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

CALGARY, ALBERTA--(Marketwire - Jan 31, 2013) - 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, 2012:

  • Cash flow from operations was $418 million ($0.86 per Share) in the fourth quarter of 2012 compared with cash flow from operations of $363 million ($0.75 per Share) in the same quarter of 2011. For the 2012 year, cash flow from operations totalled $1,581 million ($3.26 per Share), down 17 per cent from $1,897 million ($3.91 per Share) in 2011.
  • The quarter-over-quarter increase in cash flow from operations reflects higher sales volumes, partially offset by a lower realized selling price. The year-over-year decrease in cash flow from operations reflects a lower realized selling price, partially offset by lower Crown royalties.
  • Net income for the fourth quarter of 2012 was $221 million ($0.46 per Share), down from $232 million ($0.48 per Share) in the 2011 fourth quarter. On an annual basis, net income was $981 million ($2.02 per Share) in 2012 compared with $1,144 million ($2.36 per Share) in 2011. 
  • COS maintained its quarterly dividend at $0.35 per Share, payable on February 28, 2013 to shareholders of record on February 22, 2013. During 2012, the Corporation paid a total of $654 million, or $1.35 per Share, in dividends to shareholders.
  • Sales volumes averaged 105,700 barrels per day in 2012 compared with volumes averaging 106,000 barrels per day in 2011.
  • Operating expenses were $1,511 million, or $39.06 per barrel, in 2012, compared with operating expenses of $1,501 million, or $38.80 per barrel, in 2011. In 2012, higher production costs, primarily related to lower reliability in mining, offset savings in purchased energy costs from lower natural gas prices and diesel volumes relative to 2011.
  • Capital expenditures increased to $1,086 million in 2012 from $643 million in 2011, as progress continued on major capital projects to replace or relocate Syncrude mining trains and to support tailings management plans.
  • Net debt (total debt less cash and cash equivalents) decreased to $241 million at December 31, 2012 from $414 million at December 31, 2011. Net debt levels are expected to rise over the next two years, as COS draws down its $1,553 million cash balance at December 31, 2012 to fund the major capital projects program.

"Our dividend level of $0.35 per Share per quarter for 2013 is well supported by a strong balance sheet and a major capital projects program that is proceeding on schedule and on budget," said Marcel Coutu, President and Chief Executive Officer. "Our outlook for 2013 is based on an $80 per barrel plant-gate realized selling price and a five per cent increase in production rates over 2012. We will continue to conservatively manage our business as we progress through our capital program, and we are well positioned at this time both financially and operationally."

Added Coutu: "Our average realized selling price of $92 per barrel in 2012 was relatively strong, given the dynamics of North American crude oil markets. As a result of limited transportation capacity, the WTI benchmark price for crude oil traded at a discount of about $18 per barrel relative to global crude oil prices, which averaged $112 per barrel in 2012. Producers in western Canada generally experienced a further discount to WTI oil prices; however, pricing for our high-quality SCO blend averaged a discount of only $2.50 per barrel relative to WTI, demonstrating the value of our upgrader. We expect the differential between WTI and global crude oil prices to narrow as additional pipeline capacity comes on through 2013 and 2014. Our unhedged approach allows us to capture any upside in WTI oil prices."

Highlights
  Three Months Ended Year Ended
  December 31 December 31
  2012 2011 2012   2011
           
Cash flow from operations1 ($ millions) $ 418 $ 363 $ 1,581   $ 1,897
  Per Share1 ($/Share) $ 0.86 $ 0.75 $ 3.26   $ 3.91
                   
Net income ($ millions) $ 221 $ 232 $ 981   $ 1,144
  Per Share, Basic and Diluted ($/Share) $ 0.46 $ 0.48 $ 2.02   $ 2.36
                   
Sales volumes2                  
  Total (mmbbls)   10.3   8.4   38.7     38.7
  Daily average (bbls)   111,669   91,259   105,680     106,015
                   
Realized SCO selling price ($/bbl) $ 89.99 $ 104.78 $ 91.90   $ 101.20
                   
West Texas Intermediate ("WTI") (average $US/bbl) $ 88.23 $ 94.06 $ 94.15   $ 95.11
                   
SCO premium (discount) to WTI $ 2.43 $ 8.51 $ (2.52 ) $ 7.32
  (weighted average $/bbl)                  
                   
Operating expenses ($/bbl) $ 38.85 $ 46.88 $ 39.06   $ 38.80
                   
Capital expenditures ($ millions) $ 299 $ 205 $ 1,086   $ 643
                   
Dividends ($ millions) $ 169 $ 146 $ 654   $ 533
  Per Share ($/Share) $ 0.35 $ 0.30 $ 1.35   $ 1.10
(1) Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined on page 5 within the Management''s Discussion and Analysis ("MD&A") section of this report.
(2) The Corporation''s sales volumes differ from its production volumes due to changes in inventory, which are primarily in-transit pipeline volumes. Sales volumes are net of purchases.

Syncrude operations

Syncrude produced an average of 298,900 barrels per day (total 27.5 million barrels) during the fourth quarter of 2012, up from 252,300 barrels per day (total 23.2 million barrels) during the same 2011 period. Production in the 2012 fourth quarter mainly reflects unplanned outages in mine trains, which limited bitumen production. Volumes in the 2011 fourth quarter reflect unplanned outages of Coker 8-1 and a hydrogen unit. 

In 2012, Syncrude production averaged about 286,500 barrels per day (104.9 million barrels total) compared with about 288,400 barrels per day (105.3 million barrels total) in 2011.

Syncrude recently released its 2010/2011 Sustainability Report, which is available on Syncrude''s website at the following link: http://www.syncrude.ca/users/folder.asp?FolderID=5713. The report provides an overview of Syncrude''s performance in the areas of economic contribution, stakeholder and employee engagement, community investment, health and safety, and environmental stewardship.

2013 Outlook

The following highlights Canadian Oil Sands'' key estimates and assumptions for 2013:

  • We estimate an annual production range for Syncrude of 105 million to 115 million barrels in 2013. The single-point production figure of 110 million barrels, 40.4 million barrels net to COS, incorporates a planned turnaround of Coker 8-1 in the second half of the year.
  • Sales, net of crude oil purchases and transportation expense, of approximately $3.2 billion reflect a production estimate of 40.4 million barrels and an $80 per barrel plant-gate realized selling price (based on a U.S. $85 per barrel WTI oil price, a foreign exchange rate of $1.00 U.S./Cdn, and a SCO discount to Cdn dollar WTI of $5.00 per barrel).
  • We estimate cash flow from operations of $1,045 million, or $2.16 per Share.
  • Capital expenditures are estimated to total $1,326 million, comprised of $836 million of spending on major projects, $393 million in regular maintenance of the business and other projects, and $97 million in capitalized interest.
  • COS intends to maintain a quarterly dividend of $0.35 per Share in 2013, based on the assumptions provided in our Outlook for 2013.

More information on the outlook is provided in the MD&A section of this report and the January 31, 2013 guidance document, which is available on our web site at www.cdnoilsands.com under "Investor Information".

The 2013 Outlook contains forward-looking information and users are cautioned that the actual amounts may vary from the estimates disclosed. Please refer to the "Forward-Looking Information Advisory" in the MD&A section of this report for the risks and assumptions underlying this forward-looking information.

Management''s Discussion and Analysis

The following Management''s Discussion and Analysis ("MD&A") was prepared as of January 31, 2013 and should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Canadian Oil Sands Limited (the "Corporation") for the three months and year ended December 31, 2012 and December 31, 2011, the audited consolidated financial statements and MD&A of the Corporation for the year ended December 31, 2011 and the Corporation''s Annual Information Form ("AIF") dated February 23, 2012. Additional information on the Corporation, including its AIF, is available on SEDAR at www.sedar.com or on the Corporation''s website at www.cdnoilsands.com. References to "Canadian Oil Sands" or "we" include the Corporation, its subsidiaries and partnerships. The financial results of Canadian Oil Sands have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") and are reported in Canadian dollars, unless stated otherwise.

Forward Looking Information Advisory

In the interest of providing the Corporation''s shareholders and potential investors with information regarding the Corporation, including management''s assessment of the Corporation''s future production and cost estimates, plans and operations, certain statements throughout this MD&A and the related press release contain "forward-looking information" under applicable securities law. Forward-looking statements are typically identified by words such as "anticipate", "expect", "believe", "plan", "intend" or similar words suggesting future outcomes.

Forward-looking statements in this MD&A and the related press release include, but are not limited to, statements with respect to: the expectations regarding the 2013 annual Syncrude forecasted production range of 105 million barrels to 115 million barrels and the single-point Syncrude production estimate of 110 million barrels (40.4 million barrels net to the Corporation); the timing of the Coker 8-1 turnaround; the intention to maintain a quarterly dividend of $0.35 per Share in 2013 based on the assumptions in our 2013 Outlook; future dividends and any increase or decrease from current payment amounts; the establishment of future dividend levels with the intent of absorbing short-term market volatility over several quarters; the level of natural gas consumption in 2013 and beyond; the expected sales, operating expenses, non-production expenses, Crown royalties, capital expenditures and cash flow from operations for 2013; the anticipated amount of current taxes in 2013; expectations regarding current taxes beyond 2013; the expectation that proceeds from the March 2012 senior note offering will be used to repay U.S. $300 million of senior notes which mature on August 15, 2013, to fund major capital projects over the next few years and for general corporate purposes; expectations regarding the Corporation''s cash levels for 2013 and 2014; the expected price for crude oil and natural gas in 2013; the expected foreign exchange rates in 2013; the expected realized selling price, which includes the anticipated differential to West Texas Intermediate ("WTI") to be received in 2013 for the Corporation''s product; the expectations regarding net debt; the anticipated impact of increases or decreases in oil prices, production, operating expenses, foreign exchange rates and natural gas prices on the Corporation''s cash flow from operations; the expectation that regular maintenance capital costs will average approximately $10 per barrel over the next few years; the expected amount of total major project costs, anticipated target in-service dates and estimated completion percentages for the Mildred Lake mine train replacements, the Aurora North mine train relocations, the composite tails plant at the Aurora North mine and the centrifuge plant at the Mildred Lake mine; the expectation that the Corporation will finance the major projects primarily with existing cash balances and cash flow from operations; the cost estimates for 2013 to 2015 major project spending; the expectation that the volatility in the Synthetic Crude Oil ("SCO") to WTI differential is likely to persist for several years until additional pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast or the Canadian East or West Coasts; and the expectation that the differential between WTI and global crude oil prices will narrow as additional pipeline capacity comes on through 2013 and 2014.

You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Corporation believes that the expectations represented by such forward-looking statements are reasonable and reflect the current views of the Corporation with respect to future events, there can be no assurance that such assumptions and expectations will prove to be correct.

The factors or assumptions on which the forward-looking information is based include, but are not limited to: the assumptions outlined in the Corporation''s guidance document as posted on the Corporation''s website at www.cdnoilsands.com as of January 31, 2013 and as subsequently amended or replaced from time to time, including without limitation, the assumptions as to production, operating expenses and oil prices; the successful and timely implementation of capital projects; Syncrude''s major project spending plans; the ability to obtain regulatory and Syncrude joint venture owner approval; our ability to either generate sufficient cash flow from operations to meet our current and future obligations or obtain external sources of debt and equity capital; the continuation of assumed tax, royalty and regulatory regimes and the accuracy of the estimates of our reserves and resources volumes.

Some of the risks and other factors which could cause actual results or events to differ materially from current expectations expressed in the forward-looking statements contained in this MD&A and the related press release include, but are not limited to: the impacts of legislative or regulatory changes especially as such relate to royalties, taxation, the environment and tailings; the impact of technology on operations and processes and how new complex technology may not perform as expected; skilled labour shortages and the productivity achieved from labour in the Fort McMurray area; the supply and demand metrics for oil and natural gas; the impact that pipeline capacity and refinery demand have on prices for our products; the unanimous joint venture owner approval for major expansions and changes in product types; the variances of stock market activities generally; global economic conditions/volatility; normal risks associated with litigation, general economic, business and market conditions; the impact of Syncrude being unable to meet the conditions of its approval for its tailings management plan under Directive 074; volatility of crude oil prices; volatility of the SCO to WTI price differential; unsuccessful or untimely implementation of capital or maintenance projects and such other risks and uncertainties described in the Corporation''s AIF dated February 23, 2012 and in the reports and filings made with securities regulatory authorities from time to time by the Corporation which are available on the Corporation''s profile on SEDAR at www.sedar.com and on the Corporation''s website at www.cdnoilsands.com.

You are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this MD&A and the related press release are made as of January 31, 2013, and unless required by law, the Corporation does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A and the related press release are expressly qualified by this cautionary statement.

Non-GAAP and Additional GAAP Financial Measures

In this MD&A and the related press release, we refer to financial measures that do not have any standardized meaning as prescribed by Canadian GAAP. These financial measures include additional GAAP financial measures, which are line items, headings or subtotals in addition to those required under Canadian GAAP, and non-GAAP financial measures. Additional GAAP and non-GAAP financial measures provide additional information that we believe is meaningful regarding the Corporation''s operational performance, its liquidity and its capacity to fund dividends, capital expenditures and other investing activities. Users are cautioned that additional GAAP and non-GAAP financial measures presented by the Corporation may not be comparable with measures provided by other entities.

We refer to one additional GAAP financial measure: cash flow from operations, which is calculated as cash from operating activities, as reported on the Consolidated Statement of Cash Flows, before changes in non-cash working capital. We believe cash flow from operations, which is not impacted by fluctuations in non-cash working capital balances, is more indicative of operational performance. The majority of our non-cash working capital is liquid and typically settles within 30 days.

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

  Three Months Ended   Year Ended
  December 31   December 31
($ millions) 2012 2011   2012 2011
           
Cash flow from operations $ 418 $ 363   $ 1,581 $ 1,897
Change in non-cash working capital1   178   (47 )   283   61
Cash from operating activities1 $ 596 $ 316   $ 1,864 $ 1,958
(1) As reported in the Consolidated Statements of Cash Flows.

Non-GAAP financial measures include cash flow from operations per Share, which is calculated as cash flow from operations divided by the weighted-average number of Shares outstanding in the period; net debt; total debt; total net capitalization; total capitalization; net debt-to-total net capitalization; and total debt-to-total capitalization. In addition, the Corporation refers to various per barrel figures, such as net realized selling prices, operating expenses and Crown royalties, which also are considered non-GAAP measures. We derive per barrel figures by dividing the relevant sales or cost figure by our sales volumes, which are net of purchased crude oil volumes in a period.

Overview
 
Highlights
  Three Months Ended Year Ended
  December 31 December 31
  2012 2011 2012   2011
                   
Cash flow from operations1 ($ millions) $ 418 $ 363 $ 1,581   $ 1,897
  Per Share1 ($/Share) $ 0.86 $ 0.75 $ 3.26   $ 3.91
                   
Net income ($ millions) $ 221 $ 232 $ 981   $ 1,144
  Per Share, Basic and Diluted ($/Share) $ 0.46 $ 0.48 $ 2.02   $ 2.36
                   
Sales volumes2                  
  Total (mmbbls)   10.3   8.4   38.7     38.7
  Daily average (bbls)   111,669   91,259   105,680     106,015
                   
Realized SCO selling price ($/bbl) $ 89.99 $ 104.78 $ 91.90   $ 101.20
                   
West Texas Intermediate ("WTI") (average $US/bbl) $ 88.23 $ 94.06 $ 94.15   $ 95.11
                   
SCO premium (discount) to WTI $ 2.43 $ 8.51 $ (2.52 ) $ 7.32
  (weighted average $/bbl)                  
                   
Operating expenses ($/bbl) $ 38.85 $ 46.88 $ 39.06   $ 38.80
                   
Capital expenditures ($ millions) $ 299 $ 205 $ 1,086   $ 643
                   
Dividends ($ millions) $ 169 $ 146 $ 654   $ 533
  Per Share ($/Share) $ 0.35 $ 0.30 $ 1.35   $ 1.10
(1) Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined on page 5 of this report.
   
(2) The Corporation''s sales volumes differ from its production volumes due to changes in inventory, which are primarily in-transit pipeline volumes. Sales volumes are net of purchases.

To view cash flow from operations, please visit the following link: http://media3.marketwire.com/docs/131cos1.pdf.

  • The quarter-over-quarter increase in cash flow from operations reflects higher sales volumes, partially offset by a lower realized selling price.
  • The year-over-year decrease in cash flow from operations reflects a lower realized selling price, partially offset by lower Crown royalties.

Sales Volumes

  • Synthetic Crude Oil ("SCO") production from the Syncrude Joint Venture ("Syncrude") during the fourth quarter of 2012 was lower than expected, primarily due to unplanned outages in mine trains which limited bitumen production.
  • SCO production in the 2012 fourth quarter totalled 27.5 million barrels, or 298,900 barrels per day, a 19 per cent increase over fourth quarter 2011 production of 23.2 million barrels, or 252,300 barrels per day, when volumes reflected the unplanned outages of Coker 8-1 and a hydrogen unit.
  • On an annual basis, Syncrude produced 104.9 million barrels of SCO, or 286,500 barrels per day, in 2012 compared with 105.3 million barrels, or 288,400 barrels per day, in 2011.
  • Volumes in 2012 reflect maintenance on Coker 8-1, planned turnarounds of Coker 8-3 and the Vacuum Distillation Unit, and unplanned outages in mine trains. Volumes in 2011 reflect the Coker 8-2 turnaround and unplanned outages of Coker 8-1 and a hydrogen unit.

Selling Price

  • The fourth quarter 2012 realized selling price averaged $90 per barrel, a $15 per barrel decrease from $105 per barrel in the fourth quarter of 2011, reflecting a lower SCO premium relative to WTI and a lower WTI oil price.
  • On an annual basis, the realized selling price in 2012 averaged $92 per barrel, a $9 per barrel decrease from $101 per barrel in 2011, reflecting a SCO discount relative to WTI in 2012 as opposed to a premium in 2011.

Crown Royalties

  • Crown royalties decreased from 2011 to 2012, reflecting increases in deductible capital expenditures.

Operating Expenses

  • On a total dollar basis, 2012 operating expenses were similar to 2011, reflecting higher production costs offset by lower purchased energy costs.
  • On a per-barrel basis, the quarter-over-quarter decrease in fourth quarter 2012 operating expenses reflects higher production volumes.

Capital Expenditures

  • Capital expenditures increased as expected in 2012, as progress on capital projects to replace or relocate Syncrude mine trains and to support tailings management plans, continued on schedule and on budget.

Net Debt

  • Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, decreased to $0.2 billion at December 31, 2012 from $0.4 billion at December 31, 2011.

Dividends

  • The Corporation has declared a quarterly dividend of $0.35 per Share, to be paid on February 28, 2013 to Shareholders of record on February 22, 2013. During 2012, the Corporation paid dividends to shareholders totalling $654 million, or $1.35 per Share.

Debt Issue

  • On March 29, 2012, the Corporation issued U.S. $700 million of long-term debt, providing increased liquidity to fund major capital projects and the U.S. $300 million debt maturity in 2013.

Review of Financial Results

Net Income

Net income decreased to $221 million, or $0.46 per Share, in the fourth quarter of 2012 from $232 million, or $0.48 per Share, in the fourth quarter of 2011, reflecting a lower realized selling price and a foreign exchange loss (as opposed to a foreign exchange gain in the 2011 fourth quarter), partially offset by higher sales volumes. The Corporation realizes foreign exchange gains and losses primarily as a result of revaluations of its U.S. dollar-denominated debt.

On an annual basis, net income decreased to $981 million, or $2.02 per Share, in 2012 from $1,144 million, or $2.36 per Share, in 2011, reflecting a lower realized selling price partially offset by lower Crown royalties, lower taxes, and a foreign exchange gain (as opposed to a loss in 2011).

The following table shows the components of net income per barrel of SCO:

    Three Months Ended   Year Ended  
    December 31   December 31  
($ per barrel)1   2012   2011   $ Change   2012   2011   $ Change  
                                       
Sales net of crude oil purchases and transportation expense   $ 90.44   $ 105.17   $ (14.73 ) $ 92.21   $ 101.66   $ (9.45 )
Operating expenses     (38.85 )   (46.88 )   8.03     (39.06 )   (38.80 )   (0.26 )
Crown royalties     (5.57 )   (8.64 )   3.07     (5.21 )   (7.93 )   2.72  
    $ 46.02   $ 49.65   $ (3.63 ) $ 47.94   $ 54.93   $ (6.99 )
                                       
Non-production expenses   $ (2.55 ) $ (3.19 ) $ 0.64   $ (2.62 ) $ (2.93 ) $ 0.31  
Administration and insurance     (0.95 )   (1.14 )   0.19     (0.95 )   (0.85 )   (0.10 )
Depreciation and depletion     (11.54 )   (11.40 )   (0.14 )   (10.41 )   (9.84 )   (0.57 )
Net finance expense     (0.66 )   (0.80 )   0.14     (1.01 )   (1.19 )   0.18  
Foreign exchange (loss) gain     (1.50 )   2.66     (4.16 )   0.65     (0.57 )   1.22  
Tax expense     (7.33 )   (8.31 )   0.98     (8.23 )   (10.00 )   1.77  
    $ (24.53 ) $ (22.18 ) $ (2.35 ) $ (22.57 ) $ (25.38 ) $ 2.81  
Net income per barrel   $ 21.49   $ 27.47   $ (5.98 ) $ 25.37   $ 29.55   $ (4.18 )
Sales volumes (mmbbls)2     10.3     8.4     1.9     38.7     38.7     -  
(1) Unless otherwise specified, the per barrel measures in this MD&A have been derived by dividing the relevant item by sales volumes in the period.
(2) Sales volumes, net of purchased crude oil volumes.
 
Sales Net of Crude Oil Purchases and Transportation Expense
  Three Months Ended   Year Ended  
  December 31   December 31  
($ millions, except where otherwise noted) 2012   2011   $ Change   2012   2011   $ Change  
                         
Sales1 $ 1,000   $ 973   $ 27   $ 3,905   $ 4,182   $ (277 )
Crude oil purchases   (55 )   (83 )   28     (295 )   (221 )   (74 )
Transportation expense   (16 )   (6 )   (10 )   (44 )   (27 )   (17 )
  $ 929   $ 884   $ 45   $ 3,566   $ 3,934   $ (368 )
Sales volumes2                                    
  Total (mmbbls)   10.3     8.4     1.9     38.7     38.7     -  
  Daily average (bbls)   111,669     91,259     20,410     105,680     106,015     (335 )
                                     
Realized SCO selling price3 $ 89.99   $ 104.78   $ (14.79 ) $ 91.90   $ 101.20   $ (9.30 )
(average $Cdn/bbl)                                    
                                     
West Texas Intermediate ("WTI") $ 88.23   $ 94.06   $ (5.83 ) $ 94.15   $ 95.11   $ (0.96 )
(average $US/bbl)                                    
                                     
SCO premium (discount) to WTI $ 2.43   $ 8.51   $ (6.08 ) $ (2.52 ) $ 7.32   $ (9.84 )
(weighted average $Cdn/bbl)                                    
                                     
Average foreign exchange rate $ 1.01   $ 0.98   $ 0.03   $ 1.00   $ 1.01   $ (0.01 )
($US/$Cdn)                                    
(1) Sales include sales of purchased crude oil and sulphur.
(2) Sales volumes, net of purchased crude oil volumes.
(3) SCO sales net of crude oil purchases and transportation expense divided by sales volumes, net of purchased crude oil volumes.

The $45 million, or five per cent, increase in fourth quarter 2012 sales, net of crude oil purchases and transportation expense, reflects higher sales volumes partially offset by a lower average realized SCO selling price relative to the 2011 fourth quarter.

Fourth quarter 2012 sales volumes averaged 111,700 barrels per day, up from 91,300 barrels per day in the 2011 fourth quarter, when production was impacted by the unplanned Coker 8-1 and hydrogen unit outages.

The fourth quarter 2012 realized selling price averaged $89.99 per barrel, a $14.79 per barrel decrease from $104.78 per barrel in the fourth quarter of 2011. The Corporation realized a $2.43 per barrel weighted-average SCO premium to WTI in the fourth quarter of 2012 compared with an $8.51 per barrel premium in the fourth quarter of 2011. WTI averaged U.S. $88 per barrel and the Canadian dollar averaged U.S. $1.01 in the 2012 fourth quarter compared with U.S. $94 per barrel and U.S. $0.98, respectively, in the 2011 fourth quarter.

On an annual basis, the $368 million, or nine per cent, decrease in 2012 sales, net of crude oil purchases and transportation expense, reflects a lower average realized SCO selling price.

The realized selling price in 2012 averaged $91.90 per barrel compared with $101.20 per barrel in 2011. The Corporation realized a $2.52 per barrel weighted-average SCO discount to WTI in 2012 as opposed to a $7.32 per barrel premium in 2011. WTI averaged U.S. $94 per barrel and the Canadian dollar averaged U.S. $1.00 in 2012, compared with U.S. $95 per barrel and U.S. $1.01, respectively, in 2011.

The SCO to WTI differential reflects supply/demand fundamentals for inland North American light crude oil. Increasing North American production of both SCO and light crude oil, and refinery modifications that enable processing of heavier crude oils, can push light crude sales, including SCO, to more distant refineries, thereby increasing transportation costs and reducing the net realized price. A number of pipelines in both Canada and the United States are at, or near, capacity and any pipeline apportionments can exacerbate this situation by restricting the ability of SCO and other crude oils to reach preferred markets. However, strong demand from customers and increases in rail shipments of inland crude to coastal refineries can offset these forces. These supply and demand dynamics create price volatility that is likely to persist for several years until additional pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast, or the Canadian East or West Coasts.

Certain of these same fundamentals are also impacting the prices of Canadian heavy oil, such as Western Canadian Select ("WCS"), which is the heavy oil reference price used as a starting point to calculate Syncrude Crown royalties. WCS is generally priced at a discount to WTI, and this discount increased in the fourth quarter of 2012 relative to the comparative 2011 quarter, contributing to lower Crown royalties.

Sales volumes averaged 105,700 barrels per day in 2012 compared with 106,000 barrels per day in 2011.

The Corporation purchases crude oil from third parties to fulfill sales commitments with customers when there are shortfalls in Syncrude''s production and to facilitate certain transportation arrangements and operations. Sales include the sale of purchased crude oil while the cost of these purchases is included in crude oil purchases and transportation expense. Crude oil purchases were lower in the 2012 fourth quarter relative to the comparative 2011 period, reflecting additional purchased volumes in 2011 to support unanticipated production shortfalls. On an annual basis, crude oil purchases were higher in 2012 relative to 2011, reflecting additional purchased volumes to support transportation arrangements.

Operating Expenses

The following table breaks down operating expenses into their major components:

  Three Months Ended Year Ended
  December 31 December 31
  2012 2011 2012 2011
  $ millions $ per bbl $ millions $ per bbl $ millions $ per bbl $ millions $ per bbl
                                 
Production1 $ 320 $ 31.11 $ 297 $ 35.40 $ 1,242 $ 32.12 $ 1,163 $ 30.08
Natural gas and diesel purchases2   38   3.67   46   5.47   125   3.22   194   5.01
Pension and long-term compensation   32   3.16   37   4.45   103   2.67   100   2.58
Other3   9   0.91   13   1.56   41   1.05   44   1.13
Total operating expenses $ 399 $ 38.85 $ 393 $ 46.88 $ 1,511 $ 39.06 $ 1,501 $ 38.80
(1) Includes maintenance (planned and unplanned) as well as non-major turnaround costs. Major turnaround costs are capitalized as property, plant and equipment.
(2) Includes costs to purchase natural gas used to produce energy and hydrogen and diesel consumed as fuel.
(3) Includes fees for management services provided by Imperial Oil Resources, insurance premiums, and greenhouse gas emissions levies.

