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CALGARY, ALBERTA--(Marketwire - Feb. 1, 2012) - Canadian Oil Sands Limited COS COSWF
All financial figures are unaudited and in Canadian dollars unless otherwise noted.
Highlights for the three and 12-month period ended December 31, 2011:
-- Cash flow from operations was $363 million ($0.75 per Share) in the
fourth quarter of 2011 compared with cash flow from operations of $398
million ($0.82 per Share) in the same quarter of the prior year. For the
2011 year, cash flow from operations totalled $1,897 million ($3.91 per
Share), up 54 per cent from $1,232 million ($2.55 per Share) in 2010.
-- The increase in year-over-year cash flow from operations reflects a
higher Canadian Oil Sands (COS) realized selling price of $101.20 per
barrel in 2011, up from $80.53 per barrel in 2010, partially offset by
lower sales volumes and higher operating expenses.
-- Net income for the fourth quarter of 2011 was $232 million ($0.48 per
Share), down from $575 million ($1.19 per Share) in the 2010 fourth
quarter. On an annual basis, net income was $1,144 million ($2.36 per
Share) in 2011 compared with $1,189 million ($2.46 per Share) in 2010.
-- The decline in net income on a quarter over quarter and annual basis is
largely a reflection of the deferred tax expense recognized in 2011 as
opposed to the significant deferred tax recovery recognized in 2010,
both resulting from the conversion from an income trust to a corporate
structure on December 31, 2010.
-- COS' dividend is maintained at $0.30 per share, payable on February 29,
2012 to shareholders of record on February 24, 2012.
-- Sales volumes averaged 106,000 barrels per day in 2011 compared with
107,000 barrels per day in 2010. Production in 2011 was impacted
primarily by maintenance on a hydrogen unit.
-- Operating expenses were $393 million during the fourth quarter of 2011
compared with $378 million for the same period of 2010. Largely as a
result of lower production volumes quarter over quarter, per barrel
operating expenses averaged $46.88 in the 2011 fourth quarter compared
with $35.81 in the same period of 2010. On an annual basis, operating
expenses averaged $38.80 per barrel in 2011 compared with $35.42 per
barrel in 2010. The increase year over year reflects increased
maintenance and higher diesel costs.
-- Capital expenditures totalled $643 million in 2011 compared with $582
million in 2010.
-- Net debt (long-term debt less cash and cash equivalents) decreased to
$414 million at December 31, 2011 from $1,171 million at December 31,
2010. During 2011, COS raised cash balances to reduce risk around
Syncrude's capital program; as these cash balances are drawn down to
fund the capital program, net debt levels are expected to rise.
"I am pleased with the financial results we delivered in 2011, including a dividend increase in the second quarter. Our approach of providing unhedged exposure to crude oil delivered a 50 per cent increase in cash flow from operations over last year. We are in a very healthy financial position as we enter 2012, which supports our ability to fund both our capital program at Syncrude and our target of at least a $0.30 per Share quarterly dividend for 2012," said Marcel Coutu, President and Chief Executive Officer. "Our strong balance sheet also positions us well in an uncertain economic environment, with the potential of a recession in Europe spreading to other regions. Despite that risk, oil prices currently remain around US$100 per barrel, providing robust support for our business."
Highlights
Three Months Ended Year Ended
December 31 December 31
($ millions except per Share and
per barrel volume amounts) 2011 2010 2011 2010
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Cash flow from operations(1) $ 363 $ 398 $ 1,897 $ 1,232
Per Share(1) $ 0.75 $ 0.82 $ 3.91 $ 2.55
Net income $ 232 $ 575 $ 1,144 $ 1,189
Per Share $ 0.48 $ 1.19 $ 2.36 $ 2.46
Sales volumes(2)
Total (mmbbs) 8.4 10.6 38.7 39.2
Daily average (bbls) 91,259 114,739 106,015 107,280
Realized SCO selling price
($/bbl) $ 104.78 $ 83.97 $ 101.20 $ 80.53
West Texas Intermediate (average
$US per barrel) $ 94.06 $ 85.24 $ 95.11 $ 79.61
Operating expenses ($/bbl) $ 46.88 $ 35.81 $ 38.80 $ 35.42
Capital expenditures $ 205 $ 189 $ 643 $ 582
Dividends $ 146 $ 242 $ 533 $ 896
Per Share $ 0.30 $ 0.50 $ 1.10 $ 1.85
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(1)Cash flow from operations and cash flow from operations per Share are
non-GAAP measures and are defined on pages 5-6 of the Management's
Discussion & Analysis ("MD&A") section of this report.
(2)The Corporation's sales volumes differ from its production volumes due to
changes in inventory, which are primarily in-transit pipeline volumes.
Sales volumes are net of purchases.
Syncrude operations
Syncrude produced an average 252,000 barrels per day (total 23.2 million barrels) during the fourth quarter of 2011 compared with 316,000 barrels per day (total 29.0 million barrels) during the same 2010 period. Production was reduced in the 2011 fourth quarter largely by maintenance on a hydrogen unit. Production volumes in the fourth quarters of both years were also impacted by coker turnarounds, which were completed in late October of each year.
For the 2011 year, Syncrude production averaged about 288,000 barrels per day (total 105.3 million barrels) compared with about 293,000 barrels per day (107.0 million barrels) in 2010.
Said Coutu: "Syncrude production in 2011 was affected by the outage of our largest hydrogen unit which reduced our production by millions of barrels in the fourth quarter and, as a result, we missed our annual target; this exemplifies the value of the effort currently underway to target unplanned capacity losses. We do expect this to gradually result in increased capacity rates at Syncrude, and in 2012 we are looking forward to a seven per cent increase in volumes over 2011."
2012 Outlook
The following highlights Canadian Oil Sands' updated key estimates and assumptions for 2012:
-- COS' estimate for 2012 Syncrude production remains at 113 million
barrels (309,000 barrels per day) with a range of 106 to 117 million
barrels. This is equivalent to 41.5 million barrels net to COS (113,000
barrels per day). The production outlook incorporates a turnaround of
Coker 8-3 in the second quarter of the year, as originally planned, and
maintenance on Coker 8-1, beginning in early February.
-- Capital expenditures are estimated to total $1,460 million, comprised of
$974 million of spending on major projects, $405 million in regular
maintenance of the business and other projects, and $81 million in
capitalized interest.
-- Sales, net of crude oil purchases and transportation expense, of
approximately $3.8 billion, or $92 per barrel (based on a U.S. $90 per
barrel WTI oil price, an SCO price equivalent to Cdn dollar WTI, and a
U.S./Cdn foreign exchange rate of $0.98)
-- Cash flow from operations of $1,825 billion, or $3.77 per Share. After
deducting forecast 2012 capital expenditures, we estimate $365 million
in remaining cash flow from operations, or $0.75 per Share.
-- COS is targeting a quarterly dividend of at least $0.30 per Share for
2012, based on current assumptions with support from our cash balances,
as necessary.
More information on the outlook is provided in the MD&A section of this report and the February 1, 2012 guidance document, which is available on our web site at www.cdnoilsands.com under "Investor Information".
The 2012 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis ("MD&A") was prepared as of February 1, 2012 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Limited (the "Corporation") for the three and twelve months ended December 31, 2011 and December 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 partnerships 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 information" 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 and the related press release include, but are not limited to, statements with respect to: the expectations regarding the 2012 annual Syncrude forecasted production range of 106 to 117 million barrels and the single-point Syncrude production estimate of 113 million barrels; the timing and impact on production of the turnaround of Coker 8-3 and maintenance on Coker 8-1; the expectation that capacity rates at Syncrude will gradually increase and that 2012 volumes at Syncrude will increase by seven per cent over 2011 volumes; future dividends and any increase or decrease from current payment amounts, and our intention to pay a quarterly dividend of at least $0.30 per Share for 2012; the establishment of future dividend levels with the intent of absorbing short-term market volatility over several quarters; the expectation that the new accounting standards relating to joint arrangements, employee benefits, consolidated financial statements, disclosures of interests in other entities, fair value measurements and stripping costs will not result in any significant accounting or disclosure changes; plans regarding crude oil hedges and currency hedges in the future; the level of natural gas consumption in 2012 and beyond; the expected sales, operating expenses, Crown royalties, capital expenditures, current and deferred taxes, and cash flow from operations for 2012;
the expectation that 2012 deferred taxes will flow through current taxes and cash flow from operations in 2013; the expected price for crude oil and natural gas in 2012; the expected foreign exchange rates in 2012; the expected realized selling price, which includes the anticipated differential to West Texas Intermediate ("WTI") to be received in 2012 for the Corporation's product; the expectations regarding net debt in 2012; the anticipated impact of increases or decreases in oil prices, production, operating expenses, foreign exchange rates and natural gas prices on the Corporation's cash flow from operations; the expectation that regular maintenance capital costs will average approximately $10 per barrel over the next few years; the expected amount of total major project costs 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 projects primarily through cash flow from operations and the cost estimates for 2012 major project spending and post-2012 major project spending.
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 the 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 expenses 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 AIF 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. In addition, the Corporation refers to various per barrel figures, such as net realized selling prices, operating expenses 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.
Since January, 2011, we report 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 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 Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
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Cash flow from operations $ 363 $ 398 $ 1,897 $ 1,232
Change in non-cash working
capital(1) (47) (150) 61 63
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Cash from operating
activities(1) $ 316 $ 248 $ 1,958 $ 1,295
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(1)As reported in 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.
Financial measures for the three and twelve months ended December 31, 2010 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 9. The accounting policies applied in these interim unaudited consolidated financial statements are based on IFRS issued, outstanding, and effective as of February 1, 2012. 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.
Under IFRS, the Corporation's consolidated balance sheets are adjusted to reflect the following:
-- The deferred tax liability was re-measured on transition to IFRS 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, as
applicable, at the end of each reporting period thereafter, 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
thereafter, to record previously unrecognized actuarial losses on
Syncrude Canada Ltd.'s ("Syncrude Canada's") defined benefit pension
plan.
Under IFRS, beginning in 2010 net income is adjusted to reflect the following:
-- 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 qualifying 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.
-- 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, beginning in 2010 cash flow from operations and cash used in investing activities have each been adjusted, by equal and offsetting amounts, to reflect the capitalization of both major turnaround costs and interest costs on certain qualifying assets during construction.
Revenues are now reported net of Crown royalties; previously Crown royalties were reported as an expense. Lastly, future income taxes are now referred to as deferred taxes.
REVIEW OF SYNCRUDE OPERATIONS
Synthetic crude oil ("SCO") production from the Syncrude Joint Venture ("Syncrude") during the fourth quarter of 2011 totalled 23.2 million barrels, or 252,000 barrels per day, compared with 29.0 million barrels, or 316,000 barrels per day, during the fourth quarter of 2010. Net to the Corporation, production totalled 8.5 million barrels in the fourth quarter of 2011 compared with 10.7 million barrels in the fourth quarter of 2010, based on Canadian Oil Sands' 36.74 per cent working interest in Syncrude. Lower production in the fourth quarter of 2011 reflected the unplanned shutdown of a hydrogen unit to perform required maintenance and a process upset in Coker 8-1. Production volumes in both the fourth quarters of 2011 and 2010 also reflected planned coker turnarounds, which were completed in late October of each year.
For the full year 2011, Syncrude production volumes fell 1.6 per cent to 105.3 million barrels, or about 288,000 barrels per day, from 107.0 million barrels, or about 293,000 barrels per day, in 2010. The production estimate in the original 2011 budget was for 110 million barrels. Production volumes in 2011 reflect the hydrogen unit and Coker 8-1 operational issues in the fourth quarter.
Canadian Oil Sands' operating expenses were $393 million, or $46.88 per barrel, in the fourth quarter of 2011, compared with $378 million, or $35.81 per barrel, in the fourth quarter of 2010. For the full year 2011, Canadian Oil Sands' operating expenses increased about eight per cent to $1,501 million, or $38.80 per barrel, from $1,387 million, or $35.42 per barrel, in 2010. The increase in year-over-year operating expenses was mainly due to increased maintenance and higher diesel costs in 2011. Per barrel operating expenses also reflect the Corporation's lower sales volumes in the fourth quarter and full year 2011 relative to the comparative 2010 periods (see the "Operating Expenses" section of this MD&A for further discussion).
The productive capacity of Syncrude's facilities is approximately 350,000 barrels per day on average, including an allowance for downtime, and is referred to as "barrels per calendar day". All references to Syncrude's production capacity in this report refer to barrels per calendar day, unless stated otherwise. Canadian Oil Sands' production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes.
SUMMARY OF QUARTERLY RESULTS
2011
Q4 Q3 Q2 Q1
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Sales(1) ($ millions) $ 884 $ 989 $ 1,045 $ 1,016
Net income ($ millions) $ 232 $ 242 $ 346 $ 324
Per Share, Basic & Diluted $ 0.48 $ 0.50 $ 0.71 $ 0.67
Cash flow from operations(2)
($ millions) $ 363 $ 512 $ 544 $ 478
Per Share(2) $ 0.75 $ 1.06 $ 1.12 $ 0.99
Dividends ($ millions) $ 146 $ 145 $ 145 $ 97
Per Share $ 0.30 $ 0.30 $ 0.30 $ 0.20
Daily averages sales
volumes(3) (bbls) 91,259 109,260 102,938 120,894
Realized SCO selling price
($/bbl) $ 104.78 $ 97.89 $ 111.00 $ 93.04
Operating expenses(4)
($/bbl) $ 46.88 $ 37.19 $ 37.07 $ 35.53
Purchased natural gas price
($/GJ) $ 3.19 $ 3.51 $ 3.62 $ 3.59
West Texas Intermediate(5)
(avg $US/bbl) $ 94.06 $ 89.54 $ 102.34 $ 94.60
Foreign exchange rates
($US/$Cdn)
Average $ 0.98 $ 1.02 $ 1.03 $ 1.02
Quarter-end $ 0.98 $ 0.96 $ 1.04 $ 1.03
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(1)Sales after crude oil purchases and transportation expense.
(2)Cash flow from operations and cash flow from operations per Share are
non-GAAP measures and are defined on pages 5-6 of this MD&A.
(3)Daily average sales volumes net of crude oil purchases.
(4)Derived from operating expenses, as reported on the Consolidated
Statements of Income and Comprehensive Income, divided by sales volumes
during the period.
(5)Pricing obtained from Bloomberg.
2010
Q4 Q3 Q2 Q1
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Sales(1) ($ millions) $ 912 $ 692 $ 842 $ 734
Net income ($ millions) $ 575 $ 193 $ 245 $ 176
Per Share, Basic & Diluted $ 1.19 $ 0.40 $ 0.51 $ 0.36
Cash flow from operations(2)
($ millions) $ 398 $ 230 $ 379 $ 225
Per Share(2) $ 0.82 $ 0.48 $ 0.78 $ 0.46
Dividends ($ millions) $ 242 $ 242 $ 242 $ 170
Per Share $ 0.50 $ 0.50 $ 0.50 $ 0.35
Daily averages sales
volumes(3) (bbls) 114,739 96,477 118,569 99,286
Realized SCO selling price
($/bbl) $ 83.97 $ 77.94 $ 78.07 $ 82.06
Operating expenses(4)
($/bbl) $ 35.81 $ 37.97 $ 30.86 $ 37.94
Purchased natural gas price
($/GJ) $ 3.45 $ 3.44 $ 3.68 $ 4.95
West Texas Intermediate(5)
(avg $US/bbl) $ 85.24 $ 76.21 $ 78.05 $ 78.88
Foreign exchange rates
($US/$Cdn)
Average $ 0.99 $ 0.96 $ 0.97 $ 0.96
Quarter-end $ 1.01 $ 0.97 $ 0.94 $ 0.98
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(1)Sales after crude oil purchases and transportation expense.
(2)Cash flow from operations and cash flow from operations per Share are
non-GAAP measures and are defined on pages 5-6 of this MD&A.
(3)Daily average sales volumes net of crude oil purchases.
(4)Derived from operating expenses, as reported on the Consolidated
Statements of Income and Comprehensive Income, divided by sales volumes
during the period.
(5)Pricing obtained from Bloomberg.
During the last eight quarters, the following items have had a significant impact on the 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, net income and cash flow
from operations;
-- planned and unplanned maintenance activities have impacted quarterly
production volumes, revenues and operating expenses;
-- net income in 2011 reflects an increase in deferred taxes after
conversion to a corporation on December 31, 2010. Tax pools are being
drawn down to shelter taxable income under the corporate structure,
whereas distributions were available to shelter taxable income prior to
2011.
-- net income 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 (see the
"Deferred Taxes" section of this MD&A for further discussion).
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. In addition, recent technological developments in North American natural gas production have significantly increased production levels and reduced natural gas prices. These conditions may persist for the next several years.
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 outages cannot be precisely scheduled, and unplanned outages may occur. The costs of major turnarounds are 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 are expensed in the period incurred, which can result in volatility in quarterly operating expenses. The effect on per barrel operating expenses of the expensed turnaround and maintenance work is amplified because it results in reduced sales volumes when this work is occurring.
REVIEW OF FINANCIAL RESULTS
Highlights
Three Months Ended Year Ended
December 31 December 31
($ millions, except per
Share and per barrel volume
amounts) 2011 2010 2011 2010
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Cash flow from operations(1) $ 363 $ 398 $ 1,897 $ 1,232
Per Share(1) $ 0.75 $ 0.82 $ 3.91 $ 2.55
Net income $ 232 $ 575 $ 1,144 $ 1,189
Per Share $ 0.48 $ 1.19 $ 2.36 $ 2.46
Sales volumes(2)
Total (mmbbs) 8.4 10.6 38.7 39.2
Daily average (bbls) 91,259 114,739 106,015 107,280
Realized SCO selling price
($/bbl) $ 104.78 $ 83.97 $ 101.20 $ 80.53
West Texas Intermediate
(average $US per barrel) $ 94.06 $ 85.24 $ 95.11 $ 79.61
Operating expenses ($/bbl) $ 46.88 $ 35.81 $ 38.80 $ 35.42
Capital expenditures $ 205 $ 189 $ 643 $ 582
Dividends $ 146 $ 242 $ 533 $ 896
Per Share $ 0.30 $ 0.50 $ 1.10 $ 1.85
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(1)Cash flow from operations and cash flow from operations per Share are
non-GAAP measures and are defined on pages 5-6 of this MD&A.
(2)The Corporation's sales volumes differ from its production volumes due to
changes in inventory, which are primarily in-transit pipeline volumes.
Sales volumes are net of purchases.
Net Income per Barrel
Three Months Ended Year Ended
December 31 December 31
($ per
barrel)(1) 2011 2010 $ Change 2011 2010 $ Change
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Sales after
crude oil
purchases and
transportation
expense $ 105.17 $ 86.36 $ 18.81 $ 101.66 $ 81.21 $ 20.45
Operating
expenses (46.88) (35.81) (11.07) (38.80) (35.42) (3.38)
Crown royalties (8.64) (7.06) (1.58) (7.93) (7.80) (0.13)
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$ 49.65 $ 43.49 $ 6.16 $ 54.93 $ 37.99 $ 16.94
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Non-production
expenses (3.19) (2.29) (0.90) (2.93) (2.68) (0.25)
Administration
and insurance (1.14) (0.76) (0.38) (0.85) (0.80) (0.05)
Depreciation and
depletion (11.40) (10.52) (0.88) (9.84) (10.96) 1.12
Net finance
expense (0.80) (1.52) 0.72 (1.19) (2.09) 0.90
Foreign exchange
gain (loss) 2.66 3.31 (0.65) (0.57) 1.54 (2.11)
Deferred tax
(expense)
recovery (8.31) 22.77 (31.08) (10.00) 7.36 (17.36)
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(22.18) 10.99 (33.17) (25.38) (7.63) (17.75)
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Net income per
barrel $ 27.47 $ 54.48 $ (27.01) $ 29.55 $ 30.36 $ (0.81)
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Sales volumes
(mmbbls)(2) 8.4 10.6 (2.2) 38.7 39.2 (0.5)
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(1)Unless otherwise specified, the per barrel measures in this MD&A have
been derived by dividing the relevant item by sales volumes in the period.
(2)Sales volumes, net of purchased crude oil volumes.
Cash flow from operations was $363 million, or $0.75 per Share, in the fourth quarter of 2011, about nine per cent lower than fourth quarter 2010 cash flow from operations of $398 million, or $0.82 per Share, reflecting lower sales net of crude oil purchases and transportation expense and higher operating expenses in the fourth quarter of 2011. On an annual basis, cash flow from operations increased 54 per cent to $1,897 million, or $3.91 per Share, in 2011 from $1,232 million, or $2.55 per Share, in 2010. The increase was due mainly to higher sales partially offset by higher operating expenses.
Sales net of crude oil purchases and transportation expense fell $28 million to $884 million in the fourth quarter of 2011 from $912 million in the fourth quarter of 2010. The decrease reflects lower sales volumes partially offset by a higher average realized SCO selling price. On an annual basis, sales net of crude oil purchases and transportation expense increased $754 million to $3,934 million in 2011 from $3,180 million in 2010, reflecting a higher average realized selling price partially offset by lower sales volumes (see the "Sales Net of Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).
Crown royalties totalled $73 million, or $8.64 per barrel, in the fourth quarter of 2011, similar to the fourth quarter of 2010 when Crown royalties totalled $75 million, or $7.06 per barrel. On an annual basis, Crown royalties totalled $307 million, or $7.93 per barrel, in 2011, similar to 2010 when Crown royalties totalled $306 million, or $7.80 per barrel. Despite increases in realized SCO prices, bitumen prices were largely unchanged quarter-over-quarter and year-over-year. The impact of slightly lower bitumen production volumes and higher allowed costs in 2011 relative to 2010 was largely offset by additional royalties recognized in the fourth quarter of 2011 to reflect revisions to the estimated quality, transportation and handling deductions used to calculate bitumen values (see the "Crown Royalties" section of this MD&A for further discussion).
Operating expenses in the fourth quarter of 2011 were $393 million, or $46.88 per barrel, compared with $378 million, or $35.81 per barrel, in the fourth quarter of 2010. On an annual basis, operating expenses in 2011 increased about eight per cent to $1,501 million, or $38.80 per barrel, from $1,387 million, or $35.42 per barrel, in 2010. The increase in year-over-year operating expenses was primarily due to increased maintenance and higher diesel costs in 2011. Per barrel operating expenses also reflect the Corporation's lower sales volumes in the fourth quarter and full year 2011 relative to the comparative 2010 periods (see the "Operating Expenses" section of this MD&A for further discussion).
