Canadian Oil Sands Announces 2013 Financial Results and a $0.35 per Share Dividend

Marketwired

CALGARY, ALBERTA--(Marketwired - Jan 30, 2014) - Canadian Oil Sands Limited ( COS.TO )( COSWF ) -

All financial figures are unaudited and in Canadian dollars unless otherwise noted.

Highlights for the three months and year ended December 31, 2013:

  • Cash flow from operations was $392 million ($0.81 per Share) in the fourth quarter of 2013 compared with cash flow from operations of $418 million ($0.86 per Share) in the same quarter of 2012. For the 2013 year, cash flow from operations totalled $1,349 million ($2.78 per Share), down 15 per cent from $1,581 million ($3.26 per Share) in 2012.
  • The quarter-over-quarter change in cash flow from operations primarily reflects higher current taxes partially offset by a higher realized selling price. The year-over-year change in cash flow from operations reflects higher current taxes, with lower sales volumes offsetting a higher realized selling price.
  • Net income for the fourth quarter of 2013 was $192 million ($0.40 per Share), down from $218 million ($0.45 per Share) in the 2012 fourth quarter. On an annual basis, net income was $834 million ($1.72 per Share) in 2013 compared with $973 million ($2.01 per Share) in 2012.
  • COS maintained its quarterly dividend at $0.35 per Share, payable on February 28, 2014 to shareholders of record on February 21, 2014. During 2013, the Corporation paid a total of $678 million, or $1.40 per Share, in dividends to shareholders.
  • Sales volumes averaged 98,000 barrels per day in 2013 compared with volumes averaging 105,700 barrels per day in 2012.
  • Operating expenses were $1,494 million, or $41.75 per barrel, in 2013, compared with operating expenses of $1,505 million, or $38.91 per barrel, in 2012. The increase in per barrel operating expenses in 2013 relative to 2012 reflects lower sales volumes.
  • Syncrude completed its Aurora North Tailings Management and Aurora North Mine Train Relocation projects in 2013, ahead of schedule and about $200 million (gross to Syncrude) under budget.
  • Capital expenditures increased to $1,342 million in 2013 from $1,086 million in 2012, as planned, to execute Syncrude's major capital projects.
  • Net debt (total debt less cash and cash equivalents) increased to $796 million at December 31, 2013 from $241 million at December 31, 2012. COS plans to continue drawing down its cash balance in 2014 to fund the major capital projects, which is expected to increase net debt levels during 2014.

"We achieved a key milestone during the quarter with the completion of two of Syncrude's major projects. We can now look forward to the completion of the remaining two projects and the potential for free cash flow expansion following the decline in capital expenditures after 2014," said Ryan Kubik, President and Chief Executive Officer. "Syncrude operations performed largely as expected in the fourth quarter of 2013 and we remain focused on delivering more consistent production levels in 2014."

Highlights

...
Three Months Ended Year Ended
December 31 December 31
2013 2012 2013 2012
Cash flow from operations 1 ($ millions) $ 392 $ 418 $ 1,349 $ 1,581
Per Share 1 ($/Share) $ 0.81 $ 0.86 $ 2.78 $ 3.26
Net income ($ millions) $ 192 $ 218 $ 834 $ 973
Per Share, Basic and Diluted ($/Share) $ 0.40 $ 0.45 $ 1.72 $ 2.01
Sales volumes 2
Total (mmbbls) 10.3 10.3 35.8 38.7
Daily average (bbls) 112,092 111,669 98,037 105,680
Realized SCO selling price ($/bbl) $ 91.47 $ 89.99 $ 99.55 $ 91.90
West Texas Intermediate ("WTI") (average $US/bbl) $ 97.61 $ 88.23 $ 98.05 $ 94.15
SCO premium (discount) to WTI $ (10.84 ) $ 2.52 $ (1.10 ) $ (2.42 )
(weighted average $/bbl)
Operating expenses ($ millions) $ 388 $ 398 $ 1,494 $ 1,505 Per barrel ($/bbl) $ 37.60 $ 38.76 $ 41.75 $ 38.91 Capital expenditures ($ millions) $ 292 $ 299 $ 1,342 $ 1,086 Dividends ($ millions) $ 169 $ 169 $ 678 $ 654 Per Share ($/Share) $ 0.35 $ 0.35 $ 1.40 $ 1.35 1Cash flow from operations and cash flow from operations per Share are additional GAAP financial measures and are defined in the "Additional GAAP Financial Measures" section of our Management's Discussion and Analysis ("MD&A"). 2The 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 307,600 barrels per day (total 28.3 million barrels) during the fourth quarter of 2013, up from 298,900 barrels per day (total 27.5 million barrels) during the same 2012 period.

In 2013 Syncrude production averaged about 267,000 barrels per day (total 97.5 million barrels) compared with about 286,500 barrels per day (total 104.9 million barrels) in 2012. The decrease in 2013 volumes primarily reflects delays completing turnarounds on the Coker 8-1, LC Finer and secondary upgrading units. Production volumes in both 2013 and 2012 reflect unplanned outages in extraction units.

Progress on Syncrude's major capital projects is tracking to plan, with the Mildred Lake Mine Train Replacement project reaching an estimated 80 per cent completion and the Centrifuge Tailings Management project reaching 70 per cent completion at the end of 2013. The Aurora North Mine Train Relocation and Aurora North Tailings Management projects were completed in 2013.

Syncrude recently released its 2012 Sustainability Report, which is available on Syncrude's website at the following link: http://syncrudesustainability.com/2012/. 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.

