Canadian Oil Sands' Third Quarter Cash Flow from Operations More Than Doubles
(firmenpresse) - CALGARY, ALBERTA -- (Marketwire) -- 10/27/11 -- Canadian Oil Sands Limited (TSX: COS)
All financial figures are unaudited and in Canadian dollars unless otherwise noted.
Highlights for the three and nine-month period ended September 30, 2011:
"We are enjoying one of Syncrude's best operational years. Our major coker turnaround is expected to be completed on schedule following a record run, and we expect to meet our original annual production target. Despite general market uncertainties globally, Syncrude's solid operations combined with the robust price premiums we are receiving for our crude oil relative to WTI give us the confidence to maintain our dividend level," said Marcel Coutu, President and Chief Executive Officer. "With the Syncrude Emissions Reduction project nearly behind us, together with a very strong balance sheet and liquidity position, we are well positioned to fund our mine train relocations and weather the continued volatility in crude oil prices."
Highlights
(1)Cash flow from operations and cash flow from operations per Share are non-GAAP measures and are defined on pages 6-7 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 299,000 barrels per day (total 27.5 million barrels) during the third quarter of 2011 compared with 264,000 barrels per day (total 24.3 million barrels) during the third quarter of 2010. Production in both periods reflects planned coker turnarounds, which commenced in early September of each year; however, operations overall were more stable in the 2011 period than during the same 2010 period.
Year-to-date, Syncrude produced 301,000 barrels per day (total 82.0 million barrels) in 2011, up five per cent over the 2010 period; this is consistent with the annual 2011 guidance expectation originally provided in December 2010.
Major Projects Update
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 replacement/relocation of mine trains, the crushing and slurrying facilities to process bitumen; the construction of a plant to process tailings; and the Syncrude Emissions Reduction (SER) project aimed at reducing sulphur dioxide and other emissions.
The front-end engineering design work is now complete for the Mildred Lake mine train replacements, resulting in a fully engineered project cost estimate of $4.2 billion gross to Syncrude ($1.6 billion net to COS).
The target in-service date for the SER project has been extended to the first quarter of 2012. While the construction will be completed during the fourth quarter of 2011, commissioning work will continue into early 2012. The current cost estimate remains $1.6 billion, gross to Syncrude.
Further detail on Syncrude's major projects is provided on pages 27-28 of the MD&A section of this report.
2011 Outlook
Canadian Oil Sands' 2011 outlook includes the following key estimates and assumptions:
More information on the outlook is provided in the MD&A section of this report and the October 27, 2011 guidance document, which is available on our web site at under "Investor Information".
The 2011 Outlook contains forward-looking information and users are cautioned that the actual amounts may vary from the estimates disclosed. Please refer to the "Forward-Looking Information Advisory" in the MD&A section of this report for the risks and assumptions underlying this forward-looking information.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis ("MD&A") was prepared as of October 27, 2011 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Limited (the "Corporation") for the three and nine months ended September 30, 2011 and September 30, 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 or on the Corporation's website at . 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 expectation that the Coker 8-2 turnaround will be completed as planned; the expectation that the unplanned maintenance on the hydrogen unit will continue into early December; the expectation that having bitumen and untreated product inventory in tankage should support Syncrude in achieving the 110 million barrel production outlook; the expectations regarding the annual Syncrude forecasted production range of 107 to 111 million barrels and the single-point Syncrude production estimate of 110 million barrels; future dividends and any increase or decrease from current payment amounts, any inference as to the stability or sustainability of dividends is unwarranted and not to be inferred; 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 and employee benefits 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 2011 and beyond; the expected sales, operating expenses, Crown royalties, capital expenditures and cash flow from operations for 2011;
the expected price for crude oil and natural gas in 2011; the expected foreign exchange rates in 2011; the expected realized selling price, which includes the anticipated differential to West Texas Intermediate ("WTI") to be received in 2011 for the Corporation's product; 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 expected amount of total major projects cost, including the revised estimate for the Mildred Lake mine train replacements and anticipated target in-service dates for the Syncrude Emissions Reduction ("SER") project, the Mildred Lake mine train replacements, the Aurora North mine train relocation 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; the cost estimates for 2011 total major project spending and post-2011 major project spending and the expectation that the development of Aurora South will expand bitumen production by approximately 50 per cent before 2020. You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Corporation believes that the expectations represented by such forward-looking statements are reasonable and reflect the current views of 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 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 and on the Corporation's website at .