Net income fell $343 million to $232 million, or $0.48 per Share, in the fourth quarter of 2011, from $575 million, or $1.19 per Share, in the fourth quarter of 2010. On an annual basis, net income fell $45 million to $1,144 million, or $2.36 per Share, in 2011, from $1,189 million, or $2.46 per Share, in 2010. In addition to the variances in sales and operating expenses described earlier, net income was impacted by variances in deferred taxes and foreign exchange gains and losses.
Canadian Oil Sands recorded deferred tax expenses of $70 million and $387 million in the fourth quarter and full year 2011, respectively, versus recoveries of $240 million and $289 million in the comparative 2010 periods. Prior to December 31, 2010, income was sheltered from current taxes by the payment of distributions to trust unitholders. As such, there were no significant drawdowns of tax pools or a resulting deferred tax expense in 2010. Upon conversion from an income trust to a corporate structure effective December 31, 2010, Canadian Oil Sands' earnings are sheltered from current taxes through the drawdown of tax pools. A deferred tax expense has been recognized in 2011 to reflect the cost of consuming these pools. The 2010 deferred tax recovery incorporates the $269 million re-measurement of the corporation's deferred tax liability at a lower tax rate upon conversion to a corporation. While Canadian Oil Sands was structured as an income trust, deferred taxes were measured using the 39 per cent individual tax rate applicable to earnings not distributed to trust unitholders. Beginning December 31, 2010, deferred taxes are measured using the 25 per cent corporate tax rate (see the "Deferred Taxes" section of this MD&A for further discussion).
Canadian Oil Sands recorded a $24 million foreign exchange gain on the revaluation of its U.S. dollar-denominated long-term debt in the fourth quarter of 2011 as the Canadian dollar strengthened relative to the U.S. dollar. For the full year 2011, Canadian Oil Sands recorded a $25 million foreign exchange loss, reflecting a weaker Canadian dollar relative to the U.S. dollar at the end of 2011 compared with the end of 2010. By comparison, Canadian Oil Sands recorded foreign exchange gains of $39 million and $58 million in the fourth quarter and full year of 2010, respectively, reflecting a strengthening in the value of the Canadian dollar relative to the U.S. dollar.
Net debt, comprised of long-term debt less cash and cash equivalents, decreased to $0.4 billion at December 31, 2011 from $1.2 billion at December 31, 2010 as Canadian Oil Sands generated $1.9 billion in cash flow from operations in 2011 while capital expenditures and dividend payments were $0.6 billion and $0.5 billion, respectively.
Canadian Oil Sands increased its estimated asset retirement obligation during the fourth quarter of 2011 to $1,037 million at December 31, 2011 from $545 million at September 30, 2011 and $501 million at December 31, 2010. The increase was capitalized as property, plant and equipment and reflects the fourth quarter completion of a revised comprehensive mine development and closure plan (see the "Asset Retirement Obligation" section of this MD&A for further discussion).
Sales Net of Crude Oil Purchases and Transportation Expense
Three Months Ended Year Ended
December 31 December 31
($ millions) 2011 2010 $Change 2011 2010 $Change
----------------------------------------------------------------------------
Sales(1) $ 973 $ 936 $ 37 $ 4,182 $ 3,460 $ 722
Crude oil purchases (83) (18) (65) (221) (254) 33
Transportation expense (6) (6) - (27) (26) (1)
----------------------------------------------------------------------------
$ 884 $ 912 $ (28) $ 3,934 $ 3,180 $ 754
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales volumes
(mmbbls)(2) 8.4 10.6 (2.2) 38.7 39.2 (0.5)
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----------------------------------------------------------------------------
Realized SCO selling
price(3) $104.78 $ 83.97 $ 20.81 $101.20 $ 80.53 $ 20.67
(average $Cdn/bbl)
West Texas
Intermediate ("WTI") 94.06 85.24 8.82 95.11 79.61 15.50
(average $US/bbl)
SCO premium (discount)
to WTI 8.51 (2.63) 11.14 7.32 (1.61) 8.93
(weighted average
$Cdn/bbl)
Average foreign
exchange rate 0.98 0.99 (0.01) 1.01 0.97 0.04
($US/$Cdn)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1)Sales include sales of purchased crude oil, sales of sulphur and
proceeds from insurance claims.
(2)Sales volumes, net of purchased crude oil volumes.
(3)SCO sales net of crude oil purchases and transportation expense divided
by sales volumes, net of purchased crude oil volumes.
The $28 million, or three per cent, decrease in sales net of crude oil purchases and transportation expense in the fourth quarter of 2011 relative to the comparative 2010 period is the result of lower sales volumes in 2011 partially offset by a higher average realized selling price for our SCO. The higher realized SCO selling price reflects a higher West Texas Intermediate ("WTI") crude oil price, which averaged U.S. $94 per barrel in the fourth quarter of 2011 compared with U.S. $85 per barrel in the comparative 2010 period, and a weaker Canadian dollar, which averaged $0.98 U.S./Cdn in the fourth quarter of 2011 compared with $0.99 U.S./Cdn in the comparative 2010 period. The Corporation's SCO selling price is also affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the fourth quarter of 2011, the Corporation realized a weighted-average SCO premium of $8.51 per barrel versus a $2.63 per barrel discount in the fourth quarter of 2010. The Corporation's fourth quarter sales volumes averaged 91,000 barrels per day in 2011 compared with 115,000 barrels per day in 2010, reflecting the operational issues with the hydrogen unit and Coker 8-1 in the fourth quarter of 2011.
On an annual basis, the $754 million, or 24 per cent, increase in sales net of crude oil purchases and transportation expense in 2011 relative to 2010 reflects a higher average realized SCO selling price in 2011 partially offset by lower sales volumes. Higher WTI crude oil prices, which averaged U.S. $95 per barrel in 2011 compared with U.S. $80 per barrel in 2010, were offset somewhat by a stronger Canadian dollar, which averaged $1.01 U.S./Cdn in 2011, up from $0.97 U.S./Cdn in 2010. In addition, the Corporation realized a weighted-average SCO premium of $7.32 per barrel in 2011 versus a $1.61 per barrel discount in 2010. Sales volumes averaged 106,000 barrels per day in 2011 compared with 107,000 barrels per day in 2010, reflecting the operational issues with the hydrogen unit and Coker 8-1 in the fourth quarter of 2011.
The differential between SCO and WTI can change quickly, reflecting changes in the short-term supply and demand dynamics in the market and pipeline availability for transporting crude oil. The increase in the 2011 differential was primarily the result of two factors. The first was the lower supply of SCO in the market because of operational upsets and maintenance at several oil sands plants during the year. The second was the dislocation of the WTI crude oil benchmark to other light oil benchmarks such as European Brent Crude ("Brent") and Louisiana Light Sweet ("LLS") crude due to an over-supply of crude oil to North American inland markets. In certain U.S. markets, SCO sometimes competes with crude oil priced higher than WTI, such as LLS, which can contribute to a positive differential to WTI.
The Corporation purchases crude oil from third parties 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 include the sale of purchased crude oil while the cost of these purchases is included in crude oil purchases and transportation expense. Crude oil purchases were higher in the fourth quarter of 2011 relative to the comparative 2010 period, reflecting additional purchased volumes to support transportation arrangements and unanticipated production shortfalls, combined with higher crude oil prices in 2011. On an annual basis, crude oil purchases were lower in 2011 relative to 2010, reflecting lower purchased volumes partially offset by higher crude oil prices in 2011.
Crown Royalties
Crown royalties totalled $73 million, or $8.64 per barrel, in the fourth quarter of 2011, similar to the fourth quarter of 2010 when Crown royalties totalled $75 million, or $7.06 per barrel. On an annual basis, Crown royalties totalled $307 million, or $7.93 per barrel, in 2011, similar to 2010 when Crown royalties totalled $306 million, or $7.80 per barrel. Despite increases in realized SCO prices, bitumen prices were largely unchanged quarter-over-quarter and year-over-year. The impact of slightly lower bitumen production volumes and higher allowed costs in 2011 relative to 2010 was largely offset by additional royalties recognized in the fourth quarter of 2011 to reflect revisions to the estimated quality, transportation and handling deductions used to calculate bitumen values over the 2009 to 2011 period.
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. For estimating and paying royalties, Syncrude used a bitumen value based on Syncrude and its owners' interpretation of the Syncrude Royalty Amending Agreement. In the fourth quarter of 2011, Syncrude revised its estimate of this bitumen value for the period from January 1, 2009 to December 31, 2011 and, as a result, approximately $20 million of additional Crown royalties were recognized.
In December 2010 the Alberta government provided a modified notice of a bitumen value for Syncrude (the "Syncrude BVM") which is different than the bitumen value used by Syncrude for estimating and paying royalties. Canadian Oil Sands' share of the royalties recognized for the period from January 1, 2009 to December 31, 2011 are estimated to be approximately $40 million lower than the amount calculated using the Syncrude BVM. The Syncrude owners and the Alberta government continue to discuss the basis for reasonable quality, transportation, and handling adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. Should these discussions or a judicial determination result in a deemed bitumen value different than that used by Syncrude for estimating and paying royalties, the cumulative impact on Canadian Oil Sands' share of royalties since January 1, 2009 will be recognized immediately and will impact both net income and cash flow from operations accordingly.
Operating Expenses
The following table breaks down operating expenses into their major components and shows operating expenses per barrel of bitumen and SCO. The information allocates costs to bitumen production and upgrading on the basis used to determine Crown royalties.
Three Months Ended
December 31
2011 2010
----------------------------------------------------------------------------
($ per barrel) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Bitumen production $ 30.79 $ 36.62 $ 22.03 $ 23.98
Internal fuel allocation(2) 2.47 2.93 1.91 2.08
----------------------------------------------------------------------------
Total produced bitumen costs 33.26 39.55 23.94 26.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Upgrading costs(1) 13.88 14.77
Less: internal fuel allocation to
bitumen(2) (2.93) (2.08)
Bitumen purchases - -
----------------------------------------------------------------------------
Total Syncrude operating expenses 50.50 38.75
Canadian Oil Sands adjustments(3) (3.62) (2.94)
----------------------------------------------------------------------------
Total operating expenses 46.88 35.81
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(thousands of barrels per day) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude production volumes 300 252 343 316
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year Ended
December 31
2011 2010
----------------------------------------------------------------------------
($ per barrel) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Bitumen production $ 25.53 $ 30.37 $ 20.63 $ 24.34
Internal fuel allocation(2) 2.40 2.85 2.36 2.79
----------------------------------------------------------------------------
Total produced bitumen costs 27.93 33.22 22.99 27.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Upgrading costs(1) 10.62 13.34
Less: internal fuel allocation to
bitumen(2) (2.85) (2.79)
Bitumen purchases - -
----------------------------------------------------------------------------
Total Syncrude operating expenses 40.99 37.68
Canadian Oil Sands adjustments(3) (2.19) (2.26)
----------------------------------------------------------------------------
Total operating expenses 38.80 35.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(thousands of barrels per day) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude production volumes 343 288 346 293
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1)Upgrading costs include the production and ongoing maintenance costs associated with processing and upgrading of bitumen to SCO.
(2)Reflects energy generated by the upgrader that is used in the bitumen production process and is valued by reference to natural gas prices. Natural gas prices averaged $3.19 per GJ and $3.48 per GJ for the three months and year ended December 31, 2011, respectively, and $3.45 per GJ and $3.87 per GJ for the three months and year ended December 31, 2010.