2014 Outlook

The following highlights Canadian Oil Sands' key estimates and assumptions for 2014:

  • We estimate an annual production range for Syncrude of 95 million to 110 million barrels in 2014. The single-point production figure of 105 million barrels, 38.6 million barrels net to COS, incorporates the turnaround of Coker 8-2 in the second quarter of the year.
  • Sales, net of crude oil purchases and transportation expense, of approximately $3.4 billion reflect a production estimate of 38.6 million barrels net to COS and an $88 per barrel plant-gate realized selling price (based on a U.S. $90 per barrel WTI oil price, a foreign exchange rate of $0.97 U.S./Cdn, and a SCO discount to Cdn dollar WTI of $5 per barrel).
  • We estimate cash flow from operations of $1,158 million, or $2.39 per Share.
  • Capital expenditures are estimated to total $1,097 million, comprised of $653 million of spending on major projects, $361 million in regular maintenance of the business and other projects, and $83 million in capitalized interest.

More information on the 2014 Outlook is provided in our MD&A and the January 30, 2014 guidance document, which is available on our web site at www.cdnoilsands.com under "Investor Centre".

The 2014 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 30, 2014 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, 2013 and December 31, 2012, the audited consolidated financial statements and MD&A of the Corporation for the year ended December 31, 2012 and the Corporation's Annual Information Form ("AIF") dated February 21, 2013. 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", "COS" 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 otherwise noted.

Table of Contents

1. Advisories 4-6
2. Overview 7
3. Review of Financial Results 8-14
4. Summary of Quarterly Results 15-16
5. Capital Expenditures 16
6. Contractual Obligations and Commitments 16
7. Dividends 17
8. Liquidity and Capital Resources 17-18
9. Shareholders' Capital and Trading Activity 18
10. Changes in Accounting Policies 18
11. 2014 Outlook 19-20
12. Major Projects 21

Advisories

Forward Looking Information

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 2014 annual Syncrude forecasted production range of 95 million barrels to 110 million barrels and the single-point Syncrude production estimate of 105 million barrels (38.6 million barrels net to the Corporation; the timing of the Coker 8-2 turnaround; the intention to fund the Syncrude major projects primarily with cash flow from operations and existing cash balances; the establishment of future dividend levels with the intent of absorbing short-term market volatility over several quarters; the expected sales, operating expenses, purchased energy costs, development expenses, Crown royalties, capital expenditures and cash flow from operations for 2014; the anticipated amount of current taxes in 2014; expectations regarding the Corporation's cash levels for 2014; the expected price for crude oil and natural gas in 2014; the expected foreign exchange rates in 2014; the expected realized selling price, which includes the anticipated differential to West Texas Intermediate ("WTI") to be received in 2014 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 belief that fluctuations in the Corporation's realized selling prices, U.S. to Canadian dollar exchange rate fluctuations and planned and unplanned maintenance activities may impact the Corporation's financial results in the future; the expected amount of total major project costs, anticipated target in-service dates and estimated completion percentages for the Mildred Lake mine train replacements and the centrifuge plant at the Mildred Lake mine; the cost estimates for 2014 and 2015 major project spending; and 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.

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 30, 2014 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 product; the unanimous joint venture owner approval for major expansions and changes in product types; the variances of stock market activities generally; 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 74; currency and interest rate fluctuations; volatility of crude oil prices; volatility of the SCO to WTI price differential; unsuccessful or untimely implementation of capital or maintenance projects; various events that could disrupt operations, including fires, equipment failures and severe weather and such other risks and uncertainties described in the Corporation's AIF dated February 21, 2013 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 30, 2014, 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.

Additional GAAP Financial Measures

In this MD&A and the related press release, we refer to additional GAAP financial measures that do not have any standardized meaning as prescribed by Canadian GAAP. Additional GAAP financial measures are line items, headings or subtotals in addition to those required under Canadian GAAP, and financial measures disclosed in the notes to the financial statements which are relevant to an understanding of the financial statements and are not presented elsewhere in the financial statements. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. Users are cautioned that additional GAAP financial measures presented by the Corporation may not be comparable with measures provided by other entities.

Additional GAAP financial measures include: cash flow from operations, cash flow from operations per Share, net debt, total net capitalization, total capitalization, net debt-to-total net capitalization and long-term debt-to-total capitalization.

Cash flow from operations is calculated as cash from operating activities 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. Because cash flow from operations and cash flow from operations per Share are not impacted by fluctuations in non-cash working capital balances, we believe these measures are more indicative of operational performance than cash from operating activities. With the exception of current tax payable, liabilities for Crown royalties and the current portion of our asset retirement obligation, 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) 2013 2012 2013 2012
Cash flow from operations1 $ 392 $ 418 $ 1,349 $ 1,581
Change in non-cash working capital1 75 178 233 283
Cash from operating activities1 $ 467 $ 596 $ 1,582 $ 1,864
1As reported in the Consolidated Statements of Cash Flows.

Net debt, total net capitalization, total capitalization, net debt-to-total net capitalization and long-term debt-to-total capitalization are used by the Corporation to analyze liquidity and manage capital, as discussed in the "Liquidity and Capital Resources" section of this MD&A and in Note 12 to the unaudited consolidated financial statements for the three months and year ended December 31, 2013.