You are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and unless required by law, the Corporation does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.
NON-GAAP FINANCIAL MEASURES: In this MD&A and the related press release, we refer to financial measures that do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles ("GAAP"). These non-GAAP financial measures include cash flow from operations, cash flow from operations on a per Share basis, net debt, total capitalization and net debt to total capitalization. These measures are indicators of the Corporation's capacity to fund capital expenditures, other investing activities, and dividends without incremental financing. In addition, the Corporation refers to various per barrel figures, such as net realized selling prices, operating 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.
Beginning this year, we are reporting cash flow from operations in total and on a per Share basis. Previously, we reported cash from operating activities. Cash flow from operations is calculated as cash from operating activities, as reported on the Consolidated Statement of Cash Flows, before changes in non-cash working capital. Cash flow from operations per Share is calculated as cash flow from operations divided by the weighted-average number of Shares outstanding in the period. We believe 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:
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 nine months ended September 30, 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 10. The accounting policies applied in these interim unaudited consolidated financial statements are based on IFRS issued and outstanding as of October 27, 2011. Any subsequent changes to IFRS that are given effect in the Corporation's annual consolidated financial statements for the year ending December 31, 2011 could result in a restatement of these interim consolidated financial statements, including the adjustments recognized on transition to IFRS.
Under IFRS, the Corporation's balance sheets are adjusted to reflect the following:
Under IFRS, beginning in 2010 net income is adjusted to reflect the following:
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 third quarter of 2011 totalled 27.5 million barrels, or 299,000 barrels per day, compared with 24.3 million barrels, or 264,000 barrels per day, during the third quarter of 2010. Net to the Corporation, production totalled 10.1 million barrels in the third quarter of 2011 compared with 8.9 million barrels in the third quarter of 2010, based on Canadian Oil Sands' 36.74 per cent working interest in Syncrude. Higher production in the third quarter of 2011 reflected improved utilization rates and more stable operations relative to the third quarter of 2010. Production volumes in both the third quarters of 2011 and 2010 reflected planned coker turnarounds, which commenced in early September of each year.
A key factor in improving utilization rates is extending the time between turnarounds for each of Syncrude's three coking units. Syncrude has been targeting a 36 month run-time for its cokers, which was achieved in the third quarter of 2011 with Coker 8-2.
Year-to-date, Syncrude produced 82.0 million barrels in 2011, or about 301,000 barrels per day. This compares with 78.0 million barrels, or about 286,000 barrels per day, in 2010. The 2011 year-to-date production increase reflects improved utilization rates and more stable operations relative to 2010. Syncrude remains on target to meet Canadian Oil Sands' production estimate of 110 million barrels (40.4 million barrels net to the Corporation).
Canadian Oil Sands' operating expenses were $374 million, or $37.19 per barrel, in the third quarter of 2011, compared with $337 million, or $37.97 per barrel, in the same quarter of 2010. On a year-to-date basis, Canadian Oil Sands' operating expenses were $1,108 million, or $36.56 per barrel, in 2011 compared with $1,009 million, or $35.28 per barrel, in the comparative 2010 period. The increase in operating expenses was mainly due to higher diesel costs and increased costs for planned maintenance in 2011 (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
During the last eight quarters, the following items have had a significant impact on the Corporation's financial results:
Quarterly variances in net income and cash flow from operations are caused mainly by fluctuations in crude oil prices, production and sales volumes, operating expenses and natural gas prices. Net income is also impacted by unrealized foreign exchange gains and losses, depreciation and depletion, impairment charges and deferred tax amounts.
While the supply/demand balance for crude oil affects selling prices, the impact of this relationship is difficult to predict and quantify and has not displayed significant seasonality. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is influenced by weather conditions and North American natural gas inventory levels.
