Canadian Oil Sands Announces Third Quarter 2012 Financial Results and a $0.35 Per Share Dividend

CALGARY, ALBERTA--(Marketwire - Oct 29, 2012) - Canadian Oil Sands Limited (COS.TO) (COSWF)

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

Highlights for the three and nine-month periods ended September 30, 2012:

  • COS has declared a quarterly dividend of $0.35 per Share. The dividend will be paid on November 30, 2012 to Shareholders of record on November 26, 2012.
  • Cash flow from operations decreased eight per cent to $470 million ($0.97 per Share) in the third quarter of 2012 from $512 million ($1.06 per Share) in the third quarter of 2011. The decrease was due mainly to a lower average realized selling price, partially offset by higher sales volumes in 2012. Year-to-date cash flow from operations decreased 24 per cent to $1,163 million ($2.40 per Share) in 2012 from $1,534 million ($3.16 per Share) in the same 2011 period. The decline is due mainly to a lower average realized selling price and lower sales volumes in 2012.
  • Net income increased to $338 million ($0.70 per Share) in the third quarter of 2012 from $242 million ($0.50 per Share) in the third quarter of 2011. Year-to-date net income decreased to $760 million ($1.57 per Share) in 2012 from $912 million ($1.88 per Share) in 2011. In addition to the variances in sales, pricing and Crown royalties, 2012 net income was impacted by foreign exchange gains and losses and tax expense.
  • The third quarter 2012 realized selling price averaged $89.89 per barrel, an $8.00 per barrel decrease from $97.89 per barrel in the third quarter of 2011. The realized selling price in the first nine months of 2012 averaged $92.59 per barrel, a $7.61 per barrel decrease from $100.20 per barrel in the 2011 comparative period. The lower realized prices in 2012 reflect a Synthetic Crude Oil ("SCO") discount relative to WTI in 2012 as opposed to a significant premium in 2011.
  • Sales volumes averaged about 113,300 barrels per day in the third quarter of 2012, up from 109,300 barrels per day in the 2011 third quarter. Year-to-date, sales volumes averaged about 103,700 barrels per day compared with 111,000 barrels per day in the 2011 period.
  • Per barrel operating expenses in the third quarter of 2012 decreased to $36.17 from $37.19 in the third quarter of 2011, mainly as a result of higher production volumes. Year-to-date, 2012 operating expenses have increased to $39.14 per barrel from $36.56 per barrel in the comparative 2011 period, reflecting lower production volumes in 2012. Total operating expenses year-to-date in 2012 are essentially flat compared to the same period in 2011.
  • COS announced earlier this month that Syncrude will embark upon a mine extension project at its Mildred Lake mine ("the MLX Project"). The MLX Project will employ the same mine trains that are currently being constructed at Mildred Lake. This project is expected to be highly economic, enabling Syncrude to access a large bitumen source at a cost that is expected to be significantly lower than the cost of a new mine. 

"As a result of stronger than expected pricing for SCO year-to-date, we have increased our 2012 cash flow guidance by 20 per cent to approximately $1.7 billion. Based on our guidance, we anticipate exiting the year with $1.6 billion of cash and about $0.2 billion of net debt. While we had expected to draw down on our cash balances this year, we were able to fund our capital expenditures and dividends essentially from internally generated cash flow.  As such, we continue to be well-positioned to finance the remainder of our major project capital program while maintaining an attractive dividend.  These projects are tracking to plan, and Syncrude''s owners remain confident in the schedule and budget estimates," said Marcel Coutu, President and CEO.

Mr. Coutu added: "The recently announced MLX project further positions Syncrude very favourably amongst oil sands mining projects. Our Mildred Lake and Aurora North mines should operate into the 2030s and 2040s, respectively. The scope of the MLX project is of a much smaller scale than what is required to develop a new mine, with the majority of construction limited to a bridge and utilities. As a result, we believe this will be a highly economic project while also providing the opportunity to minimize new land disturbance by utilizing existing infrastructure."  

Highlights
 
  Three Months Ended Nine Months Ended
  September 30 September 30
  2012   2011 2012   2011
                     
Cash flow from operations1($ millions) $ 470   $ 512 $ 1,163   $ 1,534
  Per Share1($/Share) $ 0.97   $ 1.06 $ 2.40   $ 3.16
                     
Net income ($ millions) $ 338   $ 242 $ 760   $ 912
  Per Share, Basic and Diluted ($/Share) $ 0.70   $ 0.50 $ 1.57   $ 1.88
                     
Sales volumes2                    
  Total (mmbbls)   10.4     10.1   28.4     30.3
  Daily average (bbls)   113,331     109,260   103,669     110,988
                     
Realized SCO selling price ($/bbl) $ 89.89   $ 97.89 $ 92.59   $ 100.20
                     
West Texas Intermediate ("WTI") (average $US/bbl) $ 92.20   $ 89.54 $ 96.16   $ 95.47
                     
SCO premium (discount) to WTI (weighted average $/bbl) $ (2.09 ) $ 9.77 $ (4.32 ) $ 6.99
                     
Operating expenses ($/bbl) $ 36.17   $ 37.19 $ 39.14   $ 36.56
                     
Capital expenditures ($ millions) $ 354   $ 189 $ 787   $ 438
                     
Dividends ($ millions) $ 170   $ 145 $ 485   $ 387
  Per Share ($/Share) $ 0.35   $ 0.30 $ 1.00   $ 0.80
(1) Cash flow from operations and cash flow from operations per Share are non-GAAP measures 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

SCO production from Syncrude during the third quarter of 2012 totalled 28.8 million barrels, or 313,300 barrels per day, compared with 27.5 million barrels, or 299,100 barrels per day, in the third quarter of 2011. Both periods reflected stable operations. Volumes in the 2011 third quarter reflect the Coker 8-2 turnaround, which commenced in early September 2011 and continued through October 2011. There was no major maintenance activity in the third quarter of 2012.

