EX-99.2 3 a2218559zex-99_2.htm EX-99.2
QuickLinks -- Click here to rapidly navigate through this document

EXHIBIT 99-2


Management's Discussion and Analysis for the fiscal year ended December 31, 2013,
dated February 28, 2014


MANAGEMENT'S DISCUSSION
AND ANALYSIS
February 24, 2014
 
   
   
   

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's December 31, 2013 audited Consolidated Financial Statements and the accompanying notes. Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and the Annual Information Form dated February 28, 2014 (the 2013 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website, www.suncor.com. Information contained in or otherwise accessible through our website does not form a part of this MD&A, and is not incorporated into this MD&A by reference.

References to "we", "our", "Suncor", or "the company" mean Suncor Energy Inc., its subsidiaries, partnerships and joint arrangements, unless the context requires otherwise. For a list of abbreviations that may be used in this MD&A, refer to the Advisories – Common Abbreviations section of this MD&A.

 
 
 
 
 
 

16   SUNCOR ENERGY INC. ANNUAL REPORT 2013

 
 
 
 
MD&A – Table of Contents
18   Financial and Operating Summary
20   Suncor Overview
22   Financial Information
27   Segment Results and Analysis
46   Fourth Quarter 2013 Analysis
49   Quarterly Financial Data
52   Capital Investment Update
56   Financial Condition and Liquidity
61   Accounting Policies and Critical Accounting Estimates
67   Risk Factors
72   Other Items
73   Advisories

Basis of Presentation

Unless otherwise noted, all financial information has been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and Canadian generally accepted accounting principles (GAAP) as contained within Part 1 of the Canadian Institute of Chartered Accountants Handbook.

Effective January 1, 2013, Suncor adopted new and amended accounting standards, described in the Accounting Policies and Critical Accounting Estimates section of this MD&A. Comparative figures presented in this document pertaining to Suncor's 2012 results have been restated while comparative figures pertaining to Suncor's results prior to and including 2011 have not been restated in accordance with the respective transitional provisions of the new and amended standards.

All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, unless otherwise noted.

Non-GAAP Financial Measures

Certain financial measures in this MD&A – namely operating earnings, cash flow from operations, free cash flow, return on capital employed (ROCE), Oil Sands cash operating costs, and last-in, first-out (LIFO) – are not prescribed by GAAP. Operating earnings, Oil Sands cash operating costs and LIFO are defined in the Advisories – Non-GAAP Financial Measures section of this MD&A and reconciled to GAAP measures in the Financial Information and Segment Results and Analysis sections of this MD&A. Cash flow from operations, ROCE and free cash flow are defined and reconciled to GAAP measures in the Advisories – Non-GAAP Financial Measures section of this MD&A.

Measurement Conversions

Crude oil and natural gas liquids volumes have been converted to mcfe or mmcfe on the basis of one bbl to six mcf basis in this MD&A. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Refer to the Advisories – Measurement Conversions section of this MD&A.

Common Abbreviations

For a list of abbreviations that may be used in this MD&A, refer to the Advisories – Common Abbreviations section of this MD&A.

Risks and Forward-Looking Information

The company's financial and operational performance is potentially affected by a number of factors, including, but not limited to, the factors described in the Risk Factors section of this MD&A.

This MD&A contains forward-looking information based on Suncor's current expectations, estimates, projections and assumptions. This information is subject to a number of risks and uncertainties, including those discussed in this MD&A and Suncor's other disclosure documents, many of which are beyond the company's control. Users of this information are cautioned that actual results may differ materially. Refer to the Advisories – Forward-Looking Information section of this MD&A for information on the material risk factors and assumptions underlying our forward-looking information.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    17

1. FINANCIAL AND OPERATING SUMMARY

Financial Summary

Year ended December 31 ($ millions, except per share amounts)   2013   2012   2011  
Net earnings   3 911   2 740   4 304  
  per common share – basic   2.61   1.77   2.74  
  per common share – diluted   2.60   1.76   2.67  
Operating earnings(1)   4 700   4 847   5 674  
  per common share – basic   3.13   3.14   3.61  
Cash flow from operations(1)   9 412   9 733   9 746  
  per common share – basic   6.27   6.30   6.20  
Dividends on common shares(2)   1 095   756   664  
  per common share – basic   0.73   0.50   0.43  
Weighted average number of common shares in millions – basic   1 501   1 545   1 571  
Weighted average number of common shares in millions – diluted   1 502   1 549   1 582  
Operating revenues, net of royalties   39 593   38 107   38 339  
ROCE(1)(3) (%)              
  For the twelve months ended   11.5   7.2   13.8  
Capital Expenditures(4)   6 380   6 370   6 291  
  Sustaining   3 725   3 252   3 278  
  Growth   2 655   3 118   3 013  
Free cash flow(1)   2 635   2 776   2 896  
Balance Sheet (at December 31)              
  Total assets   78 315   76 401   74 741  
  Long-term debt(5)   10 660   10 249   10 016  
  Net debt   6 256   6 639   6 976  
(1)
Non-GAAP financial measures. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

(2)
Dividends paid on common shares does not include a value for common share dividends granted under the company's dividend reinvestment program.

(3)
ROCE excludes capitalized costs related to major projects in progress.

(4)
Excludes capitalized interest.

(5)
Includes current portion of long-term debt.

18   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Operating Summary

Year ended December 31   2013   2012   2011  
Production Volumes (mboe/d)              
  Oil Sands   392.5   359.2   339.3  
  Exploration and Production   169.9   189.9   206.7  
Total   562.4   549.1   546.0  
Average Price Realizations ($/boe)              
  Oil Sands   84.22   82.75   90.07  
  Exploration and Production   91.44   84.05   79.95  
Refinery Utilization(1)(2) (%)              
  Eastern North America   91   89   94  
  Western North America   96   100   91  
    94   95   92  
(1)
Refinery utilization is the amount of crude oil run through crude distillation units, expressed as a percentage of the capacity of these units.

(2)
Effective January 1, 2013, the company increased the nameplate capacity of the Edmonton refinery from 135,000 bbls/d to 140,000 bbls/d. Effective January 1, 2012, the company increased the nameplate capacity of the Montreal refinery from 130,000 bbls/d to 137,000 bbls/d and the nameplate capacity of the Commerce City refinery from 93,000 bbls/d to 98,000 bbls/d. Prior years' utilization rates have not been recalculated and reflect the lower nameplate capacities.

Segment Summary

Year ended December 31 ($ millions)   2013   2012   2011    
Net earnings (loss)                
  Oil Sands   2 040   468   2 603    
  Exploration and Production   1 000   138   306    
  Refining and Marketing   2 022   2 137   1 726    
  Corporate, Energy Trading and Eliminations   (1 151 ) (3 ) (331 )  
Total   3 911   2 740   4 304    
Operating earnings (loss)(1)                
  Oil Sands   2 098   2 025   2 737    
  Exploration and Production   1 210   850   1 358    
  Refining and Marketing   2 022   2 152   1 726    
  Corporate, