All financial figures are unaudited and in Canadian dollars unless otherwise noted.
Highlights for the three months and year ended December 31, 2012:
“Our dividend level of $0.35 per Share per quarter for 2013 is well supported by a strong balance sheet and a major capital projects program that is proceeding on schedule and on budget,” said Marcel Coutu, President and Chief Executive Officer. “Our outlook for 2013 is based on an $80 per barrel plant-gate realized selling price and a five per cent increase in production rates over 2012. We will continue to conservatively manage our business as we progress through our capital program, and we are well positioned at this time both financially and operationally.”
Added Coutu: “Our average realized selling price of $92 per barrel in 2012 was relatively strong, given the dynamics of North American crude oil markets. As a result of limited transportation capacity, the WTI benchmark price for crude oil traded at a discount of about $18 per barrel relative to global crude oil prices, which averaged $112 per barrel in 2012. Producers in western Canada generally experienced a further discount to WTI oil prices; however, pricing for our high-quality SCO blend averaged a discount of only $2.50 per barrel relative to WTI, demonstrating the value of our upgrader. We expect the differential between WTI and global crude oil prices to narrow as additional pipeline capacity comes on through 2013 and 2014. Our unhedged approach allows us to capture any upside in WTI oil prices.”
| Highlights | ||||||||||
| Three Months Ended | Year Ended | |||||||||
| December 31 | December 31 | |||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||
| Cash flow from operations1 ($ millions) | $ | 418 | $ | 363 | $ | 1,581 | $ | 1,897 | ||
| Per Share1 ($/Share) | $ | 0.86 | $ | 0.75 | $ | 3.26 | $ | 3.91 | ||
| Net income ($ millions) | $ | 221 | $ | 232 | $ | 981 | $ | 1,144 | ||
| Per Share, Basic and Diluted ($/Share) | $ | 0.46 | $ | 0.48 | $ | 2.02 | $ | 2.36 | ||
| Sales volumes2 | ||||||||||
| Total (mmbbls) | 10.3 | 8.4 | 38.7 | 38.7 | ||||||
| Daily average (bbls) | 111,669 | 91,259 | 105,680 | 106,015 | ||||||
| Realized SCO selling price ($/bbl) | $ | 89.99 | $ | 104.78 | $ | 91.90 | $ | 101.20 | ||
| West Texas Intermediate (“WTI”) (average $US/bbl) | $ | 88.23 | $ | 94.06 | $ | 94.15 | $ | 95.11 | ||
| SCO premium (discount) to WTI | $ | 2.43 | $ | 8.51 | $ | (2.52 | ) | $ | 7.32 | |
| (weighted average $/bbl) | ||||||||||
| Operating expenses ($/bbl) | $ | 38.85 | $ | 46.88 | $ | 39.06 | $ | 38.80 | ||
| Capital expenditures ($ millions) | $ | 299 | $ | 205 | $ | 1,086 | $ | 643 | ||
| Dividends ($ millions) | $ | 169 | $ | 146 | $ | 654 | $ | 533 | ||
| Per Share ($/Share) | $ | 0.35 | $ | 0.30 | $ | 1.35 | $ | 1.10 | ||
| (1) | Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined on page 5 within the Management”s Discussion and 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 of 298,900 barrels per day (total 27.5 million barrels) during the fourth quarter of 2012, up from 252,300 barrels per day (total 23.2 million barrels) during the same 2011 period. Production in the 2012 fourth quarter mainly reflects unplanned outages in mine trains, which limited bitumen production. Volumes in the 2011 fourth quarter reflect unplanned outages of Coker 8-1 and a hydrogen unit.
In 2012, Syncrude production averaged about 286,500 barrels per day (104.9 million barrels total) compared with about 288,400 barrels per day (105.3 million barrels total) in 2011.
Syncrude recently released its 2010/2011 Sustainability Report, which is available on Syncrude”s website at the following link: http://www.syncrude.ca/users/folder.asp?FolderID=5713. The report provides an overview of Syncrude”s performance in the areas of economic contribution, stakeholder and employee engagement, community investment, health and safety, and environmental stewardship.
2013 Outlook
The following highlights Canadian Oil Sands” key estimates and assumptions for 2013:
More information on the outlook is provided in the MD&A section of this report and the January 31, 2013 guidance document, which is available on our web site at www.cdnoilsands.com under “Investor Information”.
The 2013 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 January 31, 2013 and should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Canadian Oil Sands Limited (the “Corporation”) for the three months and year ended December 31, 2012 and December 31, 2011, the audited consolidated financial statements and MD&A of the Corporation for the year ended December 31, 2011 and the Corporation”s Annual Information Form (“AIF”) dated February 23, 2012. 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 “we” include the Corporation, its subsidiaries and partnerships. 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.
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 2013 annual Syncrude forecasted production range of 105 million barrels to 115 million barrels and the single-point Syncrude production estimate of 110 million barrels (40.4 million barrels net to the Corporation); the timing of the Coker 8-1 turnaround; the intention to maintain a quarterly dividend of $0.35 per Share in 2013 based on the assumptions in our 2013 Outlook; future dividends and any increase or decrease from current payment amounts; the establishment of future dividend levels with the intent of absorbing short-term market volatility over several quarters; the level of natural gas consumption in 2013 and beyond; the expected sales, operating expenses, non-production expenses, Crown royalties, capital expenditures and cash flow from operations for 2013; the anticipated amount of current taxes in 2013; expectations regarding current taxes beyond 2013; the expectation that proceeds from the March 2012 senior note offering will be used to repay U.S. $300 million of senior notes which mature on August 15, 2013, to fund major capital projects over the next few years and for general corporate purposes; expectations regarding the Corporation”s cash levels for 2013 and 2014; the expected price for crude oil and natural gas in 2013; the expected foreign exchange rates in 2013; the expected realized selling price, which includes the anticipated differential to West Texas Intermediate (“WTI”) to be received in 2013 for the Corporation”s product; the expectations regarding net debt; 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, anticipated target in-service dates and estimated completion percentages for the Mildred Lake mine train replacements, the Aurora North mine train relocations, the composite tails plant at the Aurora North mine and the centrifuge plant at the Mildred Lake mine; the expectation that the Corporation will finance the major projects primarily with existing cash balances and cash flow from operations; the cost estimates for 2013 to 2015 major project spending; the expectation that the volatility in the Synthetic Crude Oil (“SCO”) to WTI differential is likely to persist for several years until additional pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast or the Canadian East or West Coasts; and the expectation that the differential between WTI and global crude oil prices will narrow as additional pipeline capacity comes on through 2013 and 2014.
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 January 31, 2013 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; Syncrude”s major project spending plans; 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 and resources 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; volatility of crude oil prices; volatility of the SCO to WTI price differential; unsuccessful or untimely implementation of capital or maintenance projects and such other risks and uncertainties described in the Corporation”s AIF dated February 23, 2012 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 and the related press release are made as of January 31, 2013, 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 and the related press release are expressly qualified by this cautionary statement.
Non-GAAP and Additional 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 GAAP. These financial measures include additional GAAP financial measures, which are line items, headings or subtotals in addition to those required under Canadian GAAP, and non-GAAP financial measures. Additional GAAP and 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 additional GAAP and non-GAAP financial measures presented by the Corporation may not be comparable with measures provided by other entities.
We refer to one additional GAAP financial measure: cash flow from operations, which is calculated as cash from operating activities, as reported on the Consolidated Statement of Cash Flows, before changes in non-cash working capital. 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) | 2012 | 2011 | 2012 | 2011 | |||||
| Cash flow from operations | $ | 418 | $ | 363 | $ | 1,581 | $ | 1,897 | |
| Change in non-cash working capital1 | 178 | (47 | ) | 283 | 61 | ||||
| Cash from operating activities1 | $ | 596 | $ | 316 | $ | 1,864 | $ | 1,958 | |
| (1) | As reported in the Consolidated Statements of Cash Flows. |
Non-GAAP financial measures include cash flow from operations per Share, which is calculated as cash flow from operations divided by the weighted-average number of Shares outstanding in the period; net debt; total debt; total net capitalization; total capitalization; net debt-to-total net capitalization; and total 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.
| Overview | ||||||||||
| Highlights | ||||||||||
| Three Months Ended | Year Ended | |||||||||
| December 31 | December 31 | |||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||
| Cash flow from operations1 ($ millions) | $ | 418 | $ | 363 | $ | 1,581 | $ | 1,897 | ||
| Per Share1 ($/Share) | $ | 0.86 | $ | 0.75 | $ | 3.26 | $ | 3.91 | ||
| Net income ($ millions) | $ | 221 | $ | 232 | $ | 981 | $ | 1,144 | ||
| Per Share, Basic and Diluted ($/Share) | $ | 0.46 | $ | 0.48 | $ | 2.02 | $ | 2.36 | ||
| Sales volumes2 | ||||||||||
| Total (mmbbls) | 10.3 | 8.4 | 38.7 | 38.7 | ||||||
| Daily average (bbls) | 111,669 | 91,259 | 105,680 | 106,015 | ||||||
| Realized SCO selling price ($/bbl) | $ | 89.99 | $ | 104.78 | $ | 91.90 | $ | 101.20 | ||
| West Texas Intermediate (“WTI”) (average $US/bbl) | $ | 88.23 | $ | 94.06 | $ | 94.15 | $ | 95.11 | ||
| SCO premium (discount) to WTI | $ | 2.43 | $ | 8.51 | $ | (2.52 | ) | $ | 7.32 | |
| (weighted average $/bbl) | ||||||||||
| Operating expenses ($/bbl) | $ | 38.85 | $ | 46.88 | $ | 39.06 | $ | 38.80 | ||
| Capital expenditures ($ millions) | $ | 299 | $ | 205 | $ | 1,086 | $ | 643 | ||
| Dividends ($ millions) | $ | 169 | $ | 146 | $ | 654 | $ | 533 | ||
| Per Share ($/Share) | $ | 0.35 | $ | 0.30 | $ | 1.35 | $ | 1.10 | ||
| (1) | Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined on page 5 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. |
To view cash flow from operations, please visit the following link: http://media3.marketwire.com/docs/131cos1.pdf.