On a total dollar basis, operating expenses in the fourth quarter of 2012 were similar to the fourth quarter of 2011, reflecting higher production costs largely offset by decreases in other operating expense components. The increase in production costs was due primarily to:

  • the start-up of a pilot centrifuge plant to treat tailings;
  • higher mining expenses, primarily due to reliability issues with Syncrude''s trucks and other mobile equipment; and
  • higher maintenance costs, reflecting the unplanned outages in the mine trains.

On an annual basis, total operating expenses in 2012 were similar to 2011, reflecting higher production costs largely offset by lower natural gas and diesel purchases. The increase in production costs was due primarily to:

  • the start-up of a pilot centrifuge plant to treat tailings;
  • cost escalation; and
  • higher maintenance costs, reflecting the Coker 8-1 shutdown in the first quarter of the year.

The lower natural gas and diesel purchases reflect lower natural gas prices and diesel volumes relative to 2011.

Per-barrel operating expenses decreased in the fourth quarter of 2012, mainly as a result of higher production volumes.

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

  Three Months Ended   Year Ended  
  December 31   December 31  
  2012   20113   2012   20113  
($ per barrel) Bitumen SCO   Bitumen SCO   Bitumen SCO   Bitumen SCO  
Bitumen production $ 24.67 $ 28.44   $ 29.58 $ 35.18   $ 25.70 $ 29.73   $ 24.43 $ 29.07  
Internal fuel allocation1   2.05   2.37     2.47   2.93     2.11   2.44     2.40   2.85  
Total bitumen production expenses $ 26.72 $ 30.81   $ 32.05 $ 38.11   $ 27.81 $ 32.17   $ 26.83 $ 31.92  
                                         
Upgrading2     $ 10.41       $ 11.70       $ 9.33       $ 9.73  
Less: internal fuel allocation to       (2.37 )       (2.93 )       (2.44 )       (2.85 )
bitumen production1                                        
Total upgrading expenses     $ 8.04       $ 8.77       $ 6.89       $ 6.88  
                                         
Total operating expenses     $ 38.85       $ 46.88       $ 39.06       $ 38.80  
                                         
(thousands of barrels per day)                                        
Syncrude production volumes   345   299     300   252     331   287     343   288  
Canadian Oil Sands sales volumes       122         91         106         106  
(1) Reflects energy generated by the upgrader that is used in the bitumen production process and is valued by reference to natural gas and diesel prices. Natural gas prices averaged $3.02 per GJ and $2.34 per GJ in the three months and year ended December 31, 2012, respectively, and $3.19 per GJ and $3.48 per GJ in the three months and year ended December 31, 2011, respectively. Diesel prices averaged $0.90 per litre in the three months and year ended December 31, 2012, and $1.08 per litre and $0.94 per litre in the three months and year ended December 31, 2011, respectively.
(2) Upgrading expenses include the production and maintenance expenses associated with processing and upgrading bitumen to SCO.
(3) Certain comparative period amounts have been restated to conform to the current period presentation.

Crown Royalties

Crown royalties decreased to $57 million, or $5.57 per barrel, in the fourth quarter of 2012, from $73 million, or $8.64 per barrel, in the fourth quarter of 2011 due primarily to increases in deductible capital expenditures, partially offset by higher bitumen volumes in the 2012 quarter. On an annual basis, Crown royalties decreased to $202 million, or $5.21 per barrel, in 2012 from $307 million, or $7.93 per barrel, in 2011 due primarily to increases in deductible capital expenditures in 2012. The higher capital expenditures in 2012 reflect increased spending on capital projects to replace or relocate Syncrude mine trains and to support tailings management plans.

The Syncrude Royalty Amending Agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil reference price further adjusted to reflect quality and location differences between Syncrude''s bitumen and the Canadian reference price bitumen. In addition, the agreement provides that a minimum bitumen value, or "floor price," may be imposed in circumstances where Canadian heavy oil prices are temporarily suppressed relative to North American heavy oil prices.

Canadian Oil Sands'' share of the royalties recognized for the period from January 1, 2009 to December 31, 2012 reflect management''s best estimate of both reasonable quality and transportation deductions and adjustments to reflect the "floor price." However, the Syncrude owners and the Alberta government are disputing the basis for the quality, transportation and "floor price" adjustments. Under alternate assumptions, Crown royalties for this period could be as much as $55 million (on an after-tax basis) more than the amounts recognized.

The Syncrude owners and the Alberta government continue to discuss these matters, but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. The cumulative impact, if any, of such discussions or judicial determination, as applicable, would be recognized and impact both net income and cash flow from operations accordingly.

Non-Production Expenses

Non-production expenses totalled $26 million and $101 million in the 2012 fourth quarter and full year, respectively, compared with $27 million and $113 million in the comparative 2011 periods. Non-production expenses consist primarily of development expenditures relating to capital programs, which are expensed, such as pre-feasibility engineering, technical and support services, research and development, evaluation drilling and regulatory and stakeholder consultation expenditures. Non-production expenses can vary from period to period depending on the number of projects underway and the development stage of the projects.

Depreciation and Depletion Expense

Depreciation and depletion expense totalled $119 million and $403 million in the 2012 fourth quarter and full year, respectively, compared with $96 million and $381 million in the comparative 2011 periods, reflecting changes made during the fourth quarter of 2012 to the estimated useful lives of certain assets.

Net Finance Expense  
  Three Months Ended   Year Ended  
  December 31   December 31  
($ millions) 2012   2011   2012   2011  
                         
Interest costs1 $ 26   $ 20   $ 105   $ 87  
  Less capitalized interest   (26 )   (18 )   (92 )   (57 )
Interest expense $ -   $ 2   $ 13   $ 30  
Accretion of asset retirement obligation   7     4     26     16  
Net finance expense $ 7   $ 6   $ 39   $ 46  
                         
(1) Interest costs are net of interest income of $3 million and $12 million for the three months and year ended December 31, 2012, respectively ($2 million and $4 million for the three months and year ended December 31, 2011, respectively).

