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

Marketwired

Wed, Oct 30, 2013, 5:26 PM

CALGARY, ALBERTA--(Marketwired - Oct 30, 2013) - 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, 2013:

COS has maintained its quarterly dividend at $0.35 per Share, payable on November 29, 2013 to shareholders of record on November 22, 2013. During the first nine months of 2013, we paid dividends to shareholders totalling $509 million, or $1.05 per Share.
Sales volumes were down in the third quarter of 2013, averaging about 84,300 barrels per day compared with 113,300 barrels per day in the 2012 third quarter due to extended turnarounds on the Coker 8-1, LC Finer and hydrotreating units. Year-to-date sales volumes in 2013 were also lower than 2012, averaging about 93,300 barrels per day compared with 103,700 barrels per day in 2012. The decline in 2013 sales volumes reflects the extended turnarounds as well as unplanned outages in extraction units.
Lower sales volumes partially offset by higher realized selling prices resulted in cash flow from operations declining to $339 million, or $0.70 per Share, in the third quarter of 2013 from $470 million, or $0.97 per Share, in the 2012 third quarter. In the first nine months of 2013, a higher realized selling price largely offset lower sales volumes; however, higher current taxes reduced 2013 cash flow from operations to $957 million, or $1.97 per Share, from $1,163 million, or $2.40 per Share, in the comparative 2012 period.
Operating expenses in the third quarter and first nine months of 2013 increased to $46.15 per barrel and $43.43 per barrel, respectively, from $36.07 per barrel and $38.96 per barrel in the comparative 2012 periods. The increase in per barrel operating expenses is due to lower sales volumes in 2013, as total operating expenses for both the third quarter and year-to-date 2013 were largely unchanged from the prior year periods.
The Aurora North Mine Train Relocation project has been completed, ahead of schedule and under budget, following the relocation and start-up of the second of two mine trains at the Aurora North mine in early October. The first mine train was relocated in July of this year.

"We reached an important milestone with the completion of Syncrude's Aurora North Mine Train Relocation project ahead of schedule and under budget," said Marcel Coutu, President and Chief Executive Officer. "The remaining projects are also progressing well and tracking to plan. Healthy crude oil prices have facilitated funding of these major projects and our dividend while maintaining a very strong balance sheet, despite lower than expected production at Syncrude."

Mr. Coutu added: "It has been a particularly challenging year for Syncrude operations with maintenance issues in our extraction facilities and an extended coker turnaround in the third quarter. Syncrude is continuing to work through the implementation of reliability systems, and improving reliability remains ours and Syncrude's main focus."

Highlights

			Three Months Ended					Nine Months Ended
			September 30					September 30
			2013		2012			2013		2012

Cash flow from operations ⁽¹⁾ ($ millions)		$	339	$	470		$	957	$	1,163
	Per Share ⁽¹⁾ ($/Share)	$	0.70	$	0.97		$	1.97	$	2.40

Net income ($ millions)		$	246	$	336		$	642	$	755
	Per Share, Basic and Diluted ($/Share)	$	0.51	$	0.69		$	1.32	$	1.56

Sales volumes ⁽²⁾
	Total (mmbbls)		7.8		10.4			25.5		28.4
	Daily average (bbls)		84,250		113,331			93,301		103,669

Realized SCO selling price ($/bbl)		$	112.55	$	89.89		$	102.83	$	92.59

West Texas Intermediate ("WTI") (average $US/bbl)		$	105.81	$	92.20		$	98.20	$	96.16

SCO premium (discount) to WTI		$	2.51	$	(2.09	)	$	2.74	$	(4.32	)
	(weighted average $/bbl)

Operating expenses ($ millions)		$	357	$	377		$	1,106	$	1,107
	Per barrel ($/bbl)	$	46.15	$	36.07		$	43.43	$	38.96

Capital expenditures ($ millions)		$	413	$	354		$	1,050	$	787

Dividends ($ millions)		$	170	$	170		$	509	$	485
	Per Share ($/Share)	$	0.35	$	0.35		$	1.05	$	1.00

(1)	Cash flow from operations and cash flow from operations per Share are additional GAAP financial measures and are defined in the "Additional GAAP Financial Measures" section of our Management's Discussion and Analysis ("MD&A").
(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.

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

COS has been named to the Dow Jones Sustainability North America Index for the third year in a row. The Dow Jones Sustainability Index (DJSI) recognizes companies for leadership in corporate responsibility. Inclusion in the index is based on Syncrude's practices, policies and performance related to sustainability, as well as COS' own strong governance and community investment initiatives. More information about the selection criteria and detailed performance data is available at www.sustainability-indices.com. Information on Syncrude's sustainability performance is available on their website and in their sustainability report at www.syncrude.ca.

2013 Outlook revised

We have revised our key estimates and assumptions for 2013 as follows:

The production range estimate for Syncrude has been reduced to 97 to 100 million barrels. The single-point estimate of 98 million barrels requires Syncrude to average 313,400 barrels per day in the fourth quarter.
Sales, net of crude oil purchases and transportation expense, increased to $3.6 billion, reflecting a higher forecast plant-gate realized selling price of $100 per barrel (based on a U.S. $98 per barrel WTI oil price, no SCO premium/discount to Canadian dollar WTI and a foreign exchange rate of $0.98 U.S./Cdn) partially offset by lower estimated sales volumes of 36 million barrels.
Operating expenses of $1,504 million, or $41.77 per barrel, reflecting actual costs incurred to date and a natural gas price assumption of $3.00 per gigajoule.
Cash flow from operations of $1,331 million, or $2.75 per Share.

More information on the 2013 Outlook is provided in our MD&A and the October 30, 2013 guidance document, which is available on our web site at www.cdnoilsands.com under "Investor Centre".

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 October 30, 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 and nine months ended September 30, 2013 and September 30, 2012, the audited consolidated financial statements and MD&A of the Corporation for the year ended December 31, 2012 and the Corporation's Annual Information Form ("AIF") dated February 21, 2013. Additional information on the Corporation, including its AIF, is available on SEDAR at www.sedar.com or on the Corporation's website at www.cdnoilsands.com. References to "Canadian Oil Sands", "COS" or "we" include the Corporation, its subsidiaries and partnerships. The financial results of Canadian Oil Sands have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") and are reported in Canadian dollars, unless otherwise noted.

Advisories

Forward Looking Information

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

Forward-looking statements in this MD&A and the related press release include, but are not limited to, statements with respect to: the expectations regarding the 2013 annual Syncrude forecasted production range of 97 million barrels to 100 million barrels and the single-point Syncrude production estimate of 98 million barrels (36.0 million barrels net to the Corporation); 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 expected sales, operating expenses, Crown royalties, capital expenditures and cash flow from operations for 2013; the anticipated amount of current taxes in 2013; 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 belief that items that impacted the Corporation's financial results in the last eight quarters are reasonably likely to impact the Corporation's financial results in the future; the expected amount of total major project costs, anticipated target in-service dates and estimated completion percentages for the Mildred Lake mine train replacements, 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 cost estimates for 2013 to 2015 major project spending; and the expectation that the volatility in the Synthetic Crude Oil ("SCO") to WTI differential is likely to persist for several years until additional pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast or the Canadian East or West Coasts.

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

The factors or assumptions on which the forward-looking information is based include, but are not limited to: the assumptions outlined in the Corporation's guidance document as posted on the Corporation's website at www.cdnoilsands.com as of October 30, 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 product; the unanimous joint venture owner approval for major expansions and changes in product types; the variances of stock market activities generally; normal risks associated with litigation, general economic, business and market conditions; the impact of Syncrude being unable to meet the conditions of its approval for its tailings management plan under Directive 74; volatility of crude oil prices; volatility of the SCO to WTI price differential; unsuccessful or untimely implementation of capital or maintenance projects; various events that could disrupt operations, including fires, equipment failures and severe weather and such other risks and uncertainties described in the Corporation's AIF dated February 21, 2013 and in the reports and filings made with securities regulatory authorities from time to time by the Corporation which are available on the Corporation's profile on SEDAR at www.sedar.com and on the Corporation's website at www.cdnoilsands.com.

You are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this MD&A and the related press release are made as of October 30, 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.

Additional GAAP Financial Measures

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

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

Cash flow from operations is calculated as cash from operating activities before changes in non-cash working capital. Cash flow from operations per Share is calculated as cash flow from operations divided by the weighted-average number of Shares outstanding in the period. We believe cash flow from operations and cash flow from operations per Share, which are not impacted by fluctuations in non-cash working capital balances, are more indicative of operational performance than cash from operating activities. With the exception of current tax payable, liabilities for Crown royalties and the current portion of our asset retirement obligation, our non-cash working capital is liquid and typically settles within 30 days.

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

		Three Months Ended						Nine Months Ended
		September 30						September 30
($ millions)		2013			2012			2013		2012

Cash flow from operations⁽¹⁾	$	339		$	470		$	957	$	1,163
Change in non-cash working capital⁽¹⁾		(14	)		(124	)		158		105
Cash from operating activities⁽¹⁾	$	325		$	346		$	1,115	$	1,268

(1)	As reported in the Unaudited Consolidated Statements of Cash Flows.