Syncrude production levels may not display seasonal patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit 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 costs. The effect on per barrel operating costs of the expensed turnaround and maintenance work is amplified because it results in reduced production rates when this work is occurring.
(1) Cash flow from operations and cash flow from operations per Share are non-GAAP measures and are defined on pages 6-7 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. volumes.
(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 $512 million, or $1.06 per Share, in the third quarter of 2011 compared with cash flow from operations of $230 million, or $0.48 per Share, in the third quarter of 2010. Higher sales in the third quarter of 2011 were partially offset by higher operating expenses quarter-over-quarter. Year-to-date cash flow from operations increased to $1,534 million, or $3.16 per Share, in 2011 from $834 million, or $1.72 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 costs totalled $989 million in the third quarter of 2011 compared with $692 million in the third quarter of 2010. The increase in sales in the third quarter of 2011 reflects higher crude oil prices, a premium for the Corporation's realized SCO price relative to WTI (versus a discount in the comparative 2010 period), and higher sales volumes. Year-to-date sales net of crude oil purchases and transportation costs increased to $3,050 million in 2011 from $2,268 million in 2010 due to these same factors (see the "Sales Net of Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).
Crown royalties totalled $65 million, or $6.53 per barrel, in the third quarter of 2011, similar to the third quarter of 2010 when Crown royalties totalled $68 million, or $7.66 per barrel. Year-to-date, Crown royalties totalled $234 million, or $7.74 per barrel, in 2011, similar to 2010 when Crown royalties totalled $231 million, or $8.08 per barrel. Royalties remained relatively unchanged quarter-over-quarter and year-over-year because deemed bitumen prices were relatively stable despite increases in realized SCO prices, while increases in bitumen production volumes were offset by higher allowed costs (see the "Crown royalties" section of this MD&A for further discussion of Crown royalties).
Operating expenses in the third quarter of 2011 totalled $374 million, or $37.19 per barrel, compared with $337 million, or $37.97 per barrel, in the third quarter of 2010. On a year-to-date basis, operating expenses in 2011 totalled $1,108 million, or $36.56 per barrel, compared with $1,009 million, or $35.28 per barrel, in 2010. The increase in 2011 year-to-date operating expenses compared with the same period in 2010 was primarily due to higher diesel costs and increased planned maintenance in 2011 (see the "Operating Expenses" section of this MD&A for further discussion).
Net income totalled $242 million, or $0.50 per Share, in the third quarter of 2011, compared with $193 million, or $0.40 per Share, in the third quarter of 2010. Year-to-date net income totalled $912 million, or $1.88 per Share, in 2011, compared with $614 million, or $1.27 per Share, in 2010. The variances in sales, Crown royalties, and operating expenses described earlier impacted net income, as did variances in foreign exchange gains, depreciation and depletion expense and deferred taxes.
Depreciation and depletion expense totalled $93 million in the third quarter of 2011 and $285 million in the first nine months of 2011, compared with $107 million and $318 million, respectively, in the comparative 2010 periods.
Canadian Oil Sands recorded foreign exchange losses on the revaluation of its U.S. dollar-denominated long-term debt of $83 million and $49 million in the third quarter and first nine months of 2011, respectively, which is the result of a weakening in the value of the Canadian dollar relative to the U.S. dollar. Conversely, Canadian Oil Sands recorded foreign exchange gains of $35 million and $19 million in the comparative 2010 periods, reflecting a strengthening in the value of the Canadian dollar relative to the U.S. dollar.
Canadian Oil Sands recorded deferred tax expenses of $95 million and $317 million in the third quarter and first nine months of 2011, respectively, versus recoveries of $35 million and $49 million in the comparative 2010 periods. The 2011 expense reflects the conversion from an income trust to a corporate structure on December 31, 2010, which resulted in taxable income no longer being sheltered by the payment of distributions (see the "Deferred Taxes" section of this MD&A for further discussion).