Overview

Synthetic crude oil ("SCO") production from the Syncrude Joint Venture ("Syncrude") totalled 28.3 million barrels, or 307,600 barrels per day, in the fourth quarter of 2013 and 97.5 million barrels, or 267,000 barrels per day, for the full year, which is within the 97 to 100 million barrel range forecast provided in our 2013 Outlook dated October 30, 2013 (included in the third quarter 2013 MD&A). Canadian Oil Sands sales volumes averaged 112,100 barrels per day in the fourth quarter and 98,000 barrels per day in the full year 2013.

COS' realized selling price for the quarter was also in line with our October 2013 Outlook and averaged approximately $91 per barrel, reflecting a U.S. $98 per barrel West Texas Intermediate ("WTI") oil price, an average foreign exchange rate of 0.95 $US/$Cdn, and an $11 per barrel SCO discount to Canadian dollar WTI.

Operating expenses were $37.60 per barrel and cash flow from operations totalled $392 million in the quarter.

Syncrude's major projects progressed as planned with $292 million of total capital spending (net to COS) in the quarter. The Aurora North Tailings Management and Aurora North Mine Train Relocation projects were completed in the fourth quarter, ahead of schedule and about $200 million (gross to Syncrude) under budget. The Mildred Lake Mine Train Replacement and Centrifuge Tailings Management projects remain on schedule and on budget.

Net debt was approximately $800 million at December 31, 2013 and is expected to increase in 2014 as we spend existing cash balances to fund our major projects and settle accounts payable of approximately $500 million for taxes and Crown royalties.

Highlights

Three Months Ended Year Ended
December 31 December 31
2013 2012 2013 2012
Cash flow from operations1 ($ millions) $ 392 $ 418 $ 1,349 $ 1,581
Per Share1 ($/Share) $ 0.81 $ 0.86 $ 2.78 $ 3.26
Net income ($ millions) $ 192 $ 218 $ 834 $ 973
Per Share, Basic and Diluted ($/Share) $ 0.40 $ 0.45 $ 1.72 $ 2.01
Sales volumes2
Total (mmbbls) 10.3 10.3 35.8 38.7
Daily average (bbls) 112,092 111,669 98,037 105,680
Realized SCO selling price ($/bbl) $ 91.47 $ 89.99 $ 99.55 $ 91.90
West Texas Intermediate ("WTI") (average $US/bbl) $ 97.61 $ 88.23 $ 98.05 $ 94.15
SCO premium (discount) to WTI $ (10.84 ) $ 2.52 $ (1.10 ) $ (2.42 )
(weighted average $/bbl)
Operating expenses ($ millions) $ 388 $ 398 $ 1,494 $ 1,505
Per barrel ($/bbl) $ 37.60 $ 38.76 $ 41.75 $ 38.91
Capital expenditures ($ millions) $ 292 $ 299 $ 1,342 $ 1,086
Dividends ($ millions) $ 169 $ 169 $ 678 $ 654
Per Share ($/Share) $ 0.35 $ 0.35 $ 1.40 $ 1.35
1Cash flow from operations and cash flow from operations per Share are additional GAAP financial measures and are defined in the "Additional GAAP
Financial Measures" section of this MD&A.
2The 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.

Review of Financial Results

Cash Flow from Operations

To view graph comparison, visit the following link: http://media3.marketwire.com/docs/Q4_GraphFigures.jpg

Cash flow from operations decreased to $392 million, or $0.81 per Share, in the fourth quarter of 2013 from $418 million, or $0.86 per Share, in the fourth quarter of 2012 primarily due to higher current taxes partially offset by a higher realized selling price in the 2013 fourth quarter. On an annual basis, cash flow from operations decreased to $1,349 million, or $2.78 per Share, in 2013 from $1,581 million, or $3.26 per Share, in 2012 reflecting higher current taxes, with lower sales volumes offsetting a higher realized selling price in 2013.

Current taxes increased in 2013 primarily because tax pools and the partnership structure sheltered the majority of 2012 income from current taxes.

The average realized selling price increased to $91.47 per barrel in the fourth quarter of 2013 from $89.99 per barrel in the same quarter of 2012, reflecting a higher WTI oil price and a weaker Canadian dollar, largely offset by a deterioration in the SCO differential to WTI. On an annual basis, the average realized selling price increased to $99.55 per barrel in 2013 from $91.90 in 2012, reflecting a higher WTI oil price, an improvement in the SCO differential to WTI and a weaker Canadian dollar.

Syncrude production in the 2013 fourth quarter totalled 28.3 million barrels, or 307,600 barrels per day, a three per cent increase over fourth quarter 2012 production of 27.5 million barrels, or 298,900 barrels per day. Net to the Corporation, sales volumes were 10.3 million barrels, or approximately 112,000 barrels per day, in the fourth quarters of 2013 and 2012.

On an annual basis, Syncrude produced 97.5 million barrels, or 267,000 barrels per day, in 2013 compared with 104.9 million barrels, or 286,500 barrels per day, in 2012. The decrease in 2013 volumes primarily reflects delays completing turnarounds on the Coker 8-1, LC Finer and secondary upgrading units. Production volumes in both 2013 and 2012 reflect unplanned outages in extraction units. Net to the Corporation, sales volumes totalled 35.8 million barrels, or 98,000 barrels per day, in 2013 compared with 38.7 million barrels, or 105,700 barrels per day, in 2012.

Net Income

Net income decreased to $192 million, or $0.40 per Share, in the fourth quarter of 2013 from $218 million, or $0.45 per Share, in the fourth quarter of 2012 reflecting higher depreciation and depletion expense and a $30 million increase in the Corporation's foreign exchange loss, partially offset by a higher realized selling price in the 2013 fourth quarter. Changes in net income components are discussed in greater detail later in this MD&A.

