
Syncrude $ 1,384 $ 6.9
COS share
509
2.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Major Capital Projects(1)
Annual Spending Profile(2)
Cost Estimate
Spent to --------------------------------------------------
Dec 31,
2010
2011
2012
2013
2014 Total
($ ($
($
($ ($ ($
millions) millions) billions) billions) billions) billions)
----------------------------------------------------------------------------
Syncrude
Major capital
projects
$ 1,384 $ 1,672 $ 1.9 $ 1.7 $ 0.3 $ 6.9
Regular
maintenance of
the
business
and other
projects
831
----------
Total capital
expenditures
$ 2,503
----------------------------------------------------------------------------
Canadian Oil
Sands
share
Major capital
projects
$ 509 $ 614 $ 0.7 $ 0.6 $ 0.1 $ 2.5
Regular
maintenance of
the
business
and other
projects
305
----------
Total direct
capital
expenditures
919
Capitalized
interest
60
----------
Total capital
expenditures
$ 979
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Major capital projects include the Syncrude
Emissions Reduction (SER),
Mildred Lake Mine Train Replacement, Aurora North Mine Train Relocation
and Aurora North Tailings Management. Major Capital Projects do not
include projects that have not reached sufficient design definition,
such as Aurora South and other tailings management infrastructure.
(2) Total project costs include both capital costs and
certain
non-production costs. Costs exclude capitalized interest.
Canadian Oil Sands plans to finance these major
capital projects primarily through cash flow from operations.
Beyond 2014, Syncrude's capital program includes
development of a group of undeveloped leases called Aurora South aimed at
expanding bitumen production by approximately 50 per cent before 2020. Syncrude
is in the process of developing cost estimates for this expansion, which
expansion must also be approved by the Syncrude joint venture owners.
The major capital projects descriptions and tables and
the expectations regarding the development of Aurora South contain
forward-looking information and users of this information are cautioned that
the actual yearly and total capital expenditures, the actual in-service dates
for the major capital projects and the actual level and timing of bitumen
production growth expected from the development of Aurora South may vary from
the plans disclosed. The capital expenditure cost estimates and major capital
project target in-service dates and expectation regarding the development of
Aurora South are based on current capital spending plans. Please refer to the
"Forward-Looking Information Advisory" section of this MD&A for
the risks and assumptions underlying this forward-looking information. For a
list of additional risk factors that could cause the actual amount of the
capital expenditures and the major capital project target in-service dates and
the level and timing of bitumen production growth expected from the development
of Aurora South to differ materially, please refer to the Corporation's Annual
Information Form dated March 10, 2011 which is available on the Corporation's
profile on SEDAR at www.sedar.com and on the Corporation's website at www.cdnoilsands.com.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE
INCOME
(unaudited)
Three Months Ended
March 31
($ millions, except per Share amounts)
2011
2010
----------------------------------------------------------------------------
Sales
$
1,083 $ 899
Crown royalties (Note 12)
(71)
(78)
----------------------------------------------------------------------------
Revenues
1,012
821
----------------------------------------------------------------------------
Expenses:
Operating 387
339
Non-production
33
36
Crude oil
purchases and transportation
67
165
Administration
9
9
Insurance
2
2
Depreciation and depletion
95
106
----------------------------------------------------------------------------
593
657
----------------------------------------------------------------------------
Earnings from operating activities
419
164
Foreign
exchange gain (22)
(33)
Net
finance expense (Note 11 )
14
25
----------------------------------------------------------------------------
Earnings before taxes
427
172
Deferred
tax expense (recovery)
103
(4)
----------------------------------------------------------------------------
Net income
324
176
Other comprehensive loss, net of income taxes
Reclassification of derivative gains to
net
income
(1)
(1)
----------------------------------------------------------------------------
Comprehensive income
$
323 $ 175
----------------------------------------------------------------------------
Weighted average shares (millions)
485
484
Shares, end of period (millions) 485
484
Net income per share:
Basic and
diluted
$
0.67 $ 0.36
See Notes to Unaudited Consolidated Financial
Statements
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(unaudited)
Three Months Ended
March 31
($ millions)
2011
2010
----------------------------------------------------------------------------
Retained earnings
Balance,
beginning of period
$
1,034 $ 802
Net
income
324
176
Dividends
(97)
(170)
----------------------------------------------------------------------------
Balance,
end of period
1,261
808
----------------------------------------------------------------------------
Accumulated other comprehensive income
Balance,
beginning of period
15
18
Reclassification of derivative gains to
net
income
(1)
(1)
----------------------------------------------------------------------------
Balance,
end of period
14
17
----------------------------------------------------------------------------
Shareholders' capital
Balance,
beginning of period
2,671
2,671
Issuance
of shares
1
-
----------------------------------------------------------------------------
Balance,
end of period
2,672
2,671
----------------------------------------------------------------------------
Contributed surplus
Balance,
beginning of period
7
-
Share-based compensation (Note 10)
1
-
----------------------------------------------------------------------------
Balance,
end of period
8
-
----------------------------------------------------------------------------
Total Shareholders' equity
$
3,955 $ 3,496
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See Notes to Unaudited Consolidated Financial
Statements
CONSOLIDATED BALANCE SHEETS AS AT
(unaudited)
March 31
December 31
January 1
($ millions)
2011
2010
2010
----------------------------------------------------------------------------
ASSETS
Current
assets:
Cash and
cash equivalents $ 189 $
80 $ 122
Accounts
receivable
418
379
354
Inventories
118
129
133
Prepaid
expenses
3
6
7
----------------------------------------------------------------------------
728
594
616
Property,
plant and equipment,
net (Note
6)
6,396
6,395
6,265
Exploration and evaluation
89
89
89
Reclamation trust
54
53
48
----------------------------------------------------------------------------
$
7,267 $ 7,131 $ 7,018
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS'
EQUITY
Current
liabilities:
Accounts
payable and accrued
liabilities
$
418 $ 405 $ 284
Current
portion of employee
future benefits
51
51
17
----------------------------------------------------------------------------
469
456
301
Employee
future benefits and
other
liabilities
315
316
284
Long-term
debt
1,081
1,251
1,163
Asset
retirement obligation
(Note
9)
425
463
550
Deferred
taxes
1,022
920
1,229
----------------------------------------------------------------------------
3,312
3,406
3,527
Shareholders' equity
3,955
3,725
3,491
----------------------------------------------------------------------------
$
7,267 $ 7,131 $ 7,018
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See Notes to Unaudited Consolidated Financial
Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Ended
March 31
($ Cdn millions)
2011
2010
----------------------------------------------------------------------------
Cash from (used in) operating activities
Net
income
$
324 $ 176
Items not
requiring outlay of cash:
Depreciation and depletion
95
106
Accretion
of assets retirement obligation
4
5
Foreign
exchange gain on long-term debt
(25)
(34)
Share-based compensation
5
-
Deferred
tax expense (recovery)
103
(4)
Actual
reclamation expenditures (Note 9)
(29)
(23)
Change in
employee future benefits and other
liabilities
1
(1)
----------------------------------------------------------------------------
478
225
Change in
non-cash working capital
(19)
104
----------------------------------------------------------------------------
Cash from
operating activities
459
329
----------------------------------------------------------------------------
Cash from (used in) financing activities
Repayment
of bank credit facilities
(145)
-
Issuance
of shares
1
-
Dividends (97)
(170)
----------------------------------------------------------------------------
Cash used
in financing activities
(241)
(170)
----------------------------------------------------------------------------
Cash from (used in) investing activities
Capital
expenditures
(109)
(112)
Reclamation trust funding
(2)
(1)
Change in
non-cash working capital
2
7
----------------------------------------------------------------------------
Cash used
in investing activities
(109)
(106)
----------------------------------------------------------------------------
Increase in cash and cash equivalents
109
53
Cash and cash equivalents at beginning of
period
80
122
----------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 189 $ 175
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents consist of:
Cash
$
29 $ 16
Short-term
investments
160
159
----------------------------------------------------------------------------
$
189 $ 175
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information (Note 13)
See Notes to Unaudited Consolidated Financial
Statements
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED MARCH 31, 2011
(Tabular amounts expressed in millions of Canadian
dollars, except where otherwise noted.)