Interest costs in 2012 were higher than the comparative 2011 periods as a result of the U.S. $700 million debt issued on March 29, 2012. However, interest expense in 2012 was lower than the comparative 2011 periods because a higher portion of interest costs were capitalized in 2012, as cumulative capital expenditures on qualifying assets rose. The period-over-period increases in accretion of the asset retirement obligation from 2011 to 2012 reflect the increase in the estimated asset retirement obligation recognized in the fourth quarter of 2011.

Foreign Exchange (Gain) Loss  
  Three Months Ended   Year Ended  
  December 31   December 31  
($ millions) 2012   2011   2012   2011  
                 
Foreign exchange (gain) loss - long-term debt $ 20   $ (24 ) $ (28 ) $ 25  
Foreign exchange (gain) loss - other (4 ) 1   3   (3 )
Total foreign exchange (gain) loss $ 16   $ (23 ) $ (25 ) $ 22  

Foreign exchange gains/losses are primarily the result of revaluations of our U.S. dollar-denominated long-term debt caused by fluctuations in U.S./Cdn dollar exchange rates.

The foreign exchange loss on long-term debt in the 2012 fourth quarter was the result of a weakening Canadian dollar to U.S. $1.01 at December 31, 2012 from U.S. $1.02 at September 30, 2012. The foreign exchange gain for the full year 2012 was the result of a strengthening Canadian dollar from U.S. $0.98 at December 31, 2011. Conversely, the foreign exchange gain in the 2011 fourth quarter was the result of a strengthening Canadian dollar to U.S. $0.98 at December 31, 2011 from U.S. $0.96 at September 30, 2011, and the foreign exchange loss for the full year 2011 was the result of a weakening Canadian dollar from U.S. $1.01 at December 31, 2010.

Tax Expense
  Three Months Ended Year Ended
  December 31 December 31
($ millions) 2012 2011 2012 2011
                 
Current tax expense $ 10 $ - $ 40 $ -
Deferred tax expense   65   70   278   387
Total tax expense $ 75 $ 70 $ 318 $ 387

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

Asset Retirement Obligation
  Year Ended  
  December 31  
($ millions) 2012   2011  
             
Asset retirement obligation, beginning of year $ 1,037   $ 501  
Change in risk-free interest rate   68     98  
Change in estimated liability   25     471  
Accretion expense   26     16  
Liabilities settled   (54 )   (49 )
Asset retirement obligation, end of year $ 1,102   $ 1,037  
Less current portion   (44 )   (29 )
Non-current portion $ 1,058   $ 1,008  

Canadian Oil Sands increased its estimated asset retirement obligation from $1,037 million at December 31, 2011 to $1,102 million at December 31, 2012. The increase reflects:

  • a 0.25 per cent decrease in the interest rate used to discount future reclamation and closure expenditures; and
  • an acceleration in the estimated timing of certain future reclamation and closure expenditures;

partially offset by:

  • reclamation spending during the year.

Pension and Other Post-Employment Benefit Plans

The Corporation''s share of the estimated unfunded portion of Syncrude Canada''s pension and other post-employment benefit plans decreased to $438 million at December 31, 2012 from $465 million at December 31, 2011, reflecting contributions to the plans and higher than estimated returns on plan assets, partially offset by a decrease in the interest rate used to discount future pension costs.

Summary of Quarterly Results
  2012 2011
  Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
                                 
Sales1 ($ millions) $ 929 $ 941 $ 740 $ 956 $ 884 $ 989 $ 1,045 $ 1,016
                                 
Net income ($ millions) $ 221 $ 338 $ 101 $ 321 $ 232 $ 242 $ 346 $ 324
  Per Share, Basic & Diluted $ 0.46 $ 0.70 $ 0.21 $ 0.66 $ 0.48 $ 0.50 $ 0.71 $ 0.67
                                 
Cash flow from operations2 ($ millions) $ 418 $ 470 $ 245 $ 454 $ 363 $ 512 $ 544 $ 478
  Per Share2 $ 0.86 $ 0.97 $ 0.51 $ 0.94 $ 0.75 $ 1.06 $ 1.12 $ 0.99
                                 
Dividends ($ millions) $ 169 $ 170 $ 170 $ 145 $ 146 $ 145 $ 145 $ 97
  Per Share $ 0.35 $ 0.35 $ 0.35 $ 0.30 $ 0.30 $ 0.30 $ 0.30 $ 0.20
                                 
Daily average sales volumes3 (bbls)   111,669   113,331   89,597   108,108   91,259   109,260   102,938   120,894
                                 
Realized SCO selling price ($/bbl) $ 89.99 $ 89.89 $ 90.45 $ 97.07 $ 104.78 $ 97.89 $ 111.00 $ 93.04
                                 
Operating expenses4 ($/bbl) $ 38.85 $ 36.71 $ 50.66 $ 32.68 $ 46.88 $ 37.19 $ 37.07 $ 35.53
                                 
Purchased natural gas price ($/GJ) $ 3.02 $ 2.00 $ 1.79 $ 2.23 $ 3.19 $ 3.51 $ 3.62 $ 3.59
                                 
WTI5 (average $US/bbl) $ 88.23 $ 92.20 $ 93.35 $ 103.03 $ 94.06 $ 89.54 $ 102.34 $ 94.60
                                 
Foreign exchange rates ($US/$Cdn)                                
  Average $ 1.01 $ 1.00 $ 0.99 $ 1.00 $ 0.98 $ 1.02 $ 1.03 $ 1.02
  Quarter-end $ 1.01 $ 1.02 $ 0.98 $ 1.00 $ 0.98 $ 0.96 $ 1.04 $ 1.03
(1) Sales after crude oil purchases and transportation expense.
(2) Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined on page 5 of this report.
(3) Daily average sales volumes net of crude oil purchases.
(4) Derived from operating expenses, as reported on the Consolidated Statements of Income and Comprehensive Income, divided by sales volumes during the period.
(5) Pricing obtained from Bloomberg.