Net debt, comprised of long-term debt less cash and cash equivalents, decreased to $0.4 billion at September 30, 2011 from $1.2 billion at December 31, 2010. The decrease is a result of cash flow from operations exceeding capital expenditures, dividends and reclamation trust fund contributions in the first nine months of 2011. Partially offsetting these factors, a weaker Canadian dollar at September 30, 2011 relative to December 31, 2010 increased the Canadian dollar equivalent value of the U.S. dollar-denominated long-term debt.
Capital expenditures through the first nine months of 2011 increased to $438 million from $393 million for the same period in 2010, reflecting spending on Syncrude's mine train replacement/relocation projects.
(1) Sales include sales of purchased crude oil and 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 increase in sales net of crude oil purchases and transportation expense in the third quarter and first nine months of 2011 relative to the same periods in 2010 reflects a higher realized selling price for our SCO and higher sales volumes.
During the third quarter of 2011, the West Texas Intermediate ("WTI") crude oil price averaged U.S. $90 per barrel compared with U.S. $76 per barrel in the third quarter of 2010. The impact of the higher U.S. dollar WTI oil price was offset somewhat by a stronger Canadian dollar, which averaged $1.02 U.S./Cdn in the third quarter of 2011 versus $0.96 U.S./Cdn in the third quarter of 2010. Year-to-date, WTI averaged U.S. $95 per barrel in 2011 compared with $78 per barrel in 2010 while the Canadian dollar averaged $1.02 U.S./Cdn in 2011 compared with $0.97 U.S./Cdn in 2010.
The Corporation's SCO price is also affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the third quarter of 2011, the Corporation realized a weighted-average SCO premium of $9.77 per barrel versus a $1.46 per barrel discount in the third quarter of 2010. Year-to-date, the Corporation realized a weighted-average SCO premium of $6.99 per barrel in 2011 versus a $1.23 per barrel discount in 2010, reflecting premiums in the second and third quarters of 2011 partially offset by a discount in the first quarter. 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 differential in the second and third quarters of 2011 is primarily the result of two factors. The first is the lower supply of SCO in the market because of operational upsets and maintenance at several oil sands plants during the first nine months of the year. The second is 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 competes with crude oil priced higher than WTI, such as LLS, which results in a positive differential to WTI.
The Corporation's third quarter sales volumes averaged 109,000 barrels per day in 2011 compared with 96,000 barrels per day in 2010. Year-to-date sales volumes averaged 111,000 barrels per day in 2011 compared with 105,000 barrels per day through the first nine months of 2010. The increase in both quarter-over-quarter and year-over-year sales volumes reflect higher utilization rates and more stable operations.
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 lower in the first nine months of 2011 relative to the comparative 2010 period, reflecting additional activities in 2010 to support unanticipated production shortfalls and incremental purchases associated with tankage arrangements; however, the lower purchased volumes were partially offset by higher crude oil prices in 2011.
Crown Royalties
Crown royalties totalled $65 million, or $6.53 per barrel, in the third quarter of 2011, similar to the third quarter of 2010 when Crown royalties totalled $68 million, or $7.66 per barrel. Year-to-date, Crown royalties totalled $234 million, or $7.74 per barrel, in 2011, similar to 2010 when Crown royalties totalled $231 million, or $8.08 per barrel. Royalties remained relatively unchanged quarter-over-quarter and year-over-year because deemed bitumen prices were relatively stable despite increases in realized SCO prices, while increases in bitumen production volumes were offset by higher allowed costs.
The Syncrude Royalty Amending Agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil price adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude's bitumen and the reference price of bitumen. The Alberta government and the Syncrude owners are in discussions to determine the appropriate adjustments for quality, transportation and handling. In December 2010 the Alberta government provided a modified notice of a bitumen value for Syncrude (the "Syncrude BVM"). For estimating and paying royalties, Syncrude used a bitumen value based on Syncrude and its owners' interpretation of the Syncrude Royalty Amending Agreement, which is different than the Syncrude BVM. As a result, Canadian Oil Sands' share of the royalties recognized for the period from January 1, 2009 to September 30, 2011 are estimated to be approximately $50 million lower than the amount calculated under the Syncrude BVM. The Syncrude owners and the Alberta government continue to discuss the basis for reasonable quality, transportation, and handling adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. Should these discussions or a judicial determination result in a deemed bitumen value different than that used by Syncrude for estimating and paying royalties, the cumulative impact on Canadian Oil Sands' share of royalties since January 1, 2009 will be recognized immediately and will impact both net income and cash royalties accordingly.