(3)Canadian Oil Sands' adjustments mainly pertain to actual reclamation costs and major turnaround costs, which Syncrude includes in operating expenses. Canadian Oil Sands capitalizes major turnaround costs and recognizes actual reclamation costs through its asset retirement obligation. Major turnaround costs are expensed through depreciation and reclamation costs are expensed through both depletion and accretion (within net finance expense).
Three Months Ended Year Ended
December 31 December 31
($ per barrel of SCO) 2011 2010 $ Change 2011 2010 $ Change
----------------------------------------------------------------------------
Production costs $ 41.50 $ 31.28 $ 10.22 $ 33.79 $ 31.15 $ 2.64
Purchased energy 5.38 4.53 0.85 5.01 4.27 0.74
----------------------------------------------------------------------------
Total operating
expenses $ 46.88 $ 35.81 $ 11.07 $ 38.80 $ 35.42 $ 3.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(GJs per barrel of
SCO)
----------------------------------------------------------------------------
Purchased energy
consumption 1.69 1.31 0.38 1.44 1.10 0.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the fourth quarter of 2011, operating expenses were $393 million, averaging $46.88 per barrel, compared with $378 million, or $35.81 per barrel, in the fourth quarter of 2010. For the full year 2011, operating expenses increased about eight per cent to $1,501 million, or $38.80 per barrel, in 2011 from $1,387 million, or $35.42 per barrel, in 2010.
The increase in operating expenses for the full year 2011 relative to 2010 was primarily due to:
-- increased costs for maintenance, primarily in tailings management and
extraction; and
-- increased diesel costs. New low-sulphur regulations that went into
effect in mid-2010 have reduced the amount of diesel that Syncrude can
produce internally for use in its operations, resulting in increased
diesel purchases; however, bitumen redirected from diesel production to
SCO largely offsets the operating expense impact, resulting in an
immaterial impact on net income. In addition, diesel prices were higher
in 2011 relative to 2010.
The increased diesel purchases are also reflected in the increased purchased energy consumption rate in 2011 relative to 2010.
Operating expenses on a per barrel basis are affected by the Corporation's sales volumes, which were lower in the fourth quarter and full year 2011 relative to the comparative 2010 periods.
Non-Production Expenses
Non-production expenses were $27 million in the fourth quarter of 2011, similar to the fourth quarter of 2010 when non-production costs totalled $24 million. On an annual basis, non-production costs totalled $113 million in 2011 compared with $105 million in 2010.
Non-production expenses consist primarily of development expenditures relating to capital programs, which are expensed, such as pre-feasibility engineering, technical and support services, research and development, evaluation drilling and regulatory and stakeholder consultation expenditures. Non-production expenses can vary on a periodic basis depending on the number of projects underway and the development stage of the projects.
Net Finance Expense
Three Months
Ended Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Interest costs $ 20 $ 21 $ 87 $ 91
Less capitalized interest (18) (10) (57) (30)
----------------------------------------------------------------------------
Interest expense 2 11 30 61
Accretion of asset retirement obligation 4 5 16 21
----------------------------------------------------------------------------
Net finance expense $ 6 $ 16 $ 46 $ 82
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest costs in 2011 were largely unchanged from 2010. However, interest expense was lower in 2011 because a higher portion of interest costs were capitalized in 2011 as cumulative capital expenditures on qualifying assets rose. As such, net finance expense decreased to $6 million and $46 million in the fourth quarter and full year 2011, respectively, from $16 million and $82 million in the comparative 2010 periods.
Depreciation and Depletion Expense
Depreciation and depletion expense totalled $96 million for the fourth quarter of 2011 and $381 million for the full year 2011 compared with $111 million and $429 million, respectively, for the comparative periods in 2010, reflecting changes made during 2011 to the estimated useful lives of certain assets.
Foreign Exchange (Gain) Loss
Three Months
Ended Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Foreign exchange (gain) loss - long-term
debt $ (24) $ (39) $ 25 $ (58)
Foreign exchange (gain) loss - other 1 4 (3) (2)
----------------------------------------------------------------------------
Total foreign exchange (gain) loss $ (23) $ (35) $ 22 $ (60)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 fourth quarter of 2011 were the result of a strengthening in the value of the Canadian dollar relative to the U.S. dollar from $0.96 U.S./Cdn at September 30, 2011 to $0.98 U.S./Cdn at December 31, 2011. Conversely, the foreign exchange losses on long-term debt for the full year 2011 were the result of a weakening in the value of the Canadian dollar relative to the U.S. dollar from $1.01 U.S./Cdn at December 31, 2010. The foreign exchange gains in the fourth quarter and full year 2010 were the result of a strengthening in the value of the Canadian dollar relative to the U.S. dollar to $1.01 U.S./Cdn at December 31, 2010 from $0.97 U.S./Cdn at September 30, 2010 and $0.96 U.S./Cdn at December 31, 2009.
Deferred Taxes
Canadian Oil Sands recorded deferred tax expenses of $70 million and $387 million in the fourth quarter and full year 2011, respectively, versus recoveries of $240 million and $289 million in the comparative 2010 periods. Prior to December 31, 2010, income was sheltered from current taxes by the payment of distributions to trust unitholders. As such, there were no significant drawdowns of tax pools or a resulting deferred tax expense in 2010. Upon conversion from an income trust to a corporate structure effective December 31, 2010, Canadian Oil Sands' earnings are sheltered from current taxes through the drawdown of tax pools. A deferred tax expense has been recognized in 2011 to reflect the cost of consuming these pools.
The 2010 deferred tax recovery incorporates the $269 million re-measurement of the corporation's deferred tax liability at a lower tax rate upon conversion to a corporation. While Canadian Oil Sands was structured as an income trust, deferred taxes were measured using the 39 per cent individual tax rate applicable to earnings not distributed to trust unitholders. Beginning December 31, 2010, deferred taxes are measured using the 25 per cent corporate tax rate.
Asset Retirement Obligation
Canadian Oil Sands' increased its estimated asset retirement obligation during the fourth quarter of 2011 to $1,037 million at December 31, 2011 from $545 million at September 30, 2011 and $501 million at December 31, 2010. The increase was capitalized as property, plant and equipment and reflects the fourth quarter completion of a comprehensive mine development and closure plan including:
-- the reclamation of new storage areas and additional mature fine tailings
treatment costs, both required to meet the Alberta Energy Resources
Conservation Board's Directive 074 regulations;
-- geotechnical design development for regional land drainage features
required for final closure;
-- updated material handling cost assumptions, which reflect current
contract rates and parameters; and
-- a decrease in the risk-free interest rate used to discount future
reclamation payments.
The obligation also reflects $14 million and $49 million of reclamation spending during the three months and year ended December 31, 2011, respectively. A $29 million current portion of the asset retirement obligation is included in accounts payable and accrued liabilities, while the $1,008 million non-current portion is separately presented as an asset retirement obligation on the Consolidated Balance Sheet.
Pension and Other Post-Employment Benefit Plans
The Corporation's share of the estimated unfunded portion of Syncrude Canada's pension and other post-employment benefit plans increased to $465 million at December 31, 2011 from $397 million at September 30, 2011 and $327 million at December 31, 2010. The change reflects a decrease in the interest rate used to discount estimated future pension costs combined with lower than estimated returns on the pension plan assets. For the fourth quarter of 2011, a $56 million actuarial loss, net of $18 million in deferred taxes, has been recognized in other comprehensive income to reflect these estimate changes and a $128 million actuarial loss, net of $42 million in deferred taxes, has been recognized for the full year 2011. A liability for the $465 million unfunded balance is recognized on the December 31, 2011 Consolidated Balance Sheet.
CAPITAL EXPENDITURES
Capital expenditures totalled $643 million in 2011 compared with $582 million in 2010. In the fourth quarter of 2011, capital expenditures totalled $205 million compared with $189 million in the fourth quarter of 2010. Syncrude is investing in a number of major projects in 2011 through 2014 to support strong, stable production while achieving operational efficiencies and improving environmental performance. These projects include the following:
-- The Syncrude Emissions Reduction ("SER") project, which accounted for
$110 million and $113 million of the capital spent in 2011 and 2010,
respectively. The SER project commenced in 2006 and involves
retrofitting technology into the operation of Syncrude's original two
cokers in order to reduce total sulphur dioxide and other emissions.
-- Mine train replacement and relocation projects, which accounted for $166
million and $73 million of the capital spent in 2011 and 2010,
respectively. These projects involve reconstructing or relocating
crushers, surge facilities and slurry preparation equipment to support
mine development and tailings storage.
-- The Aurora North Tailings Management project, which accounted for $40
million and $19 million of the capital spent in 2011 and 2010,
respectively. This project involves the construction of a composite
tails plant at the Aurora North mine to process tailings in support of
Syncrude's reclamation efforts.
Capital expenditures also included:
-- Capitalized interest costs, which were $57 million in 2011 compared with
$30 million in 2010, reflecting higher cumulative capital expenditures
on qualifying assets in 2011.
-- Capitalized turnaround costs, which were $44 million in 2011 compared
with $46 million in 2010.
The remaining capital expenditures related to regular maintenance of business and other investment activities, including relocation of tailings facilities and other infrastructure projects.
On an annual basis, capital expenditures were $284 million lower than the $927 million original budget due primarily to adjustments to the expected timing of spending on major projects. The expected completion dates for these major projects is not affected. More information on Canadian Oil Sands' major capital projects is provided in the "Outlook" section of this MD&A.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
Contractual obligations are summarized in Canadian Oil Sands' 2010 annual MD&A and include future cash payments that the Corporation is required to make under existing contractual arrangements entered into directly or as a 36.74 per cent owner in Syncrude. During 2011, Canadian Oil Sands entered into a new contractual obligation for approximately $700 million for the transportation of crude oil, and has assumed its share of new Syncrude capital commitments of approximately $300 million primarily related to the major projects discussed in the Outlook section of this MD&A. There have been no other significant new contractual obligations or commitments relative to the 2010 year-end disclosure.
DIVIDENDS
On February 1, 2012, the Corporation declared a quarterly dividend of $0.30 per Share for a total dividend of approximately $145 million. The dividend will be paid on February 29, 2012 to Shareholders of record on February 24, 2012.
Dividend payments continue to be set on a quarterly basis in the context of current and expected crude oil prices, economic conditions, Syncrude's operating performance, and the Corporation's capacity to finance operating and investing obligations. Dividend levels are established with the intent of absorbing short-term market volatility over several quarters. Dividend levels also recognize our intention to fund the current major projects primarily through cash flow from operations, and to maintain a strong balance sheet to reduce exposure to potential oil price declines, capital cost increases, or major operational upsets.
For 2012, Canadian Oil Sands is targeting a quarterly dividend of at least $0.30 per Share, based on current assumptions with support from our cash balances, as necessary.
LIQUIDITY AND CAPITAL RESOURCES
December 31 December 31
($ millions) 2011 2010
----------------------------------------------------------------------------
Long-term debt $ 1,132 $ 1,251
Cash and cash equivalents (718) (80)
----------------------------------------------------------------------------
Net debt 1,2 $ 414 $ 1,171
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Shareholders' equity $ 4,210 $ 3,726
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total capitalization 1,3 $ 4,624 $ 4,897
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----------------------------------------------------------------------------
Net debt to total capitalization 1,4 (%) 9 24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net debt, total capitalization, and net debt to total capitalization are
non-GAAP measures.
(2) Long-term debt less cash and cash equivalents.
(3) Net debt plus Shareholders' equity.
(4) Net debt divided by total capitalization.