1) NATURE OF OPERATIONS
Canadian Oil Sands Limited (the
"Corporation") indirectly owns a 36.74 per cent interest
("Working Interest") in the Syncrude Joint Venture
("Syncrude"). Syncrude is involved in the mining and upgrading of
bitumen from oil sands in Northern Alberta and is operated by Syncrude Canada
Ltd. ("Syncrude Canada").
2) BASIS OF PRESENTATION
The interim unaudited consolidated financial statements
reflect the December 31, 2010 reorganization from an income trust into a
corporate structure pursuant to which all outstanding trust units of Canadian
Oil Sands Trust (the "Trust") were exchanged on a one-for-one basis
for common shares ("Shares") of the Corporation (the "Corporate
Conversion"). The financial information of Canadian Oil Sands refers to
common shares or Shares, Shareholders and dividends, which were formerly
referred to as Units, Unitholders and distributions under the trust structure.
These consolidated financial statements are prepared
and reported in Canadian dollars in accordance with Canadian generally accepted
accounting principles ("Canadian GAAP") as set out in the Handbook of
the Canadian Institute of Chartered Accountants ("CICA Handbook").
Canadian GAAP has been revised to incorporate International Financial Reporting
Standards ("IFRS") and publicly accountable enterprises are required
to apply such standards for years beginning on or after January 1, 2011.
Accordingly, the Corporation has commenced reporting on this basis in these
interim unaudited consolidated financial statements. In these financial
statements, the term "Canadian GAAP" refers to Canadian GAAP before
the adoption of IFRS.
These financial statements have been prepared in
accordance with International Accounting Standard ("IAS") 34 Interim
Financial Reporting and IFRS 1 First-time adoption of IFRS. Subject to certain
transition exemptions and exceptions disclosed in Note 5, the Corporation has
applied IFRS compliant accounting policies to its transition date balance sheet
at January 1, 2010 and throughout 2010 and the first quarter of 2011 as if
these policies had always been in effect. Note 5 discloses the impact of the
transition to IFRS on the Corporation's reported financial position, income and
cash flows, including the nature and effect of changes in accounting policies
from those used in the Corporation's Canadian GAAP consolidated financial
statements for the year ended December 31, 2010.
The accounting policies applied in these interim
unaudited consolidated financial statements are based on IFRS issued and
outstanding as of April 28, 2011. Any subsequent changes to IFRS that are given
effect in the Corporation's annual consolidated financial statements for the
year ending December 31, 2011 could result in a restatement of these interim
consolidated financial statements, including the adjustments recognized on
transition to IFRS.
Certain disclosures that are normally required to be
included in the notes to the annual audited consolidated financial statements
have been condensed or omitted. These unaudited interim consolidated financial
statements should be read in conjunction with the Corporation's Canadian GAAP
audited consolidated financial statements and notes thereto in the
Corporation's annual report for the year ended December 31, 2010.
3) SUMMARY OF ACCOUNTING POLICIES
Consolidation
The consolidated financial statements include the
accounts of the Corporation and its subsidiaries and partnerships (collectively
"Canadian Oil Sands"). The activities of Syncrude are conducted
jointly with others and, accordingly, these financial statements reflect only
Canadian Oil Sands' proportionate interest in such activities, which include
the production, Crown royalties, operating expenses, and non-production
expenses, as well as a proportionate interest in Syncrude's property, plant and
equipment, inventories, employee future benefits and other liabilities, asset
retirement obligation, and associated accounts payable and receivable.
Substantially all operations of Canadian Oil Sands are carried out through
Syncrude.
Cash and Cash Equivalents
Investments with maturities of less than 90 days at
purchase are considered to be cash equivalents and are recorded at cost, which
approximates fair value.
Property, Plant and Equipment
Property, plant and equipment ("PP&E")
are recorded at cost and include the costs of acquiring the Working Interest
in, and costs that are directly related to the acquisition, development and
construction of oil sands projects, including the cost of initial overburden
removal, major turnaround costs, certain interest costs, and reclamation costs
associated with the asset retirement obligation. Repairs and maintenance,
non-major turnaround costs and ongoing overburden removal on producing oil
sands mines are expensed as operating expenses in the period incurred.
PP&E is depreciated on a straight-line basis over
the estimated useful lives of the assets, with the exception of intangible mine
development costs, which are depleted on a unit-of-production basis over the
estimated proved and probable reserves of the producing mines. The following
estimated useful lives of the tangible assets are reviewed annually for any
changes to those estimates:
----------------------------------------------------------------------------
Vehicles and equipment
5 to 20 years
----------------------------------------------------------------------------
Mining equipment
Lesser of 25 years and the remaining life of
the mine
----------------------------------------------------------------------------
Upgrading and extraction 25 years
----------------------------------------------------------------------------
Buildings
20 to 40 years
----------------------------------------------------------------------------
Major turnarounds
2 to 3 years
----------------------------------------------------------------------------
Capitalized major turnaround costs are depreciated
over the estimated period to the next turnaround.
Assets under construction are capitalized as
construction in progress. Construction in progress is not depreciated. On
completion, the cost of construction in progress is transferred to the
appropriate category of PP&E.
Exploration and evaluation
Exploration and evaluation ("E&E")
assets include the costs of acquiring undeveloped oil sands leases ("oil
sands lease acquisition costs") and interests in natural gas licenses
located in the Arctic Islands in Northern Canada (the "Arctic natural gas
assets").
Impairment
The carrying amounts of PP&E and E&E assets
are reviewed for possible impairment whenever changes in circumstances indicate
that the carrying amounts may not be recoverable. For the purpose of measuring
recoverable amounts, assets are grouped at the lowest levels for which there
are separately identifiable cash inflows ("cash generating units" or
"CGUs"). The recoverable amount is the higher of a CGU's fair value
less cost to sell (being the amount obtainable from the sale of a CGU in an
arm's length transaction, net of disposal costs) and its value in use (being the
net present value of the CGU's expected future cash flows). An impairment loss
is recognized for the amount by which the carrying amount exceeds the
recoverable amount.