Operating Expenses
The following table breaks down operating expenses into their major components and shows operating expenses per barrel of bitumen and SCO. The information allocates costs to bitumen production and upgrading on the basis used to determine bitumen royalties.
(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 $3.51 per GJ and $3.58 per GJ for the three and nine months ended September 30, 2011, respectively, and $3.44 per GJ and $4.05 per GJ for the three and nine months ended September 30, 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).
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In the third quarter of 2011, operating expenses were $374 million, averaging $37.19 per barrel, compared with $337 million, or $37.97 per barrel, in the third quarter of 2010. Year-to-date operating expenses were $1,108 million, or $36.56 per barrel, in the first nine months of 2011 compared with $1,009 million, or $35.28 per barrel, in the comparative 2010 period.
The increase in year-to-date operating expenses in 2011 relative to 2010 was primarily due to:
The increased diesel purchases also are reflected in the increased year-to-date purchased energy consumption rate.
The increase in operating expense in the third quarter of 2011 relative to the third quarter in 2010 was primarily due to:
Operating expenses on a per barrel basis are affected by the Corporation's sales volumes, which were higher in the third quarter and first nine months of 2011 relative to the comparative 2010 periods.
Non-Production Expenses
Non-production expenses were $28 million in the third quarter of 2011, similar to the third quarter of 2010 when non-production costs totalled $26 million. On a year-to-date basis, non-production costs totalled $86 million in 2011 compared with $81 million in the comparative 2010 period.
Non-production expenses consist primarily of development expenditures relating to capital programs, such as pre-feasibility engineering, technical and support services, research and development, evaluation drilling, and regulatory and stakeholder consultation expenditures. Non-production expenses can vary on a periodic basis depending on the number of projects underway and the development stage of the projects.
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 $11 million in the third quarter of 2011 from $21 million in the comparable 2010 quarter. On a year-to-date basis, net finance expense decreased to $40 million in the first nine months of 2011 from $66 million in the comparative 2010 period because a higher portion of interest costs were capitalized in 2011.
Depreciation and Depletion Expense
Depreciation and depletion expense totalled $93 million for the third quarter of 2011 and $285 million for the first nine months of 2011 compared with $107 million and $318 million, respectively, for the comparative periods in 2010.
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 losses on long-term debt in 2011 were the result of a weakening in the value of the Canadian dollar relative to the U.S. dollar to $0.96 U.S./Cdn at September 30, 2011 from $1.04 U.S./Cdn at June 30, 2011 and $1.01 U.S./Cdn at December 31, 2010. Conversely, the foreign exchange gains in 2010 were the result of a strengthening in the value of the Canadian dollar relative to the U.S. dollar to $0.97 U.S./Cdn at September 30, 2010 from $0.94 U.S./Cdn at June 30, 2010 and $0.96 U.S./Cdn at December 31, 2009.
Deferred Taxes
Canadian Oil Sands recognized a $95 million deferred tax expense in the third quarter of 2011 relative to a $35 million recovery in the third quarter of 2010. On a year-to-date basis, the deferred tax expense was $317 million in 2011 relative to a $49 million recovery in the comparative 2010 period. The 2011 deferred tax expense reflects an increase in the temporary differences between the accounting and tax values of Canadian Oil Sands' assets and liabilities, the result of drawing down tax pools to shelter taxable income. Under the trust structure prior to 2011, distributions were also available to shelter taxable income.
Asset Retirement Obligation
Canadian Oil Sands' asset retirement obligation increased to $545 million at September 30, 2011 from $465 million at June 30, 2011 and $501 million at December 31, 2010. The increase reflects a decrease in the risk-free interest rate used to discount future reclamation payments partially offset by $4 million and $35 million of reclamation spending during the three and nine months ended September 30, 2011, respectively. A $32 million current portion of the asset retirement obligation is included in accounts payable and accrued liabilities, while the $513 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 $397 million at September 30, 2011 from $313 million at June 30, 2011 and $327 million at December 31, 2010 due to a decrease in the interest rate used to discount estimated future pension costs combined with lower than estimated returns on the pension plan assets. A $68 million actuarial loss, net of $23 million deferred taxes, has been recognized in other comprehensive income to reflect these estimate changes and a liability for the $397 million unfunded balance has been recognized on the Consolidated Balance Sheet.
CAPITAL EXPENDITURES
Year-to-date capital expenditures totalled $438 million in 2011 compared with expenditures of $393 million in the comparative 2010 period. In the third quarter of 2011, capital expenditures totalled $189 million compared with expenditures of $160 million in the third quarter of 2010. Capital expenditures include the following:
The remaining capital expenditures related to other investment activities, including relocation of tailings facilities and other infrastructure projects.
Year-to-date capital expenditures were lower than 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' capital projects is provided in the "Outlook" section of this MD&A.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
Contractual obligations are summarized in the Corporation's 2010 annual MD&A and include future cash payments that the Corporation is required to make under existing contractual arrangements that it has entered into directly or as a 36.74 per cent owner in Syncrude. With the exception of the Corporation's share of new Syncrude capital commitments of approximately $60 million related to major projects referenced on the Outlook section, there have been no significant new contractual obligations or commitments relative to the 2010 year-end disclosure.
DIVIDENDS
On October 27, 2011, the Corporation declared a quarterly dividend of $0.30 per Share in respect of the fourth quarter of 2011 for a total dividend of approximately $145 million. The dividend will be paid on November 30, 2011 to Shareholders of record on November 25, 2011.
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 upcoming 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.
(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 decreased to $0.4 billion at September 30, 2011 from $1.2 billion at December 31, 2010. Cash flow from operations exceeded capital expenditures, dividends and reclamation trust fund contributions in the first nine months of 2011, resulting in the decreased leverage. Partially offsetting these factors, a weaker Canadian dollar at September 30, 2011 relative to December 31, 2010 increased the Canadian dollar equivalent value of the U.S. dollar-denominated long-term debt by $49 million.
Shareholders' equity increased to $4.2 billion at September 30, 2011 from $3.7 billion at December 31, 2010, as net income exceeded dividends in the first nine months of 2011.
On June 1, 2011, Canadian Oil Sands entered into a $1,500 million credit facility agreement, replacing its $800 million operating facility. The new agreement expires on June 1, 2015.
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 $10 billion with 484.5 million shares outstanding and a closing price of $20.39 per Share on September 30, 2011. The following table reflects the trading activity for the third quarter of 2011.
FINANCIAL RISK MANAGEMENT
The Corporation did not have any financial derivatives outstanding at September 30, 2011.
Crude Oil Price Risk
Canadian Oil Sands' revenues are impacted by changes in both the U.S. dollar-denominated crude oil prices and U.S./Cdn FX rates. Over the last three years, daily WTI prices have experienced significant volatility, ranging from U.S. $114 per barrel to U.S. $34 per barrel. Also, supply, demand, and other market factors can vary significantly between regions and, as a result, the spreads between crude oil benchmarks, such as WTI and Brent, 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 and exchange rates to reduce cash flow volatility. The Corporation did not have any crude oil price hedges in place during the first nine months of 2011 or 2010; instead, a strong balance sheet was used to mitigate the risk around crude oil price movements. As at October 27, 2011, 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 U.S. dollar WTI benchmark price 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 the first nine months of 2011 or 2010, and does not currently intend to enter into any new currency hedge positions. The Corporation may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.
Interest Rate Risk
Canadian Oil Sands' net income and cash flow from operations are impacted by U.S. and Canadian interest rate changes because our credit facilities and investments are exposed to floating interest rates. In addition, we are exposed to the refinancing of maturing long-term debt at prevailing interest rates. As at September 30, 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 investments outstanding during the quarter.
Liquidity Risk
Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they fall due. Canadian Oil Sands actively manages its liquidity risk through its cash, debt and equity strategies. The next long-term debt maturity is in August 2013, and the $1.5 billion credit facility does not expire until June 2015.