Net debt, comprised of long-term debt less cash and cash equivalents, decreased to $0.4 billion at December 31, 2011 from $1.2 billion at December 31, 2010, as Canadian Oil Sands generated $1.9 billion in cash flow from operations in 2011 while capital expenditures and dividend payments were $0.6 billion and $0.5 billion, respectively.
Shareholders' equity increased to $4.2 billion at December 31, 2011 from $3.7 billion at December 31, 2010, as net income exceeded dividends in 2011.
On June 1, 2011, Canadian Oil Sands entered into a four-year $1,500 million credit facility agreement expiring on June 1, 2015, which replaced the $800 million operating facility.
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. 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 $11 billion with 484.5 million shares outstanding and a closing price of $23.25 per Share on December 31, 2011. The following table reflects the trading activity for the fourth quarter of 2011.
Canadian Oil Sands Limited - Trading Activity
Fourth
Quarter October November December
2011 2011 2011 2011
----------------------------------------------------------------------------
Share price
High $ 24.50 $ 24.50 $ 23.08 $ 23.31
Low $ 18.17 $ 18.17 $ 19.16 $ 20.03
Close $ 23.25 $ 23.10 $ 21.45 $ 23.25
Volume of Shares traded (millions) 146.2 38.7 54.7 52.8
Weighted average Shares
outstanding (millions) 484.5 484.5 484.5 484.5
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FINANCIAL RISK MANAGEMENT
The Corporation did not have any financial derivatives outstanding at December 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 currency exchange rates. Over the last three years, daily WTI prices have experienced significant volatility, ranging from U.S. $114 per barrel to U.S. $34 per barrel. In addition, supply, demand, and other market factors can vary significantly between regions and, as a result, the spreads between crude oil benchmarks, such as WTI, Brent and LLS, can be volatile.
Canadian Oil Sands prefers to remain unhedged on crude oil prices; however, during periods of significant capital spending and financing requirements, management may hedge prices to reduce cash flow volatility. The Corporation did not have any crude oil price hedges in place during 2011 or 2010; instead, a strong balance sheet was used to mitigate the risk around crude oil price movements. As at February 1, 2012, and based on current expectations, the Corporation remains unhedged 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 sales generated are based on a WTI benchmark price in U.S. dollars while operating expenses and capital expenditures are denominated primarily in Canadian dollars. Our sales 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 sales receipts we collect 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 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 December 31, 2011, there were no amounts drawn on the credit facilities ($145 million - December 31, 2010, $nil - January 1, 2010) and the next long-term debt maturity is in August 2013. The Corporation did not have a significant exposure to interest rate risk based on the amount of floating rate debt or the short-term nature of investments outstanding during the three months or year ended December 31, 2011.
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, the $1.5 billion credit facility does not expire until June 2015, and Canadian Oil Sands held cash balances totalling $718 million at December 31, 2011, resulting in low liquidity risk.
Credit Risk
Canadian Oil Sands is exposed to credit risk primarily through customer accounts receivable balances, financial counterparties with whom the Corporation has invested its cash and cash equivalents, 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 on some counterparties 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, 2011 was due from investment grade energy producers, financial institutions, and refinery-based customers.
At December 31, 2011, our cash and cash equivalents were invested in deposits and Bankers' Acceptances with high-quality senior banks as well as investment grade commercial paper. As of February 1, 2012, 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 2011.
NEW ACCOUNTING STANDARDS
In May 2011, the International Accounting Standards Board ("IASB") issued IFRS 11, Joint Arrangements, to replace International Accounting Standard ("IAS") 31, Interests in Joint Ventures, IFRS 10, Consolidated Financial Statements, and IFRS 12, Disclosure of Interests in Other Entities, and IFRS 13, Fair Value Measurements, effective for years beginning on or after January 1, 2013 with earlier application permitted. IFRS 11 eliminates the accounting policy choice between proportionate consolidation and equity method accounting for joint ventures available under IAS 31 and, instead, mandates one of these two methodologies based on the economic substance of the joint arrangement. IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements. IFRS 12 requires entities to disclose information about the nature of their interests in joint ventures and IFRS 13 defines, and establishes a framework for measuring, fair value.
In June 2011, the IASB issued an amendment to IAS 19, Employee Benefits, to address the accounting and disclosure of defined benefit pension plans effective for years beginning on or after January 1, 2013 with earlier application permitted.
In October 2011, the IASB issued International Financial Reporting Interpretations Committee ("IFRIC") Interpretation 20, Stripping Costs in the Production Phase of a Surface Mine, which clarifies the accounting for costs associated with waste removal in surface mining effective for years beginning on or after January 1, 2013 with earlier application permitted.
Canadian Oil Sands has not applied any of these new standards as of December 31, 2011. We continue to assess their impact and, at this time, do not anticipate any of them to result in significant accounting or disclosure changes.
2012 OUTLOOK
As of As of
(millions of Canadian dollars, except volume and per February December
barrel amounts) 1, 2012 8, 2011
----------------------------------------------------------------------------
Operating assumptions
Syncrude production (mmbbls) 113 113
Canadian Oil Sands sales (mmbbls) 41.5 41.5
Sales, net of crude oil purchases and transportation $ 3,813 $ 3,684
Operating expenses $ 1,516 $ 1,526
Operating expenses per barrel $ 36.52 $ 36.75
Crown royalties $ 253 $ 212
Cash flow from operations $ 1,825 $ 1,725
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Capital expenditure assumptions
Major projects $ 974 $ 974
Regular maintenance $ 405 $ 405
Capitalized interest $ 81 $ 81
Total capital expenditures $ 1,460 $ 1,460
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Business environment assumptions
West Texas Intermediate (U.S.$/bbl) $ 90.00 $ 85.00
Premium (Discount) to average Cdn$ WTI prices (Cdn$/bbl) $ - $ 2.00
Foreign exchange rate (U.S.$/Cdn$) $ 0.98 $ 0.98
AECO natural gas (Cdn$/GJ) $ 3.50 $ 3.75
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----------------------------------------------------------------------------
In its February 1, 2012 Outlook, Canadian Oil Sands continues to estimate annual Syncrude production of 113 million barrels (309,000 barrels per day) with a range of 106 to 117 million barrels for 2012. Net to Canadian Oil Sands, this is equivalent to 41.5 million barrels (113,000 barrels per day). The production outlook incorporates a turnaround of Coker 8-3 in the second quarter of the year, as originally planned, and maintenance on Coker 8-1, beginning in early February. The 113 million barrel single-point estimate represents a 7.7 million barrel, or approximately seven per cent, increase over Syncrude's actual 2011 production.
Sales, net of crude oil purchases and transportation expense, are estimated to be approximately $3.8 billion, reflecting our 41.5 million barrel production estimate and a $92 per barrel sales price. The sales price assumes an average U.S. $90 per barrel WTI crude oil price, a $0.98 U.S./Cdn foreign exchange rate, and no SCO premium/discount to Canadian dollar WTI.
We are estimating operating expenses of approximately $1.5 billion in 2012, comprised of approximately $1.3 billion in production costs and $0.2 billion in purchased energy costs. The purchased energy costs reflect a $3.50 per gigajoule ("GJ") natural gas price assumption and a consumption rate of about one GJ per barrel of SCO produced. Based on our production assumption, this translates to operating expenses of $36.52 per barrel, a decrease from 2011 operating expenses of $38.80 per barrel.
Non-production expenses are estimated to rise by approximately $33 million over 2011 to $146 million due to a higher 2012 capital program. Also, mainly as a result of the higher capital program, 2012 Crown royalties are expected to be $54 million lower than 2011, totalling about $253 million.
Capital expenditures are estimated to total $1,460 million in 2012, comprised of $974 million of spending on major projects, $405 million in regular maintenance of the business and other projects, and $81 million in capitalized interest.
Current taxes are estimated to total $30 million in 2012. Based on the assumptions in our Outlook, Canadian Oil Sands expects to record deferred taxes of approximately 15 per cent to 20 per cent of (pre-tax) cash flow from operations in 2012, which are expected to flow through current taxes and cash flow from operations in 2013.
Based on these inputs, Canadian Oil Sands is estimating cash flow from operations of $1,825 million, or $3.77 per Share, in 2012. After deducting forecast 2012 capital expenditures, we estimate $365 million in remaining cash flow from operations for the year, or $0.75 per Share.
Net debt is expected to rise during 2012 as cash balances are used to fund a portion of capital expenditures and dividends. Our 2011 results have positioned Canadian Oil Sands to manage risk associated with a rising capital program and an uncertain outlook for the global economy, thereby providing some stability to our dividend level, which is set quarterly by our Board of Directors. For 2012, we are targeting a quarterly dividend of at least $0.30 per Share, based on current assumptions with support from our cash balances, as necessary.
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.
Outlook Sensitivity Analysis (February 1, 2012)
Cash Flow from
Operations
Increase
Variable (1) Annual Sensitivity $ millions $/Share
---------------------------------------------------------------------------
Syncrude operating expenses decrease Cdn$1.00/bbl $ 34 $ 0.07
Syncrude operating expenses decrease Cdn$50 million $ 15 $ 0.03
WTI crude oil price increase U.S.$1.00/bbl $ 35 $ 0.07
Syncrude production increase 2 million bbls $ 56 $ 0.12
Canadian dollar weakening U.S.$0.01/Cdn$ $ 32 $ 0.07
AECO natural gas price decrease Cdn$0.50/GJ $ 19 $ 0.04
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(1) 2012 cash flow from operations sensitivities are not expected to be
significantly impacted by income taxes. However, in 2012, Canadian Oil
Sands will record deferred taxes of approximately 15 per cent to 20 per
cent of cash flow from operations before taxes that are expected to flow
through current tax current tax expense and cash flow from operations in
2013.
The 2012 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 Projects
The following tables provide cost and schedule estimates for Syncrude's major projects that have reached a sufficient stage of design definition. Cost estimates do not include estimates for the centrifuge plant at Mildred Lake, which will be provided when details on the scope have been refined. Regular maintenance capital costs post 2012 are provided on an annual basis with the budget for the following year, and are currently estimated to average approximately $10 per barrel over the next few years.
Major Projects (1) - Total Project Cost and Schedule Estimates (2)
Spent to Total Cost
Dec. 31, 2011 Estimate
($ billions) ($ billions)
----------------------------------------------------------------------------
Syncrude Emissions Reduction (SER) Syncrude $ 1.4 $ 1.6
Retrofit technology into Syncrude's
original two cokers to reduce total
sulphur dioxide and other emissions COS share 0.5 0.6
Mildred Lake Mine Train Replacement Syncrude 0.5 4.2
Reconstruct crushers, surge facilities,
and slurry prep facilities to support
tailings storage requirements COS share 0.2 1.6
Aurora North Mine Train Relocation Syncrude 0.2 0.9
Relocate crushers, surge facilities,
and slurry prep facilities to support
tailings storage requirements COS share 0.1 0.3
Aurora North Tailings Management Syncrude 0.2 0.8
Construct composite tails (CT) plant at
the Aurora North mine COS share 0.1 0.3
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Total Syncrude $ 2.3 $ 7.5
COS share 0.9 2.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Target
Estimated % In-Service
Accuracy Date
----------------------------------------------------------------------------
Syncrude Emissions Reduction (SER) Syncrude +5%/-5% Q2 2012
Retrofit technology into Syncrude's
original two cokers to reduce total
sulphur dioxide and other emissions COS share
Mildred Lake Mine Train Replacement Syncrude +15%/-15% Q4 2014
Reconstruct crushers, surge facilities,
and slurry prep facilities to support
tailings storage requirements COS share
Aurora North Mine Train Relocation Syncrude +25%/-25% Q1 2014
Relocate crushers, surge facilities,
and slurry prep facilities to support
tailings storage requirements COS share
Aurora North Tailings Management Syncrude +25%/-25% Q4 2013
Construct composite tails (CT) plant at
the Aurora North mine COS share
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Total Syncrude
COS share
----------------------------------------------------------------------------
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Major Projects (1) - Annual Spending Profile (2)
Spent to
Dec. 31, 2011 2012 2013 2014 Total
($ billions) ($ billions) ($ billions) ($ billions) ($ billions)
----------------------------------------------------------------------------
Syncrude $ 2.3 $ 2.1 $ 2.0 $ 1.1 $ 7.5
Canadian
Oil Sands
share $ 0.9 $ 0.8 $ 0.7 $ 0.4 $ 2.8
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(1) Major projects include the Syncrude Emissions Reduction (SER) project,
Mildred Lake Mine Train Replacement, Aurora North Mine Train Relocation and
Aurora North Tailings Management. Major projects do not include projects
that have not reached sufficient design definition, such as the centrifuge
plant at Mildred Lake.