Syncrude produced 77.4 million barrels, or 282,300 barrels per day, of SCO through the first nine months of 2012 compared with 82.0 million barrels, or 300,500 barrels per day, in the comparative 2011 period. Production volumes in 2012 reflect maintenance on Coker 8-1 in the first quarter and the planned Coker 8-3 and Vacuum Distillation Unit turnarounds in the second quarter while 2011 production volumes partially reflect the Coker 8-2 turnaround.

MLX Project

The MLX Project will leverage current investments in the replacement of the two mine trains being constructed at the Mildred Lake mine. By employing existing operational and environmental infrastructure to access nearby high-quality bitumen deposits on Syncrude''s existing leases, MLX is expected to be highly economic.

The proposed project should extend the life of mining operations at Mildred Lake by about a decade. Project scoping is currently underway, and pending regulatory approval, construction and spending would commence in the next 10 years. 

COS included in the Dow Jones Sustainability North America Index

COS was recently named for the third time to the Dow Jones Sustainability Indexes ("DJSI") North America Index.

The DJSI is a partnership between the Dow Jones Indexes and SAM Sustainability Assessments that rates the top corporate performers in financial performance and sustainable business practices. The DJSI reviews companies on several general and industry-specific topics related to economic, environmental and social dimensions, including corporate governance, environmental policy, climate strategy, human capital development and labour practices. The DJSI North America Index ranks the top 20 percent of the 600 largest North American companies on the Dow Jones Total Stock Market Index. More information about the DJSI is available at http://www.sustainability-index.com/.

2012 Outlook

Canadian Oil Sands has revised its outlook for 2012, which includes the following estimates and assumptions:

  • Annual Syncrude production of 107 million barrels (292,300 barrels per day) with a range of 105 million to 108 million barrels. Net to Canadian Oil Sands, this is equivalent to 39.3 million barrels (107,400 barrels per day). The 107 million barrel estimate assumes robust production without major interruptions for the remainder of the year. No major maintenance is planned for the fourth quarter of 2012.
  • A realized selling price of $94 per barrel, an increase of $10 per barrel from prior guidance, which assumes a U.S. $95 per barrel WTI oil price, a foreign exchange rate of $1.00 U.S./Cdn, and a SCO discount to Cdn dollar WTI of $1.00.
  • Operating expenses of $1,485 million, or $37.77 per barrel, reflecting actual costs incurred to date and a reduced natural gas price assumption of $2.25 per gigajoule.
  • Total expected capital expenditures have decreased by $10 million to $1,114 million. 
  • Current taxes of approximately $40 million in 2012 and approximately $400 million in 2013.
  • Cash flow from operations of $1,746 million, or $3.60 per Share. After deducting forecast 2012 capital expenditures, we estimate $632 million in remaining cash flow from operations for the year, or $1.30 per Share.
  • We expect cash levels to decrease significantly from the current $1.5 billion as we fund the major capital projects and repay the 2013 debt maturity. As a result, net debt levels should rise to $1 billion to $2 billion by the end of 2014, coincident with the reduced capital expenditure risk from the completion of the major capital projects.

More information on the outlook is provided in the Management''s Discussion and Analysis ("MD&A") section of this report and the October 29, 2012 guidance document, which is available on our web site at www.cdnoilsands.com under "Investor Information."

The 2012 Outlook contains forward-looking information and users are cautioned that the actual amounts may vary from the estimates disclosed. Please refer to the "Forward-Looking Information Advisory" in the MD&A section of this report for the risks and assumptions underlying this forward-looking information. 

Management''s Discussion and Analysis

The following Management''s Discussion and Analysis ("MD&A") was prepared as of October 29, 2012 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 and nine months ended September 30, 2012 and September 30, 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 2012 annual Syncrude forecasted production range of 105 million barrels to 108 million barrels and the single-point Syncrude production estimate of 107 million barrels (39.3 million barrels net to the Corporation); 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 2012 and beyond; the expected sales, operating expenses, Crown royalties, capital expenditures and cash flow from operations for 2012; the anticipated amount of current taxes in 2012 and 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 2012 and over the next several years; the expected price for crude oil and natural gas in 2012; the expected foreign exchange rates in 2012; the expected realized selling price, which includes the anticipated differential to West Texas Intermediate ("WTI") to be received in 2012 for the Corporation''s product; the expectations regarding net debt; 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 2012 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 capacity is available to deliver crude oil from western Canada to Cushing, Oklahoma or the U.S. Gulf Coast; the expectation that the proposed Mildred Lake Mine extension project (the "MLX Project) should extend the life of mining operations at Mildred Lake by about a decade; the belief that the Mildred Lake and Aurora North mines should operate into the 2030s and 2040s, respectively; the expectations regarding the timing of construction and spending for the MLX Project; and the expectation that the MLX Project should enable Syncrude to access a large bitumen source at a cost that is expected to be significantly lower than the cost of a new mine.

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 October 29, 2012 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 October 29, 2012, 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 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 non-GAAP financial measures include cash flow from operations, cash flow from operations on a per Share basis, 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. Non-GAAP financial measures provide additional information that we believe is meaningful regarding the Corporation''s operational performance, its liquidity and its capacity to fund dividends, capital expenditures and other investing activities. Users are cautioned that non-GAAP financial measures presented by the Corporation may not be comparable with measures provided by other entities.

Cash flow from operations is calculated as cash from operating activities, as reported on the Consolidated Statement of Cash Flows, before changes in non-cash working capital. Cash flow from operations per Share is calculated as cash flow from operations divided by the weighted-average number of Shares outstanding in the period. We believe cash flow from operations, which is not impacted by fluctuations in non-cash working capital balances, is more indicative of operational performance. The majority of our non-cash working capital is liquid and typically settles within 30 days.