Net debt, total net capitalization, total capitalization, net debt-to-total net capitalization and long-term debt-to-total capitalization are used by the Corporation to manage capital, as discussed in the "Liquidity and Capital Resources" section of this MD&A and in Note 12 to the unaudited consolidated financial statements for the three and nine months ended September 30, 2013.

Overview

Synthetic Crude Oil ("SCO") production from the Syncrude Joint Venture ("Syncrude") was lower than expected in the third quarter of 2013, primarily due to delays completing turnarounds on Coker 8-1, the LC Finer and two hydrotreating units. The turnarounds were completed and the respective units returned to operation in late August and early September. Syncrude third quarter production volumes totalled 20.9 million barrels, or 227,000 barrels per day, compared with 26.0 million barrels, or 282,600 barrels per day forecasted in our July 30, 2013 Outlook (included in the second quarter 2013 MD&A).

Cash flow from operations totalled $339 million in the third quarter, reflecting a U.S. $106 per barrel West Texas Intermediate ("WTI") oil price and a $2.51 per barrel SCO premium to WTI. COS realized a $113 per barrel average selling price, 20 per cent higher than the $94 per barrel annual forecast in the July 30, 2013 Outlook. Operating expenses in the 2013 third quarter were similar to the 2012 third quarter on a total dollar basis but, on a per-barrel basis, increased to $46.15 per barrel, reflecting lower 2013 volumes. Syncrude's major projects progressed as planned with $413 million of total capital spending (net to COS) in the quarter. We achieved another important milestone with the relocation and start-up of the second of two mine trains at the Aurora North mine earlier this month. The Aurora North Mine Train Relocation project is now complete, ahead of schedule and under budget.

Based on the results achieved in the first nine months of the year, we have updated our 2013 Outlook to reflect a higher $100 per barrel annual realized selling price, a lower Syncrude production range of 97 to 100 million barrels (with a single-point estimate of 98 million barrels). Cash flow from operations for 2013 is now estimated at $1,331 million, six per cent higher than our July 30, 2013 forecast.

Highlights

			Three Months Ended					Nine Months Ended
			September 30					September 30
			2013		2012			2013		2012

Cash flow from operations ⁽¹⁾ ($ millions)		$	339	$	470		$	957	$	1,163
	Per Share ⁽¹⁾ ($/Share)	$	0.70	$	0.97		$	1.97	$	2.40

Net income ($ millions)		$	246	$	336		$	642	$	755
	Per Share, Basic and Diluted ($/Share)	$	0.51	$	0.69		$	1.32	$	1.56

Sales volumes ⁽²⁾
	Total (mmbbls)		7.8		10.4			25.5		28.4
	Daily average (bbls)		84,250		113,331			93,301		103,669

Realized SCO selling price ($/bbl)		$	112.55	$	89.89		$	102.83	$	92.59

West Texas Intermediate ("WTI") (average $US/bbl)		$	105.81	$	92.20		$	98.20	$	96.16

SCO premium (discount) to WTI		$	2.51	$	(2.09	)	$	2.74	$	(4.32	)
	(weighted average $/bbl)

Operating expenses ($ millions)		$	357	$	377		$	1,106	$	1,107
	Per barrel ($/bbl)	$	46.15	$	36.07		$	43.43	$	38.96

Capital expenditures ($ millions)		$	413	$	354		$	1,050	$	787

Dividends ($ millions)		$	170	$	170		$	509	$	485
	Per Share ($/Share)	$	0.35	$	0.35		$	1.05	$	1.00

(1)	Cash flow from operations and cash flow from operations per Share are additional GAAP financial measures and are defined in the "Additional GAAP Financial Measures" section of this MD&A.
(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.

Review of Financial Results

Cash Flow from Operations

To see the graphs associated with this release, please select the following link: http://media3.marketwire.com/docs/907277.jpg.

Cash flow from operations decreased to $339 million, or $0.70 per Share, in the third quarter of 2013 from $470 million, or $0.97 per Share, in the third quarter of 2012 primarily due to lower sales volumes and higher Crown royalties, partially offset by a higher realized selling price. On a year-to-date basis, cash flow from operations decreased to $957 million, or $1.97 per Share, in 2013 from $1,163 million, or $2.40 per Share, in 2012 reflecting higher current taxes, with lower sales volumes largely offsetting a higher realized selling price in 2013.

Syncrude production in the 2013 third quarter totalled 20.9 million barrels, or 227,000 barrels per day, a 27 per cent decrease from third quarter 2012 production of 28.8 million barrels, or 313,300 barrels per day. Production volumes in the third quarter of 2013 reflect the Coker 8-1, LC Finer and hydrotreating unit turnarounds, while third quarter 2012 production volumes reflect stable operations with no major maintenance activity. Net to the Corporation, sales volumes decreased to 7.8 million barrels, or 84,300 barrels per day, in the 2013 third quarter from 10.4 million barrels, or 113,300 barrels per day, in the 2012 third quarter.

On a year-to-date basis, Syncrude produced 69.2 million barrels, or 253,400 barrels per day, in 2013 compared with 77.4 million barrels, or 282,300 barrels per day in 2012. The decrease in 2013 production volumes reflects the delays completing the turnarounds as well as unplanned outages in extraction units. Net to the Corporation, sales volumes totalled 25.5 million barrels, or 93,300 barrels per day, in the first nine months of 2013 compared with 28.4 million barrels, or 103,700 barrels per day, in the comparative 2012 period.

Crown royalties increased to $71 million in the third quarter of 2013 from $33 million in the third quarter of 2012 primarily due to refinements in our estimates of bitumen values for both current and prior years, partially offset by higher deductible capital expenditures in the 2013 third quarter.

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

The realized selling price averaged $112.55 per barrel and $102.83 per barrel in the third quarter and first nine months of 2013, respectively, compared with $89.89 per barrel and $92.59 per barrel in the comparative 2012 periods. The increase in 2013 realized selling prices reflects both a higher WTI oil price and an improvement in the SCO differential to WTI.

Net Income

Net income decreased to $246 million, or $0.51 per Share, in the third quarter of 2013 from $336 million, or $0.69 per Share, in the third quarter of 2012 reflecting lower sales volumes and higher Crown royalties, partially offset by a higher realized selling price in the 2013 third quarter. On a year-to-date basis, net income decreased to $642 million, or $1.32 per Share, in 2013 from $755 million, or $1.56 per Share, in 2012. Lower sales volumes were largely offset by a higher realized selling price in 2013; however, the Corporation realized a $42 million foreign exchange loss as a result of revaluing U.S. dollar-denominated debt, cash and accounts receivable in the first nine months of 2013 compared with a $41 million foreign exchange gain in the comparative 2012 period.

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

		Three Months Ended									Nine Months Ended
		September 30									September 30
($ per barrel)⁽¹⁾		2013			2012			Change			2013			2012			Change

Sales net of crude oil purchases and transportation expense	$	112.52		$	90.10		$	22.42		$	102.85		$	92.82		$	10.03
Operating expense		(46.15	)		(36.07	)		(10.08	)		(43.43	)		(38.96	)		(4.47	)
Crown royalties		(9.20	)		(3.16	)		(6.04	)		(4.79	)		(5.11	)		0.32
	$	57.17		$	50.87		$	6.30		$	54.63		$	48.75		$	5.88

Development expense ⁽²⁾	$	(5.27	)	$	(2.40	)	$	(2.87	)	$	(4.10	)	$	(2.65	)	$	(1.45	)
Administration and insurance expenses		(1.43	)		(0.93	)		(0.50	)		(1.34	)		(0.96	)		(0.38	)
Depreciation and depletion expense		(13.01	)		(9.19	)		(3.82	)		(12.78	)		(10.00	)		(2.78	)
Net finance expense		(1.62	)		(1.25	)		(0.37	)		(1.49	)		(1.57	)		0.08
Foreign exchange gain (loss)		4.03			4.86			(0.83	)		(1.65	)		1.43			(3.08	)
Tax expense		(8.24	)		(9.86	)		1.62			(8.06	)		(8.48	)		0.42
		(25.54	)		(18.77	)		(6.77	)		(29.42	)		(22.23	)		(7.19	)
Net income per barrel	$	31.63		$	32.10		$	(0.47	)	$	25.21		$	26.52		$	(1.31	)
Sales volumes (mmbbls) ⁽³⁾		7.8			10.4			(2.6	)		25.5			28.4			(2.9	)

(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)	Previously referred to as non-production expenses.
(3)	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)			2013			2012 ⁽⁴⁾			Change			2013			2012⁽⁴⁾			Change

Sales⁽¹⁾		$	1,163		$	1,006		$	157		$	3,160		$	2,905		$	255
Crude oil purchases			(281	)		(55	)		(226	)		(505	)		(240	)		(265	)
Transportation expense			(11	)		(10	)		(1	)		(35	)		(28	)		(7	)
		$	871		$	941		$	(70	)	$	2,620		$	2,637		$	(17	)
Sales volumes⁽²⁾
	Total (mmbbls)		7.8			10.4			(2.6	)		25.5			28.4			(2.9	)
	Daily average (bbls)		84,250			113,331			(29,081	)		93,301			103,669			(10,368	)