E&E assets are also subject to impairment testing
at the time they are transferred to PP&E.
PP&E consists entirely of Canadian Oil Sands'
proportionate interest in Syncrude's PP&E. PP&E is combined with the
oil sands lease acquisition costs, within the E&E assets, to form one CGU
for impairment testing purposes. The balance of the E&E assets, being the Arctic
natural gas assets, form a second CGU and are tested for impairment separately
from the oil sands assets.
Impairments are reversed, net of imputed depreciation
and depletion, if the reversal can be related objectively to an event occurring
after the impairment charge was recognized. Impairment charges and reversals
are recorded as depreciation and depletion.
Interest Costs
Interest costs attributable to the acquisition or
construction of qualifying assets which require a substantial period time to
prepare for their intended use are capitalized as PP&E. All other interest
costs are recognized as net finance expense in the period in which they are
incurred.
Inventories
Inventories, which include crude oil and materials and
supplies, are valued at the lower of average cost and their net realizable
value.
Asset Retirement Obligation
The estimated fair value of Canadian Oil Sands' share
of Syncrude's asset retirement obligation is recognized on the Consolidated
Balance Sheets. Syncrude's asset retirement obligation, or reclamation
obligation, relates to the site restoration of each mine site and the
decommissioning of utilities plants, bitumen extraction plants, and upgrading
complex. The discounted amount of the future reclamation payments is recorded
upon initial land disturbance or when a reasonable estimate of the fair value
of the reclamation expenditures can be determined. The fair value is determined
by estimating the timing and amounts of the future reclamation expenditures,
and discounting the expenditures using a risk-free interest rate. The cost of
the asset retirement obligation is capitalized as PP&E and depreciated over
the remaining life of the associated mine or plant.
The fair value of the asset retirement obligation is
re-measured at each reporting date using the risk-free interest rate in effect
at that time and changes in the fair value are capitalized as PP&E.
The asset retirement obligation is accreted using the
risk-free interest rate and the accretion expense is included in net finance
expense on the Consolidated Statements of Income and Comprehensive Income.
Actual reclamation expenditures are charged against the asset retirement
obligation when incurred.
Revenue Recognition
Sales include sales of synthetic crude oil, including
both produced and purchased volumes, sales of other products, and proceeds from
insurance. Sales from the sale of synthetic crude oil and other products are
recorded when title passes from Canadian Oil Sands to a third party. Revenues
are net of Crown royalties and include gains and losses, if any, from crude oil
hedge contracts designated as hedges for accounting purposes. Sales are
presented before Crown royalties.
Employee Future Benefits
Canadian Oil Sands accrues its proportionate share of
obligations as a joint venture owner in respect of Syncrude Canada's
post-employment benefit obligations, which include a defined benefit pension
plan, two defined contribution pension plans, and a defined benefit other post-employment
benefits ("OPEB") plan which provides certain health care and life
insurance benefits for retirees, their beneficiaries and covered dependents.
The cost of the defined benefit pension plan and OPEB
plan is actuarially determined using the projected unit credit method based on
length of service and reflects Syncrude's best estimate of the expected
performance of the plan investment, salary escalation factors, retirement ages
of employees and future health care costs. The discount rate used to determine
the accrued benefit obligation is based on a market rate of interest for
high-quality corporate debt instruments with cash flows that match the timing
and amount of expected benefit payments. The expected return on plan assets is
based on the fair value of those assets. Actuarial gains and losses, net of
income taxes, are recognized immediately in other comprehensive income. The
current service cost of the defined benefit plans is recognized in operating
expenses as the service is rendered. Any past service costs arising from plan
amendments are recognized immediately in operating expenses.
The cost of the defined contribution plans is
recognized in operating expenses as the service is rendered and contributions
become payable.
Taxes
Taxes are recognized in net income, except where they
relate to items recognized directly in other comprehensive income or
shareholders' equity, in which case the related taxes are recognized in other
comprehensive income or shareholders' equity.
Current taxes receivable or payable are estimated on
taxable income for the current year at the statutory tax rates enacted or
substantively enacted.
Deferred tax assets and liabilities are recognized
based on the differences between the tax and accounting values of assets and
liabilities, referred to as temporary differences, and are calculated using
enacted or substantively enacted tax rates for the periods in which the
temporary differences are expected to reverse. The effect of tax rate changes
is recognized in net income, other comprehensive income or shareholders'
equity, as the case may be, in the period of substantive enactment. Deferred
tax assets are recognized only to the extent that it is probable that future
taxable profits will be available against which the assets can be utilized.
Share-Based Compensation
Canadian Oil Sands recognizes share-based compensation
expense in its Consolidated Statements of Income and Comprehensive Income for
all options granted with a corresponding increase to contributed surplus in
Shareholders' Equity. Canadian Oil Sands determines the compensation cost based
on the estimated fair values of the options at the time of grant, which is then
recognized in net income over the vesting periods of the options.
Canadian Oil Sands also recognizes share-based
compensation expense related to its performance units ("PSUs"), which
are awards granted to Canadian Oil Sands' officers and other select employees.
Canadian Oil Sands determines compensation expense based on the estimated fair
values of the PSUs, which is recognized in net income over the vesting periods
of the units. Changes in the fair values of the performance units over the
vesting period are recorded in net income in the period the change occurs.
As an owner in Syncrude, Canadian Oil Sands accrues
its share of amounts payable for Syncrude Canada's share-based compensation
programs with a corresponding increase or decrease in operating expenses.
Syncrude Canada's programs include an Incentive Phantom Share Units Plan
("Phantom Units") and an Incentive Restricted Share Units Plan
("Restricted Units"), both of which require settlement by cash
payments. The Phantom Units' and the Restricted Units' fair values are based on
a weighted-average of the price of certain Syncrude owners' shares at the time
of issue. Compensation expense for the Phantom Units and Restricted Units is
recognized in net income over the shorter of the normal vesting period and the
period to eligible retirement if vesting is accelerated on retirement. The
changes in the fair values of the Phantom Units and Restricted Units over the
vesting periods are recognized in net income in the period the change occurs.
Foreign Currency Translation
The principal currency of the economic environment in
which the Corporation and its subsidiaries and wholly owned partnerships
operate is the Canadian dollar. Monetary assets and liabilities denominated in
foreign currencies are translated into Canadian dollars at exchange rates in
effect at the end of the period, with the resulting gain or loss recorded in
the Consolidated Statements of Income and Comprehensive Income. Revenues and
expenses are translated into Canadian dollars at average exchange rates.
Translation gains and losses on U.S. dollar denominated long-term debt are
unrealized until repayment of the debt obligations. All other translation gains
and losses are classified as realized.
Net Income per Share
The Corporation calculates basic earnings per share by
dividing net income by the weighted average number of common shares outstanding
during the period. Diluted earnings per share are calculated by adjusting the
weighted average number of common shares outstanding for dilutive common shares
related to the Corporation's share-based compensation plans. The number of
shares included is computed using the treasury stock method, which assumes that
proceeds received from the exercise of in-the-money options are used to
repurchase common shares at the average market price.