Cash flow from operations is reconciled to cash from operating activities as follows:

  Three Months Ended Nine Months Ended
  September 30 September 30
($ millions) 2012   2011 2012 2011
                   
Cash flow from operations $ 470   $ 512 $ 1,163 $ 1,534
Change in non-cash working capital1   (124 )   144   105   108
Cash from operating activities1 $ 346   $ 656 $ 1,268 $ 1,642
(1) As reported in the Consolidated Statements of Cash Flows.
   
Overview
  Three Months Ended Nine Months Ended
  September 30 September 30
  2012   2011 2012   2011
Cash flow from operations1($ millions) $ 470   $ 512 $ 1,163   $ 1,534
  Per Share1($/Share) $ 0.97   $ 1.06 $ 2.40   $ 3.16
                     
Net income ($ millions) $ 338   $ 242 $ 760   $ 912
  Per Share, Basic and Diluted ($/Share) $ 0.70   $ 0.50 $ 1.57   $ 1.88
                     
Sales volumes2                    
  Total (mmbbls)   10.4     10.1   28.4     30.3
  Daily average (bbls)   113,331     109,260   103,669     110,988
                     
Realized SCO selling price ($/bbl) $ 89.89   $ 97.89 $ 92.59   $ 100.20
                     
West Texas Intermediate ("WTI") (average $US/bbl) $ 92.20   $ 89.54 $ 96.16   $ 95.47
                     
SCO premium (discount) to WTI $ (2.09 ) $ 9.77 $ (4.32 ) $ 6.99
  (weighted average $/bbl)                    
                     
Operating expenses ($/bbl) $ 36.17   $ 37.19 $ 39.14   $ 36.56
                     
Capital expenditures ($ millions) $ 354   $ 189 $ 787   $ 438
                     
Dividends ($ millions) $ 170   $ 145 $ 485   $ 387
  Per Share ($/Share) $ 0.35   $ 0.30 $ 1.00   $ 0.80
(1) Cash flow from operations and cash flow from operations per Share are non-GAAP measures 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.

Cash flow from operations decreased eight per cent to $470 million, or $0.97 per Share, in the third quarter of 2012 from $512 million, or $1.06 per Share, in the third quarter of 2011, due mainly to a lower realized selling price partially offset by higher sales volumes in 2012. Year-to-date cash flow from operations decreased 24 per cent to $1,163 million, or $2.40 per Share, in 2012 from $1,534 million, or $3.16 per Share, in 2011 due mainly to a lower realized selling price and lower sales volumes in 2012.

The third quarter 2012 realized selling price averaged $89.89 per barrel, an $8.00 per barrel decrease from $97.89 per barrel in the third quarter of 2011. The realized selling price in the first nine months of 2012 averaged $92.59 per barrel, a $7.61 per barrel decrease from $100.20 per barrel in the 2011 comparative period. The lower realized prices in 2012 reflect a Synthetic Crude Oil ("SCO") discount relative to WTI in 2012 as opposed to a significant premium in 2011.

SCO production from the Syncrude Joint Venture ("Syncrude") during the third quarter of 2012 totalled 28.8 million barrels, or 313,300 barrels per day, compared with 27.5 million barrels, or 299,100 barrels per day, in the third quarter of 2011. Net to the Corporation, sales volumes totalled 10.4 million barrels, or about 113,300 barrels per day, in the third quarter of 2012, compared with 10.1 million barrels, or about 109,300 barrels per day, in the third quarter of 2011, based on Canadian Oil Sands'' 36.74 per cent working interest in Syncrude. Both periods exhibited stable operations. Volumes in the 2011 third quarter reflect the Coker 8-2 turnaround, which commenced in early September and continued through October. There was no major maintenance activity in the third quarter of 2012.

Syncrude produced 77.4 million barrels, or 282,300 barrels per day, of SCO through the first nine months of 2012 compared with 82.0 million barrels, or 300,500 barrels per day, in the comparative 2011 period. Net to the Corporation, sales volumes totalled 28.4 million barrels, or 103,700 barrels per day, through the first nine months of 2012, down from 30.3 million barrels, or 111,000 barrels per day, in the comparative 2011 period. Volumes in 2012 reflect Coker 8-1 maintenance in the first quarter and the planned Coker 8-3 and Vacuum Distillation Unit turnarounds in the second quarter, while 2011 production volumes partially reflect the Coker 8-2 turnaround.

Additional information on realized selling prices and sales volumes is provided in the "Sales Net of Crude Oil Purchases and Transportation Expense" section of this MD&A.

Operating expenses in the third quarter of 2012 decreased $1.02 per barrel to $36.17 per barrel from $37.19 per barrel in the third quarter of 2011, mainly as a result of higher 2012 production volumes. Year-to-date, 2012 operating expenses increased $2.58 per barrel to $39.14 per barrel from $36.56 per barrel in 2011, reflecting lower 2012 production volumes. Additional information is provided in the "Operating Expenses" section of this MD&A.

Crown royalties decreased to $33 million, or $3.16 per barrel, in the third quarter of 2012, from $65 million, or $6.53 per barrel, in the third quarter of 2011, due primarily to higher bitumen-related capital costs in 2012. On a year-to-date basis, 2012 Crown royalties decreased to $145 million, or $5.11 per barrel, from $234 million, or $7.74 per barrel, in 2011, reflecting lower 2012 bitumen volumes and higher bitumen-related capital costs. Additional information is provided in the "Crown Royalties" section of this MD&A.