Credit Risk
Canadian Oil Sands is exposed to credit risk primarily through customer accounts receivable balances and financial counterparties with whom the Corporation has invested its cash or from whom it has purchased its term deposits, and with its insurance providers in the event of an outstanding claim. The maximum exposure to any one customer or financial counterparty is managed through a credit policy that limits exposure based on credit ratings.
Canadian Oil Sands carries credit insurance to help mitigate a portion of the impact should a loss occur and continues to transact primarily with investment grade customers. The vast majority of accounts receivable at September 30, 2011 was due from investment grade energy producers, financial institutions, and refinery-based customers.
At September 30, 2011, our cash and cash equivalents were invested mainly in term deposits and Bankers' Acceptances with high-quality senior banks. As of October 27, 2011, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.
CHANGES IN ACCOUNTING POLICIES
Apart from the changes described in the "Transition to International Financial Reporting Standards" section of this MD&A, there were no new accounting policies adopted, nor any changes to accounting policies, in the first nine months of 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, and IFRS 12, Disclosure of Interests in Other Entities, effective for years beginning on or after January 1, 2013. 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 12 requires entities to disclose information about the nature of their interests in joint ventures.
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.
Canadian Oil Sands does not anticipate significant accounting or disclosure changes as a result of these new standards.
Canadian Oil Sands is maintaining its 2011 Syncrude production estimate of 110 million barrels (40.4 million barrels net to the Corporation), which is equivalent to 301,400 barrels per day (110,700 barrels per day net to the Corporation). The production range has been narrowed to 107 to 111 million barrels based on the results achieved during the first nine months of the year. The turnaround of Coker 8-2 is expected to be completed as planned. While unplanned maintenance on a hydrogen unit is expected to continue into early December, Syncrude has bitumen and untreated product inventory in tankage which can be processed in December to support achievement of the 110 million barrel production outlook.
Canadian Oil Sands' estimate for operating costs has decreased to $38.15 per barrel to reflect a lower natural gas price assumption of $3.75 per gigajoule and a reclassification of certain maintenance costs associated with the Coker 8-2 turnaround from operating expenses to capital expenditures.
The estimate for 2011 capital expenditures has decreased by $218 million to $691 million to reflect adjustments to the expected timing of spending on major projects, partially offset by the increase in capitalized turnaround costs. The expected completion dates for these major projects is not affected.
The revised Outlook assumes a decreased U.S. $92 per barrel WTI oil price but an increase in the premium SCO receives to Cdn dollar WTI to $8.00 per barrel. The higher premium estimate reflects reduced SCO supply from maintenance activities at SCO producers and the continuing dislocation of the WTI crude oil benchmark relative to other crudes against which a portion of our barrels compete.
The pricing assumptions, together with a U.S./Cdn foreign exchange rate of $1.01, result in estimated sales of $4,005 million, or $99 per barrel, in 2011.
We are estimating cash flow from operations of approximately $1,952 million, or $4.03 per Share, in 2011. After deducting forecast 2011 capital expenditures, we estimate $1,261 million in remaining cash flow from operations for the year, or $2.60 per Share.
Changes in certain factors and market conditions could potentially impact Canadian Oil Sands' Outlook. The following table provides a sensitivity analysis of the key factors affecting the Corporation's performance.
Outlook Sensitivity Analysis (October 27, 2011)
(1)An opposite change in each of these variables will result in the opposite cash flow from operations impacts. Canadian Oil Sands anticipates $nil current taxes in 2011. As such, the sensitivities in the table above do not reflect any impact for current taxes.
The 2011 Outlook contains forward-looking information and users are cautioned that the actual amounts may vary from the estimates disclosed. Please refer to the "Forward-Looking Information Advisory" section of this MD&A for the risks and assumptions underlying this forward-looking information.
Major 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 for the development of the Aurora South leases and other tailings management infrastructure will be provided when additional scope and cost details are available. Regular maintenance capital post 2011 is provided on an annual basis with the budget for the following year.
Major Projects(1) - Total Project Cost and Schedule Estimates(2)
Major Projects(1) - Annual Spending Profile(2)
(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 development of the Aurora South leases and other tailings management infrastructure.