Sales Volumes
Selling Price
Crown Royalties
Operating Expenses
Capital Expenditures
Net Debt
Dividends
Debt Issue
Review of Financial Results
Net Income
Net income decreased to $221 million, or $0.46 per Share, in the fourth quarter of 2012 from $232 million, or $0.48 per Share, in the fourth quarter of 2011, reflecting a lower realized selling price and a foreign exchange loss (as opposed to a foreign exchange gain in the 2011 fourth quarter), partially offset by higher sales volumes. The Corporation realizes foreign exchange gains and losses primarily as a result of revaluations of its U.S. dollar-denominated debt.
On an annual basis, net income decreased to $981 million, or $2.02 per Share, in 2012 from $1,144 million, or $2.36 per Share, in 2011, reflecting a lower realized selling price partially offset by lower Crown royalties, lower taxes, and a foreign exchange gain (as opposed to a loss in 2011).
The following table shows the components of net income per barrel of SCO:
| Three Months Ended | Year Ended | ||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||
| ($ per barrel)1 | 2012 | 2011 | $ Change | 2012 | 2011 | $ Change | |||||||||||||
| Sales net of crude oil purchases and transportation expense | $ | 90.44 | $ | 105.17 | $ | (14.73 | ) | $ | 92.21 | $ | 101.66 | $ | (9.45 | ) | |||||
| Operating expenses | (38.85 | ) | (46.88 | ) | 8.03 | (39.06 | ) | (38.80 | ) | (0.26 | ) | ||||||||
| Crown royalties | (5.57 | ) | (8.64 | ) | 3.07 | (5.21 | ) | (7.93 | ) | 2.72 | |||||||||
| $ | 46.02 | $ | 49.65 | $ | (3.63 | ) | $ | 47.94 | $ | 54.93 | $ | (6.99 | ) | ||||||
| Non-production expenses | $ | (2.55 | ) | $ | (3.19 | ) | $ | 0.64 | $ | (2.62 | ) | $ | (2.93 | ) | $ | 0.31 | |||
| Administration and insurance | (0.95 | ) | (1.14 | ) | 0.19 | (0.95 | ) | (0.85 | ) | (0.10 | ) | ||||||||
| Depreciation and depletion | (11.54 | ) | (11.40 | ) | (0.14 | ) | (10.41 | ) | (9.84 | ) | (0.57 | ) | |||||||
| Net finance expense | (0.66 | ) | (0.80 | ) | 0.14 | (1.01 | ) | (1.19 | ) | 0.18 | |||||||||
| Foreign exchange (loss) gain | (1.50 | ) | 2.66 | (4.16 | ) | 0.65 | (0.57 | ) | 1.22 | ||||||||||
| Tax expense | (7.33 | ) | (8.31 | ) | 0.98 | (8.23 | ) | (10.00 | ) | 1.77 | |||||||||
| $ | (24.53 | ) | $ | (22.18 | ) | $ | (2.35 | ) | $ | (22.57 | ) | $ | (25.38 | ) | $ | 2.81 | |||
| Net income per barrel | $ | 21.49 | $ | 27.47 | $ | (5.98 | ) | $ | 25.37 | $ | 29.55 | $ | (4.18 | ) | |||||
| Sales volumes (mmbbls)2 | 10.3 | 8.4 | 1.9 | 38.7 | 38.7 | – | |||||||||||||
| (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. |
| Sales Net of Crude Oil Purchases and Transportation Expense | |||||||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||
| ($ millions, except where otherwise noted) | 2012 | 2011 | $ Change | 2012 | 2011 | $ Change | |||||||||||||
| Sales1 | $ | 1,000 | $ | 973 | $ | 27 | $ | 3,905 | $ | 4,182 | $ | (277 | ) | ||||||
| Crude oil purchases | (55 | ) | (83 | ) | 28 | (295 | ) | (221 | ) | (74 | ) | ||||||||
| Transportation expense | (16 | ) | (6 | ) | (10 | ) | (44 | ) | (27 | ) | (17 | ) | |||||||
| $ | 929 | $ | 884 | $ | 45 | $ | 3,566 | $ | 3,934 | $ | (368 | ) | |||||||
| Sales volumes2 | |||||||||||||||||||
| Total (mmbbls) | 10.3 | 8.4 | 1.9 | 38.7 | 38.7 | – | |||||||||||||
| Daily average (bbls) | 111,669 | 91,259 | 20,410 | 105,680 | 106,015 | (335 | ) | ||||||||||||
| Realized SCO selling price3 | $ | 89.99 | $ | 104.78 | $ | (14.79 | ) | $ | 91.90 | $ | 101.20 | $ | (9.30 | ) | |||||
| (average $Cdn/bbl) | |||||||||||||||||||
| West Texas Intermediate (“WTI”) | $ | 88.23 | $ | 94.06 | $ | (5.83 | ) | $ | 94.15 | $ | 95.11 | $ | (0.96 | ) | |||||
| (average $US/bbl) | |||||||||||||||||||
| SCO premium (discount) to WTI | $ | 2.43 | $ | 8.51 | $ | (6.08 | ) | $ | (2.52 | ) | $ | 7.32 | $ | (9.84 | ) | ||||
| (weighted average $Cdn/bbl) | |||||||||||||||||||
| Average foreign exchange rate | $ | 1.01 | $ | 0.98 | $ | 0.03 | $ | 1.00 | $ | 1.01 | $ | (0.01 | ) | ||||||
| ($US/$Cdn) | |||||||||||||||||||
| (1) | Sales include sales of purchased crude oil and sulphur. |
| (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 $45 million, or five per cent, increase in fourth quarter 2012 sales, net of crude oil purchases and transportation expense, reflects higher sales volumes partially offset by a lower average realized SCO selling price relative to the 2011 fourth quarter.
Fourth quarter 2012 sales volumes averaged 111,700 barrels per day, up from 91,300 barrels per day in the 2011 fourth quarter, when production was impacted by the unplanned Coker 8-1 and hydrogen unit outages.
The fourth quarter 2012 realized selling price averaged $89.99 per barrel, a $14.79 per barrel decrease from $104.78 per barrel in the fourth quarter of 2011. The Corporation realized a $2.43 per barrel weighted-average SCO premium to WTI in the fourth quarter of 2012 compared with an $8.51 per barrel premium in the fourth quarter of 2011. WTI averaged U.S. $88 per barrel and the Canadian dollar averaged U.S. $1.01 in the 2012 fourth quarter compared with U.S. $94 per barrel and U.S. $0.98, respectively, in the 2011 fourth quarter.
On an annual basis, the $368 million, or nine per cent, decrease in 2012 sales, net of crude oil purchases and transportation expense, reflects a lower average realized SCO selling price.
The realized selling price in 2012 averaged $91.90 per barrel compared with $101.20 per barrel in 2011. The Corporation realized a $2.52 per barrel weighted-average SCO discount to WTI in 2012 as opposed to a $7.32 per barrel premium in 2011. WTI averaged U.S. $94 per barrel and the Canadian dollar averaged U.S. $1.00 in 2012, compared with U.S. $95 per barrel and U.S. $1.01, respectively, in 2011.
The SCO to WTI differential reflects supply/demand fundamentals for inland North American light crude oil. Increasing North American production of both SCO and light crude oil, and refinery modifications that enable processing of heavier crude oils, can push light crude sales, including SCO, to more distant refineries, thereby increasing transportation costs and reducing the net realized price. A number of pipelines in both Canada and the United States are at, or near, capacity and any pipeline apportionments can exacerbate this situation by restricting the ability of SCO and other crude oils to reach preferred markets. However, strong demand from customers and increases in rail shipments of inland crude to coastal refineries can offset these forces. These supply and demand dynamics create price volatility that is likely to persist for several years until additional pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast, or the Canadian East or West Coasts.
Certain of these same fundamentals are also impacting the prices of Canadian heavy oil, such as Western Canadian Select (“WCS”), which is the heavy oil reference price used as a starting point to calculate Syncrude Crown royalties. WCS is generally priced at a discount to WTI, and this discount increased in the fourth quarter of 2012 relative to the comparative 2011 quarter, contributing to lower Crown royalties.
Sales volumes averaged 105,700 barrels per day in 2012 compared with 106,000 barrels per day in 2011.
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 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 2012 fourth quarter relative to the comparative 2011 period, reflecting additional purchased volumes in 2011 to support unanticipated production shortfalls. On an annual basis, crude oil purchases were higher in 2012 relative to 2011, reflecting additional purchased volumes to support transportation arrangements.
Operating Expenses
The following table breaks down operating expenses into their major components:
| Three Months Ended | Year Ended | |||||||||||||||
| December 31 | December 31 | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| $ millions | $ per bbl | $ millions | $ per bbl | $ millions | $ per bbl | $ millions | $ per bbl | |||||||||
| Production1 | $ | 320 | $ | 31.11 | $ | 297 | $ | 35.40 | $ | 1,242 | $ | 32.12 | $ | 1,163 | $ | 30.08 |
| Natural gas and diesel purchases2 | 38 | 3.67 | 46 | 5.47 | 125 | 3.22 | 194 | 5.01 | ||||||||
| Pension and long-term compensation | 32 | 3.16 | 37 | 4.45 | 103 | 2.67 | 100 | 2.58 | ||||||||
| Other3 | 9 | 0.91 | 13 | 1.56 | 41 | 1.05 | 44 | 1.13 | ||||||||
| Total operating expenses | $ | 399 | $ | 38.85 | $ | 393 | $ | 46.88 | $ | 1,511 | $ | 39.06 | $ | 1,501 | $ | 38.80 |
| (1) | Includes maintenance (planned and unplanned) as well as non-major turnaround costs. Major turnaround costs are capitalized as property, plant and equipment. |
| (2) | Includes costs to purchase natural gas used to produce energy and hydrogen and diesel consumed as fuel. |
| (3) | Includes fees for management services provided by Imperial Oil Resources, insurance premiums, and greenhouse gas emissions levies. |
On a total dollar basis, operating expenses in the fourth quarter of 2012 were similar to the fourth quarter of 2011, reflecting higher production costs largely offset by decreases in other operating expense components. The increase in production costs was due primarily to:
On an annual basis, total operating expenses in 2012 were similar to 2011, reflecting higher production costs largely offset by lower natural gas and diesel purchases. The increase in production costs was due primarily to:
The lower natural gas and diesel purchases reflect lower natural gas prices and diesel volumes relative to 2011.