Net income increased to $338 million, or $0.70 per Share, in the third quarter of 2012 from $242 million, or $0.50 per Share, in the third quarter of 2011. Year-to-date net income decreased to $760 million, or $1.57 per Share, in 2012 from $912 million, or $1.88 per Share, in 2011. In addition to the variances in net sales and Crown royalties described earlier, the change in net income was impacted by foreign exchange gains and losses and tax expense.

The Corporation recognizes foreign exchange gains and losses primarily as a result of revaluations of its U.S. dollar-denominated long-term debt caused by fluctuations in U.S./Cdn dollar exchange rates. The Corporation recorded foreign exchange gains of $51 million and $41 million for the third quarter and first nine months of 2012, respectively, reflecting a strengthening Canadian dollar during these periods. Conversely, foreign exchange losses of $75 million and $45 million were recorded in the third quarter and first nine months of 2011, respectively, reflecting a weakening Canadian dollar during those periods.

Tax expense increased to $104 million in the third quarter of 2012 from $95 million in the third quarter of 2011 due to higher 2012 earnings before tax, while year-to-date tax expense in 2012 fell to $243 million from $317 million in 2011 due to lower 2012 earnings before tax.

Capital expenditures totalled $354 million and $787 million in the third quarter and first nine months of 2012, respectively, up from $189 million and $438 million in the comparative 2011 periods, as spending increased on multi-year capital projects to replace or relocate Syncrude mining trains and to support tailings management plans. Additional information is provided in the "Capital Expenditures" section of this MD&A.

Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, decreased to $0.3 billion at September 30, 2012 from $0.4 billion at December 31, 2011. While $1,163 million of cash flow from operations in the first nine months of 2012 fell short of capital expenditures and dividend payments of $787 million and $485 million, respectively, a reduction in non-cash working capital balances more than offset this difference.

Review of Financial Results  
   
Net Income per Barrel  
   
  Three Months Ended   Nine Months Ended  
  September 30   September 30  
($ per barrel)1 2012   2011   $ Change   2012   2011   $ Change  
Sales net of crude oil purchases and transportation expense $ 90.10   $ 98.42   $ (8.32 ) $ 92.82   $ 100.68   $ (7.86 )
Operating expenses   (36.17 )   (37.19 )   1.02     (39.14 )   (36.56 )   (2.58 )
Crown royalties   (3.16 )   (6.53 )   3.37     (5.11 )   (7.74 )   2.63  
  $ 50.77   $ 54.70   $ (3.93 ) $ 48.57   $ 56.38   $ (7.81 )
Non-production expenses $ (2.40 ) $ (2.86 ) $ 0.46   $ (2.65 ) $ (2.85 ) $ 0.20  
Administration and insurance   (0.93 )   (0.65 )   (0.28 )   (0.96 )   (0.77 )   (0.19 )
Depreciation and depletion   (9.28 )   (9.20 )   (0.08 )   (10.00 )   (9.41 )   (0.59 )
Net finance expense   (0.87 )   (0.97 )   0.10     (1.15 )   (1.30 )   0.15  
Foreign exchange (loss) gain   4.86     (7.43 )   12.29     1.43     (1.47 )   2.90  
Tax expense   (9.96 )   (9.47 )   (0.49 )   (8.55 )   (10.47 )   1.92  
    (18.58 )   (30.58 )   12.00     (21.88 )   (26.27 )   4.39  
Net income per barrel $ 32.19   $ 24.12   $ 8.07   $ 26.69   $ 30.11   $ (3.42 )
Sales volumes (mmbbls)2   10.4     10.1     0.3     28.4     30.3     (1.9 )
(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   Nine Months Ended  
  September 30   September 30  
($ millions, except where otherwise noted) 2012   2011   $ Change   2012   2011   $ Change  
                                     
Sales1 $ 1,022   $ 1,034   $ (12 ) $ 2,983   $ 3,209   $ (226 )
Crude oil purchases   (72 )   (38 )   (34 )   (319 )   (138 )   (181 )
Transportation expense   (9 )   (7 )   (2 )   (27 )   (21 )   (6 )
  $ 941   $ 989   $ (48 ) $ 2,637   $ 3,050   $ (413 )
Sales volumes2                                    
  Total (mmbbls)   10.4     10.1     0.3     28.4     30.3     (1.9 )
  Daily average (bbls)   113,331     109,260     4,071     103,669     110,988     (7,319 )
                                     
Realized SCO selling price3(average $Cdn/bbl) $ 89.89   $ 97.89   $ (8.00 ) $ 92.59   $ 100.20   $ (7.61 )
                                     
West Texas Intermediate ("WTI") (average $US/bbl)   92.20     89.54     2.66     96.16     95.47     0.69  
                                     
SCO premium (discount) to WTI (weighted average $Cdn/bbl)   (2.09 )   9.77     (11.86 )   (4.32 )   6.99     (11.31 )
                                     
Average foreign exchange rate ($US/$Cdn)   1.00     1.02     (0.02 )   1.00     1.02     (0.02 )
                                     
(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 $48 million, or five per cent, decrease in third quarter 2012 sales, net of crude oil purchases and transportation expense, reflects a lower average realized SCO selling price partially offset by higher sales volumes relative to the 2011 third quarter.

The third quarter 2012 realized selling price averaged $89.89 per barrel, an $8.00 per barrel decrease from $97.89 per barrel in the third quarter of 2011. The Corporation realized a $2.09 per barrel weighted-average SCO discount to WTI in the third quarter of 2012 as opposed to a $9.77 per barrel premium in the third quarter of 2011. WTI averaged U.S. $92 per barrel and the Canadian dollar averaged $1.00 U.S. in the 2012 third quarter compared with U.S. $90 per barrel and $1.02 U.S., respectively, in the 2011 third quarter.

Third quarter 2012 sales volumes averaged 113,300 barrels per day, up from 109,300 barrels per day in the 2011 third quarter, primarily due to the 2011 Coker 8-2 turnaround.