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

  • fluctuations in realized selling prices have affected the Corporation''s sales and Crown royalties. 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;
  • fluctuations in natural gas prices have affected the Corporation''s operating expenses and Crown royalties; and
  • increased spending on capital projects to replace or relocate Syncrude mining trains and to support tailings management plans has reduced Crown royalties.

Quarterly variances in net income and cash flow from operations are caused mainly by fluctuations in realized selling prices, production and sales volumes, operating expenses and natural gas prices. Net income is also impacted by foreign exchange gains and losses, depreciation and depletion, and tax expense. The dividends paid to Shareholders are likewise dependent on the factors impacting cash flow from operations as well as the amount and timing of capital expenditures.

While the supply/demand balance for crude oil affects selling prices, the impact of this relationship has not displayed significant seasonality. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is influenced by weather conditions and North American natural gas inventory levels.

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

Syncrude production levels may not display seasonal patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit outages cannot be precisely scheduled and unplanned outages may occur. The costs of major turnarounds are capitalized as property, plant and equipment and depreciated over the period until the next scheduled turnaround. The costs of all other turnarounds and maintenance activities are expensed in the period incurred, which can result in volatility in quarterly operating expenses. All turnarounds and maintenance activities impact per barrel operating expenses because sales volumes are lower in the periods when this work is occurring.

Capital Expenditures
  Three Months Ended Year Ended
  December 31 December 31
($ millions) 2012 2011 2012 2011
                 
Major Projects                
                 
  Mildred Lake Mine Train Replacement $ 96 $ 62 $ 362 $ 139
  Reconstruct crushers, surge facilities, and slurry prep facilities to support tailings storage requirements                
                   
  Aurora North Mine Train Relocation   34   12   98   27
  Relocate crushers, surge facilities, and slurry prep facilities to support tailings storage requirements                
                   
  Aurora North Tailings Management   32   19   123   40
  Construct a composite tails (CT) plant at the Aurora North mine to process tailings                
                   
  Centrifuge Tailings Management   34   39   69   39
  Construct a centrifuge plant at the Mildred Lake mine to process tailings                
                   
  Syncrude Emissions Reduction (SER)   4   14   21   110
  Retrofit technology into Syncrude''s original two cokers to reduce total sulphur dioxide and other emissions                
                 
Capital expenditures on major projects $ 200 $ 146 $ 673 $ 355
                 
Regular maintenance                
  Capitalized turnaround costs $ - $ 21 $ 76 $ 44
  Other capital1   73   20   245   187
Capital expenditures on regular maintenance $ 73 $ 41 $ 321 $ 231
                 
Capitalized interest $ 26 $ 18 $ 92 $ 57
Total capital expenditures $ 299 $ 205 $ 1,086 $ 643
(1) Other regular maintenance capital includes expenditures on relocation of tailings facilities and other infrastructure projects.

Capital expenditures increased to $1,086 million in 2012 from $643 million in 2011, and to $299 million in the fourth quarter of 2012 from $205 million in the fourth quarter of 2011. The increases reflect spending on the major capital projects at Syncrude. More information on the major projects is provided in the "Outlook" section of this MD&A.

The increase in capitalized turnaround costs in 2012 reflects the planned turnarounds of Coker 8-3 and the Vacuum Distillation Unit. By comparison, 2011 capitalized turnaround costs reflect the Coker 8-2 turnaround.

The increase in capitalized interest costs in 2012 reflects higher cumulative capital expenditures on qualifying assets.

Contractual Obligations and Commitments

During 2012, Canadian Oil Sands entered into new contractual obligations totalling approximately $1.3 billion for the transportation and storage of crude oil in support of the Corporation''s strategy to secure access to preferred markets and enhance marketing flexibility. The Corporation also assumed $250 million in new funding commitments primarily related to the major capital projects discussed in the "Outlook" section of this MD&A, increased its funding commitment by $110 million in respect of Syncrude Canada''s registered pension plan, and assumed $70 million in new commitments related to Syncrude Canada''s employee retention program.

Dividends

On January 31, 2013, the Corporation declared a quarterly dividend of $0.35 per Share for a total dividend of approximately $170 million. The dividend will be paid on February 28, 2013 to Shareholders of record on February 22, 2013. During 2012, the Corporation paid dividends to shareholders totalling $654 million, or $1.35 per Share.

Dividend payments are set quarterly by the Board of Directors in the context of current and expected crude oil prices, economic conditions, Syncrude''s operating performance, and the Corporation''s capacity to finance operating and investing obligations. Dividend levels are established with the intent of absorbing short-term market volatility over several quarters. Dividend levels also recognize our intention to fund the current major projects primarily with cash flow from operations and existing cash balances, while maintaining a strong balance sheet to reduce exposure to potential oil price declines, capital cost increases or major operational upsets.

Liquidity and Capital Resources  
  December 31   December 31  
($ millions, except % amounts) 2012   2011  
             
Total debt1,2 $ 1,794   $ 1,132  
Cash and cash equivalents   (1,553 )   (718 )
Net debt1,3 $ 241   $ 414  
             
Shareholders'' equity $ 4,515   $ 4,210  
             
Total net capitalization1,4 $ 4,756   $ 4,624  
             
Total capitalization1,5 $ 6,309   $ 5,342  
             
Net debt-to-total net capitalization1,6 (%)   5     9  
             
Total debt-to-total capitalization1,7 (%)   28     21  
(1) Non-GAAP measure.
(2) Includes current and non-current portions of long-term debt....