Per-barrel operating expenses decreased in the fourth quarter of 2012, mainly as a result of higher production volumes.
The following table 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 | Year Ended | |||||||||||||||||||
| December 31 | December 31 | |||||||||||||||||||
| 2012 | 20113 | 2012 | 20113 | |||||||||||||||||
| ($ per barrel) | Bitumen | SCO | Bitumen | SCO | Bitumen | SCO | Bitumen | SCO | ||||||||||||
| Bitumen production | $ | 24.67 | $ | 28.44 | $ | 29.58 | $ | 35.18 | $ | 25.70 | $ | 29.73 | $ | 24.43 | $ | 29.07 | ||||
| Internal fuel allocation1 | 2.05 | 2.37 | 2.47 | 2.93 | 2.11 | 2.44 | 2.40 | 2.85 | ||||||||||||
| Total bitumen production expenses | $ | 26.72 | $ | 30.81 | $ | 32.05 | $ | 38.11 | $ | 27.81 | $ | 32.17 | $ | 26.83 | $ | 31.92 | ||||
| Upgrading2 | $ | 10.41 | $ | 11.70 | $ | 9.33 | $ | 9.73 | ||||||||||||
| Less: internal fuel allocation to | (2.37 | ) | (2.93 | ) | (2.44 | ) | (2.85 | ) | ||||||||||||
| bitumen production1 | ||||||||||||||||||||
| Total upgrading expenses | $ | 8.04 | $ | 8.77 | $ | 6.89 | $ | 6.88 | ||||||||||||
| Total operating expenses | $ | 38.85 | $ | 46.88 | $ | 39.06 | $ | 38.80 | ||||||||||||
| (thousands of barrels per day) | ||||||||||||||||||||
| Syncrude production volumes | 345 | 299 | 300 | 252 | 331 | 287 | 343 | 288 | ||||||||||||
| Canadian Oil Sands sales volumes | 122 | 91 | 106 | 106 | ||||||||||||||||
| (1) | Reflects energy generated by the upgrader that is used in the bitumen production process and is valued by reference to natural gas and diesel prices. Natural gas prices averaged $3.02 per GJ and $2.34 per GJ in the three months and year ended December 31, 2012, respectively, and $3.19 per GJ and $3.48 per GJ in the three months and year ended December 31, 2011, respectively. Diesel prices averaged $0.90 per litre in the three months and year ended December 31, 2012, and $1.08 per litre and $0.94 per litre in the three months and year ended December 31, 2011, respectively. |
| (2) | Upgrading expenses include the production and maintenance expenses associated with processing and upgrading bitumen to SCO. |
| (3) | Certain comparative period amounts have been restated to conform to the current period presentation. |
Crown Royalties
Crown royalties decreased to $57 million, or $5.57 per barrel, in the fourth quarter of 2012, from $73 million, or $8.64 per barrel, in the fourth quarter of 2011 due primarily to increases in deductible capital expenditures, partially offset by higher bitumen volumes in the 2012 quarter. On an annual basis, Crown royalties decreased to $202 million, or $5.21 per barrel, in 2012 from $307 million, or $7.93 per barrel, in 2011 due primarily to increases in deductible capital expenditures in 2012. The higher capital expenditures in 2012 reflect increased spending on capital projects to replace or relocate Syncrude mine trains and to support tailings management plans.
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 reference price further adjusted to reflect quality and location differences between Syncrude”s bitumen and the Canadian reference price bitumen. In addition, the agreement provides that a minimum bitumen value, or “floor price,” may be imposed in circumstances where Canadian heavy oil prices are temporarily suppressed relative to North American heavy oil prices.
Canadian Oil Sands” share of the royalties recognized for the period from January 1, 2009 to December 31, 2012 reflect management”s best estimate of both reasonable quality and transportation deductions and adjustments to reflect the “floor price.” However, the Syncrude owners and the Alberta government are disputing the basis for the quality, transportation and “floor price” adjustments. Under alternate assumptions, Crown royalties for this period could be as much as $55 million (on an after-tax basis) more than the amounts recognized.
The Syncrude owners and the Alberta government continue to discuss these matters, but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. The cumulative impact, if any, of such discussions or judicial determination, as applicable, would be recognized and impact both net income and cash flow from operations accordingly.
Non-Production Expenses
Non-production expenses totalled $26 million and $101 million in the 2012 fourth quarter and full year, respectively, compared with $27 million and $113 million in the comparative 2011 periods. 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 from period to period depending on the number of projects underway and the development stage of the projects.
Depreciation and Depletion Expense
Depreciation and depletion expense totalled $119 million and $403 million in the 2012 fourth quarter and full year, respectively, compared with $96 million and $381 million in the comparative 2011 periods, reflecting changes made during the fourth quarter of 2012 to the estimated useful lives of certain assets.
| Net Finance Expense | |||||||||||||
| Three Months Ended | Year Ended | ||||||||||||
| December 31 | December 31 | ||||||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | |||||||||
| Interest costs1 | $ | 26 | $ | 20 | $ | 105 | $ | 87 | |||||
| Less capitalized interest | (26 | ) | (18 | ) | (92 | ) | (57 | ) | |||||
| Interest expense | $ | – | $ | 2 | $ | 13 | $ | 30 | |||||
| Accretion of asset retirement obligation | 7 | 4 | 26 | 16 | |||||||||
| Net finance expense | $ | 7 | $ | 6 | $ | 39 | $ | 46 | |||||
| (1) | Interest costs are net of interest income of $3 million and $12 million for the three months and year ended December 31, 2012, respectively ($2 million and $4 million for the three months and year ended December 31, 2011, respectively). |
Interest costs in 2012 were higher than the comparative 2011 periods as a result of the U.S. $700 million debt issued on March 29, 2012. However, interest expense in 2012 was lower than the comparative 2011 periods because a higher portion of interest costs were capitalized in 2012, as cumulative capital expenditures on qualifying assets rose. The period-over-period increases in accretion of the asset retirement obligation from 2011 to 2012 reflect the increase in the estimated asset retirement obligation recognized in the fourth quarter of 2011.
| Foreign Exchange (Gain) Loss | ||||||||
| Three Months Ended | Year Ended | |||||||
| December 31 | December 31 | |||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | ||||
| Foreign exchange (gain) loss – long-term debt | $ 20 | $ (24 | ) | $ (28 | ) | $ 25 | ||
| Foreign exchange (gain) loss – other | (4 | ) | 1 | 3 | (3 | ) | ||
| Total foreign exchange (gain) loss | $ 16 | $ (23 | ) | $ (25 | ) | $ 22 | ||
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./Cdn dollar exchange rates.
The foreign exchange loss on long-term debt in the 2012 fourth quarter was the result of a weakening Canadian dollar to U.S. $1.01 at December 31, 2012 from U.S. $1.02 at September 30, 2012. The foreign exchange gain for the full year 2012 was the result of a strengthening Canadian dollar from U.S. $0.98 at December 31, 2011. Conversely, the foreign exchange gain in the 2011 fourth quarter was the result of a strengthening Canadian dollar to U.S. $0.98 at December 31, 2011 from U.S. $0.96 at September 30, 2011, and the foreign exchange loss for the full year 2011 was the result of a weakening Canadian dollar from U.S. $1.01 at December 31, 2010.
| Tax Expense | ||||||||
| Three Months Ended | Year Ended | |||||||
| December 31 | December 31 | |||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | ||||
| Current tax expense | $ | 10 | $ | – | $ | 40 | $ | – |
| Deferred tax expense | 65 | 70 | 278 | 387 | ||||
| Total tax expense | $ | 75 | $ | 70 | $ | 318 | $ | 387 |
The quarter-over-quarter increase in total tax expense from 2011 to 2012 reflects higher earnings before tax in the 2012 quarter, while the decrease in the annual total tax expense from 2011 to 2012 reflects lower earnings before tax in 2012.
| Asset Retirement Obligation | ||||||
| Year Ended | ||||||
| December 31 | ||||||
| ($ millions) | 2012 | 2011 | ||||
| Asset retirement obligation, beginning of year | $ | 1,037 | $ | 501 | ||
| Change in risk-free interest rate | 68 | 98 | ||||
| Change in estimated liability | 25 | 471 | ||||
| Accretion expense | 26 | 16 | ||||
| Liabilities settled | (54 | ) | (49 | ) | ||
| Asset retirement obligation, end of year | $ | 1,102 | $ | 1,037 | ||
| Less current portion | (44 | ) | (29 | ) | ||
| Non-current portion | $ | 1,058 | $ | 1,008 | ||
Canadian Oil Sands increased its estimated asset retirement obligation from $1,037 million at December 31, 2011 to $1,102 million at December 31, 2012. The increase reflects:
partially offset by:
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 decreased to $438 million at December 31, 2012 from $465 million at December 31, 2011, reflecting contributions to the plans and higher than estimated returns on plan assets, partially offset by a decrease in the interest rate used to discount future pension costs.