Realized SCO selling price⁽³⁾		$	112.55		$	89.89		$	22.66		$	102.83		$	92.59		$	10.24
	(average $Cdn/bbl)

West Texas Intermediate ("WTI")		$	105.81		$	92.20		$	13.61		$	98.20		$	96.16		$	2.04
	(average $US/bbl)

SCO premium (discount) to WTI		$	2.51		$	(2.09	)	$	4.60		$	2.74		$	(4.32	)	$	7.06
	(weighted-average $Cdn/bbl)

Average foreign exchange rate		$	0.96		$	1.00		$	(0.04	)	$	0.98		$	1.00		$	(0.02	)
	($US/$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.
(4)	During the fourth quarter of 2012, the Corporation completed a review of the presentation of crude oil purchase and sales transactions and determined that certain transactions previously reported on a gross basis (sales presented gross of crude oil purchases and transportation expense) are more appropriately reflected on a net basis (crude oil purchases and/or transportation expense are netted against sales). Prior period comparative amounts have been reclassified for comparability with the current period presentation. The impact is as follows:

($ millions)		Three months ended September 30, 2012 Increase (decrease	)		Nine months ended September 30, 2012 Increase (decrease	)
Sales	$	(16	)	$	(78	)
Crude oil purchases		(16	)		(79	)
Transportation expense		-			1
Sales net of crude oil purchases and transportation expense	$	-		$	-

The $70 million, or seven per cent, decrease in third quarter 2013 sales, net of crude oil purchases and transportation expense, reflects lower sales volumes partially offset by a higher realized selling price relative to the 2012 third quarter.

Third quarter 2013 sales volumes, which averaged 84,300 barrels per day, were impacted by the extended turnarounds on Coker 8-1, the LC Finer and hydrotreating units while third quarter 2012 sales volumes, which averaged 113,300 barrels per day, reflect stable operations with no major maintenance activity.
The third quarter 2013 realized selling price increased by $22.66 per barrel reflecting a U.S. $13.61 per barrel increase in WTI oil prices, a $4.60 per barrel improvement in the SCO differential to WTI and a weaker Canadian dollar.

On a year-to-date basis, sales, net of crude oil purchases and transportation expense, decreased $17 million, or less than one per cent, relative to the comparative 2012 period as lower sales volumes in 2013 were largely offset by a higher realized selling price.

Sales volumes in the first nine months of 2013 averaged 93,300 barrels per day, down from 103,700 barrels per day in the comparative 2012 period, reflecting delays completing the turnarounds and unplanned outages in extraction units.
The realized selling price for the first nine months of 2013 increased $10.24 per barrel relative to the comparative 2012 period, reflecting a $7.06 per barrel improvement in the SCO differential to WTI, a U.S. $2.04 per barrel increase in WTI oil prices and a weaker Canadian dollar.

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

Increases in pipeline and rail capacity in 2013 have resulted in a narrowing of the discount between WTI and world oil prices. However, we expect volatility in the SCO differential to WTI 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.

The Corporation purchases crude oil from third parties to fulfill sales commitments with customers when there are shortfalls in Syncrude's production and to facilitate certain transportation arrangements. Sales include the sale of purchased crude oil while the cost of these purchases is included in crude oil purchases and transportation expense. Crude oil purchases were higher in the third quarter and first nine months of 2013, relative to the comparative 2012 periods, reflecting additional purchased volumes to support unanticipated production shortfalls and facilitate certain transportation arrangements combined with higher oil prices in 2013.

Operating Expenses

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

		Three Months Ended								Nine Months Ended
		September 30								September 30
		2013				2012				2013				2012
	$	millions	$	per bbl	$	millions	$	per bbl	$	millions	$	per bbl	$	millions	$	per bbl

Production and maintenance⁽¹⁾	$	300	$	38.77	$	317	$	30.37	$	909	$	35.69	$	922	$	32.47
Natural gas and diesel purchases⁽²⁾		24		3.10		28		2.70		107		4.18		89		3.13
Syncrude pension and incentive compensation		24		3.11		23		2.16		64		2.53		66		2.32
Other⁽³⁾		9		1.17		9		0.84		26		1.03		30		1.04
Total operating expenses	$	357	$	46.15	$	377	$	36.07	$	1,106	$	43.43	$	1,107	$	38.96

(1)	Includes 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 third quarter of 2013 decreased slightly, relative to the third quarter of 2012, as lower production costs, due primarily to less mining activity, were partially offset by higher maintenance costs associated with the extended turnarounds, the Aurora North mine train relocations and unplanned outages in extraction units. Year to date, total dollar operating expenses were similar in 2013 and 2012, as lower production costs were offset by higher maintenance costs and higher natural gas prices in 2013.

On a per barrel basis, operating expenses in the third quarter and first nine months of 2013 increased, reflecting lower sales volumes.

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

		Three Months Ended										Nine Months Ended
		September 30										September 30
		2013					2012⁽³⁾					2013					2012⁽³⁾
($ per barrel)		Bitumen		SCO			Bitumen		SCO			Bitumen		SCO			Bitumen		SCO
Bitumen production	$	27.56	$	36.84		$	24.92	$	28.69		$	27.36	$	33.67		$	25.63	$	29.68
Internal fuel allocation⁽¹⁾		2.76		3.68			1.97		2.27			2.70		3.32			2.14		2.48
Total bitumen production expenses	$	30.32	$	40.52		$	26.89	$	30.96		$	30.06	$	36.99		$	27.77	$	32.16

Upgrading⁽²⁾			$	9.31				$	7.38				$	9.76				$	9.28
Less: internal fuel allocation⁽¹⁾				(3.68	)				(2.27	)				(3.32	)				(2.48	)
Total upgrading expenses			$	5.63				$	5.11				$	6.44				$	6.80

Total operating expenses			$	46.15				$	36.07				$	43.43				$	38.96

(thousands of barrels per day)
Syncrude production volumes		303		227			361		313			312		253			327		282
Canadian Oil Sands sales volumes				84					113					93					104

(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 $2.59 per GJ and $3.02 per GJ in the three and nine months ended September 30, 2013, respectively, and $2.23 per GJ and $2.06 per GJ in the three and nine months ended September 30, 2012, respectively. Diesel prices averaged $0.92 per litre and $0.90 per litre in the three and nine months ended September 30, 2013, respectively, and $0.81 per litre and $0.87 per litre in the three and nine months ended September 30, 2012, 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 increased to $71 million, or $9.20 per barrel, in the third quarter of 2013 from $33 million, or $3.16 per barrel, in the third quarter of 2012, primarily due to refinements in our estimates of bitumen values for both current and prior years, partially offset by increases in deductible capital expenditures in the 2013 third quarter. On a year-to-date basis, Crown royalties decreased to $122 million, or $4.79 per barrel, in 2013 from $145 million, or $5.11 per barrel, in the comparative 2012 period, as higher deductible capital expenditures and lower bitumen volumes in 2013 more than offset the impact of the refinements in our bitumen value estimates.

The higher capital expenditures in 2013 reflect spending on capital projects to replace or relocate Syncrude mine trains and to support tailings management plans.

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

Canadian Oil Sands' share of the royalties recognized for the period from January 1, 2009 to September 30, 2013 reflect management's best estimate of the adjustments to reflect the quality and location differences and "floor price". However, the Syncrude owners and the Alberta government are disputing the basis for these adjustments. Under alternate assumptions, Canadian Oil Sands' share of Crown royalties for this period could be as much as $35 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.

Development Expenses

Development expenses totalled $41 million and $104 million in the third quarter and first nine months of 2013, respectively, compared with $25 million and $75 million in the comparative 2012 periods. Development expenses consist primarily of expenditures relating to capital programs, which are expensed, such as pre-feasibility engineering, technical and support services, research, evaluation drilling and regulatory and stakeholder consultation expenditures. Development expenses can vary from period to period depending on the number of projects underway and the development stage of the projects.

Depreciation and Depletion Expense

Depreciation and depletion expense increased to $101 million and $326 million in the third quarter and first nine months of 2013, respectively, from $96 million and $284 million in the comparative 2012 periods, reflecting:

changes made to the estimated useful lives of certain assets; and
new depreciation charges related to the Syncrude Emissions Reduction (SER) project.

Net Finance Expense

			Three Months Ended						Nine Months Ended
			September 30						September 30
($ millions)			2013			2012			2013			2012

Interest costs on long-term debt⁽¹⁾		$	30		$	28		$	87		$	78
	Less capitalized interest on long-term debt		(29	)		(25	)		(80	)		(65	)
Interest expense on long-term debt		$	1		$	3		$	7		$	13
Interest expense on employee future benefits			4			4			12			12
Accretion of asset retirement obligation			7			6			19			19
Net finance expense		$	12		$	13		$	38		$	44

(1)	Interest costs on long-term debt are net of interest income of $3 million and $11 million for the three and nine months ended September 30, 2013 and $4 million and $9 million for the three and nine months ended September 30, 2012, respectively.

Interest costs on long-term debt were higher in the first nine months of 2013 relative to the comparative 2012 period as a result of the U.S. $700 million debt issued on March 29, 2012. Conversely, interest expense on long-term debt was lower in the first nine months of 2013, relative to the comparative 2012 periods, because a higher portion of interest costs were capitalized in 2013, as cumulative capital expenditures on qualifying assets rose.

Foreign Exchange (Gain) Loss

		Three Months Ended						Nine Months Ended
		September 30						September 30
($ millions)		2013			2012			2013			2012

Foreign exchange (gain) loss - long-term debt	$	(40	)	$	(64	)	$	62		$	(48	)
Foreign exchange (gain) loss - other		9			13			(20	)		7
Total foreign exchange (gain) loss	$	(31	)	$	(51	)	$	42		$	(41	)

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

The foreign exchange gains in the third quarter of 2013 were the result of a strengthening Canadian dollar to U.S. $0.97 at September 30, 2013 from U.S. $0.95 at June 30, 2013, whereas the foreign exchange losses in the first nine months of 2013 were the result of a weakening Canadian dollar from U.S. $1.01 at December 31, 2012. The foreign exchange gains in 2012 were the result of a strengthening Canadian dollar from U.S. $0.98 at December 31, 2011 and June 30, 2012 to U.S. $1.02 at September 30, 2012.

Tax Expense

		Three Months Ended				Nine Months Ended
		September 30				September 30
($ millions)		2013		2012		2013			2012

Current tax expense	$	32	$	10	$	212		$	30
Deferred tax expense (recovery)		32		93		(6	)		211
Total tax expense	$	64	$	103	$	206		$	241

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

Current taxes increased in 2013 because:

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

Asset Retirement Obligation

		September 30
Nine months ended ($ millions)		2013

Asset retirement obligation, beginning of period	$	1,102
Increase in risk-free interest rate		(170	)
Accretion expense		19
Reclamation expenditures		(40	)
Asset retirement obligation, end of period	$	911
Less current portion		(45	)
Non-current portion	$	866

Canadian Oil Sands' asset retirement obligation decreased from $1,102 million at December 31, 2012 to $911 million at September 30, 2013, mainly reflecting a 75 basis point increase in the interest rate used to discount future reclamation and closure expenditures.

Pension and Other Post-Employment Benefit Plans

The Corporation's share of the estimated unfunded portion of Syncrude Canada Ltd.'s ("Syncrude Canada") pension and other post-employment benefit plans (the "accrued benefit liability") decreased to $309 million at September 30, 2013 from $438 million at December 31, 2012, reflecting a 50 basis point increase in the interest rate used to discount the accrued benefit liability and contributions to the plans in excess of the current period expenses.

Summary of Quarterly Results

			2013						2012⁽⁶⁾								2011⁽⁶⁾
			Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4

Sales ⁽¹⁾($ millions)		$	871	$	921	$	828	$	929	$	941	$	740	$	956	$	884

Net income ($ millions)		$	246	$	219	$	177	$	219	$	336	$	101	$	318	$	232
	Per Share, Basic & Diluted	$	0.51	$	0.45	$	0.37	$	0.45	$	0.69	$	0.21	$	0.66	$	0.48

Cash flow from operations ⁽²⁾($ millions)		$	339	$	343	$	275	$	418	$	470	$	245	$	454	$	363
	Per Share ⁽²⁾	$	0.70	$	0.71	$	0.57	$	0.86	$	0.97	$	0.51	$	0.94	$	0.75

Dividends ($ millions)		$	170	$	169	$	170	$	169	$	170	$	170	$	145	$	146
	Per Share	$	0.35	$	0.35	$	0.35	$	0.35	$	0.35	$	0.35	$	0.30	$	0.30

Daily average sales volumes ⁽³⁾ (bbls)			84,250		100,094		95,683		111,669		113,331		89,460		108,108		91,259

Realized SCO selling price ($/bbl)		$	112.55	$	100.90	$	96.11	$	89.99	$	89.89	$	90.59	$	97.07	$	104.78

WTI⁽⁴⁾ (average $US/bbl)		$	105.81	$	94.17	$	94.36	$	88.23	$	92.20	$	93.35	$	103.03	$	94.06

SCO premium (discount) to WTI		$	2.51	$	4.69	$	0.88	$	2.43	$	(2.09)	$	(5.31)	$	(5.89)	$	8.51
(weighted-average $/bbl)

Operating expenses⁽⁵⁾ ($/bbl)		$	46.15	$	43.23	$	41.20	$	38.76	$	36.07	$	50.25	$	32.68	$	46.88

Purchased natural gas price ($/GJ)		$	2.59	$	3.41	$	2.95	$	3.02	$	2.23	$	1.79	$	2.23	$	3.19

Foreign exchange rates ($US/$Cdn)
	Average	$	0.96	$	0.98	$	0.99	$	1.01	$	1.00	$	0.99	$	1.00	$	0.98
	Quarter-end	$	0.97	$	0.95	$	0.98	$	1.01	$	1.02	$	0.98	$	1.00	$	0.98

(1)	Sales after crude oil purchases and transportation expense.
(2)	Cash flow from operations and cash flow from operations per Share are additional GAAP financial measures and are defined in the "Additional GAAP Financial Measures" section of this MD&A.
(3)	Daily average sales volumes net of crude oil purchases.
(4)	Pricing obtained from Bloomberg.
(5)	Derived from operating expenses, as reported on the Consolidated Statements of Income and Comprehensive Income, divided by sales volumes during the period.
(6)	Net income and operating expenses in 2012 have been adjusted to reflect the amendments to International Accounting Standard ("IAS") 19, Employee Benefits. Net income and operating expenses in 2011 have not been adjusted. Additional information on the amendments to IAS 19 is provided in the "Changes in Accounting Policies" section of this MD&A and in Note 3 to the unaudited consolidated financial statements for the three and nine months ended September 30, 2013 and September 30, 2012.

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. Monthly average WTI prices have ranged from U.S. $82 per barrel to U.S. $107 per barrel, and the monthly average differentials between our realized selling price and Canadian dollar WTI prices have ranged from an $11 per barrel premium to
a $17 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;
increased spending on capital projects to replace or relocate Syncrude mining trains and to support tailings management plans has reduced Crown royalties;
bitumen valuation estimates used to calculate Crown royalties from 2009 to 2013 have changed as new information becomes available;
fluctuations in natural gas prices have affected operating expenses and Crown royalties; and
increases in current taxes in 2013 have reduced cash flow from operations. Prior to 2013, tax pools sheltered the Corporation's income from significant current taxes. In addition, taxes on a portion of the income generated in the Corporation's partnership in 2012 were deferred to 2013.

These same factors are reasonably likely to impact the Corporation's financial results in the future.

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 oil and natural gas production have significantly increased production, impacting prices and volatility.

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. Given the relatively fixed nature of operating costs, 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)			2013		2012		2013		2012

Major Projects

	Mildred Lake Mine Train Replacement	$	124	$	135	$	352	$	266
	Reconstruct crushers, surge facilities, and slurry prep facilities to support tailings storage requirements

	Aurora North Mine Train Relocation		54		32		142		64
	Relocate crushers, surge facilities, and slurry prep facilities to support tailings storage requirements

	Aurora North Tailings Management		22		52		67		91
	Construct a composite tails (CT) plant at the Aurora North mine to process tailings

	Centrifuge Tailings Management		62		16		146		36
	Construct a centrifuge plant at the Mildred Lake mine to process tailings

Capital expenditures on major projects		$	262	$	235	$	707	$	457

Regular maintenance
	Capitalized turnaround costs	$	33	$	9	$	54	$	76
	Other¹		89		85		209		189
Capital expenditures on regular maintenance		$	122	$	94	$	263	$	265

Capitalized interest		$	29	$	25	$	80	$	65
Total capital expenditures		$	413	$	354	$	1,050	$	787

(1)	Other regular maintenance capital includes expenditures to relocate tailings facilities as well as other infrastructure projects.

Capital expenditures increased to $1,050 million in the first nine months of 2013 from $787 million in the comparative 2012 period, primarily due to spending on the major projects at Syncrude.

Capital expenditures increased to $413 million in the third quarter of 2013 from $354 million in the comparative 2012 quarter due to:

spending on the major projects; and
the Coker 8-1 and LC Finer turnarounds.

More information on the major projects is provided in the "Outlook" section of this MD&A.

Contractual Obligations and Commitments

Canadian Oil Sands' contractual obligations and commitments are summarized in the 2012 annual MD&A and include future cash payments that the Corporation is required to make under existing contractual arrangements entered into directly or as a 36.74 per cent owner in Syncrude. During the first nine months of 2013, Canadian Oil Sands entered into new contractual obligations totalling approximately $700 million for the transportation of crude oil in support of the Corporation's strategy to secure access to preferred markets and enhance marketing flexibility.

Dividends

On October 30, 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 November 29, 2013 to shareholders of record on November 22, 2013. During the first nine months of 2013, the Corporation paid dividends to shareholders totalling $509 million, or $1.05 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

		September 30			December 31
As at ($ millions, except % amounts)		2013			2012

Long-term debt^(1,2)	$	1,549		$	1,794
Cash and cash equivalents		(840	)		(1,553	)
Net debt^(1,3)	$	709		$	241

Shareholders' equity	$	4,716		$	4,515

Total net capitalization^(1,4)	$	5,425		$	4,756

Total capitalization^(1,5)	$	6,265		$	6,309

Net debt-to-total net capitalization^(1,6) (%)		13			5

Long-term debt-to-total capitalization^(1,7) (%)		25			28

(1)	Additional GAAP financial measure.
(2)	Includes current and non-current portions of long-term debt.
(3)	Long-term debt less cash and cash equivalents.
(4)	Net debt plus Shareholders' equity.
(5)	Long-term debt plus Shareholders' equity.
(6)	Net debt divided by total net capitalization.
(7)	Long-term debt divided by total capitalization.

Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, increased to $709 million at September 30, 2013 from $241 million at December 31, 2012, as existing cash balances were used to fund capital expenditures and dividend payments in excess of cash flow from operations. In addition, a weakening Canadian dollar from December 31, 2012 to September 30, 2013 increased the Canadian dollar equivalent value of Canadian Oil Sands' outstanding long-term debt, all of which is denominated in U.S. dollars. As a result, net debt-to-total net capitalization increased to 13 per cent at September 30, 2013 from five per cent at December 31, 2012.

On August 15, 2013, Canadian Oil Sands repaid U.S. $300 million of Senior Notes upon maturity, resulting in long-term debt-to-total capitalization of 25 per cent at September 30, 2013 compared with 28 per cent at December 31, 2012.

We plan to spend existing cash balances by the end of 2014 to fund our major projects and settle accounts payable for accrued current taxes and Crown royalties. As a result, and based on the assumptions in our 2013 Outlook, our net debt levels are expected to rise to $1 billion to $2 billion by the end of 2014, coincident with reduced capital expenditure risk from the expected substantial completion of our major projects.

Shareholders' equity increased to $4,716 million at September 30, 2013 from $4,515 million at December 31, 2012, as net income exceeded dividends in the first nine months of 2013.

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

The Senior Notes indentures and credit facility agreements contain certain covenants that restrict Canadian Oil Sands' ability to sell all or substantially all of its assets or change the nature of its business, and limit long-term debt-to-total capitalization to 55 per cent. Canadian Oil Sands is in compliance with its debt covenants, and with a long-term debt-to-total capitalization of 25 per cent at September 30, 2013, a significant increase in debt or decrease in equity would be required to negatively impact the Corporation's financial flexibility.

Shareholders' Capital and Trading Activity

The Corporation's shares trade on the Toronto Stock Exchange under the symbol COS. On September 30, 2013, the Corporation had a market capitalization of approximately $9.7 billion with 484.6 million shares outstanding and a closing price of $19.96 per Share. The following table summarizes the trading activity for the third quarter of 2013.

Canadian Oil Sands Limited - Trading Activity

			Third
			Quarter		July		August		September
			2013		2013		2013		2013

Share price
	High	$	21.18	$	20.97	$	21.18	$	20.68
	Low	$	19.60	$	19.60	$	20.05	$	19.92
	Close	$	19.96	$	19.94	$	20.21	$	19.96

Volume of Shares traded (millions)			130.4		33.2		48.7		48.5
Weighted average Shares outstanding (millions)			484.6		484.6		484.6		484.6

Changes in Accounting Policies

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

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

Canadian Oil Sands has applied the amendments effective January 1, 2013 in accordance with the applicable transitional provisions with no material impact to the Corporation's financial results. Additional information is provided in Note 3 to the unaudited consolidated financial statements for the three and nine months ended September 30, 2013 and September 30, 2012.

2013 Outlook

		As of		As of
		October 30		July 30
(millions of Canadian dollars, except volume and per barrel amounts)		2013		2013

Operating assumptions
Syncrude production (mmbbls)		98		102
Canadian Oil Sands sales (mmbbls)		36.0		37.5
Sales, net of crude oil purchases and transportation	$	3,603	$	3,518
Operating expenses	$	1,504	$	1,507
Operating expenses per barrel	$	41.77	$	40.21
Crown royalties	$	194	$	104
Current taxes	$	300	$	400
Cash flow from operations⁽¹⁾	$	1,331	$	1,260

Capital expenditure assumptions
Major projects	$	842	$	828
Regular maintenance	$	346	$	349
Capitalized interest	$	104	$	102
Total capital expenditures	$	1,292	$	1,279

Business environment assumptions
West Texas Intermediate (U.S.$/bbl)	$	98.00	$	90.00
Premium to average Cdn$ WTI prices (Cdn$/bbl)	$	-	$	2.00
Foreign exchange rate (U.S.$/Cdn$)	$	0.98	$	0.98
AECO natural gas (Cdn$/GJ)	$	3.00	$	3.50

(1)	Cash flow from operations is an additional GAAP financial measure and is defined in the "Additional GAAP Financial Measures" section of this MD&A.

We have increased estimated 2013 sales, net of crude oil purchases and transportation expense, to $3,603 million due to an increase in the forecast realized selling price partially offset by a decrease in estimated production volumes.

The forecast annual realized selling price for 2013 has increased $6 per barrel to $100 per barrel and assumes a U.S. $98 per barrel WTI oil price, no SCO premium/discount to Canadian dollar WTI and a foreign exchange rate of $0.98 U.S./Cdn.

We have adjusted our 2013 Syncrude production range to 97 to 100 million barrels with a single-point estimate of 98 million barrels (268,500 barrels per day). Net to Canadian Oil Sands, the single-point estimate is equivalent to 36.0 million barrels (98,600 barrels per day). The production outlook reflects actual results to date and assumes reliable operations for the remainder of the year, requiring average daily Syncrude production volumes of 313,400 barrels in the fourth quarter.

We estimate 2013 operating expenses of $1,504 million, reflecting actual costs incurred to date and a reduced natural gas price assumption of $3.00 per gigajoule. We have increased our per barrel operating expense estimate to $41.77 per barrel, reflecting the lower production forecast.

Our estimate of 2013 Crown royalties has increased to $194 million due primarily to refinements in our estimates of bitumen values.

Our estimate of 2013 current taxes has decreased to $300 million, reflecting changes in the estimated timing of capital expenditure and other deductions.

Based on these assumptions, estimated 2013 cash flow from operations has increased to $1,331 million, or $2.75 per Share.

We estimate 2013 capital expenditures of $1,292 million, comprised of $842 million of spending on major projects, $346 million in regular maintenance of the business and other projects, and $104 million in capitalized interest.

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 30, 2013)

			Cash Flow from Operations
			Increase
Variable	Annual Sensitivity	$	millions^1,2	$	/ Share^1,2

Syncrude operating expense decrease	Cdn$1.00/bbl	$	21	$	0.04
Syncrude operating expense decrease	Cdn$50 million	$	11	$	0.02
WTI crude oil price increase	U.S.$1.00/bbl	$	22	$	0.05
Syncrude production increase	2 million bbls	$	45	$	0.09
Canadian dollar weakening	U.S.$0.01/Cdn$	$	23	$	0.05
AECO natural gas price decrease	Cdn$0.50/GJ	$	13	$	0.03

(1)	Canadian Oil Sands anticipates recording approximately $300 million in current taxes in 2013. These sensitivities are after the impact of taxes.
(2)	These sensitivities assume Canadian Oil Sands pays Crown royalties based on net bitumen revenues in 2013. Lower bitumen revenues or higher deductible bitumen-related costs may result in minimum Crown royalties based on gross revenues which will change the sensitivities to these variables.

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

Major Projects

The following tables provide cost and schedule estimates for Syncrude's major projects. Regular maintenance capital costs for years after 2013 will be provided on an annual basis when we disclose the budgets for those years.

Major Projects - Total Project Cost and Schedule Estimates⁽¹⁾

			Total Cost		Total Cost		Estimated	%	Target
			Estimate		Estimate		Complete at		In-Service
		$	(billions	)	Accuracy(	%)	Sept 30, 2013⁽²⁾		Date

Mildred Lake Mine Train Replacement	Syncrude	$	4.2		+15%/-15	%	65	%	Q4 2014
	COS share		1.6

Aurora North Mine Train Relocation	Syncrude	$	1.0		+0%/-10	%	100	%	Q4 2013
	COS share		0.4

Aurora North Tailings Management	Syncrude	$	0.8		+5%/-10	%	95	%	Q4 2013
	COS share		0.3

Centrifuge Tailings Management	Syncrude	$	1.9		+15%/-15	%	50	%	H1 2015
	COS share		0.7

Major Projects - Annual Spending Profile⁽¹⁾

		Spent to
($ billions)		to Dec 31, 2012		2013		2014		2015		Total

Syncrude	$	2.6	$	2.4	$	2.3	$	0.6	$	7.9
Canadian Oil Sands share	$	1.0	$	0.9	$	0.9	$	0.2	$	3.0

(1)	Major projects costs include capital expenditures, excluding capitalized interest, and certain development expenses.
(2)	The estimated percentage complete is based on hours spent as a percentage of total forecasted hours to project completion.

The second of the two mine train relocations at Aurora North was completed earlier this month. The Aurora North Mine Train Relocation project is now complete, ahead of schedule and under budget. The Aurora North Tailings Management project is on schedule for completion in the fourth quarter of 2013. The Mildred Lake Mine Train and Centrifuge Tailings Management projects are tracking to plan.

The major projects tables contain forward-looking information and users of this information are cautioned that the actual yearly and total major project costs and the actual in-service dates for the major projects may vary from the plans disclosed. The major project cost estimates and major project target in-service dates are based on current spending plans. Please refer to the "Forward-Looking Information Advisory" section of this MD&A for the risks and assumptions underlying this forward-looking information. For a list of additional risk factors that could cause the actual amount of the major project costs and the major project target in-service dates to differ materially, please refer to the Corporation's Annual Information Form dated February 21, 2013 which is available on the Corporation's profile on SEDAR at www.sedar.com and on the Corporation's website at www.cdnoilsands.com.

Consolidated Statements of Income and Comprehensive Income

(unaudited)

				Three Months Ended						Nine Months Ended
				September 30						September 30
(millions of Canadian dollars, except per Share and Share volume amounts)				2013			2012			2013			2012

Sales (Note 17)			$	1,163		$	1,006		$	3,160		$	2,905
Crown royalties (Note 15)				(71	)		(33	)		(122	)		(145	)
Revenues			$	1,092		$	973		$	3,038		$	2,760

Expenses
	Operating (Note 3)		$	357		$	377		$	1,106		$	1,107
	Development			41			25			104			75
	Crude oil purchases and transportation (Note 17)			292			65			540			268
	Administration			8			5			24			19
	Insurance			2			4			10			8
	Depreciation and depletion			101			96			326			284
			$	801		$	572		$	2,110		$	1,761
Earnings from operating activities			$	291		$	401		$	928		$	999
	Foreign exchange (gain) loss (Note 9)			(31	)		(51	)		42			(41	)
	Net finance expense (Notes 3 and 10)			12			13			38			44
Earnings before taxes			$	310		$	439		$	848		$	996
	Tax expense (Notes 3 and 11)			64			103			206			241
Net income			$	246		$	336		$	642		$	755
Other comprehensive income (loss), net of income taxes
	Items not reclassified to net income:
		Re-measurements of employee future benefit plans (Notes 3 and 8)		68			4			68			(23	)
	Items reclassified to net income:
		Derivative gains		(1	)		-			(2	)		(2	)
Comprehensive income			$	313		$	340		$	708		$	730

Weighted average Shares (millions)				485			485			485			485
Shares, end of period (millions)				485			485			485			485

Net income per Share
	Basic and diluted		$	0.51		$	0.69		$	1.32		$	1.56

See Notes to Unaudited Consolidated Financial Statements

Consolidated Statements of Shareholders' Equity

(unaudited)

			Three Months Ended						Nine Months Ended
			September 30						September 30
(millions of Canadian dollars)			2013			2012			2013			2012

Retained earnings
	Balance, beginning of period	$	1,880		$	1,594		$	1,823		$	1,517
	Net income		246			336			642			755
	Re-measurements of employee future benefit plans		68			4			68			(23	)
	Dividends		(170	)		(170	)		(509	)		(485	)
	Balance, end of period	$	2,024		$	1,764		$	2,024		$	1,764
Accumulated other comprehensive income
	Balance, beginning of period	$	8		$	10		$	9		$	12
	Reclassification of derivative gains to net income		(1	)		-			(2	)		(2	)
	Balance, end of period	$	7		$	10		$	7		$	10
Shareholders' capital
	Balance, beginning of period	$	2,674		$	2,673		$	2,673		$	2,673
	Issuance of shares		-			-			1			-
	Balance, end of period	$	2,674		$	2,673		$	2,674		$	2,673
Contributed surplus
	Balance, beginning of period	$	11		$	9		$	10		$	8
	Share-based compensation		-			-			1			1
	Balance, end of period		11			9			11			9
Total Shareholders' equity		$	4,716		$	4,456		$	4,716		$	4,456

See Notes to Unaudited Consolidated Financial Statements

Consolidated Balance Sheets

(unaudited)

			September 30		December 31
As at (millions of Canadian dollars)			2013		2012

Assets
Current assets
	Cash and cash equivalents	$	840	$	1,553
	Accounts receivable		415		311
	Inventories		160		137
	Prepaid expenses		9		9
		$	1,424	$	2,010
Property, plant and equipment, net (Note 4)			8,558		8,003
Exploration and evaluation			89		89
Reclamation trust			75		69
		$	10,146	$	10,171

Liabilities and Shareholders' Equity
Current liabilities
	Accounts payable and accrued liabilities (Note 5)	$	882	$	704
	Current portion of long-term debt		-		297
	Current taxes		185		40
	Current portion of employee future benefits		82		76
		$	1,149	$	1,117
Employee future benefits			227		362
Other liabilities (Note 6)			89		89
Long-term debt			1,549		1,497
Asset retirement obligation (Note 7)			866		1,058
Deferred taxes			1,550		1,533
		$	5,430	$	5,656
Shareholders' equity			4,716		4,515
		$	10,146	$	10,171

Commitments and Contingencies (Notes 14 and 15, respectively)

See Notes to Unaudited Consolidated Financial Statements

Consolidated Statements of Cash Flows

(unaudited)

				Three Months Ended						Nine Months Ended
				September 30						September 30
(millions of Canadian dollars)				2013			2012			2013			2012

Cash from (used in) operating activities
	Net income		$	246		$	336		$	642		$	755
	Adjustments to reconcile net income to cash flow from operations:
		Depreciation and depletion		101			96			326			284
		Accretion of asset retirement obligation (Note 7)		7			6			19			19
		Foreign exchange (gain) loss on long-term debt (Note 9)		(40	)		(64	)		62			(48	)
		Deferred taxes (Note 11)		32			93			(6	)		211
		Share-based compensation		1			(1	)		4			2
		Reclamation expenditures (Note 7)		(1	)		(6	)		(40	)		(48	)
		Change in employee future benefits and other		(7	)		10			(50	)		(12	)
		Cash flow from operations	$	339		$	470		$	957		$	1,163
	Change in non-cash working capital (Note 16)			(14	)		(124	)		158			105
		Cash from operating activities	$	325		$	346		$	1,115		$	1,268

Cash from (used in) financing activities
	Repayment of senior notes		$	(310	)	$	-		$	(310	)	$	-
	Issuance of senior notes			-			-			-			689
	Issuance of shares			-			-			1			-
	Dividends			(170	)		(170	)		(509	)		(485	)
		Cash from (used in) financing activities	$	(480	)	$	(170	)	$	(818	)	$	204

Cash from (used in) investing activities
	Capital expenditures		$	(413	)	$	(354	)	$	(1,050	)	$	(787	)
	Reclamation trust funding			(2	)		(2	)		(7	)		(7	)
	Change in non-cash working capital (Note 16)			-			42			36			78
		Cash used in investing activities	$	(415	)	$	(314	)	$	(1,021	)	$	(716	)


Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency			$	(6	)	$	(11	)	$	11		$	(5	)

Increase (decrease) in cash and cash equivalents			$	(576	)	$	(149	)	$	(713	)	$	751
Cash and cash equivalents, beginning of period				1,416			1,618			1,553			718
Cash and cash equivalents, end of period			$	840		$	1,469		$	840		$	1,469

Cash and cash equivalents consist of:
	Cash		$	659		$	150		$	659		$	150
	Short-term investments			181			1,319			181			1,319
			$	840		$	1,469		$	840		$	1,469

Supplementary Information (Note 16)

See Notes to Unaudited Consolidated Financial Statements

Notes to Unaudited Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2013

(Tabular amounts expressed in millions of Canadian dollars, except where otherwise noted)

1) Nature of Operations

Canadian Oil Sands Limited ("Canadian Oil Sands" or the "Corporation") was incorporated in 2010 under the laws of the Province of Alberta, Canada pursuant to a plan of arrangement effecting the reorganization from an income trust into a corporate structure effective December 31, 2010.

The Corporation indirectly owns a 36.74 per cent interest ("Working Interest") in the Syncrude Joint Venture ("Syncrude"). Syncrude is involved in the mining and upgrading of bitumen from oil sands near Fort McMurray in northern Alberta. The Syncrude Project is comprised of open-pit oil sands mines, utilities plants, bitumen extraction plants, and an upgrading complex that processes bitumen into Synthetic Crude Oil ("SCO"). Syncrude is a joint operation jointly controlled by seven owners. Decisions about Syncrude's relevant activities require unanimous consent of the owners. Each owner takes its proportionate share of production in kind, and funds its proportionate share of Syncrude's operating development and capital costs on a daily basis. The Corporation also owns 36.74 per cent of the issued and outstanding shares of Syncrude Canada Ltd. ("Syncrude Canada"). Syncrude Canada operates Syncrude on behalf of the owners and is responsible for selecting, compensating, directing and controlling Syncrude's employees, and for administering all related employment benefits and obligations. The Corporation's investment in Syncrude and Syncrude Canada represents its only producing asset.

The Corporation's office is located at the following address: 2000 First Canadian Centre, 350 - 7th Avenue S.W., Calgary, Alberta, Canada T2P 3N9.

2) Basis of Presentation

These unaudited interim consolidated financial statements are prepared and reported in Canadian dollars in accordance with Canadian generally accepted accounting principles as set out in the Handbook of the Canadian Institute of Chartered Accountants ("CICA Handbook"). The CICA Handbook incorporates International Financial Reporting Standards ("IFRS") and publicly accountable enterprises, such as the Corporation, are required to apply such standards. These unaudited interim financial statements have been prepared in accordance with IFRS applicable to the preparation of interim financial statements and International Accounting Standard ("IAS") 34, Interim Financial Reporting, and the accounting policies applied in these interim unaudited consolidated financial statements are based on IFRS as issued, outstanding and effective on September 30, 2013.

Certain disclosures that are normally required to be included in the notes to the annual audited consolidated financial statements have been condensed or omitted. These unaudited interim consolidated financial statements should be read in conjunction with the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2012.

3) Accounting Policies

The same accounting policies and methods of computation are followed in these unaudited interim consolidated financial statements as compared with the most recent audited annual consolidated financial statements for the year ended December 31, 2012 except as follows:

Taxes

Current taxes in interim periods are accrued based on our best estimate of the annual effective tax rate applied to year-to-date earnings. Current taxes accrued in one interim period may be adjusted prospectively in a subsequent interim period if the estimate of the annual effective tax rate changes.

Employee Future Benefits

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

Canadian Oil Sands has applied the amendments effective January 1, 2013 in accordance with the applicable transitional provisions. Certain amounts reported in the Corporation's Consolidated Statements of Income and Comprehensive Income have been adjusted as follows:

		Three Months Ended							Nine Months Ended
		September 30, 2013							September 30, 2013
($ millions, except per Share amounts)		Before Adjustments		Adjustments			After Adjustments		Before Adjustments		Adjustments			After Adjustments

Operating expenses	$	357	$	-		$	357	$	1,106	$	-		$	1,106
Net finance expense	$	8	$	4		$	12	$	26	$	12		$	38
Tax expense	$	65	$	(1	)	$	64	$	209	$	(3	)	$	206
Net income	$	249	$	(3	)	$	246	$	651	$	(9	)	$	642
Re-measurements of employee future benefit plans, net of tax	$	65	$	3		$	68	$	59	$	9		$	68
Earnings per Share	$	0.52	$	(0.01	)	$	0.51	$	1.34	$	(0.02	)	$	1.32

		Three Months Ended							Nine Months Ended
		September 30, 2012							September 30, 2012
($ millions, except per Share amounts)		Before Adjustments		Adjustments			After Adjustments		Before Adjustments			Adjustments			After Adjustments

Operating expenses	$	378	$	(1	)	$	377	$	1,112		$	(5	)	$	1,107
Net finance expense	$	9	$	4		$	13	$	32		$	12		$	44
Tax expense	$	104	$	(1	)	$	103	$	243		$	(2	)	$	241
Net income	$	338	$	(2	)	$	336	$	760		$	(5	)	$	755
Re-measurements of employee future benefit plans, net of tax	$	2	$	2		$	4	$	(28	)	$	5		$	(23	)
Earnings per Share	$	0.70	$	(0.01	)	$	0.69	$	1.57		$	(0.01	)	$	1.56

Consolidation

In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements; IFRS 11, Joint Arrangements, to replace International Accounting Standard ("IAS") 31, Interests in Joint Ventures; IFRS 12, Disclosure of Interests in Other Entities; and amendments to IAS 27, Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures.

Canadian Oil Sands has applied these new standards effective January 1, 2013 in accordance with the transitional provisions. IFRS 10, which establishes principles for the presentation and preparation of consolidated financial statements, has not impacted Canadian Oil Sands' financial statements or disclosures. IFRS 11 eliminates the accounting policy choice between proportionate consolidation and equity method accounting for joint ventures available under IAS 31 and, instead, mandates one of these two methodologies based on the economic substance of the joint arrangement. Canadian Oil Sands has determined that its investments in Syncrude and Syncrude Canada are considered joint operations under the new standard and continues to recognize its proportionate share of the assets, liabilities, revenues, expenses, and commitments of both. IFRS 12 requires entities to disclose information about the nature of their interests in joint ventures, which has resulted in additional disclosures in Note 1, Nature of Operations.

Fair Value Measurement

In May 2011, the IASB issued IFRS 13, Fair Value Measurements, which establishes a single source of guidance for fair value measurements and related disclosures. Canadian Oil Sands has applied this new standard effective January 1, 2013 in accordance with the transitional provisions, resulting in new fair value disclosures in Note 13, Financial Instruments.

Financial Instruments: Disclosures

In December 2011, the IASB issued amendments to IFRS 7, Financial Instruments: Disclosures, requiring entities to disclose information about the effect, or potential effect, of netting arrangements on an entity's financial position. Canadian Oil Sands has applied these amendments effective January 1, 2013 in accordance with their transitional provisions, resulting in additional disclosures in Note 13, Financial Instruments.

Production Stripping Costs

In October 2011, the IASB issued International Financial Reporting Interpretations Committee ("IFRIC") Interpretation 20, Stripping Costs in the Production Phase of a Surface Mine, which clarifies the accounting for costs associated with waste removal in surface mining during the production phase of a mine. Canadian Oil Sands has applied this new interpretation effective January 1, 2013 in accordance with the transitional provisions and there has been no impact on Canadian Oil Sands' financial statements or disclosures.

4) Property, Plant and Equipment, Net

	Nine Months Ended September 30, 2013

($ millions)		Upgrading and Extracting			Mining Equipment		Vehicles and Equipment			Buildings		Asset Retirement Costs			Major Turnaround Costs			Construction in Progress			Mine Development		Total

Cost
Balance at January 1, 2013	$	5,300		$	1,397	$	686		$	324	$	1,024		$	166		$	1,501		$	392	$	10,790
Additions		-			-		8			-		-			54			988			-		1,050
Change in asset retirement costs		-			-		-			-		(170	)		-			-			-		(170	)
Retirements		(22	)		-		(18	)		-		-			(47	)		-			-		(87	)
Reclassifications⁽¹⁾		11			154		-			5		17			-			(187	)		-		-
Balance at September 30, 2013	$	5,289		$	1,551	$	676		$	329	$	871		$	173		$	2,302		$	392	$	11,583

Accumulated depreciation
Balance at January 1, 2013	$	1,447		$	539	$	320		$	107	$	180		$	73		$	-		$	121	$	2,787
Depreciation		156			47		38			6		33			42			-			4		326
Retirements		(22	)		-		(19	)		-		-			(47	)		-			-		(88	)
Reclassifications⁽¹⁾		-			-		-			-		-			-			-			-		-
Balance at September 30, 2013	$	1,581		$	586	$	339		$	113	$	213		$	68		$	-		$	125	$	3,025

Net book value at September 30, 2013	$	3,708		$	965	$	337		$	216	$	658		$	105		$	2,302		$	267	$	8,558

(1)	Reclassifications are primarily transfers from construction in progress to other categories of property, plant and equipment when construction is completed and assets are available for use.

For the three and nine months ended September 30, 2013, interest costs of $29 million and $80 million, respectively, were capitalized and included in property, plant and equipment (three and nine months ended September 30, 2012 - $25 million and $65 million, respectively) based on a 6.5 per cent interest capitalization rate for the three and nine months ended September 30, 2013 (6.5 per cent and 6.7 per cent, respectively, for the three and nine months ended September 30, 2012).

5) Accounts Payable and Accrued Liabilities

		September 30			December 31
($ millions)		2013			2012

Trade payables	$	586		$	498
Crown royalties		291			215
Current portion of asset retirement obligation		45			44
Interest payable		38			29
	$	960		$	786
Less non-current portion of Crown royalties		(78	)		(82	)
Accounts payable and accrued liabilities	$	882		$	704

6) Other Liabilities

		September 30		December 31
($ millions)		2013		2012

Non-current portion of Crown royalties	$	78	$	82
Other		11		7
Other liabilities	$	89	$	89

7) Asset Retirement Obligation

The Corporation and each of the other Syncrude owners are liable for their share of ongoing obligations related to the reclamation and closure of the Syncrude properties on abandonment. The Corporation estimates reclamation and closure expenditures will be made progressively over the next 70 years and has applied a risk-free interest rate of 3.0 per cent at September 30, 2013 (December 31, 2012 - 2.25 per cent) in deriving the asset retirement obligation. The risk-free rate is based on the yield for benchmark Government of Canada long-term bonds.

($ millions)		Nine Months Ended September 30 2013			Year Ended December 31 2012

Asset retirement obligation, beginning of period	$	1,102		$	1,037
Change in risk-free interest rate		(170	)		68
Change in estimated reclamation and closure expenditures		-			25
Accretion expense		19			26
Reclamation expenditures		(40	)		(54	)
Asset retirement obligation, end of period	$	911		$	1,102
Less current portion		(45	)		(44	)
Non-current portion	$	866		$	1,058

The $170 million decrease in the asset retirement obligation in 2013, due to the increase in the risk-free rate, was recorded as a decrease in property, plant and equipment. The $45 million current portion of the asset retirement obligation is included in accounts payable and accrued liabilities, while the $866 million non-current portion is presented separately as a liability on the September 30, 2013 Consolidated Balance Sheet. The total undiscounted estimated cash flows required to settle Canadian Oil Sands' share of the asset retirement obligation were $2,064 million at September 30, 2013 (December 31, 2012 - $2,104 million).