Dividends
Dividends on common shares are recognized in the
period in which the dividends are approved by the Corporation's Board of
Directors.
Financial Instruments
All financial instruments are initially measured at
fair value on the Consolidated Balance Sheets. Subsequent measurement of
financial instruments is based on their classification as follows:
Classification
Measurement
Held for trading
Fair value with changes recognized in net income
Held to maturity
Amortized cost using effective interest method
Loans and receivables Amortized cost
using effective interest method
Available for sale
Fair value with changes recognized in other
comprehensive income
Other liabilities
Amortized cost using effective interest method
Transaction costs in respect of financial instruments
measured at fair value are recognized immediately in net income. Transaction
costs in respect of other financial instruments are included in the initial
cost and amortized accordingly using the effective interest method.
The inputs to fair value measurements of financial
instruments, including their classification within a hierarchy that prioritizes
the inputs to fair value measurement, are as follows:
Level 1: Quoted prices in active markets for identical
assets or liabilities;
Level 2: Inputs other than quoted prices included
within Level 1 that are observable for the asset or liability, either directly
or indirectly; and
Level 3: Inputs for the asset or liability that are
not based on observable market data.
4) CRITICAL ACCOUNTING ESTIMATES
A critical accounting estimate is considered to be one
that requires assumptions be made about matters that are uncertain at the time
the accounting estimate is made and would have a material impact on the financial
results if different assumptions were used. Canadian Oil Sands makes numerous
estimates in its financial results in order to provide timely information to
users. The following estimates are, however, considered critical:
a) Canadian Oil Sands records an asset retirement
obligation liability and capitalizes the costs of the obligation as PP&E
based on the estimated discounted fair value of its share of Syncrude's future
payments required for the restoration of each of Syncrude's mine sites that have
been disturbed and for the decommissioning of Syncrude's utilities plants,
bitumen extraction plants, and upgrading complex. Syncrude is required to
reclaim disturbed areas to a sustainable landscape with productivity that is
equal or greater than existed prior to development. In determining the fair
value, Canadian Oil Sands must estimate the amount of the future cash payments,
the timing of when those payments will be required, and then apply an
appropriate risk-free interest rate. Given the long reserve life of Syncrude's
leases, the reclamation payments will be made over approximately the next 70
years, and it is difficult to estimate the timing and amount of the payments
that will be required as they occur far into the future.
Any changes in the anticipated timing or the amount of
the payments or to the risk free interest rate subsequent to the initial
obligation being recorded results in a change to the asset retirement
obligation and corresponding PP&E. Such changes will impact the accretion
of the obligation and the depreciation or depletion of the PP&E and will
correspondingly impact net income.
Canadian Oil Sands' asset retirement obligation was
$462 million at March 31, 2011 (December 31, 2010 - $500 million) (see Note 9).
b) Canadian Oil Sands accrues its obligations for
Syncrude Canada's post-employment benefits using actuarial and other
assumptions to estimate the projected benefit obligation, the return on plan
assets and the expense related to the current period. The basic assumptions
utilized are outlined in Note 10(a) to the December 31, 2010 audited
Consolidated Financial Statements. Changes in these assumptions give rise to
actuarial gains and losses which are recognized immediately in other
comprehensive income as incurred. The projected benefit obligation is measured
using the estimated discounted fair value of the Canadian Oil Sands' share of
future payments under Syncrude Canada's post-employment benefits plans. A 0.25
per cent change in the interest rate used to discount the projected benefit
obligation would result in an approximate increase/decrease of $25 million in
Canadian Oil Sands' share of the employee future benefits liability.
In addition, actual payments related to Syncrude
Canada's post-employment benefits plans could vary greatly from estimates
assumed in the projected benefit obligation and the plan assets, resulting in
actuarial gains and losses.
Canadian Oil Sands does not have a post-employment
benefits plan for its own employees. Therefore, all of the employee future benefits
liabilities and expenditures relate to its Working Interest in Syncrude
Canada's post-employment benefits plans. Canadian Oil Sands' liability for
employee future benefits was $315 million at March 31, 2011 (December 31, 2010
- $327 million).
c) Canadian Oil Sands calculates depreciation expense
for certain tangible oil sands assets on a straight-line basis. As such,
Canadian Oil Sands must estimate the useful lives of these assets. While these
useful life estimates are reviewed on a regular basis and depreciation
calculations are revised accordingly, actual lives may differ from the
estimates. As such, assets may continue in use after being fully depreciated,
or may be retired or disposed of before being fully depreciated. The latter
could result in additional depreciation expense in the period of disposition.
d) Canadian Oil Sands must estimate the reserves it
expects to recover in the future and the related net revenues expected to be
generated from producing those reserves. Reserves and future net revenues are
evaluated and reported in a reserve report prepared by independent petroleum
reserve evaluators who determine these evaluations using various factors and
assumptions, such as: forecasts of mining and extraction recovery and upgrading
yield based on geological and engineering data, projected future rates of
production, projected operating costs, Crown royalties and taxes, projected
crude oil prices and oil price differentials and timing and amounts of future
capital expenditures and other development costs, all of which are estimates.
The factors and assumptions used in the estimates are assessed for
reasonableness based on the information available at the time that the
estimates are prepared. Estimates of reserves and future net revenues are critical
to asset impairment tests. In addition, for certain intangible assets, which
are depleted on a unit-of-production basis, reserves are used as a component of
the depletion calculations to allocate capital costs over their estimated
useful lives. The reserve report is reviewed by Canadian Oil Sands' management,
the Reserves, Marketing Operations and Environmental, Health and Safety
Committee and the Board of Directors.
As circumstances change and new information becomes
available, the reserve report data could change. Future actual results could
vary greatly from our estimates, and could cause changes in our asset
impairment tests or depletion estimates, both of which use the reserves and/or
future net revenues in their respective calculations.
e) Accounting for income taxes is a complex process
that requires the Corporation to interpret frequently changing laws and
regulations, including changing income tax rates, and make certain judgments
with respect to the application of tax law, estimating the timing of temporary
difference reversals, and estimating the realizability of tax assets.
Therefore, income taxes are subject to measurement uncertainty. Canadian Oil
Sands' liability for deferred taxes was 1,022 million at March 31, 2011
(December 31, 2010 - $920 million).