| Summary of Quarterly Results | |||||||||||||||||
| 2012 | 2011 | ||||||||||||||||
| Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||
| Sales1 ($ millions) | $ | 929 | $ | 941 | $ | 740 | $ | 956 | $ | 884 | $ | 989 | $ | 1,045 | $ | 1,016 | |
| Net income ($ millions) | $ | 221 | $ | 338 | $ | 101 | $ | 321 | $ | 232 | $ | 242 | $ | 346 | $ | 324 | |
| Per Share, Basic & Diluted | $ | 0.46 | $ | 0.70 | $ | 0.21 | $ | 0.66 | $ | 0.48 | $ | 0.50 | $ | 0.71 | $ | 0.67 | |
| Cash flow from operations2 ($ millions) | $ | 418 | $ | 470 | $ | 245 | $ | 454 | $ | 363 | $ | 512 | $ | 544 | $ | 478 | |
| Per Share2 | $ | 0.86 | $ | 0.97 | $ | 0.51 | $ | 0.94 | $ | 0.75 | $ | 1.06 | $ | 1.12 | $ | 0.99 | |
| Dividends ($ millions) | $ | 169 | $ | 170 | $ | 170 | $ | 145 | $ | 146 | $ | 145 | $ | 145 | $ | 97 | |
| Per Share | $ | 0.35 | $ | 0.35 | $ | 0.35 | $ | 0.30 | $ | 0.30 | $ | 0.30 | $ | 0.30 | $ | 0.20 | |
| Daily average sales volumes3 (bbls) | 111,669 | 113,331 | 89,597 | 108,108 | 91,259 | 109,260 | 102,938 | 120,894 | |||||||||
| Realized SCO selling price ($/bbl) | $ | 89.99 | $ | 89.89 | $ | 90.45 | $ | 97.07 | $ | 104.78 | $ | 97.89 | $ | 111.00 | $ | 93.04 | |
| Operating expenses4 ($/bbl) | $ | 38.85 | $ | 36.71 | $ | 50.66 | $ | 32.68 | $ | 46.88 | $ | 37.19 | $ | 37.07 | $ | 35.53 | |
| Purchased natural gas price ($/GJ) | $ | 3.02 | $ | 2.00 | $ | 1.79 | $ | 2.23 | $ | 3.19 | $ | 3.51 | $ | 3.62 | $ | 3.59 | |
| WTI5 (average $US/bbl) | $ | 88.23 | $ | 92.20 | $ | 93.35 | $ | 103.03 | $ | 94.06 | $ | 89.54 | $ | 102.34 | $ | 94.60 | |
| Foreign exchange rates ($US/$Cdn) | |||||||||||||||||
| Average | $ | 1.01 | $ | 1.00 | $ | 0.99 | $ | 1.00 | $ | 0.98 | $ | 1.02 | $ | 1.03 | $ | 1.02 | |
| Quarter-end | $ | 1.01 | $ | 1.02 | $ | 0.98 | $ | 1.00 | $ | 0.98 | $ | 0.96 | $ | 1.04 | $ | 1.03 | |
| (1) | Sales after crude oil purchases and transportation expense. |
| (2) | Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined on page 5 of this report. |
| (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:
Quarterly variances in net income and cash flow from operations are caused mainly by fluctuations in realized selling prices, production and sales volumes, operating expenses and natural gas prices. Net income is also impacted by foreign exchange gains and losses, depreciation and depletion, and tax expense. The dividends paid to Shareholders are likewise dependent on the factors impacting cash flow from operations as well as the amount and timing of capital expenditures.
While the supply/demand balance for crude oil affects selling prices, the impact of this relationship 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.
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. All turnarounds and maintenance activities impact per barrel operating expenses because sales volumes are lower in the periods when this work is occurring.
| Capital Expenditures | |||||||||
| Three Months Ended | Year Ended | ||||||||
| December 31 | December 31 | ||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | |||||
| Major Projects | |||||||||
| Mildred Lake Mine Train Replacement | $ | 96 | $ | 62 | $ | 362 | $ | 139 | |
| Reconstruct crushers, surge facilities, and slurry prep facilities to support tailings storage requirements | |||||||||
| Aurora North Mine Train Relocation | 34 | 12 | 98 | 27 | |||||
| Relocate crushers, surge facilities, and slurry prep facilities to support tailings storage requirements | |||||||||
| Aurora North Tailings Management | 32 | 19 | 123 | 40 | |||||
| Construct a composite tails (CT) plant at the Aurora North mine to process tailings | |||||||||
| Centrifuge Tailings Management | 34 | 39 | 69 | 39 | |||||
| Construct a centrifuge plant at the Mildred Lake mine to process tailings | |||||||||
| Syncrude Emissions Reduction (SER) | 4 | 14 | 21 | 110 | |||||
| Retrofit technology into Syncrude”s original two cokers to reduce total sulphur dioxide and other emissions | |||||||||
| Capital expenditures on major projects | $ | 200 | $ | 146 | $ | 673 | $ | 355 | |
| Regular maintenance | |||||||||
| Capitalized turnaround costs | $ | – | $ | 21 | $ | 76 | $ | 44 | |
| Other capital1 | 73 | 20 | 245 | 187 | |||||
| Capital expenditures on regular maintenance | $ | 73 | $ | 41 | $ | 321 | $ | 231 | |
| Capitalized interest | $ | 26 | $ | 18 | $ | 92 | $ | 57 | |
| Total capital expenditures | $ | 299 | $ | 205 | $ | 1,086 | $ | 643 | |
| (1) | Other regular maintenance capital includes expenditures on relocation of tailings facilities and other infrastructure projects. |
Capital expenditures increased to $1,086 million in 2012 from $643 million in 2011, and to $299 million in the fourth quarter of 2012 from $205 million in the fourth quarter of 2011. The increases reflect spending on the major capital projects at Syncrude. More information on the major projects is provided in the “Outlook” section of this MD&A.
The increase in capitalized turnaround costs in 2012 reflects the planned turnarounds of Coker 8-3 and the Vacuum Distillation Unit. By comparison, 2011 capitalized turnaround costs reflect the Coker 8-2 turnaround.
The increase in capitalized interest costs in 2012 reflects higher cumulative capital expenditures on qualifying assets.
Contractual Obligations and Commitments
During 2012, Canadian Oil Sands entered into new contractual obligations totalling approximately $1.3 billion for the transportation and storage of crude oil in support of the Corporation”s strategy to secure access to preferred markets and enhance marketing flexibility. The Corporation also assumed $250 million in new funding commitments primarily related to the major capital projects discussed in the “Outlook” section of this MD&A, increased its funding commitment by $110 million in respect of Syncrude Canada”s registered pension plan, and assumed $70 million in new commitments related to Syncrude Canada”s employee retention program.
Dividends
On January 31, 2013, the Corporation declared a quarterly dividend of $0.35 per Share for a total dividend of approximately $170 million. The dividend will be paid on February 28, 2013 to Shareholders of record on February 22, 2013. During 2012, the Corporation paid dividends to shareholders totalling $654 million, or $1.35 per Share.
Dividend payments are set quarterly by the Board of Directors in the context of current and expected crude oil prices, economic conditions, Syncrude”s operating performance, and the Corporation”s capacity to finance operating and investing obligations. Dividend levels are established with the intent of absorbing short-term market volatility over several quarters. Dividend levels also recognize our intention to fund the current major projects primarily with cash flow from operations and existing cash balances, while maintaining a strong balance sheet to reduce exposure to potential oil price declines, capital cost increases or major operational upsets.
| Liquidity and Capital Resources | ||||||
| December 31 | December 31 | |||||
| ($ millions, except % amounts) | 2012 | 2011 | ||||
| Total debt1,2 | $ | 1,794 | $ | 1,132 | ||
| Cash and cash equivalents | (1,553 | ) | (718 | ) | ||
| Net debt1,3 | $ | 241 | $ | 414 | ||
| Shareholders” equity | $ | 4,515 | $ | 4,210 | ||
| Total net capitalization1,4 | $ | 4,756 | $ | 4,624 | ||
| Total capitalization1,5 | $ | 6,309 | $ | 5,342 | ||
| Net debt-to-total net capitalization1,6 (%) | 5 | 9 | ||||
| Total debt-to-total capitalization1,7 (%) | 28 | 21 | ||||
| (1) | Non-GAAP measure. |
| (2) | Includes current and non-current portions of long-term debt. |
| (3) | Total debt less cash and cash equivalents. |
| (4) | Net debt plus Shareholders” equity. |
| (5) | Total debt plus Shareholders” equity. |
| (6) | Net debt divided by total net capitalization. |
| (7) | Total debt divided by total capitalization. |
Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, decreased to $0.2 billion at December 31, 2012 from $0.4 billion at December 31, 2011. As a result, net debt-to-total net capitalization fell to five per cent at December 31, 2012 from nine per cent at December 31, 2011. While $1,581 million of cash flow from operations in 2012 fell short of capital expenditures and dividend payments of $1,086 million and $654 million, respectively, a reduction in non-cash working capital more than offset this difference. Shareholders” equity increased to $4.5 billion at December 31, 2012 from $4.2 billion at December 31, 2011, as net income exceeded dividends in 2012.
In June 2012, the Corporation extended the terms of its credit facilities by one year. The term of the $1,500 million operating credit facility was extended to June 1, 2016 and the $40 million extendible revolving term credit facility to June 30, 2014. No amounts were drawn against these facilities at December 31, 2012.
In March 2012, Canadian Oil Sands issued U.S. $400 million of 4.5 per cent senior unsecured notes due April 1, 2022 and U.S. $300 million of 6.0 per cent senior unsecured notes due April 1, 2042 (collectively, the “Notes”). Interest on the Notes is payable semi-annually on April 1 and October 1. Proceeds from the issues will be used to repay U.S. $300 million of senior notes, which mature on August 15, 2013, to fund major capital projects over the next few years and for general corporate purposes. As a result of these issues, total debt-to-total capitalization rose to 28 per cent at December 31, 2012 from 21 per cent at December 31, 2011.
The senior notes indentures and credit facility agreements contain certain covenants that 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. Canadian Oil Sands is in compliance with its debt covenants and, with a total debt-to-total capitalization of 28 per cent at December 31, 2012, a significant increase in debt or decrease in equity would be required to negatively impact the Corporation”s financial flexibility.