On a year-to-date basis, the $413 million, or 14 per cent, decrease in 2012 sales, net of crude oil purchases and transportation expense, reflects lower sales volumes and a lower average realized SCO selling price.

Sales volumes averaged 103,700 barrels per day in the first nine months of 2012 compared with 111,000 barrels per day in the comparative 2011 period, reflecting lower production at Syncrude. Volumes in 2012 reflect Coker 8-1 maintenance in the first quarter and the planned Coker 8-3 and Vacuum Distillation Unit turnarounds in the second quarter, while 2011 production volumes reflect the Coker 8-2 turnaround.

The realized selling price in the first nine months of 2012 averaged $92.59 per barrel compared with $100.20 per barrel in the 2011 comparative period. The Corporation realized a $4.32 per barrel weighted-average SCO discount to WTI in the first nine months of 2012 as opposed to a $6.99 per barrel premium in the comparative 2011 period. WTI averaged U.S. $96 per barrel and the Canadian dollar averaged $1.00 U.S. in the first nine months of 2012, compared with U.S. $95 per barrel and $1.02 U.S., respectively, in the comparative 2011 periods.

The volatile 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. Pipeline apportionments can exacerbate this situation by restricting the ability of SCO and other crude oils to reach their 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 capacity is available to deliver crude oil from western Canada to Cushing, Oklahoma or the U.S. Gulf Coast.

The Corporation purchases crude oil from third parties to fulfill sales commitments with customers when there are shortfalls in Syncrude''s production and to facilitate certain transportation and tankage arrangements and operations. Sales include the sale of purchased crude oil while the cost of these purchases is included in crude oil purchases and transportation expense. Crude oil purchases were higher in the three and nine months ended September 30, 2012 relative to the comparative 2011 periods, reflecting additional 2012 purchased volumes to support transportation and storage arrangements and unanticipated production shortfalls.

Operating Expenses

The following table breaks down operating expenses into their major components and shows operating expenses per barrel of bitumen and SCO. The information allocates costs to bitumen production and upgrading on the basis used to determine Crown royalties.

  Three Months Ended   Nine Months Ended  
  September 30   September 30  
  2012   20114   2012   20114  
($ per barrel) Bitumen SCO   Bitumen SCO   Bitumen SCO   Bitumen SCO  
Bitumen production $ 23.84 $ 27.46   $ 24.07 $ 28.61   $ 27.64 $ 32.01   $ 24.05 $ 28.61  
Internal fuel allocation2   1.92   2.21     1.86   2.21     2.13   2.47     2.38   2.83  
Total produced bitumen costs   25.76   29.67     25.93   30.82     29.77   34.48     26.43   31.44  
Upgrading costs1       10.09         9.63         11.35         9.69  
Less: internal fuel allocation to bitumen2       (2.21 )       (2.21 )       (2.47 )       (2.83 )
Total Syncrude operating expenses       37.55         38.24         43.36         38.30  
Canadian Oil Sands adjustments3       (1.38 )       (1.05 )       (4.22 )       (1.74 )
Total operating expenses       36.17         37.19         39.14         36.56  
                                         
(thousands of barrels per day)                                        
Syncrude production volumes   361   313     355   299     327   282     358   301  
(1) Upgrading costs include the production and ongoing maintenance costs associated with processing and upgrading of bitumen to SCO.
(2) Reflects energy generated by the upgrader that is used in the bitumen production process and is valued by reference to natural gas and diesel prices. Natural gas prices averaged $2.00 per GJ and $2.10 per GJ in the three and nine months ended September 30, 2012, respectively, and $3.50 per GJ and $3.60 per GJ in the three and nine months ended September 30, 2011, respectively. Diesel prices averaged $0.80 per litre and $0.90 per litre in the three and nine months ended September 30, 2012, respectively, and $0.90 per litre in the three and nine months ended September 30, 2011, respectively.
(3) Canadian Oil Sands'' adjustments mainly pertain to actual reclamation costs and major turnaround costs, which Syncrude includes in operating expenses. Canadian Oil Sands capitalizes major turnaround costs and recognizes actual reclamation costs through its asset retirement obligation. Major turnaround costs are expensed through depreciation and reclamation costs are expensed through both depletion and accretion (within net finance expense). Costs of non-major turnarounds are expensed through operating expenses.
(4) Certain comparative period amounts have been restated to conform to the current period presentation.

Operating expenses in the third quarter of 2012 decreased $1.02 per barrel to $36.17 per barrel from $37.19 per barrel in the third quarter of 2011, mainly as a result of higher 2012 production volumes. Year-to-date, 2012 operating expenses increased $2.58 per barrel to $39.14 per barrel from $36.56 per barrel in 2011, reflecting lower 2012 production volumes.

On a total dollar basis, operating expenses in the third quarter and first nine months of 2012 were $378 million and $1,112 million, respectively, compared with $374 million and $1,108 million in the comparative 2011 periods. Operating expenses in the 2012 periods reflect:

  • higher mining contractor costs in the 2012 third quarter relative to the 2011 third quarter;
  • more maintenance activity in the first nine months of 2012 compared to the same period in 2011; and
  • an increase in the value of Syncrude''s long-term incentive plans, as opposed to a decrease in the comparative 2011 periods. A portion of Syncrude''s long-term incentive plans is based on the market return performance of several Syncrude owners'' shares, including those of the Corporation, which was stronger in 2012 than in 2011.

The increase in operating expenses was offset by:

  • lower purchased energy costs, due to lower natural gas prices and diesel volumes, relative to the comparative 2011 periods.

Crown Royalties

Crown royalties decreased to $33 million, or $3.16 per barrel, in the third quarter of 2012 from $65 million, or $6.53 per barrel, in the third quarter of 2011 due primarily to higher bitumen-related capital costs in 2012. On a year-to-date basis, Crown royalties decreased to $145 million, or $5.11 per barrel, in 2012 from $234 million, or $7.74 per barrel, in 2011 due primarily to lower bitumen volumes and higher bitumen-related capital costs in 2012.