5) TRANSITION TO INTERNATIONAL FINANCIAL REPORTING
STANDARDS
The impact of the transition to IFRS is summarized in
this note as follows:
a)
Transition Exceptions and Exemptions
b)
Reconciliation of Assets, Liabilities and Shareholders' Equity as
previously reported
under Canadian GAAP to IFRS
c)
Reconciliation of Net Income and Comprehensive Income as previously
reported under
Canadian GAAP to IFRS
d)
Reconciliation of Cash Flows as previously reported under Canadian
GAAP to IFRS
e) Notes
to the reconciliations
a) Transition Exceptions and Exemptions
Canadian Oil Sands has applied the following
transition exceptions and
exemptions to full retrospective application of IFRS:
As
Exception
Description
described
/
exemption
in Note 5 (e)
----------------------------------------------------------------------------
Capitalization of
Exempt all interest costs incurred prior to
(ii)
interest
costs January 1, 2010
from capitalization
----------------------------------------------------------------------------
Asset retirement Apply prescribed method to
estimate
(iii)
obligation
January 1, 2010 net book value of asset
retirement obligation's cost capitalized in
PP&E
----------------------------------------------------------------------------
Employee future Record previously
unrecognized actuarial
(iv)
benefits
losses on defined benefit pension plan
through January 1, 2010 retained earnings
----------------------------------------------------------------------------
Business
Exempt pre-January 1, 2010 business
combinations combinations
from re-measurement
----------------------------------------------------------------------------
Leases
Exempt all leases assessed under
Canadian GAAP from re-assessment
b) Reconciliations of Assets, Liabilities and
Shareholders' Equity as
previously reported under Canadian GAAP to IFRS
December 31
March 31 January
1
($ millions)
Note
2010
2010
2010
----------------------------------------------------------------------------
Assets as reported under
Canadian
GAAP
$ 7,016 $ 6,983 $ 6,953
Property,
plant and equipment
as
reported under Canadian
GAAP
$ 6,369 $ 6,284 $ 6,289
Capitalization of turnaround
costs
(i)
51
51
46
Capitalization
of interest
costs
(ii)
30
6
-
Asset
retirement obligation
(iii)
34
18
19
Reclass
to exploration and
evaluation
(viii)
(89)
(89)
(89)
---------------------------------------
Property,
plant and equipment
as
reported under IFRS
$ 6,395 $ 6,270 $ 6,265
Exploration and evaluation as
reported
under Canadian GAAP
$
- $ - $ -
Reclass
from property, plant
and
equipment
(viii)
89
89
89
---------------------------------------
Exploration
and evaluation as
reported
under IFRS
$ 89 $ 89 $ 89
---------------------------------------
Assets as reported under IFRS
$ 7,131 $ 7,058 $ 7,018
---------------------------------------
---------------------------------------
Liabilities as reported under
Canadian
GAAP
$ (3,058) $
(3,017) $ (2,984)
Employee
future benefits and
other
liabilities as reported
under
Canadian GAAP
$ (67) $ (103) $ (104)
Defined
benefit pension plan
(iv)
(240)
(164)
(166)
Cash
settled share-based
awards
(v)
-
(8)
(7)
Equity
settled share-based
awards
(vi)
(9)
(8)
(7)
---------------------------------------
Employee
future benefits and
other
liabilities as reported
under
IFRS
(316)
(283)
(284)
Asset
retirement obligation
as
reported under Canadian
GAAP
$ (286) $ (372) $ (389)
Asset retirement obligation (iii)
(177)
(160)
(161)
---------------------------------------
Asset
retirement obligation
as
reported under IFRS
$ (463) $ (532) $ (550)
Deferred
taxes as reported
under
Canadian GAAP
$ (998) $ (1,020) $ (1,027)
Deferred
taxes
(vii)
78
(204)
(201)
---------------------------------------
Deferred
taxes as reported
under
IFRS
$ (920) $ (1,224) $ (1,228)
---------------------------------------
Liabilities as reported under
IFRS
$
(3,406) $ (3,561) $ (3,526)
---------------------------------------
---------------------------------------
Shareholders' equity as
reported
under Canadian GAAP
$ (3,958) $
(3,966) $ (3,969)
Retained
earnings as reported
under
Canadian GAAP
$ (1,349) $
(1,356) $ (1,359)
Capitalization of turnaround
costs
(i)
(51) (51)
(46)
Capitalization of interest
costs
(ii)
(30)
(6)
-
Asset
retirement obligation
(iii)
143
142
142
Defined
benefit pension plan
(iv)
240 164
166
Cash
settled share-based
awards
(v)
9
8
7
Reclass
equity-settled
share-based awards
(vi)
84
84
84
Equity-settled
share-based
awards
(vi)
-
2
2
Deferred
taxes
(vii)
(78)
204
201
---------------------------------------
---------------------------------------
Retained
earnings as reported
under
IFRS
$ (1,032) $ (809) $ (803)
Shareholders' capital as
reported
under Canadian GAAP
$ (2,587) $
(2,587) $ (2,587)
Reclass
equity-settled
share-based awards
(vi)
(84)
(84)
(84)
---------------------------------------
---------------------------------------
Shareholders' capital as
reported
under IFRS
$ (2,671) $
(2,671) $ (2,671)
Contributed surplus as
reported
under Canadian GAAP
$ (7) $ (6) $ (5)
Equity-settled share-based
awards
(vi)
-
6
5
---------------------------------------
Contributed surplus as
reported
under IFRS
$ (7) $ - $ -
---------------------------------------
Shareholders' equity as
reported
under IFRS
$ (3,725) $
(3,497) $ (3,492)
---------------------------------------
---------------------------------------
c) Reconciliations of Net Income and Comprehensive
Income as previously
reported under Canadian GAAP to IFRS
Three
Months
Year Ended
Ended
December 31
March 31
($ millions)
Note 2010
2010
----------------------------------------------------------------------------
Operating expenses as reported under
Canadian
GAAP
$ (1,439) $ (354)
Capitalization of turnaround costs (i)
46
14
Actuarial
losses on defined benefit
pension
plan
(iv)
9
2
Cash
settled share-based awards
(v)
(2)
(1)
----------------------------
Operating expenses as reported under IFRS
$ (1,386) $ (339)
Depreciation and depletion expense as
reported
under Canadian GAAP
$ (408) $ (103)
Capitalization of turnaround costs
(i)
(40)
(8)
Increase
in depletion of asset retirement
obligation's cost
(6)
(1)
Reclass
accretion of asset retirement
obligation to net finance expense (x)
25
6
----------------------------
Depreciation and depletion expense as
reported
under IFRS
$ (429) $ (106)
Interest expense as reported under
Canadian
GAAP
$
(91)
$ (26)
Capitalization of interest costs
(ii)
30
6
Decrease
in accretion of asset retirement
obligation
4
1
Reclass
accretion of asset retirement
obligation from depreciation and depletion
expense
(x)
(25)
(6)
----------------------------
Net finance expense as reported under IFRS
$
(82)
$ (25)
Administration expense as reported under
Canadian
GAAP
$
(23)
$ (8)
Equity
settled share-based awards
(vi) 2
(1)
----------------------------
Administration expense as reported under
IFRS
$
(21) $ (9)
Deferred tax recovery as reported under
Canadian
GAAP
$
29
$ 7
Deferred
taxes
(vii)
259
(3)
----------------------------
Deferred tax recovery as reported under
IFRS
$ 288 $ 4
Net income as reported under Canadian GAAP
$ 886 $ 167
Sum of
adjustments above
302
9
----------------------------
Net income as reported under IFRS
$ 1,188 $ 176
----------------------------
----------------------------
Other comprehensive loss as reported under
Canadian
GAAP
$
(3) $ (1)
Actuarial
losses on defined benefit
pension
plan
(iv) (62)
-
----------------------------
Other comprehensive loss as reported under
IFRS
$
(65) $ (1)
Comprehensive income as reported under
Canadian
GAAP
$ 883 $ 166
Sum of
adjustments above
240
9
----------------------------
Comprehensive income as reported under
IFRS
$ 1,123 $ 175
----------------------------
----------------------------
d) Reconciliation of Cash Flows as previously reported
under Canadian GAAP
to IFRS
Three Months
Year ended
Ended
December
31 March 31
($
millions)
Note
2010
2010
----------------------------------------------------------------------------
Cash from operating activities as reported
under
Canadian GAAP
$ 1,219 $ 309
Capitalization of turnaround costs
(i)
46
14
Capitalization of interest costs
(ii)
30
6
----------------------------
Cash from operating activities as reported
under
IFRS
$ 1,295 $ 329
----------------------------
----------------------------
Cash used in investing activities as
reported
under Canadian GAAP
$ (510) $ (86)
Capitalization of turnaround costs
(i)
(46)
(14)
Capitalization
of interest costs
(ii)
(30)
(6)
----------------------------
Cash used in investing activities as
reported
under IFRS
$ (586) $ (106)
----------------------------
----------------------------
e) Notes to the reconciliations
i) Capitalization of turnaround costs
Under Canadian GAAP, turnaround costs were expensed as
operating expenses as incurred. Under IFRS, costs of major turnarounds are
capitalized as property, plant, and equipment and depreciated over the period
until the next turnaround, which typically ranges from 24 to 30 months.