On an annual basis, net income decreased to $834 million, or $1.72 per Share, in 2013 from $973 million, or $2.01 per Share, in 2012. Lower sales volumes were largely offset by a higher realized selling price in 2013. However, depreciation and depletion expense increased by $75 million in 2013 and the Corporation recognized an $88 million foreign exchange loss as opposed to a $25 million foreign exchange gain in 2012.

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 2013 2012 Change 2013 2012 Change
Sales net of crude oil purchases and transportation expense $ 91.63 $ 90.47 $ 1.16 $ 99.63 $ 92.20 $ 7.43
Operating expense (37.60 ) (38.76 ) 1.16 (41.75 ) (38.91 ) (2.84 )
Crown royalties (5.00 ) (5.52 ) 0.52 (4.85 ) (5.21 ) 0.36
$ 49.03 $ 46.19 $ 2.84 $ 53.03 $ 48.08 $ 4.95
Development expense2 $ (2.80 ) $ (2.55 ) $ (0.25 ) $ (3.72 ) $ (2.62 ) $ (1.10 )
Administration and insurance expenses (0.72 ) (0.95 ) 0.23 (1.16 ) (0.94 ) (0.22 )
Depreciation and depletion expense (14.78 ) (11.54 ) (3.24 ) (13.36 ) (10.41 ) (2.95 )
Net finance expense (0.53 ) (1.15 ) 0.62 (1.21 ) (1.45 ) 0.24
Foreign exchange gain (loss) (4.48 ) (1.54 ) (2.94 ) (2.46 ) 0.65 (3.11 )
Tax expense (7.12 ) (7.23 ) 0.11 (7.79 ) (8.15 ) 0.36
(30.43 ) (24.96 ) (5.47 ) (29.70 ) (22.92 ) (6.78 )
Net income per barrel $ 18.60 $ 21.23 $ (2.63 ) $ 23.33 $ 25.16 $ (1.83 )
Sales volumes (mmbbls)3 10.3 10.3 - 35.8 38.7 (2.9 )
1Unless otherwise specified, the per barrel measures in this MD&A have been derived by dividing the relevant item by sales volumes in the period.
2Previously referred to as non-production expenses.
3Sales 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) 2013 2012 Change 2013 2012 Change
Sales1 $ 1,048 $ 1,000 $ 48 $ 4,208 $ 3,905 $ 303
Crude oil purchases (87 ) (55 ) (32 ) (591 ) (295 ) (296 )
Transportation expense (16 ) (16 ) - (52 ) (44 ) (8 )
$ 945 $ 929 $ 16 $ 3,565 $ 3,566 $ (1 )
Sales volumes2
Total (mmbbls) 10.3 10.3 - 35.8 38.7 (2.9 )
Daily average (bbls) 112,092 111,669 423 98,037 105,680 (7,643 )
Realized SCO selling price3 $ 91.47 $ 89.99 $ 1.48 $ 99.55 $ 91.90 $ 7.65
(average $Cdn/bbl)
West Texas Intermediate ("WTI") $ 97.61 $ 88.23 $ 9.38 $ 98.05 $ 94.15 $ 3.90
(average $US/bbl)
SCO premium (discount) to WTI $ (10.84 ) $ 2.52 $ (13.36 ) $ (1.10 ) $ (2.42 ) $ 1.32
(weighted-average $Cdn/bbl)
Average foreign exchange rate $ 0.95 $ 1.01 $ (0.06 ) $ 0.97 $ 1.00 $ (0.03 )
($US/$Cdn)
1Sales include sales of purchased crude oil and sulphur.
2Sales volumes, net of purchased crude oil volumes.
3SCO sales net of crude oil purchases and transportation expense divided by sales volumes, net of purchased crude oil volumes.

The $16 million, or two per cent, increase in fourth quarter 2013 sales, net of crude oil purchases and transportation expense, mainly reflects a higher realized selling price relative to the 2012 fourth quarter.

  • The fourth quarter 2013 realized selling price increased by $1.48 per barrel reflecting a U.S. $9.38 per barrel increase in WTI oil prices and a weaker Canadian dollar, largely offset by a $13.36 per barrel deterioration in the SCO differential to WTI.

On an annual basis, sales, net of crude oil purchases and transportation expense, were virtually unchanged year over year as lower sales volumes in 2013 were offset by a higher realized selling price.

  • The realized selling price in 2013 increased $7.65 per barrel relative to 2012, reflecting a U.S. $3.90 per barrel increase in WTI oil prices, a $1.32 per barrel improvement in the SCO differential to WTI, and a weaker Canadian dollar.
  • Sales volumes in 2013 averaged 98,000 barrels per day, down from 105,700 barrels per day in 2012, reflecting delays completing the Coker 8-1, LC Finer and secondary upgrading unit turnarounds in 2013. Sales volumes in both 2013 and 2012 reflect unplanned outages in extraction units.

Both WTI and the SCO differential to WTI reflect supply/demand fundamentals for inland North American light crude oil. Increasing North American production of light and heavy crude oils, and refinery modifications that enable processing of heavier crude oils, can push light crude sales, including SCO, to more distant refineries, exposing COS' product to supply/demand factors in different markets and increasing transportation costs. A number of pipelines in both Canada and the United States are at, or near, capacity and any pipeline apportionments restrict the ability of SCO and other crude oils to reach preferred markets. However, rail shipments of crude to refineries have become another transportation option, alleviating some of the pipeline capacity constraints.