The Syncrude Royalty Amending Agreement requires that bitumen be valued by a formula that references the value of bitumen based on North American heavy oil reference prices adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude''s bitumen and the reference price of bitumen. Canadian Oil Sands'' share of the royalties recognized for the period from January 1, 2009 to September 30, 2012 are estimated to be approximately $45 million lower than the amount calculated using the Alberta-government-provided bitumen value for Syncrude. The Syncrude owners and the Alberta government continue to discuss the basis for reasonable quality, transportation, and other adjustments 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 immediately and would impact both net income and cash flow from operations accordingly.

Non-Production Expenses

Non-production expenses totalled $25 million and $75 million in the third quarter and first nine months of 2012, respectively, compared with $28 million and $86 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 $96 million and $284 million in the third quarter and first nine months of 2012, respectively, compared with $93 million and $285 million in the comparative 2011 periods, as Canadian Oil Sands'' depreciable property, plant and equipment, and the estimated useful lives over which most of these assets are depreciated, were similar in both periods.

Net Finance Expense  
   
  Three Months Ended   Nine Months Ended  
  September 30   September 30  
($ millions) 2012   2011   2012   2011  
Interest costs $ 28   $ 22   $ 78   $ 67  
  Less capitalized interest   (25 )   (15 )   (65 )   (39 )
Interest expense   3     7     13     28  
Accretion of asset retirement obligation   6     4     19     12  
Net finance expense $ 9   $ 11   $ 32   $ 40  

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   Nine Months Ended  
  September 30   September 30  
($ millions) 2012   2011   2012   2011  
Foreign exchange (gain) loss - long-term debt $ (64 ) $ 83   $ (48 ) $ 49  
Foreign exchange (gain) loss - other   13     (8 )   7     (4 )
Total foreign exchange (gain) loss $ (51 ) $ 75   $ (41 ) $ 45  

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 gains on long-term debt in 2012 were the result of a strengthening in the value of the Canadian dollar relative to the U.S. dollar to $1.02 U.S./Cdn at September 30, 2012 from $0.98 U.S./Cdn at June 30, 2012 and December 31, 2011. Conversely, the foreign exchange losses in 2011 were the result of a weakening in the value of the Canadian dollar relative to the U.S. dollar to $0.96 U.S./Cdn at September 30, 2011 from $1.04 U.S./Cdn at June 30, 2011 and $1.01 U.S./Cdn at December 31, 2010.

Tax Expense
 
  Three Months Ended Nine Months Ended
  September 30 September 30
($ millions) 2012 2011 2012 2011
Current tax expense $ 10 $ - $ 30 $ -
Deferred tax expense   94   95   213   317
Total tax expense $ 104 $ 95 $ 243 $ 317

The quarter-over-quarter increase in total tax expense from 2011 to 2012 reflects higher earnings before tax in 2012, while the decrease in year-to-date total tax expense from 2011 to 2012 reflects lower 2012 earnings before tax.

Asset Retirement Obligation

Canadian Oil Sands increased its estimated asset retirement obligation from $1,037 million at December 31, 2011 to $1,076 million at September 30, 2012. The increase reflects a lower interest rate used to discount future reclamation payments, partially offset by $48 million of reclamation spending during the first nine months of 2012. The $29 million current portion of the asset retirement obligation is included in accounts payable and accrued liabilities, while the $1,047 million non-current portion is presented separately as an asset retirement obligation on the September 30, 2012 Consolidated Balance Sheet.

Pension and Other Post-Employment Benefit Plans

The Corporation''s share of the estimated unfunded portion of Syncrude Canada''s pension and other post-employment benefit plans decreased to $460 million at September 30, 2012 from $465 million at December 31, 2011, reflecting contributions to the plans largely offset by a lower discount rate used in determining the liability. For the nine months ended September 30, 2012, a $28 million actuarial loss, net of $10 million in deferred taxes, has been recognized in other comprehensive income to reflect the change in the discount rate.

Summary of Quarterly Results
 
  2012 2011 2010
  Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
                                 
Sales1($ millions) $ 941 $ 740 $ 956 $ 884 $ 989 $ 1,045 $ 1,016 $ 912
                                 
Net income ($ millions) $ 338 $ 101 $ 321 $ 232 $ 242 $ 346 $ 324 $ 575
  Per Share, Basic & Diluted $ 0.70 $ 0.21 $ 0.66 $ 0.48 $ 0.50 $ 0.71 $ 0.67 $ 1.19
                                 
Cash flow from operations2($ millions) $ 470 $ 245 $ 454 $ 363 $ 512 $ 544 $ 478 $ 398
  Per Share2 $ 0.97 $ 0.51 $ 0.94 $ 0.75 $ 1.06 $ 1.12 $ 0.99 $ 0.82
                                 
Dividends ($ millions) $ 170 $ 170 $ 145 $ 146 $ 145 $ 145 $ 97 $ 242
  Per Share $ 0.35 $ 0.35 $ 0.30 $ 0.30 $ 0.30 $ 0.30 $ 0.20 $ 0.50
                                 
Daily average sales volumes3 (bbls)   113,331   89,597   108,108   91,259   109,260   102,938   120,894   114,739
                                 
Realized SCO selling price ($/bbl) $ 89.89 $ 90.45 $ 97.07 $ 104.78 $ 97.89 $ 111.00 $ 93.04 $ 83.97
                                 
Operating expenses4 ($/bbl) $ 36.71 $ 50.66 $ 32.68 $ 46.88 $ 37.19 $ 37.07 $ 35.53 $ 35.81
                                 