(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 projects primarily through cash flow from operations.
The major projects tables contain forward-looking information and users of this information are cautioned that the actual yearly and total major project costs and the actual in-service dates for the major projects may vary from the plans disclosed. The major project cost estimates and major project target in-service dates are based on current 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 major project costs and the major project target in-service dates 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 Year Ended
December 31 December 31
($ millions, except per
Share and Share volume
amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
Sales $ 973 $ 936 $ 4,182 $ 3,460
Crown royalties (Note
13) (73) (75) (307) (306)
----------------------------------------------------
Revenues 900 861 3,875 3,154
----------------------------------------------------
Expenses
Operating 393 378 1,501 1,387
Non-production 27 24 113 105
Crude oil purchases and
transportation 89 24 248 280
Administration 8 7 25 20
Insurance 2 1 8 11
Depreciation and
depletion 96 111 381 429
----------------------------------------------------
615 545 2,276 2,232
----------------------------------------------------
Earnings from operating
activities 285 316 1,599 922
Foreign exchange (gain)
loss (23) (35) 22 (60)
Net finance expense
(Note 11) 6 16 46 82
----------------------------------------------------
Earnings before taxes 302 335 1,531 900
Deferred tax expense
(recovery) 70 (240) 387 (289)
----------------------------------------------------
Net income 232 575 1,144 1,189
Other comprehensive
loss, net of income
taxes
Actuarial loss on
employee future
benefits plans (56) (54) (128) (61)
Reclassification of
derivative gains to
net income (1) (1) (3) (3)
----------------------------------------------------
Comprehensive income $ 175 $ 520 $ 1,013 $ 1,125
----------------------------------------------------
----------------------------------------------------
Weighted average Shares
(millions) 485 484 485 484
Shares, end of period
(millions) 485 484 485 484
Net income per Share:
Basic and diluted $ 0.48 $ 1.19 $ 2.36 $ 2.46
See Notes to Unaudited
Consolidated Financial
Statements
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(unaudited)
Three Months Ended Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Retained earnings
Balance, beginning of
period $ 1,487 $ 755 $ 1,034 $ 802
Net income 232 575 1,144 1,189
Actuarial loss (56) (54) (128) (61)
Dividends (146) (242) (533) (896)
----------------------------------------------------
Balance, end of period 1,517 1,034 1,517 1,034
----------------------------------------------------
Accumulated other
comprehensive income
Balance, beginning of
period 13 16 15 18
Reclassification of
derivative gains to
net income (1) (1) (3) (3)
----------------------------------------------------
Balance, end of period 12 15 12 15
----------------------------------------------------
Shareholders' capital
Balance, beginning of
period 2,672 2,671 2,671 2,671
Issuance of shares 1 - 2 -
----------------------------------------------------
Balance, end of period 2,673 2,671 2,673 2,671
----------------------------------------------------
Contributed surplus
Balance, beginning of
period 7 - 6 -
Share-based
compensation 1 6 2 6
----------------------------------------------------
Balance, end of period 8 6 8 6
----------------------------------------------------
Total Shareholders'
equity $ 4,210 $ 3,726 $ 4,210 $ 3,726
----------------------------------------------------
----------------------------------------------------
See Notes to Unaudited
Consolidated Financial
Statements
CONSOLIDATED BALANCE SHEETS
(unaudited)
As at December 31 December 31 January 1
($ millions) 2011 2010 2010
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash
equivalents $ 718 $ 80 $ 122
Accounts
receivable 376 379 354
Inventories 142 129 133
Prepaid expenses 10 6 7
---------------------------------------------------------
1,246 594 616
Property, plant and
equipment, net
(Note 6) 7,227 6,396 6,265
Exploration and
evaluation 89 89 89
Reclamation trust 58 53 48
---------------------------------------------------------
$ 8,620 $ 7,132 $ 7,018
---------------------------------------------------------
---------------------------------------------------------
LIABILITIES AND
SHAREHOLDERS'
EQUITY
Current liabilities
Accounts payable
and accrued
liabilities $ 479 $ 405 $ 284
Current portion of
employee future
benefits 47 51 17
---------------------------------------------------------
526 456 301
Employee future
benefits and other
liabilities 480 316 284
Long-term debt 1,132 1,251 1,163
Asset retirement
obligation (Note
9) 1,008 464 550
Deferred taxes 1,264 919 1,229
---------------------------------------------------------
4,410 3,406 3,527
Shareholders'
equity 4,210 3,726 3,491
---------------------------------------------------------
$ 8,620 $ 7,132 $ 7,018
---------------------------------------------------------
---------------------------------------------------------
Commitment (Note
12), Contingency
(Note 13)
See Notes to
Unaudited
Consolidated
Financial
Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Ended Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash from (used in)
operating activities
Net income $ 232 $ 575 $ 1,144 $ 1,189
Items not requiring an
outlay of cash
Depreciation and depletion 96 111 381 429
Accretion of asset
retirement obligation 4 5 16 21
Foreign exchange (gain)
loss on long-term debt (24) (39) 25 (58)
Deferred tax expense
(recovery) 70 (240) 387 (289)
Other (1) - 2 (3)
Actual reclamation
expenditures (Note 9) (14) (17) (49) (48)
Change in employee future
benefits and other
liabilities - 3 (9) (9)
------------------------------------------------
363 398 1,897 1,232
Change in non-cash working
capital (47) (150) 61 63
------------------------------------------------
Cash from operating
activities 316 248 1,958 1,295
------------------------------------------------
Cash from (used in)
financing activities
Net drawdown (repayment)
of bank credit facilities - 145 (145) 145
Issuance of shares 1 - 2 -
Dividends (146) (242) (533) (896)
------------------------------------------------
Cash used in financing
activities (145) (97) (676) (751)
------------------------------------------------
Cash from (used in)
investing activities
Capital expenditures (205) (189) (643) (582)
Reclamation trust funding (1) (1) (5) (5)
Change in non-cash working
capital (17) (8) 4 1
------------------------------------------------
Cash used in investing
activities (223) (198) (644) (586)
------------------------------------------------
Increase (decrease) in cash
and cash equivalents (52) (47) 638 (42)
Cash and cash equivalents,
beginning of period 770 127 80 122
------------------------------------------------
Cash and cash equivalents,
end of period $ 718 $ 80 $ 718 $ 80
------------------------------------------------
------------------------------------------------
Cash and cash equivalents
consist of:
Cash $ 326 $ 52 $ 326 $ 52
Short-term investments 392 28 392 28
------------------------------------------------
$ 718 $ 80 $ 718 $ 80
------------------------------------------------
------------------------------------------------
Supplementary Information
(Note 14)
See Notes to Unaudited
Consolidated Financial
Statements
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS AND YEAR ENDED DECEMBER 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 the Corporation refers to common shares or Shares, Shareholders and dividends, which were formerly referred to as Units, Unitholders and distributions under the trust structure.
These interim unaudited 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 is 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 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 equity, 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, outstanding and effective as of February 1, 2012. As disclosed in Note 14, Canadian Oil Sands has not early-adopted any of the IFRS issued and outstanding but not yet effective. 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.
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 mine development and asset retirement 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:
Category Estimated Useful Life
----------------------------------------------------------------------------
Major turnarounds 2 to 3 years
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
Capitalized major turnaround costs are depreciated over the estimated period to the next turnaround.
Costs of assets under construction are capitalized as construction in progress. Construction in progress is not depreciated. On completion, the cost of construction in progress, including capitalized interest, is transferred to the appropriate category of PP&E and depreciated accordingly.
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 which is 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 of 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 provides for the site restoration of each mine site and the decommissioning of utilities plants, bitumen extraction plants, and the upgrading complex. The discounted amount of these future restoration and decommissioning (collectively "reclamation") expenditures 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 expenditures, and discounting them 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 payments reduce 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. Sales also include gains and losses, if any, from crude oil hedge contracts designated as hedges for accounting purposes. Sales are presented before Crown royalties whereas revenues are presented net of Crown royalties.
Employee Future Benefits
Canadian Oil Sands accrues its proportionate share of obligations as a joint interest owner in respect of Syncrude Canada's post-employment benefit obligations, which include defined benefit and 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 also 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 enactment or 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 PSUs 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 ("Phantom Units") Plan and an Incentive Restricted Share Units ("Restricted Units") Plan, 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 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
expenditures 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 expenditures, the timing of when they
will be required, and then apply an appropriate risk-free interest rate.
Given the long reserve life of Syncrude's leases, the expenditures will
be made over approximately the next 70 years; as such, it is difficult
to estimate their precise timing and amount.
Any changes in the anticipated timing or the amount of the expenditures
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 $1,037 million at
December 31, 2011 (December 31, 2010 - $501 million, January 1, 2010 -
$550 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. 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 one per cent decrease in the interest rate
used to discount the projected benefit obligation would result in an
approximate $175 million increase in Canadian Oil Sands' share of the
employee future benefits liability, while a one per cent increase in the
interest rate would result in an approximate $135 million decrease in
Canadian Oil Sands' share of the 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 $465 million at December 31, 2011
(December 31, 2010 - $327 million, January 1, 2010 - $281 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 expense in the period of retirement or
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 $1,262 million at
December 31, 2011 (December 31, 2010 - $919 million, January 1, 2010 -
$1,229 million).
5. TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS
The impact of the transition to IFRS is summarized in this note as follows:
a) Transition Exceptions and Exemptions
b) Reconciliation of Assets, Liabilities and Shareholders' Equity as previously reported under Canadian GAAP to IFRS
c) Reconciliation of Net Income and Comprehensive Income as previously reported under Canadian GAAP to IFRS
d) Reconciliation of Cash Flows as previously reported under Canadian GAAP to IFRS
e) Notes to the reconciliations
a. Transition Exceptions and Exemptions
Canadian Oil Sands has applied the following transition exceptions and exemptions to full retrospective application of IFRS:
Exception / As described in Note
exemption Description 5 (e)
----------------------------------------------------------------------------
Capitalization of Exempt all interest costs incurred (ii)
interest costs prior to January 1, 2010 from
capitalization
Asset retirement Apply prescribed method to estimate (iii)
obligation January 1, 2010 net book value of
asset retirement obligation's cost
capitalized in PP&E
Employee future Record previously unrecognized (iv)
benefits actuarial losses on defined benefit
pension plan through January 1, 2010
retained earnings
Business Exempt pre-January 1, 2010 business
combinations combinations from re-measurement
Leases Exempt all leases assessed under
Canadian GAAP from re-assessment
b. Reconciliations of Assets, Liabilities and Shareholders' Equity as
previously reported under Canadian GAAP to IFRS
December 31 January 1
($ millions) Note 2010 2010
----------------------------------------------------------------------------
Assets - Canadian GAAP $ 7,016 $ 6,953
Property, plant and equipment -
Canadian GAAP $ 6,369 $ 6,289
Capitalization of turnaround
costs (i) 52 46
Capitalization of interest costs (ii) 30 -
Asset retirement obligation (iii) 34 19
Reclass to exploration and
evaluation (viii) (89) (89)
------------------------------
Property, plant and equipment -
IFRS $ 6,396 $ 6,265
Exploration and evaluation -
Canadian GAAP $ - $ -
Reclass from property, plant and
equipment (viii) 89 89
------------------------------
Exploration and evaluation - IFRS $ 89 $ 89
------------------------------
Assets - IFRS $ 7,132 $ 7,018
------------------------------
------------------------------
Liabilities - Canadian GAAP $ (3,058) $ (2,984)
Employee future benefits and other
liabilities- Canadian GAAP $ (67) $ (104)
Defined benefit pension plan (iv) (240) (166)
Cash settled share-based awards (v) (9) (7)
Equity settled share-based awards (vi) - (7)
------------------------------
Employee future benefits and other
liabilities - IFRS $ (316) $ (284)
Asset retirement obligation -
Canadian GAAP $ (286) $ (389)
Asset retirement obligation (iii) (178) (161)
------------------------------
Asset retirement obligation - IFRS $ (464) $ (550)
Deferred taxes - Canadian GAAP $ (998) $ (1,027)
Deferred taxes (vii) 79 (202)
------------------------------
Deferred taxes - IFRS $ (919) $ (1,229)
------------------------------
Liabilities - IFRS $ (3,406) $ (3,527)
------------------------------
------------------------------
Shareholders' Equity - Canadian GAAP $ (3,958) $ (3,969)
Retained earnings - Canadian GAAP $ (1,349) $ (1,359)
Capitalization of turnaround
costs (i) (52) (46)
Capitalization of interest costs (ii) (30) -
Asset retirement obligation (iii) 144 142
Defined benefit pension plan (iv) 240 166
Cash settled share-based awards (v) 9 7
Reclass equity settled share-
based awards (vi) 84 84
Equity settled share-based awards (vi) (1) 2
Deferred taxes (vii) (79) 202
------------------------------
Retained earnings - IFRS $ (1,034) $ (802)
Shareholders' capital - Canadian
GAAP $ (2,587) $ (2,587)
Reclass equity settled share-
based awards (vi) (84) (84)
------------------------------
Shareholders' capital - IFRS $ (2,671) $ (2,671)
Contributed surplus - Canadian GAAP $ (7) $ (5)
Equity settled share-based awards (vi) 1 5
------------------------------
Contributed surplus - IFRS $ (6) $ -
------------------------------
Shareholders' Equity - IFRS $ (3,726) $ (3,491)
------------------------------
------------------------------
c. Reconciliations of Net Income and Comprehensive Income as previously
reported under Canadian GAAP to IFRS
Three months
Year ended ended
December 31 December 31
($ millions) Note 2010 2010
----------------------------------------------------------------------------
Net income - Canadian GAAP $ 886 $ 311
Operating expenses - Canadian GAAP $ (1,439) $ (394)
Capitalization of turnaround
costs (i) 46 16
Actuarial losses on defined
benefit pension plan (iv) 8 2
Cash settled share-based awards (v) (2) (2)
------------------------------
Operating expenses - IFRS $ (1,387) $ (378)
Depreciation and depletion expense
- Canadian GAAP $ (408) $ (106)
Capitalization of turnaround
costs (i) (40) (9)
Increase in depletion of asset
retirement obligation's cost (6) (2)
Reclass accretion of asset
retirement obligation to (x) 25 6
net finance expense
------------------------------
Depreciation and depletion expense
- IFRS $ (429) $ (111)
Interest expense - Canadian GAAP $ (91) $ (21)
Capitalization of interest costs (ii) 30 10
Decrease in accretion of asset
retirement obligation 4 1
Reclass accretion of asset
retirement obligation from (x) (25) (6)
depreciation and depletion
expense
------------------------------
Net finance expense - IFRS $ (82) $ (16)
Administration expense - Canadian
GAAP $ (23) $ (6)
Equity settled share-based awards (vi) 3 (1)
------------------------------
Administration expense - IFRS $ (20) $ (7)
Deferred tax recovery (expense) -
Canadian GAAP $ 29 $ (9)
Deferred taxes (vii) 260 249
------------------------------
Deferred tax recovery - IFRS $ 289 $ 240
------------------------------
Net income - IFRS $ 1,189 $ 575
------------------------------
------------------------------
Comprehensive income - Canadian GAAP $ 883 $ 310
Other comprehensive loss - Canadian
GAAP $ (3) $ (1)
Actuarial losses on defined
benefit pension plan (iv) (61) (54)
------------------------------
Other comprehensive loss - IFRS $ (64) $ (55)
Sum of net income adjustments above $ 303 $ 264
------------------------------
Comprehensive income - IFRS $ 1,125 $ 520
------------------------------
------------------------------
d. Reconciliation of Cash Flows as previously reported under Canadian GAAP
to IFRS
Three months
Year ended ended
December 31 December 31
($ millions) Note 2010 2010
----------------------------------------------------------------------------
Cash from operating activities -
Canadian GAAP $ 1,219 $ 222
Capitalization of turnaround costs (i) 46 16
Capitalization of interest costs (ii) 30 10
------------------------------
Cash from operating activities - IFRS $ 1,295 $ 248
------------------------------
------------------------------
Cash used in investing activities -
Canadian GAAP $ (510) $ (172)
Capitalization of turnaround costs (i) (46) (16)
Capitalization of interest costs (ii) (30) (10)
------------------------------
Cash used in investing activities -
IFRS $ (586) $ (198)
------------------------------
------------------------------
e. Notes to the Reconciliations
i. Capitalization of turnaround costs
Under Canadian GAAP, turnaround costs were expensed as operating expenses when 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 December 31, 2010, the capitalization of turnaround costs under IFRS resulted in a $16 million decrease in operating expenses and a $9 million increase in depreciation and depletion. Expenditures of $16 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 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 $52 million higher under IFRS relative to Canadian GAAP 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 December 31, 2010, the capitalization of interest costs under IFRS resulted in a $10 million decrease in interest expense with a corresponding increase in property, plant and equipment. Expenditures of $10 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. December 31, 2010 property, plant and equipment and retained earnings were each $30 million higher under IFRS relative to Canadian GAAP as a result of capitalizing interest costs.
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 lower at December 31, 2010 than at January 1, 2010 and the asset retirement obligation and related property, plant and equipment were re-measured. At December 31, 2010, the asset retirement obligation was $178 million higher and the related property, plant and equipment asset was $34 million higher under IFRS relative to Canadian GAAP as a result of the January 1, 2010 transition adjustments and the 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
For the three months ended December 31, 2010, $2 million of operating expenses relating to the amortization of actuarial losses under Canadian GAAP were removed.
For the year ended December 31, 2010, actuarial losses of $61 million, net of $21 million in deferred taxes, were immediately recognized in other comprehensive income while $8 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 under IFRS relative to Canadian GAAP as a result of these 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. The share-based compensation expense relating to these options was measured using their grant date fair value and amortized over their vesting period with a corresponding charge to contributed surplus. When options were exercised, amounts in contributed surplus were reclassified to share capital.
Under IFRS, these options were not recognized as equity-settled share-based awards until the December 31, 2010 conversion to a corporation. Prior to this, options were re-measured at fair value at each reporting date. While share-based compensation expense was still amortized over the vesting period of the options, this charge was recorded as a liability, rather than to contributed surplus, under IFRS. However, when options were exercised, liabilities were still reclassified to shareholders' capital.
Beginning December 31, 2010, upon conversion to a corporation, the issued and outstanding options are classified under IFRS as equity-settled share-based awards and share-based compensation expense is measured using the grant-date fair value amortized over the 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 39 per cent individual tax rate applicable to earnings not distributed to trust unitholders. At December 31, 2010, after the conversion to a corporation, IFRS requires that deferred taxes be measured using the 25 per cent corporate tax rate, resulting in the recognition of a deferred tax recovery.
January 1, 2010 transition adjustments
An adjustment to re-measure deferred taxes using the 39 per cent rate was recorded at January 1, 2010 resulting in 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 impact of this re-measurement combined with the tax effect of the January 1, 2010 transition adjustments resulted in a $202 million increase in the deferred tax liability and a corresponding $202 million decrease in retained earnings under IFRS relative to Canadian GAAP.
2010 adjustments
For the three months and year ended December 31, 2010, deferred tax recovery adjustments of $249 million and $260 million, respectively, were recorded mainly as a result of the tax rate reduction from 39 per cent to 25 per cent, reflecting the conversion from an income trust to a corporation.
The $202 million increase in the deferred tax liability at January 1, 2010, the $260 million deferred tax recovery adjustments for the year ended December 31, 2010, and the $21 million deferred tax recovery adjustment recorded with the actuarial losses in other comprehensive income, collectively result in a $79 million decrease in the December 31, 2010 deferred tax liability and a $79 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 on the balance sheet.
January 1, 2010 transition adjustments
An adjustment was recorded at January 1, 2010 to reclassify $89 million from property, plant, and equipment to exploration and evaluation assets.
2010 adjustments
There were no incremental exploration and evaluation costs capitalized during the three months and year ended December 31, 2010.
ix. Crown royalties
Under Canadian GAAP, Crown royalties were presented as expenses in the statements of income and comprehensive income. Under IFRS, Crown royalties are netted against revenues.
x. Net finance expense
Under Canadian GAAP, accretion of the asset retirement obligation was presented with depreciation and depletion in the statements of income and comprehensive income. Under IFRS, accretion is combined with interest expense and presented as finance expense. Finance expense is presented net of interest income earned on cash and cash equivalents.