January 1, 2010 transition adjustments
An adjustment was recorded at January 1, 2010 to
capitalize turnaround costs expensed under Canadian GAAP. This adjustment
resulted in a $46 million increase in property, plant and equipment, net of $48
million accumulated depreciation, with a corresponding $46 million increase in
retained earnings.
2010 adjustments
For the three months ended March 31, 2010, the
capitalization of turnaround costs under IFRS resulted in a $14 million
decrease in operating expenses and an $8 million increase in depreciation and
depletion. Expenditures of $14 million were reclassified from operating
activities to investing activities in the statement of cash flows. March 31,
2010 property, plant and equipment, net of accumulated depreciation, and
retained earnings were each $51 million higher as a result of capitalizing
turnaround costs.
For the year ended December 31, 2010, the
capitalization of turnaround costs under IFRS resulted in a $46 million
decrease in operating expenses and a $40 million increase in depreciation and
depletion. Expenditures of $46 million were reclassified from operating
activities to investing activities in the statement of cash flows. December 31,
2010 property, plant and equipment, net of accumulated depreciation, and
retained earnings were each $51 million higher as a result of capitalizing
turnaround costs.
ii) Capitalization of interest costs
Under Canadian GAAP, all interest costs were expensed.
Under IFRS, interest costs relating to qualifying assets that take a
substantial period of time to construct are capitalized and subsequently
expensed as depreciation over the assets' expected useful lives.
January 1, 2010 transition adjustments
Canadian Oil Sands has applied the transition election
available under IFRS 1 to exempt all interest costs incurred prior to January
1, 2010 from capitalization. As such, there is no adjustment at January 1,
2010.
2010 adjustments
For the three months ended March 31, 2010, the
capitalization of interest costs under IFRS resulted in a $6 million decrease
in interest expense with a corresponding increase in property, plant and
equipment. Expenditures of $6 million were reclassified from operating
activities to investing activities in the statement of cash flows.
For the year ended December 31, 2010, the
capitalization of interest costs under IFRS resulted in a $30 million decrease
in interest expense with a corresponding increase in property, plant and
equipment. Expenditures of $30 million were reclassified from operating
activities to investing activities in the statement of cash flows.
iii) Asset retirement obligation
Under Canadian GAAP, the asset retirement obligation
was measured, when initially recognized, using a credit-adjusted discount rate
and was not re-measured for changes to this rate. Under IFRS, the asset
retirement obligation is measured, when initially recognized, using a risk free
discount rate and is re-measured at each reporting date for changes to this
rate.
January 1, 2010 transition adjustments
Canadian Oil Sands has applied the transition election
available under IFRS 1 to estimate the January 1, 2010 net book value of the
asset retirement obligation's cost capitalized in property, plant and
equipment.
An adjustment was recorded at January 1, 2010 to
re-measure the asset retirement obligation using a risk free discount rate and
to recognize the impact of applying the IFRS 1 election. The combined effect
was a $161 million increase in the asset retirement obligation and a $19
million increase in property, plant, and equipment, with a corresponding $142
million decrease in retained earnings.
2010 adjustments
The risk free discount rate was unchanged from January
1, 2010 to March 31, 2010. As such, the asset retirement obligation and related
property, plant and equipment were not re-measured. At March 31, 2010, the
asset retirement obligation was $160 million higher and the related property,
plant and equipment asset was $18 million higher mainly as a result of the
January 1, 2010 transition adjustments.
The risk free discount rate was higher at December 31,
2010 than at March 31, 2010 and the asset retirement obligation and related
property, plant and equipment were re-measured. At December 31, 2010, the asset
retirement obligation was $177 million higher and the related property, plant
and equipment asset was $34 million higher mainly as a result of the January 1,
2010 transition adjustments and December 31, 2010 re-measurement.
iv) Actuarial losses on defined benefit pension plan
Under Canadian GAAP, Canadian Oil Sands recognized its
proportionate share of actuarial gains and losses on Syncrude Canada's defined
benefit pension plan using the corridor method whereby the excess of any net
actuarial gain or loss exceeding 10 per cent of the greater of the benefit
obligation or fair value of plan assets was amortized over the estimated
average remaining service life of employees. Under IFRS, these actuarial gains
and losses are immediately recognized as incurred in other comprehensive
income.
January 1, 2010 transition adjustments
Canadian Oil Sands has applied the transition election
available under IFRS 1 to recognize previously unrecognized actuarial losses
through January 1, 2010 retained earnings. This resulted in a $166 million
increase in employee future benefits and accrued liabilities with a
corresponding $166 million decrease in retained earnings.
2010 adjustments
At March 31, 2010, employee future benefits and
accrued liabilities were $164 million higher while retained earnings were $164
million lower, mainly as a result of the January 1, 2010 transition
adjustments.
Actuarial losses of $62 million, net of $20 million in
deferred taxes, were immediately recognized in other comprehensive income
during year ended December 31, 2010 while $9 million of operating expenses
relating to the amortization of these costs under Canadian GAAP were removed.
At December 31, 2010, employee future benefits and
accrued liabilities were $240 million higher while retained earnings were $240
million lower as a result of these IFRS adjustments.
v) Cash-settled share-based awards
Under Canadian GAAP, cash-settled share-based awards
were measured at each reporting date at their intrinsic value. Under IFRS,
cash-settled share-based awards are measured at fair value. The cash-settled
share-based awards include Canadian Oil Sands' proportionate share of Syncrude
Canada's Restricted Units and Phantom Units and Canadian Oil Sands' PSUs.
vi) Equity-settled share-based awards
Under Canadian GAAP, options were classified as
equity-settled share-based awards while Canadian Oil Sands operated as a trust.