Purchased natural gas price ($/GJ) $ 2.00 $ 1.79 $ 2.23 $ 3.19 $ 3.51 $ 3.62 $ 3.59 $ 3.45
                                 
WTI5 (average $US/bbl) $ 92.20 $ 93.35 $ 103.03 $ 94.06 $ 89.54 $ 102.34 $ 94.60 $ 85.24
                                 
Foreign exchange rates ($US/$Cdn)                                
  Average $ 1.00 $ 0.99 $ 1.00 $ 0.98 $ 1.02 $ 1.03 $ 1.02 $ 0.99
  Quarter-end $ 1.02 $ 0.98 $ 1.00 $ 0.98 $ 0.96 $ 1.04 $ 1.03 $ 1.01
(1) Sales after crude oil purchases and transportation expense.
(2) Cash flow from operations and cash flow from operations per Share are non-GAAP measures and are defined on 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:

  • fluctuations in realized selling prices have affected the Corporation''s sales, Crown royalties, net income and cash flow from operations. WTI prices have ranged from U.S. $76 per barrel to U.S. $114 per barrel, and the monthly average differentials between SCO and Canadian dollar WTI prices have ranged from a $15 per barrel premium to a $15 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,
  • beginning in the first quarter of 2011, net income reflects an increase in tax expense following the December 31, 2010 conversion from an income trust to a corporation. Net income was higher in the fourth quarter of 2010 due to a $269 million deferred tax recovery resulting from re-measuring the deferred tax liability at a lower tax rate upon corporate conversion.

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. Recent technological developments in North American natural gas production have significantly increased production levels and reduced natural gas prices. These conditions may persist for the next several years.

Syncrude production levels may not display seasonal patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit outages cannot be precisely scheduled and unplanned outages may occur. The costs of major turnarounds are capitalized as property, plant and equipment and depreciated over the period until the next scheduled turnaround. The costs of all other turnarounds and maintenance activities are expensed in the period incurred, which can result in volatility in quarterly operating expenses. 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 Nine Months Ended
  September 30 September 30
($ millions, except % amounts) 2012 2011 2012 2011
                 
Major Projects                
                 
  Mildred Lake Mine Train Replacement $ 135 $ 39 $ 266 $ 77
  Reconstruct crushers, surge facilities, and slurry prep facilities to support tailings storage requirements                
                   
  Aurora North Mine Train Relocation   32   7   64   15
  Relocate crushers, surge facilities, and slurry prep facilities to support tailings storage requirements                
                   
  Aurora North Tailings Management   52   9   91   21
  Construct a composite tails (CT) plant at the Aurora North mine to process tailings                
                   
  Centrifuge Tailings Management   16   -   36   -
  Construct a centrifuge plant at the Mildred Lake mine to process tailings                
                   
  Syncrude Emissions Reduction (SER)   7   30   18   96
  Retrofit technology into Syncrude''s original two cokers to reduce total sulphur dioxide and other emissions                
                 
Capital expenditures on major projects   242   85   475   209
                 
Regular maintenance                
  Capitalized turnaround costs   9   17   76   23
  Other capital1   78   72   171   167
Capital expenditures on regular maintenance   87   89   247   190
                 
Capitalized interest   25   15   65   39
                 
Total capital expenditures $ 354 $ 189 $ 787 $ 438
(1) Other regular maintenance capital includes expenditures on relocation of tailings facilities and other infrastructure projects.

Year-to-date capital expenditures increased to $787 million in 2012 from $438 million in 2011, and to $354 million in the third quarter of 2012 from $189 million in the third quarter of 2011. The increase reflects 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 from 2011 to 2012 reflects the planned turnarounds of Coker 8-3 and the Vacuum Distillation Unit during the second quarter of 2012; by comparison, 2011 capitalized turnaround costs reflect the Coker 8-2 turnaround, which commenced in September 2011 and continued through October 2011. The increase in capitalized interest costs from 2011 to 2012 reflects higher cumulative capital expenditures on qualifying assets in 2012.

Contractual Obligations and Commitments

During the first nine months of 2012, Canadian Oil Sands entered into new contractual obligations totalling approximately $1.2 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 $312 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 $120 million in respect of Syncrude Canada''s registered pension plan, and assumed $84 million in new commitments related to Syncrude Canada''s employee retention program.

Dividends

On October 29, 2012, 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 November 30, 2012 to Shareholders of record on November 26, 2012.

Dividend payments continue to be 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  
   
  September 30   December 31  
($ millions, except % amounts) 2012   2011  
Total debt1,2 $ 1,773   $ 1,132  
Cash and cash equivalents   (1,469 )   (718 )
Net debt1,3 $ 304   $ 414  
Shareholders'' equity $ 4,456   $ 4,210  
Total net capitalization1,4 $ 4,760   $ 4,624  
Total capitalization1,5 $ 6,229   $ 5,342  
Net debt-to-total net capitalization1,6 (%)   6     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 $0.3 billion at September 30, 2012 from $0.4 billion at December 31, 2011. While $1,163 million of cash flow from operations in the first nine months of 2012 fell short of capital expenditures and dividend payments of $787 million and $485 million, respectively, a reduction in non-cash working capital balances more than offset this difference. Shareholders'' equity increased to $4.5 billion at September 30, 2012 from $4.2 billion at December 31, 2011, as net income exceeded dividends in the first nine months of 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 September 30, 2012.

In March 2012, Canadian Oil Sands issued U.S. $400 million of 4.5% senior unsecured notes due April 1, 2022 and U.S. $300 million of 6.0% 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.

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 September 30, 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 the first nine months of 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 several years as we fund major capital projects and repay the 2013 debt maturity. As a result, net debt levels should 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 September 30, 2012, the Corporation had a market capitalization of approximately $10.2 billion with 484.6 million shares outstanding and a closing price of $21.05 per Share. The following table summarizes the trading activity for the third quarter of 2012.