The Corporation”s liquidity position has improved in 2012 as a result of our growing cash position and the issuance of the Notes. We expect cash levels to decrease significantly over the next two years as we fund major capital projects and repay the 2013 debt maturity. As a result, and based on the assumptions in our Outlook, net debt levels are expected to rise to $1 billion to $2 billion by the end of 2014, coincident with reduced capital expenditure risk from the completion of our major capital projects.
Shareholders” Capital and Trading Activity
The Corporation”s shares trade on the Toronto Stock Exchange under the symbol COS. On December 31, 2012, the Corporation had a market capitalization of approximately $9.8 billion with 484.6 million shares outstanding and a closing price of $20.17 per Share. The following table summarizes the trading activity for the fourth quarter of 2012.
| Canadian Oil Sands Limited – Trading Activity | |||||||||||||
| Fourth | |||||||||||||
| Quarter | October | November | December | ||||||||||
| 2012 | 2012 | 2012 | 2012 | ||||||||||
| Share price | |||||||||||||
| High | $ | 21.69 | $ | 21.60 | $ | 21.69 | $ | 20.50 | |||||
| Low | $ | 19.10 | $ | 20.27 | $ | 19.70 | $ | 19.10 | |||||
| Close | $ | 20.17 | $ | 21.20 | $ | 20.16 | $ | 20.17 | |||||
| Volume of Shares traded (millions) | 81.9 | 29.8 | 25.8 | 26.3 | |||||||||
| Weighted average Shares outstanding (millions) | 484.6 | 484.6 | 484.6 | 484.6 | |||||||||
Financial Instruments and Financial Risks
The Corporation”s financial instruments include cash and cash equivalents, accounts receivable, reclamation trust investments, accounts payable, accrued liabilities and current and non-current portions of long-term debt. The nature, the Corporation”s use of, and the risks associated with these instruments are unchanged from December 31, 2011. The Corporation did not have any financial derivatives outstanding in 2012.
Changes in Accounting Policies
There were no new accounting policies adopted, nor any changes to accounting policies, in 2012.
| 2013 Outlook | ||||||
| As of | As of | |||||
| January 31 | November 29 | |||||
| (millions of Canadian dollars, except volume and per barrel amounts) | 2013 | 2012 | ||||
| Operating assumptions | ||||||
| Syncrude production (mmbbls) | 110 | 110 | ||||
| Canadian Oil Sands sales (mmbbls) | 40.4 | 40.4 | ||||
| Sales, net of crude oil purchases and transportation | $ | 3,233 | $ | 3,233 | ||
| Operating expenses | $ | 1,482 | $ | 1,482 | ||
| Operating expenses per barrel | $ | 36.67 | $ | 36.67 | ||
| Crown royalties | $ | 113 | $ | 113 | ||
| Cash flow from operations | $ | 1,045 | $ | 1,045 | ||
| Capital expenditure assumptions | ||||||
| Major projects | $ | 836 | $ | 836 | ||
| Regular maintenance | $ | 393 | $ | 393 | ||
| Capitalized interest | $ | 97 | $ | 97 | ||
| Total capital expenditures | $ | 1,326 | $ | 1,326 | ||
| Business environment assumptions | ||||||
| West Texas Intermediate (U.S.$/bbl) | $ | 85.00 | $ | 85.00 | ||
| Discount to average Cdn$ WTI prices (Cdn$/bbl) | $ | (5.00 | ) | $ | (5.00 | ) |
| Foreign exchange rate (U.S.$/Cdn$) | $ | 1.00 | $ | 1.00 | ||
| AECO natural gas (Cdn$/GJ) | $ | 3.50 | $ | 3.50 | ||
All amounts in this 2013 Outlook dated January 31, 2013 are unchanged from the 2013 Outlook provided in the Corporation”s guidance document dated November 29, 2012.
Canadian Oil Sands continues to estimate annual Syncrude production of 105 to 115 million barrels for 2013. For the purpose of generating our 2013 Outlook, we have selected a single-point production estimate of 110 million barrels (301,400 barrels per day). Net to Canadian Oil Sands, the single-point estimate is equivalent to 40.4 million barrels (110,700 barrels per day). The production estimate incorporates a planned turnaround of Coker 8-1 in the second half of the year.
Sales, net of crude oil purchases and transportation expense, are estimated to be approximately $3.2 billion, reflecting our 40.4 million barrel production estimate and an $80 per barrel plant-gate realized selling price. The estimated selling price assumes a U.S. $85 per barrel WTI oil price, a foreign exchange rate of $1.00 U.S./Cdn, and a SCO discount to Cdn dollar WTI of $5.00 per barrel.
The $5.00 per barrel SCO discount to WTI reflects our assessment of supply/demand fundamentals for inland North American light crude oil. Increasing North American production of SCO and light crude oil, and refinery modifications that enable processing of heavier crude oils, can push light crude sales, including SCO, to more distant refineries, thereby increasing transportation costs and reducing the net realized price. A number of pipelines in both Canada and the United States are at, or near, capacity and any pipeline apportionments can exacerbate this situation by restricting the ability of SCO and other crude oils to reach preferred markets. However, strong demand from customers and increases in rail shipments of inland crude to coastal refineries can offset these forces. These supply and demand dynamics create price volatility that is likely to persist for several years until additional pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast, or the Canadian East or West Coasts.
We are estimating operating expenses of approximately $1.5 billion in 2013, 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 estimate, this translates to operating expenses of $36.67 per barrel.
Non-production expenses are estimated to rise by $55 million over 2012 to $156 million, reflecting development activity around higher capital spending in 2013.
Also, mainly as a result of higher 2013 capital expenditures, allowable deductible costs for royalty purposes in 2013 are anticipated to exceed deemed bitumen revenues. As a result, Canadian Oil Sands is estimating minimum royalties at one per cent of gross deemed bitumen revenues (instead of 25 per cent of net deemed bitumen revenue) in 2013. We will continue to expense the transition royalty and upgrader growth capital recapture.
Capital expenditures are estimated to total $1,326 million in 2013, comprised of $836 million of spending on major projects, $393 million in regular maintenance of the business and other projects, and $97 million in capitalized interest.
We estimate current taxes of approximately $350 million in 2013. We expect deductions for capital expenditures made in 2012 and 2013 will be available for deduction in 2014 and beyond, resulting in lower current taxes in subsequent years, under the assumptions outlined in the 2013 Outlook.
We estimate 2013 cash flow from operations of $1,045 million, or $2.16 per Share.
We expect cash levels to decrease significantly over the next two years as we fund major capital projects and repay the 2013 debt maturity. As a result, net debt levels are expected to rise to $1 billion to $2 billion by the end of 2014, coincident with reduced capital expenditure risk from the completion of the major capital projects.
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 (January 31, 2013) | |||
| Cash Flow from Operations | |||
| Increase | |||
| Variable | Annual Sensitivity | $ millions1,2 | $ / Share1,2 |
| Syncrude operating expense decrease | Cdn$1.00/bbl | $30 | $0.06 |
| Syncrude operating expense decrease | Cdn$50 million | $14 | $0.03 |
| WTI crude oil price increase | U.S.$1.00/bbl | $30 | $0.06 |
| Syncrude production increase | 2 million bbls | $44 | $0.09 |
| Canadian dollar weakening | U.S.$0.01/Cdn$ | $25 | $0.05 |
| AECO natural gas price decrease | Cdn$0.50/GJ | $16 | $0.03 |
| (1) | Canadian Oil Sands anticipates recording approximately $350 million in current taxes in 2013. These sensitivities are after the impact of taxes. |
| (2) | These sensitivities assume Canadian Oil Sands remains in minimum royalty in 2013. |
The 2013 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. Regular maintenance capital costs for years after 2013 will be provided on an annual basis when we disclose the budgets for those years, and are currently estimated to average approximately $10 per barrel over the next few years.