8) Employee Future Benefits

The Corporation's share of Syncrude Canada's defined benefit and contribution plans' costs for the three and nine months ended September 30, 2013 and 2012 is based on its 36.74 per cent working interest. The costs have been recorded in operating expenses, net finance expense and other comprehensive loss as follows:

		Three Months Ended						Nine Months Ended
		September 30						September 30
($ millions)		2013			2012			2013			2012

Operating expenses	$	12		$	11		$	34		$	32
Net finance expense		4		$	4			12		$	12
Other comprehensive (income) loss⁽¹⁾		(93	)		(5	)		(92	)		31
Total benefit cost (recovery)	$	(77	)	$	10		$	(46	)	$	75

(1)	The other comprehensive (income) loss is presented net of tax on the Consolidated Statements of Income and Comprehensive Income.

9) Foreign Exchange

		Three Months Ended						Nine Months Ended
		September 30						September 30
($ millions)		2013			2012			2013			2012

Foreign exchange (gain) loss - long-term debt	$	(40	)	$	(64	)	$	62		$	(48	)
Foreign exchange (gain) loss - other		9			13			(20	)		7
Total foreign exchange (gain) loss	$	(31	)	$	(51	)	$	42		$	(41	)

10) Net Finance Expense

			Three Months Ended						Nine Months Ended
			September 30						September 30
($ millions)			2013			2012			2013			2012

Interest costs on long-term debt⁽¹⁾		$	30		$	28		$	87		$	78
	Less capitalized interest on long-term debt		(29	)		(25	)		(80	)		(65	)
Interest expense on long-term debt		$	1		$	3		$	7		$	13
Interest expense on employee future benefits			4			4			12			12
Accretion of asset retirement obligation			7			6			19			19
Net finance expense		$	12		$	13		$	38		$	44

(1)	Interest costs on long-term debt are net of interest income of $3 million and $11 million for the three and nine months ended September 30, 2013 and $4 million and $9 million for the three and nine months ended September 30, 2012, respectively.

11) Tax Expense

		Three Months Ended				Nine Months Ended
		September 30				September 30
($ millions)		2013		2012		2013			2012

Current tax expense	$	32	$	10	$	212		$	30
Deferred tax expense (recovery)		32		93		(6	)		211
Total tax expense	$	64	$	103	$	206		$	241

12) Capital Management

The Corporation's capital consists of cash and cash equivalents, debt and Shareholders' equity. The balance of each of these items at September 30, 2013 and December 31, 2012 was as follows:

		September 30			December 31
($ millions, except % amounts)		2013			2012

Long-term debt^(1,2)	$	1,549		$	1,794
Cash and cash equivalents		(840	)		(1,553	)
Net debt^(1,3)	$	709		$	241

Shareholders' equity	$	4,716		$	4,515

Total net capitalization^(1,4)	$	5,425		$	4,756

Total capitalization ^(1,5)	$	6,265		$	6,309

Net debt-to-total net capitalization^(1,6) (%)		13			5

Long-term debt-to-total capitalization^(1,7) (%)		25			28

(1)	Additional GAAP financial measure.
(2)	Includes current and non-current portions of long-term debt.
(3)	Long-term debt less cash and cash equivalents.
(4)	Net debt plus Shareholders' equity.
(5)	Long-term debt plus Shareholders' equity.
(6)	Net debt divided by total net capitalization.
(7)	Long-term debt divided by total capitalization.

Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, increased to $709 million at September 30, 2013 from $241 million at December 31, 2012, as existing cash balances were used to fund capital expenditures and dividend payments in excess of cash flow from operations. In addition, a weakening Canadian dollar from December 31, 2012 to September 30, 2013 increased the Canadian equivalent value of Canadian Oil Sands' outstanding long-term debt, all of which is denominated in U.S. dollars. As a result, net debt-to-total net capitalization increased to 13 per cent at September 30, 2013 from five per cent at December 31, 2012.

On August 15, 2013, Canadian Oil Sands repaid U.S. $300 million of Senior Notes upon maturity. As result, long-term debt-to-total capitalization fell to 25 per cent at September 30, 2013 from 28 per cent at December 31, 2012.

Shareholders' equity increased to $4,716 million at September 30, 2013 from $4,515 million at December 31, 2012, as net income exceeded dividends in the first nine months of 2013.

The Corporation's senior notes indentures and credit facility agreements contain certain covenants which restrict Canadian Oil Sands' ability to sell all or substantially all of its assets or change the nature of its business, and limit long-term debt-to-total capitalization to 55 per cent. Canadian Oil Sands is in compliance with its debt covenants, and with a long-term debt-to-total capitalization of 25 per cent at September 30, 2013, a significant increase in debt or decrease in equity would be required to negatively impact the Corporation's financial flexibility.

13) Financial Instruments

The Corporation's financial instruments include cash and cash equivalents, accounts receivable, investments held in a reclamation trust, accounts payable and 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, 2012.

Offsetting Financial Assets and Financial Liabilities

The carrying values of accounts receivable and accounts payable and accrued liabilities have each been reduced by $73 million ($25 million at December 31, 2012) as a result of netting agreements with counterparties.

Fair Values

The fair values of cash and cash equivalents, accounts receivable, reclamation trust investments and accounts payable and accrued liabilities approximate their carrying values due to the short-term nature of those instruments. The fair value of long-term debt, based on third-party market indications, is as follows:

		September 30		December 31
As at ($ millions)		2013		2012

8.2% Senior Notes due April 1, 2027 (U.S. $73.95 million)	$	94	$	104
7.9% Senior Notes due September 1, 2021 (U.S. $250 million)		315		332
5.8% Senior Notes due August 15, 2013 (U.S. $300 million)		-		309
7.75% Senior Notes due May 15, 2019 (U.S. $500 million)		616		628
4.5% Senior Notes due April 1, 2022 (U.S. $400 million)		415		435
6.0% Senior Notes due April 1, 2042 (U.S. $300 million)		314		350
	$	1,754	$	2,158

14) Commitments

Canadian Oil Sands' commitments are summarized in the 2012 annual consolidated financial statements and include future cash payments that the Corporation is required to make under existing contractual arrangements entered into directly or as a 36.74 per cent owner in Syncrude. During the first nine months of 2013, Canadian Oil Sands entered into new contractual obligations totalling approximately $700 million for the transportation of crude oil in support of the Corporation's strategy to secure access to preferred markets and enhance marketing flexibility.

15) Contingencies

Crown royalties include Canadian Oil Sands' share of amounts due under the Syncrude Royalty Amending Agreement with the Alberta government. The Syncrude Royalty Amending Agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil reference price 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.

16) Supplementary Information

a) Change in Non-Cash Working Capital

			Three Months Ended						Nine Months Ended
			September 30						September 30
($ millions)			2013			2012			2013			2012

Operating activities:
	Accounts receivable ("AR")	$	(131	)	$	(167	)	$	(104	)	$	(10	)
	Inventories		(12	)		(2	)		(23	)		5
	Prepaid expenses		(7	)		(10	)		-			(1	)
	Accounts payable and accrued liabilities ("AP")		116			87			178			162
	Current taxes		21			10			145			30
	Less: AP and AR changes reclassified to investing and other		(1	)		(42	)		(38	)		(81	)
Change in operating non-cash working capital		$	(14	)	$	(124	)	$	158		$	105

Investing activities:
	Accounts payable and accrued liabilities	$	-		$	42		$	36		$	78
Change in investing non-cash working capital		$	-		$	42		$	36		$	78

Change in total non-cash working capital		$	(14	)	$	(82	)	$	194		$	183

b) Income Taxes and Interest Paid

		Three Months Ended				Nine Months Ended
		September 30				September 30
($ millions)		2013		2012		2013		2012

Income taxes paid	$	10	$	-	$	66	$	-

Interest paid	$	20	$	20	$	83	$	65

Income taxes paid and the portion of interest costs that is expensed are included within cash from operating activities on the Consolidated Statements of Cash Flows. The portion of interest costs that is capitalized as property, plant and equipment is included within cash used in investing activities on the Consolidated Statements of Cash Flows.

c) Cash Flow from Operations per Share

		Three Months Ended				Nine Months Ended
		September 30				September 30
($ millions)		2013		2012		2013		2012

Cash Flow From Operations Per Share, basic and diluted	$	0.70	$	0.97	$	1.97	$	2.40

Cash flow from operations per Share is calculated as cash flow from operations, which is cash from operating activities before changes in non-cash working capital, divided by the weighted-average number of outstanding Shares in the period.

17) Prior Period Comparative Amounts

During the fourth quarter of 2012, the Corporation completed a review of the presentation of crude oil purchase and sale transactions and it was determined that certain transactions previously reported on a gross basis (sales are presented gross of crude oil purchases and transportation expense) are more appropriately reflected on a net basis (crude oil purchases and transportation expense are netted against sales). Prior period comparative amounts have been reclassified to conform to the current period presentation. The impact is as follows:

		Three Months			Nine Months
		Ended			Ended
($ millions)		September 30, 2012			September 30, 2012

Sales	$	(16	)	$	(78	)
Crude oil purchases and transportation expense		(16	)		(78	)
Net income	$	-		$	-

Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Shares Listed - Symbol: COS Toronto Stock Exchange

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