Canadian Oil Sands Limited - Trading Activity
 
  Third Quarter 2012 July 2012 August 2012 September 2012
                 
Share price                
  High $ 22.34 $ 21.41 $ 22.30 $ 22.34
  Low $ 18.74 $ 18.74 $ 19.62 $ 20.54
  Close $ 21.05 $ 20.18 $ 21.04 $ 21.05
                 
Volume of Shares traded (millions)   91.7   25.4   30.8   35.5
Weighted average Shares outstanding (millions)   484.5   484.5   484.5   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 the first nine months of 2012.

Changes in Accounting Policies

There were no new accounting policies adopted, nor any changes to accounting policies, in the first nine months of 2012.

2012 Outlook  
 
 
(millions of Canadian dollars, except volume and per barrel amounts)
As of
October 29
2012
 
 
 
As of
July 27
2012
 
 
 
Operating assumptions            
Syncrude production (mmbbls)   107     110  
Canadian Oil Sands sales (mmbbls)   39.3     40.4  
Sales, net of crude oil purchases and transportation $ 3,698   $ 3,393  
Operating expenses $ 1,485   $ 1,514  
Operating expenses per barrel $ 37.77   $ 37.46  
Crown royalties $ 191   $ 139  
Cash flow from operations $ 1,746   $ 1,461  
Capital expenditure assumptions            
Major projects $ 701   $ 714  
Regular maintenance $ 325   $ 335  
Capitalized interest $ 88   $ 75  
Total capital expenditures $ 1,114   $ 1,124  
Business environment assumptions            
West Texas Intermediate (U.S.$/bbl) $ 95.00   $ 90.00  
Premium (Discount) to average Cdn$ WTI prices (Cdn$/bbl) $ (1.00 ) $ (7.00 )
Foreign exchange rate (U.S.$/Cdn$) $ 1.00   $ 0.99  
AECO natural gas (Cdn$/GJ) $ 2.25   $ 2.50  

Canadian Oil Sands has increased estimated 2012 sales, net of crude oil purchases and transportation expense, to $3,698 million, due primarily to an increase in the forecast realized selling price partially offset by a decrease in estimated production volumes.

The forecast plant-gate realized selling price has increased $10 per barrel to $94 per barrel and assumes a U.S. $95 per barrel WTI oil price, a foreign exchange rate of $1.00 U.S./Cdn, and a SCO discount to Cdn dollar WTI of $1.00 per barrel.

The increase in forecast SCO prices relative to WTI reflects actual year-to-date results and 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. Pipeline apportionments can exacerbate this situation by restricting the ability of SCO and other crude oils to reach their 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 capacity is available to deliver crude oil from western Canada to Cushing, Oklahoma or the U.S. Gulf Coast.

We have reduced our single-point 2012 Syncrude production estimate by three million barrels to 107 million barrels (39.3 million barrels net to the Corporation) or 292,300 barrels per day (107,400 barrels per day net to the Corporation), and have adjusted our production range estimate to 105 million to 108 million barrels, based on the results achieved during the first nine months of the year. The 107 million barrel single-point estimate assumes robust production without major interruptions for the remainder of the year. There is no major maintenance planned for the fourth quarter of 2012.

We estimate 2012 operating expenses of $1,485 million, or $37.77 per barrel, reflecting actual costs incurred to date and a reduced natural gas price assumption of $2.25 per gigajoule.

The estimate for 2012 capital expenditures has decreased by $10 million to $1,114 million.

We estimate current taxes of approximately $40 million in 2012 and approximately $400 million in 2013.

We estimate 2012 cash flow from operations of $1,746 million, or $3.60 per Share. After deducting forecast 2012 capital expenditures, we estimate $632 million in remaining cash flow from operations for the year, or $1.30 per Share.

We estimate having approximately $1.6 billion of cash, and approximately $0.2 billion of net debt, at December 31, 2012.

We expect cash levels to decrease significantly over the next several years as we fund major capital projects and repay the 2013 debt maturity. As a result, net debt levels should 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 (October 29, 2012)
    Cash Flow from Operations
    Increase
Variable1 Annual Sensitivity $ millions $ / Share
Syncrude operating expense decrease Cdn$1.00/bbl $ 32 $ 0.07
Syncrude operating expense decrease Cdn$50 million $ 15 $ 0.03
WTI crude oil price increase U.S.$1.00/bbl $ 33 $ 0.07
Syncrude production increase 2 million bbls $ 57 $ 0.12
Canadian dollar weakening U.S.$0.01/Cdn$ $ 30 $ 0.06
AECO natural gas price decrease Cdn$0.50/GJ $ 23 $ 0.05
(1) 2012 cash flow from operations sensitivities are not expected to be significantly impacted by income taxes; however, in 2013, Canadian Oil Sands expects to record current taxes of approximately $400 million.

The 2012 Outlook contains forward-looking information and users are cautioned that the actual amounts may vary from the estimates disclosed. Please refer to the "Forward-Looking Information Advisory" section of this MD&A for the risks and assumptions underlying this forward-looking information.

Major Projects

The following tables provide cost and schedule estimates for Syncrude''s major projects. Regular maintenance capital costs for years after 2012 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 Estimates 1
 
 
 
 
 
 
Total Cost
Estimate
($ billions)
Estimated %
Complete at
Sep 30, 20122
 
Estimated %
Accuracy
 
 
 
Target
In-Service
Date
Mildred Lake              
  Mine Train Replacement Syncrude $ 4.2 30 +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 40 +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 55 +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 5 +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, 2011 2012 2013 2014 2015
                     
Syncrude $ 0.9 $ 1.9 $ 2.6 $ 2.2 $ 0.3