| Major Projects – Total Project Cost and Schedule Estimates1 | ||||||
| Total Cost Estimate ($ billions) |
Estimated % Complete at Dec 31, 20122 |
Estimated % Accuracy |
Target In-Service Date |
|||
| Mildred Lake | ||||||
| Mine Train Replacement | Syncrude | $ 4.2 | 35 | +15%/-15% | Q4 2014 | |
| Reconstruct crushers, surge facilities, and slurry prep facilities to support tailings storage requirements | COS share | 1.6 | ||||
| Aurora North Mine Train Relocation | Syncrude | $ 1.0 | 55 | +15%/-15% | Q1 2014 | |
| Relocate crushers, surge facilities, and slurry prep facilities to support tailings storage requirements | COS share | 0.4 | ||||
| Aurora North Tailings Management | Syncrude | $ 0.8 | 70 | +15%/-15% | Q4 2013 | |
| Construct a composite tails (CT) plant at the Aurora North mine to process tailings | COS share | 0.3 | ||||
| Centrifuge Tailings Management | Syncrude | $ 1.9 | 10 | +15%/-15% | H1 2015 | |
| Construct a centrifuge plant at the Mildred Lake mine to process tailings | COS share | 0.7 | ||||
| Major Projects – Annual Spending Profile1 | |||||
| Spent to | |||||
| ($ billions) | Dec 31, 2012 | 2013 | 2014 | 2015 | Total |
| Syncrude | $ 2.6 | $ 2.4 | $ 2.3 | $ 0.6 | $ 7.9 |
| Canadian Oil Sands share | $ 1.0 | $ 0.9 | $ 0.9 | $ 0.2 | $ 3.0 |
| (1) | Major projects costs include capital expenditures, excluding capitalized interest, and certain non-production expenses. |
| (2) | The estimated percentage complete is based on hours spent as a percentage of total forecasted hours to project completion. |
Canadian Oil Sands plans to finance these major projects primarily with existing cash balances and 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 February 23, 2012 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 of Canadian dollars, except per Share and Share volume amounts) | 2012 | 2011 | 2012 | 2011 | |||||||||
| Sales | $ | 1,000 | $ | 973 | $ | 3,905 | $ | 4,182 | |||||
| Crown royalties (Note 16) | (57 | ) | (73 | ) | (202 | ) | (307 | ) | |||||
| Revenues | $ | 943 | $ | 900 | $ | 3,703 | $ | 3,875 | |||||
| Expenses | |||||||||||||
| Operating | $ | 399 | $ | 393 | $ | 1,511 | $ | 1,501 | |||||
| Non-production | 26 | 27 | 101 | 113 | |||||||||
| Crude oil purchases and transportation | 71 | 89 | 339 | 248 | |||||||||
| Administration | 7 | 8 | 26 | 25 | |||||||||
| Insurance | 2 | 2 | 10 | 8 | |||||||||
| Depreciation and depletion | 119 | 96 | 403 | 381 | |||||||||
| $ | 624 | $ | 615 | $ | 2,390 | $ | 2,276 | ||||||
| Earnings from operating activities | $ | 319 | $ | 285 | $ | 1,313 | $ | 1,599 | |||||
| Foreign exchange loss (gain) (Note 11) | 16 | (23 | ) | (25 | ) | 22 | |||||||
| Net finance expense (Note 12) | 7 | 6 | 39 | 46 | |||||||||
| Earnings before taxes | $ | 296 | $ | 302 | $ | 1,299 | $ | 1,531 | |||||
| Tax expense (Note 13) | 75 | 70 | 318 | 387 | |||||||||
| Net income | $ | 221 | $ | 232 | $ | 981 | $ | 1,144 | |||||
| Other comprehensive loss, net of income taxes | |||||||||||||
| Actuarial gain (loss) on employee future benefit plans (Note 10) | 7 | (56 | ) | (21 | ) | (128 | ) | ||||||
| Reclassification of derivative gains to net income | (1 | ) | (1 | ) | (3 | ) | (3 | ) | |||||
| Comprehensive income | $ | 227 | $ | 175 | $ | 957 | $ | 1,013 | |||||
| Weighted average Shares (millions) | 485 | 485 | 485 | 485 | |||||||||
| Shares, end of period (millions) | 485 | 485 | 485 | 485 | |||||||||
| Net income per Share | |||||||||||||
| Basic and diluted | $ | 0.46 | $ | 0.48 | $ | 2.02 | $ | 2.36 | |||||
| See Notes to Unaudited Consolidated Financial Statements | |||||||||||||
| Consolidated Statements of Shareholders” Equity | |||||||||||||
| (unaudited) | |||||||||||||
| Three Months Ended | Year Ended | ||||||||||||
| December 31 | December 31 | ||||||||||||
| (millions of Canadian dollars) | 2012 | 2011 | 2012 | 2011 | |||||||||
| Retained earnings | |||||||||||||
| Balance, beginning of period | $ | 1,764 | $ | 1,487 | $ | 1,517 | $ | 1,034 | |||||
| Net income | 221 | 232 | 981 | 1,144 | |||||||||
| Actuarial gain (loss) on employee future benefit plans | 7 | (56 | ) | (21 | ) | (128 | ) | ||||||
| Dividends | (169 | ) | (146 | ) | (654 | ) | (533 | ) | |||||
| Balance, end of period | $ | 1,823 | $ | 1,517 | $ | 1,823 | $ | 1,517 | |||||
| Accumulated other comprehensive income | |||||||||||||
| Balance, beginning of period | $ | 10 | $ | 13 | $ | 12 | $ | 15 | |||||
| Reclassification of derivative gains to net income | (1 | ) | (1 | ) | (3 | ) | (3 | ) | |||||
| Balance, end of period | $ | 9 | $ | 12 | $ | 9 | $ | 12 | |||||
| Shareholders” capital | |||||||||||||
| Balance, beginning of period | $ | 2,673 | $ | 2,672 | $ | 2,673 | $ | 2,671 | |||||
| Issuance of shares | – | 1 | – | 2 | |||||||||
| Balance, end of period | $ | 2,673 | $ | 2,673 | $ | 2,673 | $ | 2,673 | |||||
| Contributed surplus | |||||||||||||
| Balance, beginning of period | $ | 9 | $ | 7 | $ | 8 | $ | 6 | |||||
| Share-based compensation | 1 | 1 | 2 | 2 | |||||||||
| Balance, end of period | 10 | 8 | 10 | 8 | |||||||||
| Total Shareholders” equity | $ | 4,515 | $ | 4,210 | $ | 4,515 | $ | 4,210 | |||||
| See Notes to Unaudited Consolidated Financial Statements | |||||||||||||
| Consolidated Balance Sheets | ||||||
| (unaudited) | ||||||
| As at | ||||||
| December 31 | December 31 | |||||
| (millions of Canadian dollars) | 2012 | 2011 | ||||
| ASSETS | ||||||
| Current assets | ||||||
| Cash and cash equivalents | $ | 1,553 | $ | 718 | ||
| Accounts receivable | 311 | 376 | ||||
| Inventories | 137 | 142 | ||||
| Prepaid expenses | 9 | 10 | ||||
| $ | 2,010 | $ | 1,246 | |||
| Property, plant and equipment, net (Note 4) | 8,003 | 7,227 | ||||
| Exploration and evaluation | 89 | 89 | ||||
| Reclamation trust | 69 | 58 | ||||
| $ | 10,171 | $ | 8,620 | |||
| LIABILITIES AND SHAREHOLDERS” EQUITY | ||||||
| Current liabilities | ||||||
| Accounts payable and accrued liabilities (Note 5) | $ | 704 | $ | 479 | ||
| Current portion of long-term debt | 297 | – | ||||
| Current taxes | 40 | – | ||||
| Current portion of employee future benefits | 76 | 47 | ||||
| $ | 1,117 | $ | 526 | |||
| Employee future benefits | 362 | 418 | ||||
| Other liabilities (Note 6) | 89 | 62 | ||||
| Long-term debt (Note 8) | 1,497 | 1,132 | ||||
| Asset retirement obligation (Note 9) | 1,058 | 1,008 | ||||
| Deferred taxes | 1,533 | 1,264 | ||||
| $ | 5,656 | $ | 4,410 | |||
| Shareholders” equity | 4,515 | 4,210 | ||||
| $ | 10,171 | $ | 8,620 | |||
| Commitments and Contingencies (Notes 15 and 16, respectively) | ||||||
| See Notes to Unaudited Consolidated Financial Statements | ||||||
| Consolidated Statements of Cash Flows | ||||||||||||||
| (unaudited) | ||||||||||||||
| Three Months Ended | Year Ended | |||||||||||||
| December 31 | December 31 | |||||||||||||
| (millions of Canadian dollars) | 2012 | 2011 | 2012 | 2011 | ||||||||||
| Cash from (used in) operating activities | ||||||||||||||
| Net income | $ | 221 | $ | 232 | $ | 981 | $ | 1,144 | ||||||
| Items not requiring an outlay of cash | ||||||||||||||
| Depreciation and depletion | 119 | 96 | 403 | 381 | ||||||||||
| Accretion of asset retirement obligation (Note 9) | 7 | 4 | 26 | 16 | ||||||||||
| Foreign exchange (gain)loss on long-term debt (Note 11) | 20 | (24 | ) | (28 | ) | 25 | ||||||||
| Deferred tax expense (Note 13) | 65 | 70 | 278 | 387 | ||||||||||
| Share-based compensation | 3 | (1 | ) | 5 | 2 | |||||||||
| Reclamation expenditures | (6 | ) | (14 | ) | (54 | ) | (49 | ) | ||||||
| Change in employee future benefits and other | (11 | ) | – | (30 | ) | (9 | ) | |||||||
| Cash flow from operations | $ | 418 | $ | 363 | $ | 1,581 | $ | 1,897 | ||||||
| Change in non-cash working capital (Note 17) | 178 | (47 | ) | 283 | 61 | |||||||||
| Cash from operating activities | $ | 596 | $ | 316 | $ | 1,864 | $ | 1,958 | ||||||
| Cash from (used in) financing activities | ||||||||||||||
| Issuance of senior notes (Note 8) | $ | – | $ | – | $ | 689 | $ | – | ||||||
| Repayment of bank credit facilities | – | – | – | (145 | ) | |||||||||
| Issuance of shares | – | 1 | – | 2 | ||||||||||
| Dividends | (169 | ) | (146 | ) | (654 | ) | (533 | ) | ||||||
| Cash from (used in) financing activities | $ | (169 | ) | $ | (145 | ) | $ | 35 | $ | (676 | ) | |||
| Cash from (used in) investing activities | ||||||||||||||
| Capital expenditures | $ | (299 | ) | $ | (205 | ) | $ | (1,086 | ) | $ | (643 | ) | ||
| Reclamation trust funding | (3 | ) | (1 | ) | (10 | ) | (5 | ) | ||||||
| Change in non-cash working capital (Note 17) | (44 | ) | (17 | ) | 34 | 4 | ||||||||
| Cash used in investing activities | $ | (346 | ) | $ | (223 | ) | $ | (1,062 | ) | $ | (644 | ) | ||
| Foreign exchange (gain) loss on cash and cash equivalents held in foreign currency | $ | 3 | $ | – | $ | (2 | ) | $ | – | |||||
| Increase (decrease) in cash and cash equivalents | $ | 84 | $ | (52 | ) | $ | 835 | $ | 638 | |||||
| Cash and cash equivalents, beginning of period | 1,469 | 770 | 718 | 80 | ||||||||||
| Cash and cash equivalents, end of period | $ | 1,553 | $ | 718 | $ | 1,553 | $ | 718 | ||||||
| Cash and cash equivalents consist of: | ||||||||||||||
| Cash | $ | 607 | $ | 326 | $ | 607 | $ | 326 | ||||||
| Short-term investments | 946 | 392 | 946 | 392 | ||||||||||
| $ | 1,553 | $ | 718 | $ | 1,553 | $ | 718 | |||||||
| Supplementary Information (Note 17) | ||||||||||||||
| See Notes to Unaudited Consolidated Financial Statements | ||||||||||||||
Notes to Unaudited Consolidated Financial Statements
For the Three Months and Year Ended December 31, 2012
(Tabular amounts expressed in millions of Canadian dollars, except where otherwise noted)
1) Nature of Operations
Canadian Oil Sands Limited (“Canadian Oil Sands” or the “Corporation”) was incorporated in 2010 under the laws of the Province of Alberta, Canada pursuant to a plan of arrangement effecting the reorganization from an income trust into a corporate structure effective December 31, 2010.