The $10.84 per barrel SCO discount to WTI in the fourth quarter of 2013 reflects pipeline apportionment and resulting limitation on access to preferred markets. The impact of pipeline apportionment has lessened to date in 2014 and differentials have narrowed.

On an annual basis, the differential was negative $1.10 per barrel in 2013, largely in line with expectations and slightly improved from 2012.

We expect that volatility in the SCO differential to WTI will 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.

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. Sales include the sale of purchased crude oil while the cost of these purchases is included in crude oil purchases and transportation expense. Crude oil purchases were higher in 2013, relative to 2012, reflecting higher oil prices and additional purchased volumes to support unanticipated production shortfalls and to facilitate certain transportation arrangements.

Operating Expenses

The following table shows the major components of operating expenses in total dollars and per barrel of SCO:

Three Months Ended Year Ended
December 31 December 31
2013 2012 2013 2012
$millions $per bbl $millions $per bbl $millions $per bbl $millions $per bbl
Production and maintenance1 $ 308 $ 29.88 $ 320 $ 31.12 $ 1,217 $ 34.01 $ 1,242 $ 32.12
Natural gas and diesel purchases2 37 3.62 36 3.49 144 4.02 125 3.22
Syncrude pension and incentive compensation 34 3.25 31 3.05 98 2.74 97 2.52
Other3 9 0.85 11 1.10 35 0.98 41 1.05
Total operating expenses $ 388 $ 37.60 $ 398 $ 38.76 $ 1,494 $ 41.75 $ 1,505 $ 38.91
1Includes non-major turnaround costs. Major turnaround costs are capitalized as property, plant and equipment.
2Includes 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.

Operating expenses in the fourth quarter of 2013 were similar to the fourth quarter of 2012 on a total dollar and per barrel basis.

On an annual basis, total-dollar operating expenses were similar in 2013 and 2012, reflecting:

  • lower production costs, primarily due to lower mining volumes, in 2013;

offset by:

  • higher maintenance costs associated with the extended turnarounds and the Aurora North mine train relocations in 2013; and
  • higher natural gas prices in 2013.

Higher per-barrel operating expenses for the full year 2013 reflect lower sales volumes than 2012.

The following table shows operating expenses per barrel of bitumen and SCO. Costs are allocated to bitumen production and upgrading on the basis used to determine Crown royalties.

Three Months Ended Year Ended
December 31 December 31
2013 20123 2013 20123
($ per barrel) Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO
Bitumen production $ 25.12 $ 29.01 $ 25.29 $ 29.15 $ 26.74 $ 32.32 $ 25.54 $ 29.54
Internal fuel allocation1 2.68 3.10 2.16 2.49 2.69 3.25 2.15 2.48
Total bitumen production expenses $ 27.80 $ 32.11 $ 27.45 $ 31.64 $ 29.43 $ 35.57 $ 27.69 $ 32.02
Upgrading2 $ 8.59 $ 9.61 $ 9.43 $ 9.37
Less: internal fuel allocation1 (3.10 ) (2.49 ) (3.25 ) (2.48 )
Total upgrading expenses $ 5.49 $ 7.12 $ 6.18 $ 6.89
Total operating expenses $ 37.60 $ 38.76 $ 41.75 $ 38.91
(thousands of barrels per day)
Syncrude production volumes 355 308 345 299 323 267 331 287
Canadian Oil Sands sales volumes 112 112 98 106
1Reflects 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 $3.28 per GJ and $3.09 per GJ in the three months and year ended December 31, 2013, respectively, and $3.02 per GJ and $2.34 per GJ in the three months and year ended December 31, 2012, respectively. Diesel prices averaged $1.01 per litre and $0.91 per litre in the three months and year ended December 31, 2013, respectively, and $0.90 per litre in the three months and year ended December 31, 2012.
2Upgrading expenses include the production and maintenance expenses associated with processing and upgrading bitumen to SCO.
3Certain comparative period amounts have been restated to conform to the current period presentation.

Crown Royalties

Crown royalties decreased to $52 million in the fourth quarter of 2013 from $57 million in the fourth quarter of 2012, primarily reflecting lower bitumen prices in the 2013 period. On an annual basis, Crown royalties decreased to $174 million in 2013 from $202 million in 2012 due primarily to higher deductible capital expenditures and lower bitumen volumes in 2013. The higher capital expenditures in 2013 reflect 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 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.

The Syncrude owners and the Alberta government had been disputing the basis for determining the adjustments to reflect the quality and location differences and "floor price". In December 2013, the parties resolved the dispute with no impact on the fourth quarter net income or cash flow from operations, as the Corporation had provided for the anticipated settlement amounts in prior periods.

Development Expenses

Development expenses totalled $29 million and $133 million in the 2013 fourth quarter and full year, respectively, compared with $26 million and $101 million in the comparative 2012 periods. Development expenses consist primarily of expenditures relating to capital programs, which are expensed, such as pre-feasibility engineering, technical and support services, research, evaluation drilling and regulatory and stakeholder consultation expenditures. Development 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 increased to $152 million and $478 million in the 2013 fourth quarter and full year, respectively, from $119 million and $403 million in the comparative 2012 periods, reflecting:

  • a $35 million write-off of the Arctic natural gas assets' carrying value in the fourth quarter of 2013; and
  • $20 million in new depreciation charges in 2013 related to the Syncrude Emissions Reduction (SER) project.