6. PROPERTY, PLANT AND EQUIPMENT, NET
Year Ended December 31, 2011
Upgrading Vehicles Asset
and Mining and retirement
($ millions) Extracting equipment equipment Buildings costs
---------------------------------------------------------------------------
Cost
Balance at
December 31,
2010 $ 4,669 $ 1,381 $ 688 $ 304 $ 362
Additions - - - - -
Change in asset
retirement
costs - - - - 569
Retirements (6) (9) (22) (1) -
Reclassification
s(1) 25 45 24 7 -
-----------------------------------------------------------
Balance at
December 31,
2011 $ 4,688 $ 1,417 $ 690 $ 310 $ 931
-----------------------------------------------------------
Accumulated
depreciation
Balance at
December 31,
2010 $ 1,092 $ 449 $ 264 $ 100 $ 103
Depreciation 166 88 60 8 14
Retirements (6) (9) (22) (1) -
Reclassification
s (3) (4) 2 (3) -
-----------------------------------------------------------
Balance at
December 31,
2011 $ 1,249 $ 524 $ 304 $ 104 $ 117
-----------------------------------------------------------
Net book value
at December 31,
2011 $ 3,439 $ 893 $ 386 $ 206 $ 814
-----------------------------------------------------------
-----------------------------------------------------------
Year Ended December 31, 2011
Major Construction
turnaround in Mine
($ millions) costs progress development Total
----------------------------------------------------------------------------
Cost
Balance at
December 31,
2010 $ 103 $ 694 $ 345 $ 8,546
Additions 43 600 - 643
Change in asset
retirement
costs - - - 569
Retirements (32) - (1) (71)
Reclassification
s(1) - (150) 49 -
------------------------------------------------------------
Balance at
December 31,
2011 $ 114 $ 1,144 $ 393 $ 9,687
------------------------------------------------------------
Accumulated
depreciation
Balance at
December 31,
2010 $ 50 $ - $ 92 $ 2,150
Depreciation 35 - 10 381
Retirements (32) - (1) (71)
Reclassification
s - - 8 -
------------------------------------------------------------
Balance at
December 31,
2011 $ 53 $ - $ 109 $ 2,460
------------------------------------------------------------
Net book value
at December 31,
2011 $ 61 $ 1,144 $ 284 $ 7,227
------------------------------------------------------------
------------------------------------------------------------
Year Ended December 31, 2010
Upgrading Vehicles Asset
and Mining and retirement
($ millions) Extracting equipment equipment Buildings costs
----------------------------------------------------------------------------
Cost
Balance at
January 1, 2010 $ 4,594 $ 1,288 $ 667 $ 298 $ 384
Additions - - - - -
Change in asset
retirement costs - - - - (22)
Retirements (3) (33) (21) (1) -
Reclassifications
(1) 78 126 42 7 -
-----------------------------------------------------------
Balance at
December 31,
2010 $ 4,669 $ 1,381 $ 688 $ 304 $ 362
-----------------------------------------------------------
Accumulated
depreciation
Balance at
January 1, 2010 $ 931 $ 356 $ 231 $ 92 $ 78
Depreciation 164 126 54 9 25
Retirements (3) (33) (21) (1) -
-----------------------------------------------------------
Balance at
December 31,
2010 $ 1,092 $ 449 $ 264 $ 100 $ 103
-----------------------------------------------------------
Net book value at
December 31,
2010 $ 3,577 $ 932 $ 424 $ 204 $ 259
-----------------------------------------------------------
-----------------------------------------------------------
(1)Reclassifications are primarily transfers from Construction in progress
to other categories of property, plant and equipment when construction is
completed and assets are available for use.
Year Ended December 31, 2010
Major Construction
turnaround in Mine
($ millions) costs progress development Total
----------------------------------------------------------------------------
Cost
Balance at
January 1, 2010 $ 95 $ 439 $ 323 $ 8,088
Additions 46 536 - 582
Change in asset
retirement costs - - - (22)
Retirements (38) - (6) (102)
Reclassifications
(1) - (281) 28 -
-----------------------------------------------------------
Balance at
December 31,
2010 $ 103 $ 694 $ 345 $ 8,546
-----------------------------------------------------------
Accumulated
depreciation
Balance at
January 1, 2010 $ 48 $ - $ 87 $ 1,823
Depreciation 40 - 11 429
Retirements (38) - (6) (102)
-----------------------------------------------------------
Balance at
December 31,
2010 $ 50 $ - $ 92 $ 2,150
-----------------------------------------------------------
Net book value at
December 31,
2010 $ 53 $ 694 $ 253 $ 6,396
-----------------------------------------------------------
-----------------------------------------------------------
(1)Reclassifications are primarily transfers from Construction in progress
to other categories of property, plant and equipment when construction is
completed and assets are available for use.
For the three months and year ended December 31, 2011, interest costs of $18 million and $57 million, respectively, were capitalized and included in property, plant and equipment ($10 million and $30 million for the three months and year ended December 31, 2010, respectively).
7. EMPLOYEE FUTURE BENEFITS
Canadian Oil Sands' share of Syncrude Canada's defined benefit and contribution plans' costs for the three months and year ended December 31, 2011 and 2010 is based on its 36.74 per cent working interest. The costs have been recorded in operating expenses and other comprehensive income as follows:
Three Months Ended Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Operating expenses
Defined benefit
Pension plan $ 12 $ 11 $ 36 $ 34
Other post employment benefits
plan 1 1 4 2
----------------------------------------------------------------------------
13 12 40 36
Defined contribution plan 1 1 3 3
----------------------------------------------------------------------------
14 13 43 39
Other comprehensive income
Defined benefit
Actuarial loss 56 54 128 61
----------------------------------------------------------------------------
Total benefit cost $ 70 $ 67 $ 171 $ 100
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Corporation's share of the estimated unfunded portion of Syncrude Canada's pension and other post-employment benefit plans increased to $465 million at December 31, 2011 from $397 million at September 30, 2011 and $327 million at December 31, 2010. The fourth quarter and full year 2011 increases reflect a decrease in the interest rate used to discount estimated future pension costs combined with lower than estimated returns on the pension plan assets. For the fourth quarter of 2011, a $56 million actuarial loss, net of $18 million in deferred taxes, has been recognized in other comprehensive income to reflect these estimate changes and a $128 million actuarial loss, net of $42 in million deferred taxes, has been recognized for the full year 2011. A liability for the $465 million unfunded balance is recognized on the December 31, 2011 Consolidated Balance Sheet.
8. BANK CREDIT FACILITIES
As at December 31, 2011 ($ millions)
----------------------------------------------------------------------------
Operating credit facility (a) $ 1,500
Extendible revolving term facility (b) 40
Line of credit (c) 100
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$ 1,640
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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. Operating Credit Facility
On June 1, 2011, Canadian Oil Sands entered into a $1,500 million credit facility agreement, replacing its existing $800 million operating facility. The new agreement expires on June 1, 2015. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at December 31, 2011, no amounts were drawn against this facility ($145 million was drawn against the $800 million facility at December 31, 2010; no amounts were drawn against the $800 million facility at January 1, 2010).
b. Extendible Revolving Term Facility
The $40 million extendible revolving term facility is a two year facility expiring June 30, 2013. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at December 31, 2011, no amounts were drawn on this facility ($nil - December 31, 2010; $nil - January 1, 2010).
c. 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 December 31, 2011 ($75 million - December 31, 2010; $70 million - January 1, 2010).
9. ASSET RETIREMENT OBLIGATION
Canadian Oil Sands and each of the other Syncrude owners are liable for their share of ongoing environmental obligations related to the ultimate reclamation of the Syncrude properties on abandonment. The Corporation estimates reclamation expenditures will be made over approximately the next 70 years and has applied a risk-free interest rate of 2.50% at December 31, 2011 (December 31, 2010 - 3.35%; January 1, 2010 - 3.90%) in deriving the asset retirement obligation.
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the Corporation's share of the obligation associated with the retirement of the Syncrude properties:
Year Ended Year Ended
December 31 December 31
($ millions) 2011 2010
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Asset retirement obligation, beginning of
period $ 501 $ 550
Change in estimated liability 471 (43)
Liabilities settled (49) (48)
Accretion expense 16 21
Change in risk-free interest rate 98 21
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Asset retirement obligation, end of period 1,037 501
Less current portion (29) (37)
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Non-current portion $ 1,008 $ 464
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The increase in the asset retirement obligation from $501 million at December 31, 2010 to $1,037 million at December 31, 2011 reflects additional costs identified through the fourth quarter completion of a revised comprehensive mine development and closure plan and reflect:
-- the reclamation of new storage areas and additional mature fine tailings
treatment costs, both required to meet the Alberta Energy Resources
Conservation Board's Directive 074 regulations;
-- geotechnical design development for regional land drainage features
required for final closure;
-- revised material handling cost assumptions, which reflect current
contract rates and parameters; and
-- a decrease in the risk-free interest rate used to discount future
reclamation payments.
These increases were partially offset by reclamation spending.
10. SHARE-BASED COMPENSATION
During 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. In 2011, 84,769 options and 10,412 PSUs were forfeited and 85,928 options were exercised. The remaining options outstanding at December 31, 2011 have an average exercise price of $27.41. The remaining PSUs outstanding at December 31, 2011 have an estimated fair value of $7 million.
11. NET FINANCE EXPENSE
Three Months Ended Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Interest costs $ 20 $ 21 $ 87 $ 91
Less capitalized
interest (18) (10) (57) (30)
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Interest expense 2 11 30 61
Accretion of asset
retirement obligation 4 5 16 21
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Net finance expense $ 6 $ 16 $ 46 $ 82
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12. COMMITMENTS
Commitments are summarized in Canadian Oil Sands' 2010 annual consolidated financial statements and include future cash payments that Canadian Oil Sands is required to make under existing contractual arrangements entered directly or as an owner in Syncrude. During 2011, Canadian Oil Sands entered into a new contractual obligation for approximately $700 million for the transportation of crude oil, and has assumed its share of new Syncrude capital commitments of approximately $300 million. There have been no other significant new contractual obligations or commitments relative to the 2010 year-end disclosure.
13. 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. Canadian Oil Sands' share of the royalties recognized for the period from January 1, 2009 to December 31, 2011 are now estimated to be approximately $40 million lower than the amount calculated using the Syncrude BVM. The Syncrude owners and the Alberta government continue to discuss the basis for reasonable quality, transportation, and handling adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. Should these discussions or a judicial determination result in a deemed bitumen value different than that used by Syncrude for estimating and paying royalties, the cumulative impact on Canadian Oil Sands' share of royalties since January 1, 2009 will be recognized immediately and impact both net income and cash flow from operations accordingly.
14. SUPPLEMENTARY INFORMATION
Three Months Ended Year Ended
December 31 December 31
($ millions) 2011 2010 2011 2010
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Income taxes paid $ - $ - $ - $ -
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Interest paid $ 24 $ 23 $ 95 $ 91
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15. NEW ACCOUNTING STANDARDS
In May 2011, the International Accounting Standards Board ("IASB") issued IFRS 11, Joint Arrangements, to replace International Accounting Standard ("IAS") 31, Interests in Joint Ventures, IFRS 10, Consolidated Financial Statements, IFRS 12, Disclosure of Interests in Other Entities, and IFRS 13, Fair Value Measurements, effective for years beginning on or after January 1, 2013 with earlier application permitted. IFRS 11 eliminates the accounting policy choice between proportionate consolidation and equity method accounting for joint ventures available under IAS 31 and, instead, mandates one of these two methodologies based on the economic substance of the joint arrangement. IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements. IFRS 12 requires entities to disclose information about the nature of their interests in joint ventures and IFRS 13 defines, and establishes a framework for measuring, fair value.
In June 2011, the IASB issued an amendment to IAS 19, Employee Benefits, to address the accounting and disclosure of defined benefit pension plans effective for years beginning on or after January 1, 2013 with earlier application permitted.
In October 2011, the IASB issued International Financial Reporting Interpretations Committee ("IFRIC") Interpretation 20, Stripping Costs in the Production Phase of a Surface Mine, which clarifies the accounting for costs associated with waste removal in surface mining effective for years beginning on or after January 1, 2013 with earlier application permitted.
Canadian Oil Sands has not applied any of these new standards as of December 31, 2011. Canadian Oil Sands continues to assess their impact and, at this time, does not anticipate any of them to result in significant accounting or disclosure changes.
Canadian Oil Sands Limited
Marcel Coutu
President & Chief Executive Officer
Shares Listed - Symbol: COS
Toronto Stock Exchange
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