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 near Fort McMurray in northern Alberta. The Syncrude Project is comprised of open-pit oil sands mines, utilities plants, bitumen extraction plants, and an upgrading complex that processes bitumen into Synthetic Crude Oil. Each joint-venture owner, including the Corporation, takes its proportionate share of production in kind, and funds its proportionate share of Syncrude”s operating and capital costs on a daily basis. The Corporation also owns 36.74 per cent of the issued and outstanding shares of Syncrude Canada Ltd. (“Syncrude Canada”). Syncrude Canada operates Syncrude on behalf of the joint-venture owners and is responsible for selecting, compensating, directing and controlling Syncrude”s employees, and for administering all related employment benefits and obligations. The Corporation”s investment in Syncrude and Syncrude Canada represents its only producing asset.
The Corporation”s office is located at the following address: 2500 First Canadian Centre, 350 – 7th Avenue S.W., Calgary, Alberta, Canada T2P 3N9.
2) Basis of Presentation
These unaudited interim consolidated financial statements are prepared and reported in Canadian dollars in accordance with Canadian generally accepted accounting principles as set out in the Handbook of the Canadian Institute of Chartered Accountants (“CICA Handbook”). The CICA Handbook incorporates International Financial Reporting Standards (“IFRS”) and publicly accountable enterprises, such as the Corporation, are required to apply such standards. These unaudited interim financial statements have been prepared in accordance with IFRS applicable to the preparation of interim finanacial statements and International Accounting Standard (“IAS”) 34, Interim Financial Reporting, and the accounting policies applied in these interim unaudited consolidated financial statements are based on IFRS as issued, outstanding and effective on January 31, 2013.
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 audited consolidated financial statements and notes thereto for the year ended December 31, 2011.
3) Accounting Policies
The same accounting policies and methods of computation are followed in these unaudited interim consolidated financial statements as compared with the most recent audited annual consolidated financial statements for the year ended December 31, 2011 except for current income taxes which, in interim periods, are accrued based on an estimate of the annualized effective tax rate applied to year-to-date earnings.
4) Property, Plant and Equipment, Net
| Year Ended December 31, 2012 | ||||||||||||||||||
| ($ millions) | Upgrading and extracting | Mining equipment | Vehicles and equipment | Buildings | Asset Retirement costs | Major Turnaround costs | Construction in progress | Mine development | Total | |||||||||
| Cost | ||||||||||||||||||
| Balance at January 1, 2012 | $ 4,688 | $ 1,417 | $ 690 | $ 310 | $ 931 | $ 114 | $ 1,144 | $ 393 | $ 9,687 | |||||||||
| Additions | – | – | 23 | – | – | 76 | 987 | – | 1,086 | |||||||||
| Change in asset retirement costs | – | – | – | – | 93 | – | – | – | 93 | |||||||||
| Retirements | (3 | ) | (20 | ) | (27 | ) | (1 | ) | – | (24 | ) | – | (1 | ) | (76 | ) | ||
| Reclassifications1 | 615 | – | – | 15 | – | – | (630 | ) | – | – | ||||||||
| Balance at December 31, 2012 | $ 5,300 | $ 1,397 | $ 686 | $ 324 | $ 1,024 | $ 166 | $ 1,501 | $ 392 | $ 10,790 | |||||||||
| Accumulated depreciation | ||||||||||||||||||
| Balance at January 1, 2012 | $ 1,284 | $ 480 | $ 294 | $ 100 | $ 138 | $ 53 | $ – | $ 111 | $ 2,460 | |||||||||
| Depreciation | 166 | 79 | 53 | 8 | 42 | 44 | – | 11 | 403 | |||||||||
| Retirements | (3 | ) | (20 | ) | (27 | ) | (1 | ) | – | (24 | ) | – | (1 | ) | (76 | ) | ||
| Reclassifications | – | – | – | – | – | – | – | – | – | |||||||||
| Balance at December 31, 2012 | $ 1,447 | $ 539 | $ 320 | $ 107 | $ 180 | $ 73 | $ – | $ 121 | $ 2,787 | |||||||||
| Net book value at December 31, 2012 | $ 3,853 | $ 858 | $ 366 | $ 217 | $ 844 | $ 93 | $ 1,501 | $ 271 | $ 8,003 | |||||||||
| Year Ended December 31, 2011 | ||||||||||||||||||
| ($ millions) | Upgrading and extracting | Mining equipment | Vehicles and equipment | Buildings | Asset Retirement costs | Major Turnaround costs | Construction in progress | Mine development | Total | |||||||||
| Cost | ||||||||||||||||||
| Balance at January 1, 2011 | $ 4,669 | $ 1,381 | $ 688 | $ 304 | $ 362 | $ 103 | $ 694 | $ 345 | $ 8,546 | |||||||||
| Additions | – | – | – | – | – | 43 | 600 | – | 643 | |||||||||
| Change in asset retirement costs | – | – | – | – | 569 | – | – | – | 569 | |||||||||
| Retirements | (6 | ) | (9 | ) | (22 | ) | (1 | ) | – | (32 | ) | – | (1 | ) | (71 | ) | ||
| Reclassifications1 | 25 | 45 | 24 | 7 | – | – | (150 | ) | 49 | – | ||||||||
| Balance at December 31, 2011 | $ 4,688 | $ 1,417 | $ 690 | $ 310 | $ 931 | $ 114 | $ 1,144 | $ 393 | $ 9,687 | |||||||||
| Accumulated depreciation | ||||||||||||||||||
| Balance at January 1, 2011 | $ 1,092 | $ 449 | $ 264 | $ 100 | $ 103 | $ 50 | $ – | $ 92 | $ 2,150 | |||||||||
| Depreciation | 169 | 92 | 54 | 7 | 14 | 35 | – | 10 | 381 | |||||||||
| Retirements | (6 | ) | (9 | ) | (22 | ) | (1 | ) | – | (32 | ) | – | (1 | ) | (71 | ) | ||
| Reclassifications | 29 | (52 | ) | (2 | ) | (6 | ) | 21 | – | – | 10 | – | ||||||
| Balance at December 31, 2011 | $ 1,284 | $ 480 | $ 294 | $ 100 | $ 138 | $ 53 | $ – | $ 111 | $ 2,460 | |||||||||
| Net book value at | ||||||||||||||||||
| December 31, 2011 | $ 3,404 | $ 937 | $ 396 | $ 210 | $ 793 | $ 61 | $ 1,144 | $ 282 | $ 7,227 | |||||||||
| (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, 2012, interest costs of $26 million and $92 million, respectively, were capitalized and included in property, plant and equipment (three months and year ended December 31, 2011 – $18 million and $57 million, respectively) based on 6.5 per cent and 6.7 per cent interest capitalization rates for the three months and year ended December 31, 2012, respectively (7.3 per cent for the three months and year ended December 31, 2011).
5) Accounts Payable and Accrued Liabilities
| December 31 | December 31 | |||||
| ($ millions) | 2012 | 2011 | ||||
| Trade payables | $ | 498 | $ | 381 | ||
| Accrued liabilities for Crown royalties | 215 | 109 | ||||
| Current portion of asset retirement obligation | 44 | 29 | ||||
| Interest payable | 29 | 21 | ||||
| $ | 786 | $ | 540 | |||
| Less non-current portion of accrued liabilities for Crown royalties | (82 | ) | (61 | ) | ||
| Accounts payable and accrued liabilities | $ | 704 | $ | 479 | ||
6) Other Liabilities
| December 31 | December 31 | ||||
| ($ millions) | 2012 | 2011 | |||
| Accrued liabilities for Crown royalties | $ | 82 | $ | 61 | |
| Other | 7 | 1 | |||
| Other liabilities | $ | 89 | $ | 62 | |
7) Bank Credit Facilities
In 2012, the Corporation extended the terms of its credit facilities by one year. The term of the $1,500 million operating credit facility was extended to June 1, 2016 and the $40 million extendible revolving term credit facility to June 30, 2014. No amounts were drawn against these facilities at December 31, 2012 (December 31, 2011 – $nil).
8) Long-Term Debt
On March 29, 2012, the Corporation issued U.S. $400 million of 4.50 per cent unsecured Senior Notes maturing April 1, 2022 and U.S. $300 million of 6.00 per cent unsecured Senior Notes maturing April 1, 2042. Interest on the new Senior Notes is payable semi-annually on April 1 and October 1. The Senior Notes are unsecured, rank pari passu with other senior unsecured debt of the Corporation, and contain certain covenants that place limitations on the sale of assets and the granting of liens or other security interests.
9) Asset Retirement Obligation
The Corporation and each of the other Syncrude owners are liable for their share of ongoing obligations related to the ultimate reclamation and closure of the Syncrude properties on abandonment. The Corporation estimates reclamation and closure expenditures will be made progressively over the next 70 years and has applied a risk-free interest rate of 2.25 per cent at December 31, 2012 (December 31, 2011 – 2.50 per cent) in deriving the asset retirement obligation. The risk-free rate is based on the yield for benchmark Government of Canada long-term bonds.
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the Corporation”s share of the obligation associated with the reclamation and closure of the Syncrude properties:
| Year Ended | Year Ended | |||||
| December 31 | December 31 | |||||
| ($ millions) | 2012 | 2011 | ||||
| Asset retirement obligation, beginning of year | $ | 1,037 | $ | 501 | ||
| Change in risk-free interest rate | 68 | 98 | ||||
| Change in estimated liability | 25 | 471 | ||||
| Accretion expense | 26 | 16 | ||||
| Liabilities settled | (54 | ) | (49 | ) | ||
| Asset retirement obligation, end of year | $ | 1,102 | $ | 1,037 | ||
| Less current portion | (44 | ) | (29 | ) | ||
| Non-current portion | $ | 1,058 | $ | 1,008 |
The $25 million increase in the estimated liability was capitalized as property, plant and equipment. The $44 million current portion of the asset retirement obligation is included in accounts payable and accrued liabilities, while the $1,058 million non-current portion is presented separately as an asset retirement obligation on the December 31, 2012 Consolidated Balance Sheet. The total undiscounted estimated cash flows required to settle Canadian Oil Sand”s share of the asset retirement obligation were $2,104 million at December 31, 2012 (December 31, 2011 – $2,210 million).