Net Finance Expense

Three Months Ended Year Ended
December 31 December 31
($ millions) 2013 2012 2013 2012
Interest costs on long-term debt $ 28 $ 29 $ 123 $ 117
Less capitalized interest on long-term debt (27 ) (26 ) (107 ) (92 )
Interest expense on long-term debt $ 1 $ 3 $ 16 $ 25
Interest expense on employee future benefits 4 5 16 17
Accretion of asset retirement obligation 7 7 26 26
Interest income (6 ) (3 ) (14 ) (12 )
Net finance expense $ 6 $ 12 $ 44 $ 56

Interest costs on the Corporation's U.S. dollar-denominated long-term debt were higher in 2013, reflecting higher average outstanding debt levels and a weaker Canadian dollar in 2013. Conversely, interest expense on long-term debt was lower in 2013 because a higher portion of interest costs were capitalized as spending on the major projects continued.

Foreign Exchange (Gain) Loss

Three Months Ended Year Ended
December 31 December 31
($ millions) 2013 2012 2013 2012
Foreign exchange (gain) loss - long-term debt $ 53 $ 20 $ 115 $ (28 )
Foreign exchange (gain) loss - other (7 ) (4 ) (27 ) 3
Total foreign exchange (gain) loss $ 46 $ 16 $ 88 $ (25 )

Foreign exchange gains/losses are the result of revaluations of the Corporation's U.S. dollar-denominated long-term debt, cash, and accounts receivable into Canadian dollars.

The foreign exchange losses in the 2013 fourth quarter and full year were the result of a weakening Canadian dollar to U.S. $0.94 at December 31, 2013 from U.S. $0.97 at September 30, 2013 and U.S. $1.01 at December 31, 2012.

The foreign exchange losses in the 2012 fourth quarter were 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, whereas the foreign exchange gains in the full year 2012 were the result of a strengthening Canadian dollar from U.S. $0.98 at December 31, 2011.

Tax Expense

Three Months Ended Year Ended
December 31 December 31
($ millions) 2013 2012 2013 2012
Current tax expense $ 85 $ 10 $ 297 $ 40
Deferred tax expense (recovery) (12 ) 64 (18 ) 275
Total tax expense $ 73 $ 74 $ 279 $ 315

Total tax expense decreased in 2013 because earnings before tax were lower than in 2012.

Current taxes increased in the fourth quarter and full year 2013 because:

  • additional tax pools were available to shelter the majority of 2012 income from current taxes; and
  • taxes on a portion of income generated in the Corporation's partnership in 2012 were deferred to 2013.

Asset Retirement Obligation

December 31
Year ended ($ millions) 2013
Asset retirement obligation, beginning of year $ 1,102
Increase in risk-free interest rate (217 )
Reclamation expenditures (42 )
Increase in estimated reclamation and closure expenditures 27
Accretion expense 26
Asset retirement obligation, end of year $ 896
Less current portion (28 )
Non-current portion $ 868

Canadian Oil Sands' asset retirement obligation decreased from $1,102 million at December 31, 2012 to $896 million at December 31, 2013, primarily due to a 100 basis point increase in the interest rate used to discount future reclamation and closure expenditures (from 2.25 per cent at December 31, 2012 to 3.25 per cent at December 31, 2013). The annual review of estimated future reclamation and closure expenditures resulted in a $27 million increase in the discounted asset retirement obligation and a $56 million increase in the undiscounted obligation.

Pension and Other Post-Employment Benefit Plans

The Corporation's share of the estimated unfunded portion of Syncrude Canada Ltd.'s ("Syncrude Canada") pension and other post-employment benefit plans (the "accrued benefit liability") decreased to $308 million at December 31, 2013 from $438 million at December 31, 2012, reflecting a 50 basis point increase in the interest rate used to discount the accrued benefit liability, higher than estimated returns on plan assets and contributions to the plans in excess of the current period expenses. These factors were partially offset by the impact of an increase in the estimated average lifespan of the plans' beneficiaries as a result of new actuarial standards.