Share-based compensation expense was measured using the grant date fair value
and amortized over the vesting period of the options with a corresponding
charge to contributed surplus. When options were exercised, amounts in
contributed surplus were reclassified to share capital.
Under IFRS, these options are not recognized as
equity-settled share-based awards until the December 31, 2010 conversion to a
corporation. Prior to this, options are re-measured at fair value at each
reporting date. While share-based compensation expense is still amortized over
the vesting period of the options, this charge is recorded as a liability, rather
than to contributed surplus, under IFRS. However, when options are exercised,
liabilities are still reclassified to shareholders' capital.
Upon conversion to a corporation on December 31, 2010,
the options are classified under IFRS as equity-settled share-based awards and
future share-based compensation expense is measured using the December 31, 2010
fair value amortized over the remaining vesting periods of the options.
January 1, 2010 transition adjustments
An adjustment was recorded at January 1, 2010 to
recognize the additional share-based compensation expense relating to all
previously settled options resulting in an $84 million increase in
shareholders' capital with a corresponding $84 million decrease in retained
earnings.
vii) Deferred taxes
Under Canadian GAAP, deferred taxes were referred to
as future income taxes and were measured by applying the 25 per cent corporate
tax rate, applicable to earnings distributed to trust unitholders, to temporary
differences. While Canadian Oil Sands was structured as an income trust, IFRS
required that deferred taxes be measured using the using the 39 per cent
individual tax rate applicable to earnings not distributed to trust
unitholders. At December 31, 2010, after the conversion to a corporation,
deferred taxes are measured at the 25 per cent corporate tax rate under IFRS,
resulting in the recognition of a deferred tax recovery.
January 1, 2010 transition adjustments
An adjustment was recorded at January 1, 2010 to
recognize a $269 million increase in the deferred taxes liability with a
corresponding $269 million decrease in retained earnings. The adjustment was
reversed on December 31, 2010 resulting in a $269 million deferred tax recovery
during the year ended December 31, 2010.
The tax impact of the combined January 1, 2010
transition adjustments resulted in a $201 million increase in the deferred tax
liability and a corresponding $201 million decrease in retained earnings.
2010 adjustments
The March 31, 2010 deferred tax liability increased by
$204 million and retained earnings decreased by $204 million mainly as a result
of the transition adjustments.
For the year ended December 31, 2010, a deferred tax
recovery adjustment of $259 million was recorded mainly as a result of the tax
rate reduction from 39 per cent to 25 per cent as a result of the conversion to
a corporation.
The $201 million increase in the deferred tax
liability at January 1, 2010, the $259 million deferred tax recovery
adjustments for the year ended December 31, 2010, and the $20 million deferred
tax recovery adjustment recorded with the actuarial losses in other
comprehensive income, collectively result in a $78 million decrease in the
December 31, 2010 deferred tax liability and a $78 million increase in December
31, 2010 retained earnings under IFRS.
viii) Exploration and evaluation costs
Under Canadian GAAP, capitalized exploration and
evaluation costs were included in property, plant, and equipment on the balance
sheet. Under IFRS, capitalized exploration and evaluation costs are presented
as a separate line item.
January 1, 2010 transition adjustments
An adjustment was recorded at January 1, 2010 to
reclassify $89 million from property, plant, and equipment to exploration and
evaluation assets.
2010 adjustments
There were no exploration and evaluation costs
capitalized during the three months ended March 31, 2010, nor during the year
ended December 31, 2010.
ix) Crown royalties
Under Canadian GAAP, Crown royalties were presented as
expenses in the statements of income and comprehensive income. Under IFRS,
Crown royalties are netted against revenues.
x) Net finance expense
Under Canadian GAAP, accretion of the asset retirement
obligation was presented with depreciation and depletion in the statements of
income and comprehensive income. Under IFRS, accretion is combined with
interest expense and presented as finance expense. Finance expense is presented
net of interest income earned on cash and cash equivalents.
6) PROPERTY, PLANT AND EQUIPMENT, NET
Upgrading
Vehicles
Asset
and
Mining
and
retirement
extraction equipment equipment Buildings costs
---------------------------------------------------------
Cost
As at
December
31, 2010 $ 4,669 $
1,381 $ 688 $ 304 $ 362
Additions
9
-
7
1
-
Change
in asset
retirement
obligation
- -
-
-
(13)
Retirements
-
-
-
-
-
Reclassifications
(1)
(12)
(1)
4
-
---------------------------------------------------------
As at
March 31,
2011 $ 4,677 $ 1,369 $ 694 $
309 $ 349
---------------------------------------------------------
Accumulated
depreciation
As at
December
31, 2010 $ 1,092 $
449 $ 264 $ 100 $ 103
Depreciation
40
23
13
2
4
Retirements
-
-
-
-
-
Reclassifications
(3)
5
2
(3)
---------------------------------------------------------
As at
March 31,
2011 $ 1,129 $ 477 $ 279 $ 99 $ 107
---------------------------------------------------------
Net book value,
March 31,
2011 $ 3,548 $ 892 $ 415 $ 210 $ 242
---------------------------------------------------------
---------------------------------------------------------
Turnaround Construction
Mine
costs in progress development
Total
-------------------------------------------------
Cost
As at December 31, 2010 $ 102 $
694 $ 345 $
8,545
Additions
-
92
-
109
Change in asset retirement
obligation
-
-
-
(13)
Retirements
-
-
-
-
Reclassifications
-
-
10
-
-------------------------------------------------
As at March 31, 2011
$ 102 $
786 $ 355 $
8,641
-------------------------------------------------
Accumulated depreciation
As at December 31, 2010 $ 50 $
- $
92 $ 2,150
Depreciation
10
-
3 95
Retirements
-
-
-
-
Reclassifications
-
(1) -
-------------------------------------------------
As at March 31, 2011
$ 60
$
- $
94 $ 2,245
-------------------------------------------------
Net book value,
March 31,
2011
$ 42
$
786 $ 261 $
6,396
-------------------------------------------------
-------------------------------------------------
Upgrading
Vehicles Asset
and
Mining
and
retirement
extraction equipment equipment Buildings costs
---------------------------------------------------------
Cost
As at
January 1,
2010 $ 4,594 $ 1,288 $ 667 $
298 $ 384
Additions
78 126
42
7
-
Change in asset
retirement
obligation
-
-
-
-
(22)
Retirements
(3)
(33)
(21)
(1)
-
---------------------------------------------------------
As at
December
31, 2010 $ 4,669 $
1,381 $ 688 $ 304 $ 362
---------------------------------------------------------
Accumulated
depreciation
As at
January 1,
2010 $ 931 $ 356 $ 231 $ 92 $ 78
Depreciation
164 126
54
9
25
Retirements
(3) (33) (21)
(1)
-
---------------------------------------------------------
As at
December
31, 2010 $ 1,092 $
449 $ 264 $ 100 $ 103
---------------------------------------------------------
Net book value,
December
31, 2010 $ 3,577 $
932 $ 424 $ 204 $ 259
---------------------------------------------------------
---------------------------------------------------------
Turnaround Construction
Mine
costs in progress development
Total
-------------------------------------------------
Cost
As at January 1, 2010
$ 94 $
439 $ 323 $
8,087
Additions
46
255
28
582
Change in asset retirement
obligation
-
-
-
(22)
Retirements
(38)
-
(6) (102)
-------------------------------------------------
As at December 31, 2010 $ 102 $
694 $ 345 $
8,545
-------------------------------------------------
Accumulated depreciation
As at January 1, 2010
$ 48 $
- $ 87 $
1,823
Depreciation
40
-
11
429
Retirements
(38)
-
(6) (102)
-------------------------------------------------
As at December 31, 2010 $ 50 $
- $ 92 $
2,150
-------------------------------------------------
Net book value,
December
31, 2010
$ 52 $
694 $ 253 $
6,395
-------------------------------------------------
-------------------------------------------------
For the three months ended March 31, 2011, interest
costs of $11 million were capitalized and included in property, plant and
equipment (March 31, 2010 - $6 million).