10) Employee Future Benefits
The Corporation”s share of Syncrude Canada”s defined benefit and contribution plans” costs for the three months and year ended December 31, 2012 and 2011 is based on its 36.74 per cent working interest. The costs have been recorded in operating expenses and other comprehensive income as follows:
| Three Months Ended | Year Ended | ||||||||||||
| December 31 | December 31 | ||||||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | |||||||||
| Operating expenses | |||||||||||||
| Defined benefit plans | |||||||||||||
| Pension plan | $ | 14 | $ | 12 | $ | 45 | $ | 36 | |||||
| Other post employment benefits plan | 1 | 1 | 4 | 4 | |||||||||
| $ | 15 | $ | 13 | $ | 49 | $ | 40 | ||||||
| Defined contribution plans | – | 1 | 3 | 3 | |||||||||
| $ | 15 | $ | 14 | $ | 52 | $ | 43 | ||||||
| Other comprehensive income | |||||||||||||
| Defined benefit plans | |||||||||||||
| Actuarial (gain) loss on pension plan | (7 | ) | 56 | 21 | 128 | ||||||||
| Total benefit cost | $ | 8 | $ | 70 | $ | 73 | $ | 171 | |||||
The Corporation”s share of the estimated unfunded portion of Syncrude Canada”s pension and other post-employment benefit plans decreased to $438 million at December 31, 2012 from $465 million at December 31, 2011, reflecting contributions to the plans and higher than estimated returns on plan assets, partially offset by a lower interest rate used to discount future pension costs. The impact of the interest rate decrease, net of higher than estimated returns on plan assets, is reflected as a $21 million actuarial loss, net of $7 million in deferred taxes, in 2012 Other Comprehensive Income. A liability for the $438 million unfunded balance is recognized on the December 31, 2012 Consolidated Balance Sheet.
11) Foreign Exchange
| Three Months Ended | Year Ended | ||||||||||||||
| December 31 | December 31 | ||||||||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
| Foreign exchange (gain) loss – long-term debt | $ | 20 | $ | (24 | ) | $ | (28 | ) | $ | 25 | |||||
| Foreign exchange (gain) loss – other | (4 | ) | 1 | 3 | (3 | ) | |||||||||
| Total foreign exchange (gain) loss | $ | 16 | $ | (23 | ) | $ | (25 | ) | $ | 22 | |||||
12) Net Finance Expense
| Three Months Ended | Year Ended | |||||||||||||||
| December 31 | December 31 | |||||||||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | ||||||||||||
| Interest costs1 | $ | 26 | $ | 20 | $ | 105 | $ | 87 | ||||||||
| Less capitalized interest | (26 | ) | (18 | ) | (92 | ) | (57 | ) | ||||||||
| Interest expense | $ | – | $ | 2 | $ | 13 | $ | 30 | ||||||||
| Accretion of asset retirement obligation (Note 9) | 7 | 4 | 26 | 16 | ||||||||||||
| Net finance expense | $ | 7 | $ | 6 | $ | 39 | $ | 46 | ||||||||
| (1) | Interest costs are net of interest income of $3 million and $12 million for the three months and year ended December 31, 2012, respectively ($2 million and $4 million for the three months and year ended December 31, 2011, respectively). |
13) Tax Expense
| Three Months Ended | Year Ended | ||||||||||
| December 31 | December 31 | ||||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | |||||||
| Current tax expense | $ | 10 | $ | – | $ | 40 | $ | – | |||
| Deferred tax expense | 65 | 70 | 278 | 387 | |||||||
| Total tax expense | $ | 75 | $ | 70 | $ | 318 | $ | 387 | |||
14) Capital Management
The Corporation”s capital consists of cash and cash equivalents, debt and Shareholders” equity. The balance of each of these items at December 31, 2012 and December 31, 2011 was as follows:
| December 31 | December 31 | ||||||
| ($ millions, except % amounts) | 2012 | 2011 | |||||
| Total debt1,2 | $ | 1,794 | $ | 1,132 | |||
| Cash and cash equivalents | (1,553 | ) | (718 | ) | |||
| Net debt1,3 | $ | 241 | $ | 414 | |||
| Shareholders” equity | $ | 4,515 | $ | 4,210 | |||
| Total net capitalization1,4 | $ | 4,756 | $ | 4,624 | |||
| Total capitalization1,5 | $ | 6,309 | $ | 5,342 | |||
| Net debt-to-total net capitalization1,6 (%) | 5 | 9 | |||||
| Total debt-to-total capitalization1,7 (%) | 28 | 21 | |||||
| (1) | Non-GAAP measure. |
| (2) | Includes current and non-current portions of long-term debt. |
| (3) | Total debt less cash and cash equivalents. |
| (4) | Net debt plus Shareholders” equity. |
| (5) | Total debt plus Shareholders” equity. |
| (6) | Net debt divided by total net capitalization. |
| (7) | Total debt divided by total capitalization. |
Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, decreased to $0.2 billion at December 31, 2012 from $0.4 billion at December 31, 2011. As a result, net debt-to-total net capitalization fell to five per cent at December 31, 2012 from nine per cent at December 31, 2011. While $1,581 million of cash flow from operations in 2012 fell just short of capital expenditures and dividend payments of $1,086 million and $654 million, respectively, a reduction in non-cash working capital balances more than offset this difference.
Shareholders” equity increased to $4.5 billion at December 31, 2012 from $4.2 billion at December 31, 2011, as net income exceeded dividends in 2012.
Total debt-to-total capitalization rose to 28 per cent at December 31, 2012 from 21 per cent at December 31, 2011 as a result of the March 29, 2012 long-term debt issues.
As disclosed in Notes 9 and 10 to the 2011 annual consolidated financial statements, the Corporation”s senior notes indentures and credit facility agreements contain certain covenants which 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. Canadian Oil Sands is in compliance with its debt covenants and, with a total debt-to-total capitalization of 28 per cent at December 31, 2012, a significant increase in debt or decrease in equity would be required to negatively impact the Corporation”s financial flexibility.
15) Commitments
Commitments are summarized in Canadian Oil Sands” 2011 annual consolidated financial statements 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 2012, Canadian Oil Sands entered into new contractual obligations totalling approximately $1.3 billion for the transportation and storage of crude oil in support of the Corporation”s strategy to secure access to preferred markets and enhance marketing flexibility. The Corporation also assumed $250 million in new funding commitments relating to major capital projects, increased its funding commitment by $110 million in respect of Syncrude Canada”s registered pension plan, and assumed $70 million in new commitments related to Syncrude Canada”s employee retention program.
16) Contingencies
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 reference price further adjusted to reflect quality and location differences between Syncrude”s bitumen and the Canadian reference price bitumen. In addition, the agreement provides that a minimum bitumen value, or “floor price,” may be imposed in circumstances where Canadian heavy oil prices are temporarily suppressed relative to North American heavy oil prices.
Canadian Oil Sands” share of the royalties recognized for the period from January 1, 2009 to December 31, 2012 reflect management”s best estimate of both reasonable quality and transportation deductions and adjustments to reflect the “floor price.” However, the Syncrude owners and the Alberta government are disputing the basis for the quality, transportation and “floor price” adjustments. Under alternate assumptions, Crown royalties for this period could be as much as $55 million (on an after-tax basis) more than the amounts recognized.
The Syncrude owners and the Alberta government continue to discuss these matters, but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. The cumulative impact, if any, of such discussions or judicial determination, as applicable, would be recognized and impact both net income and cash flow from operations accordingly.
17) Supplementary Information
a) Change in Non-Cash Working Capital
| Three Months Ended | Year Ended | |||||||||||||||
| December 31 | December 31 | |||||||||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | ||||||||||||
| Operating activities: | ||||||||||||||||
| Accounts receivable (“AR”) | $ | 75 | $ | (79 | ) | $ | 65 | $ | 4 | |||||||
| Inventories | – | 1 | 5 | (13 | ) | |||||||||||
| Prepaid expenses | 2 | (1 | ) | 1 | (4 | ) | ||||||||||
| Accounts payable and accrued liabilities (“AP”) | 73 | 12 | 265 | 75 | ||||||||||||
| Less: AP and AR changes reclassified to investing and other | 28 | 20 | (53 | ) | (1 | ) | ||||||||||
| Change in operating non-cash working capital | $ | 178 | $ | (47 | ) | $ | 283 | $ | 61 | |||||||
| Investing activities: | ||||||||||||||||
| Accounts payable and accrued liabilities | $ | (44 | ) | $ | (17 | ) | $ | 34 | $ | 4 | ||||||
| Change in investing non-cash working capital | $ | (44 | ) | $ | (17 | ) | $ | 34 | $ | 4 | ||||||
| Change in total non-cash working capital | $ | 134 | $ | (64 | ) | $ | 317 | $ | 65 | |||||||
b) Income Taxes and Interest Paid
| Three Months Ended | Year Ended | ||||||||||
| December 31 | December 31 | ||||||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | |||||||
| Income taxes paid | $ | – | $ | – | $ | – | $ | – | |||
| Interest paid | $ | 41 | $ | 24 | $ | 106 | $ | 95 | |||
Income taxes and interest expense are included within cash from operating activities on the Consolidated Statements of Cash Flows. The portion of interest costs that is capitalized as property, plant and equipment is included within cash used in investing activities on the Consolidated Statements of Cash Flows.
18) Comparative figures
Certain comparative figures have been reclassified to conform to the current periods” presentation.
Canadian Oil Sands Limited
Marcel Coutu, President & Chief Executive Officer
Shares Listed – Symbol: COS
Toronto Stock Exchange