Summary of Quarterly Results

2013 20126
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
Sales1 ($ millions) $ 945 $ 871 $ 921 $ 828 $ 929 $ 941 $ 740 $ 956
Net income ($ millions) $ 192 $ 246 $ 219 $ 177 $ 218 $ 336 $ 101 $ 318
Per Share, Basic & Diluted $ 0.40 $ 0.51 $ 0.45 $ 0.37 $ 0.45 $ 0.69 $ 0.21 $ 0.66
Cash flow from operations2 ($ millions) $ 392 $ 339 $ 343 $ 275 $ 418 $ 470 $ 245 $ 454
Per Share2 $ 0.81 $ 0.70 $ 0.71 $ 0.57 $ 0.86 $ 0.97 $ 0.51 $ 0.94
Dividends ($ millions) $ 169 $ 170 $ 169 $ 170 $ 169 $ 170 $ 170 $ 145
Per Share $ 0.35 $ 0.35 $ 0.35 $ 0.35 $ 0.35 $ 0.35 $ 0.35 $ 0.30
Daily average sales volumes3 (bbls) 112,092 84,250 100,094 95,683 111,669 113,331 89,460 108,108
Realized SCO selling price ($/bbl) $ 91.47 $ 112.55 $ 100.90 $ 96.11 $ 89.99 $ 89.89 $ 90.59 $ 97.07
WTI4 (average $US/bbl) $ 97.61 $ 105.81 $ 94.17 $ 94.36 $ 88.23 $ 92.20 $ 93.35 $ 103.03
SCO premium (discount) to WTI $ (10.84 ) $ 2.63 $ 4.79 $ 1.00 $ 2.52 $ (2.00 ) $ (5.20 ) $ (5.80 )
(weighted-average $/bbl)
Operating expenses5 ($/bbl) $ 37.60 $ 46.15 $ 43.23 $ 41.20 $ 38.76 $ 36.07 $ 50.25 $ 32.68
Purchased natural gas price ($/GJ) $ 3.28 $ 2.59 $ 3.41 $ 2.95 $ 3.02 $ 2.23 $ 1.79 $ 2.23
Foreign exchange rates ($US/$Cdn)
Average $ 0.95 $ 0.96 $ 0.98 $ 0.99 $ 1.01 $ 1.00 $ 0.99 $ 1.00
Quarter-end $ 0.94 $ 0.97 $ 0.95 $ 0.98 $ 1.01 $ 1.02 $ 0.98 $ 1.00
1Sales after crude oil purchases and transportation expense.
2Cash flow from operations and cash flow from operations per Share are additional GAAP financial measures and are defined in the "Additional GAAP Financial Measures" section of this MD&A.
3Daily average sales volumes net of crude oil purchases.
4Pricing obtained from Bloomberg.
5Derived from operating expenses, as reported on the Consolidated Statements of Income and Comprehensive Income, divided by sales volumes during the period.
6Net income and operating expenses in 2012 have been adjusted to reflect the amendments to International Accounting Standard ("IAS") 19, Employee Benefits. Additional information on the amendments to IAS 19 is provided in the "Changes in Accounting Policies" section of this MD&A and in Note 3 to the unaudited consolidated financial statements for the three months and year ended December 31, 2013 and December 31, 2012.

During the last eight quarters, the following items have had a significant impact on the Corporation's financial results and may impact the financial results in the future:

  • fluctuations in realized selling prices have affected the Corporation's sales and Crown royalties. Monthly average WTI prices have ranged from U.S. $82 per barrel to U.S. $107 per barrel, and the monthly average differentials between our realized selling price and Canadian dollar WTI prices have ranged from an $10 per barrel premium to a $16 per barrel discount;
  • U.S. to Canadian dollar exchange rate fluctuations have resulted in foreign exchange gains and losses on the revaluation of U.S. dollar-denominated debt and have impacted realized selling prices;
  • planned and unplanned maintenance activities have reduced quarterly production volumes and revenues and increased operating expenses; and
  • increases in current taxes in 2013 have reduced cash flow from operations. Prior to 2013, tax pools sheltered the Corporation's income from significant current taxes. In addition, taxes on a portion of the income generated in the Corporation's partnership in 2012 were deferred to 2013.

Bitumen valuation estimates used to calculate Crown royalties from 2009 to 2013 have changed as new information becomes available. These changes have had a significant impact on the Corporation's financial results over the last eight quarters but are not expected to impact the financial results in the future.

Increased spending on capital projects to replace or relocate Syncrude mining trains and to support tailings management plans has reduced Crown royalties over the past eight quarters. These projects are all expected to be complete or substantially complete by the end of 2014.

Capital Expenditures

Three Months Ended Year Ended
December 31 December 31
($ millions) 2013 2012 2013 2012
Major Projects
Mildred Lake Mine Train Replacement $ 105 $ 96 $ 457 $ 362
Reconstruct crushers, surge facilities, and slurry prep facilities to support tailings storage requirements
Aurora North Mine Train Relocation 7 34 149 98
Relocate crushers, surge facilities, and slurry prep facilities to support tailings storage requirements
Aurora North Tailings Management 10 32 77 123
Construct a composite tails (CT) plant at the Aurora North mine to process tailings
Centrifuge Tailings Management 83 34 229 69
Construct a centrifuge plant at the Mildred Lake mine to process tailings
Capital expenditures on major projects $ 205 $ 196 $ 912 $ 652
Regular maintenance
Capitalized turnaround costs $ - $ - $ 54 $ 76
Other 60 77 269 266
Capital expenditures on regular maintenance $ 60 $ 77 $ 323 $ 342
Capitalized interest $ 27 $ 26 $ 107 $ 92
Total capital expenditures $ 292 $ 299 $ 1,342 $ 1,086

Capital expenditures increased to $1,342 million in 2013, as expected, primarily due to spending on the major projects at Syncrude. More information on the major projects is provided in the "Outlook" section of this MD&A.

Contractual Obligations and Commitments

Canadian Oil Sands' contractual obligations and commitments are summarized in the 2012 annual MD&A and include future cash payments that the Corporation is required to make under existing contractual arrangements entered into directly or as a 36.74 per cent owner in Syncrude. During 2013, Canadian Oil Sands entered into new contractual obligations totalling approximately $700 million due over the next 25 years for the transportation of crude oil to secure access to preferred markets and enhance marketing flexibility and approximately $90 million due over the next two years for new funding commitments primarily related to the major projects.

Dividends

On January 30, 2014, 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, 2014 to shareholders of record on February 21, 2014. The Corporation paid dividends to shareholders totalling $678 million, or $1.40 per Share in 2013.