(2) Total project costs include both capital costs and certain non-production costs. Costs exclude capitalized interest.
Canadian Oil Sands plans to finance these major projects primarily through cash flow from operations.
The front-end engineering design work is now complete for the Mildred Lake mine train replacements, resulting in fully engineering project cost estimate of $4.2 billion gross to Syncrude ($1.6 billion net to Canadian Oil Sands).
The target in-service date for the SER project has been extended to the first quarter of 2012. While the construction will be completed during the fourth quarter of 2011, commissioning work will continue into early 2012. The current cost estimate of $1.6 billion (gross to Syncrude) remains.
Beyond 2014, Syncrude's capital program includes development of a group of undeveloped leases called Aurora South aimed at expanding bitumen production by approximately 50 per cent by 2020. Syncrude is in the process of developing cost estimates for this expansion, which must also be approved by the Syncrude joint venture owners. The major projects tables and the expectations regarding the development of Aurora South contain forward-looking information and users of this information are cautioned that the actual yearly and total major project costs, the actual in-service dates for the major projects and the actual level and timing of bitumen production growth expected from the development of Aurora South may vary from the plans disclosed. The major project cost estimates, major project target in-service dates and expectations regarding the development of Aurora South are based on current capital spending plans. Please refer to the "Forward-Looking Information Advisory" section of this MD&A for the risks and assumptions underlying this forward-looking information. For a list of additional risk factors that could cause the actual amount of the capital expenditures, the major project target in-service dates and the level and timing of bitumen production growth expected from the development of Aurora South to differ materially, please refer to the Corporation's Annual Information Form dated March 10, 2011 which is available on the Corporation's profile on SEDAR at and on the Corporation's website at .
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(unaudited)
CONSOLIDATED BALANCE SHEETS
(unaudited)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
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").
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 the first nine months of 2011 as if these policies had always been in effect. Note 5 discloses the impact of the transition to IFRS on the Corporation's reported 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 and outstanding as of October 27, 2011. Any subsequent changes to IFRS that are given effect in the Corporation's annual consolidated financial statements for the year ending December 31, 2011 could result in a restatement of these interim consolidated financial statements, including the adjustments recognized on transition to IFRS.
Certain disclosures that are normally required to be included in the notes to the annual audited consolidated financial statements have been condensed or omitted. These unaudited interim consolidated financial statements should be read in conjunction with the Corporation's Canadian GAAP audited consolidated financial statements and notes thereto in the Corporation's annual report for the year ended December 31, 2010.
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 intangible mine development costs, which are depleted on a unit-of-production basis over the estimated proved and probable reserves of the producing mines. The following estimated useful lives of the tangible assets are reviewed annually for any changes to those estimates:
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 is transferred to the appropriate category of PP&E.
Exploration and Evaluation
Exploration and evaluation ("E&E") assets include the costs of acquiring undeveloped oil sands leases ("oil sands lease acquisition costs") and interests in natural gas licenses located in the Arctic Islands in northern Canada (the "Arctic natural gas assets").
Impairment
The carrying amounts of PP&E and E&E assets are reviewed for possible impairment whenever changes in circumstances indicate that the carrying amounts may not be recoverable. For the purpose of measuring recoverable amounts, assets are grouped at the lowest levels for which there are separately identifiable cash inflows ("cash generating units" or "CGUs"). The recoverable amount is the higher of a CGU's fair value less cost to sell (being the amount obtainable from the sale of a CGU in an arm's length transaction, net of disposal costs) and its value in use (being the net present value of the CGU's expected future cash flows). An impairment loss is recognized for the amount by which the carrying amount exceeds the recoverable amount.
E&E assets are also subject to impairment testing at the time they are transferred to PP&E.
PP&E consists entirely of Canadian Oil Sands' proportionate interest in Syncrude's PP&E. PP&E is combined with the oil sands lease acquisition costs, within the E&E assets, to form one CGU for impairment testing purposes. The balance of the E&E assets, being the Arctic natural gas assets, form a second CGU 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 r
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