7) EMPLOYEE FUTURE BENEFITS AND OTHER LIABILITIES
Canadian Oil Sands' share of Syncrude Canada's net
defined benefit and contribution plans expense for the three months ended March
31, 2011 and 2010 is based on its 36.74 per cent working interest. The costs
have been recorded in operating expense as follows:
Three Months Ended
March 31
2011
2010
----------------------------------------------------------------------------
Defined benefit plans:
Pension
benefits
$
7
$
7
Other
benefit plans
1
1
----------------------------------------------------------------------------
$
8 $ 8
Defined contribution plans
1
1
----------------------------------------------------------------------------
Total
benefit cost
$
9
$
9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8) BANK CREDIT FACILITIES
As at March 31, 2011
----------------------------------------------------------------------------
Extendible revolving term facility (a)
$ 40
Line of credit (b)
100
Operating credit facility (c)
800
----------------------------------------------------------------------------
$
940
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The credit facilities of Canadian Oil Sands are
unsecured. The credit facility agreements contain covenants relating to the
restriction 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) Extendible Revolving Term Facility
The $40 million extendible revolving term facility is
a 364-day facility expiring June 30, 2011. This facility may be extended on an
annual basis with the agreement of the bank. Amounts borrowed through this
facility bear interest at a floating rate based on bankers' acceptances plus a
credit spread, while any unused amounts are subject to standby fees. As at
March 31, 2011, no amounts were drawn on this facility ($nil - December 31,
2010).
b) Line of Credit
The $100 million line of credit is a one-year
revolving letter of credit facility. Letters of credit drawn on the facility
mature April 30th each year and are automatically renewed, unless notification
to cancel is provided by Canadian Oil Sands or the financial institution
providing the facility at least 60 days prior to expiry. Letters of credit on
this facility bear interest at a credit spread. Letters of credit of
approximately $75 million have been written against the line of credit as at
March 31, 2011 ($75 million - December 31, 2010).
c) Operating Credit Facility
The $800 million operating facility is a multi-year
facility, expiring April 27, 2012. Amounts borrowed through this facility bear
interest at a floating rate based on either prime interest rates or bankers'
acceptances plus a credit spread, while any unused amounts are subject to
standby fees. As at March 31, 2011, no amounts were drawn against this facility
($145 million - December 31, 2010).
9) ASSET RETIREMENT OBLIGATION
Canadian Oil Sands and each of the other Syncrude
owners are liable for their share of ongoing environmental obligations related
to the ultimate reclamation of the Syncrude properties on abandonment. The
Corporation estimates reclamation expenditures will be made over approximately
the next 70 years and has applied a risk-free interest rate of 3.5% at March
31, 2011 (December 31, 2010 - 3.35%) in deriving the asset retirement
obligation.
The following table presents the reconciliation of the
beginning and ending aggregate carrying amount of the Corporation's share of
the obligation associated with the retirement of the Syncrude properties:
Three Months
Year Ended
Ended March
December 31
($ millions)
2011
2010
----------------------------------------------------------------------------
Asset retirement obligation, beginning of
period
$ 500 $ 550
Liabilities settled
(29)
(48)
Accretion expense
4
21
Change in risk-free interest rate
(13)
(23)
----------------------------------------------------------------------------
Asset retirement obligation, end of period
462
500
Less current portion
(37)
(37)
----------------------------------------------------------------------------
Non-current portion
$ 425 $ 463
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10) SHARE-BASED COMPENSATION
During the first quarter of 2011, 317,512 options and
76,644 PSUs were issued by the Corporation to officers and employees pursuant
to the Corporation's Long Term Incentive Plan. The options have an average
exercise price of $26.78 and an estimated value of $2 million while the PSUs have
an estimated value of $5 million.
11) NET FINANCE EXPENSE
Three Months Ended
March 31
($ millions)
2011
2010
----------------------------------------------------------------------------
Interest costs
$ 21 $ 26
Less
capitalized interest
$ (11) $ (6)
----------------------------------------------------------------------------
Interest expense
$ 10 $ 20
Accretion of asset retirement obligation
4
5
----------------------------------------------------------------------------
Net finance expense
$ 14 $ 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12) CONTINGENCY
Crown royalties include amounts due under the Syncrude
Royalty Amending Agreement with the Alberta government. The Syncrude Royalty
Amending Agreement requires that bitumen be valued by a formula that references
the value of bitumen based on a Canadian heavy oil price adjusted for
reasonable quality, transportation and handling deductions (including diluent
costs) to reflect the quality and location differences between Syncrude's
bitumen and the reference price of bitumen. The Alberta government and the
Syncrude owners are in discussions to determine the appropriate adjustments for
quality, transportation and handling. In December 2010, the Alberta government
provided a modified notice of a bitumen value for Syncrude (the "Syncrude
BVM"). For estimating and paying royalties, Syncrude used a bitumen value
based on Syncrude and its owners' interpretation of the Syncrude Royalty
Amending Agreement, which is different than the Syncrude BVM. As a result,
Canadian Oil Sands' share of the royalties recognized for the period from
January 1, 2009 to March 31, 2011 are now estimated to be approximately $35
million less than the amount calculated under the Syncrude BVM. The Syncrude
owners and the Alberta government continue to discuss the basis for reasonable
quality, transportation, and handling adjustments but if such discussions do
not result in an agreed upon solution, either party may seek judicial
determination of the matter. Should these discussions or a judicial determination
result in a deemed bitumen value different than that used by Syncrude for
estimating and paying royalties, the cumulative impact on Canadian Oil Sands'
share of royalties since January 1, 2009 will be recognized immediately and
impact both net income and cash royalties accordingly.
13) SUPPLEMENTARY INFORMATION
Three Months Ended
March 31
2011
2010
----------------------------------------------------------------------------
Income tax paid
$
-
$ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid
$ 19 $ 24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contacts:
Canadian Oil Sands Limited
TBD
Source:
Canadian Oil Sands Limited