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 amounts are established with the intent of absorbing short-term market volatility over several quarters and 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
As at ($ millions, except % amounts) 2013 2012
Long-term debt1,2 $ 1,602 $ 1,794
Cash and cash equivalents1 (806 ) (1,553 )
Net debt3,4 $ 796 $ 241
Shareholders' equity1 $ 4,732 $ 4,515
Total net capitalization3,5 $ 5,528 $ 4,756
Total capitalization3,6 $ 6,334 $ 6,309
Net debt-to-total net capitalization3,7 (%) 14 5
Long-term debt-to-total capitalization3,8 (%) 25 28
1 As reported in the Consolidated Balance Sheets.
2 Includes current and non-current portions of long-term debt.
3Additional GAAP financial measure.
4Long-term debt less cash and cash equivalents.
5 Net debt plus Shareholders' equity.
6 Long-term debt plus Shareholders' equity.
7 Net debt divided by total net capitalization.
8Long-term debt divided by total capitalization.

Net debt, which is comprised of current and non-current portions of long-term debt less cash and cash equivalents, increased to $796 million at December 31, 2013 from $241 million at December 31, 2012, as existing cash balances were used to fund capital expenditures and dividend payments in excess of cash flow from operations in 2013. In addition, a weakening Canadian dollar from December 31, 2012 to December 31, 2013 increased the Canadian dollar equivalent carrying value of Canadian Oil Sands' outstanding long-term debt, all of which is denominated in U.S. dollars, by $115 million. As a result, net debt-to-total net capitalization increased to 14 per cent at December 31, 2013 from five per cent at December 31, 2012.

In August, 2013, Canadian Oil Sands repaid U.S. $300 million of Senior Notes upon maturity, resulting in long-term debt-to-total capitalization of 25 per cent at December 31, 2013 compared with 28 per cent at December 31, 2012.

In 2014, we plan to continue to spend existing cash balances to fund our major projects, settle accounts payable of approximately $500 million for taxes and Crown royalties and pay dividends. Based on the assumptions in our 2014 Outlook, net debt is expected to rise to a level within our targeted range of $1 billion to $2 billion by the end of 2014, coincident with the expected substantial completion of our major projects.

Shareholders' equity increased to $4,732 million at December 31, 2013 from $4,515 million at December 31, 2012, as net income exceeded dividends in 2013.

In June 2013, Canadian Oil Sands extended the terms of its $1,500 million operating credit facility to June 1, 2017 and its $40 million extendible revolving term credit facility to June 30, 2015. No amounts were drawn against these facilities at December 31, 2013 or December 31, 2012.

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 long-term debt-to-total capitalization to 55 per cent. Canadian Oil Sands is in compliance with its debt covenants, and with a long-term debt-to-total capitalization of 25 per cent at December 31, 2013, a significant increase in debt or decrease in equity would be required to negatively impact the Corporation's financial flexibility.

Shareholders' Capital and Trading Activity

The Corporation's shares trade on the Toronto Stock Exchange under the symbol COS. On December 31, 2013, the Corporation had a market capitalization of approximately $9.7 billion with 484.6 million shares outstanding and a closing price of $19.98 per Share. The following table summarizes the trading activity for the fourth quarter of 2013.

Canadian Oil Sands Limited - Trading Activity

Fourth
Quarter October November December
2013 2013 2013 2013
Share price
High $ 21.17 $ 20.79 $ 21.17 $ 20.21
Low $ 19.40 $ 19.60 $ 19.75 $ 19.40
Close $ 19.98 $ 20.32 $ 19.87 $ 19.98
Volume of Shares traded (millions) 72.1 25.8 22.4 23.9
Weighted average Shares outstanding (millions) 484.6 484.6 484.6 484.6

Changes in Accounting Policies

In June 2011, the International Accounting Standards Board ("IASB") amended International Accounting Standard ("IAS") 19, Employee Benefits, addressing the recognition and measurement of defined benefit pension expense and termination benefits and disclosures for all employee benefits. The key amendments are as follows:

  • Actuarial gains and losses, which are now referred to as re-measurements, are recognized immediately in "other comprehensive income" ("OCI"), eliminating the choice between immediate recognition through net income or OCI, or deferral using the corridor approach. This change does not impact Canadian Oil Sands as the Corporation previously recognized actuarial gains and losses immediately through OCI.
  • The expected rate of return on plan assets is no longer calculated. Instead, the estimated rate of return on plan assets is now the same rate used to accrete the discounted accrued benefit obligation. The interest cost component of the pension expense, which previously represented accretion of the discounted accrued benefit obligation, now represents accretion of the net accrued benefit liability (the accrued benefit obligation net of the fair value of plan assets).
  • The interest cost component of pension expense, which was previously presented within operating expenses, is now presented within net finance expense.

Canadian Oil Sands has applied the amendments effective January 1, 2013 in accordance with the applicable transitional provisions with no material impact to the Corporation's financial results. Additional information is provided in Note 3 to the unaudited consolidated financial statements for the three months and years ended December 31, 2013 and December 31, 2012.

2014 Outlook

...
As of
January 30
(millions of Canadian dollars, except volume and per barrel amounts) 2014
Operating assumptions
Syncrude production (mmbbls) 105
Canadian Oil Sands sales (mmbbls) 38.6
Sales, net of crude oil purchases and transportation $ 3,386
Realized SCO selling price ($/bbl) $ 87.78
Contact:
Canadian Oil Sands Limited
Siren Fisekci
Vice President, Investor & Corporate Relations
(403) 218-6228
Canadian Oil Sands Limited
2000 First Canadian Centre
350 - 7 Avenue S.W., Calgary, Alberta T2P 3N9
(403) 218-6200
(403) 218-6201
invest@cdnoilsands.com
www.cdnoilsands.com

View Comments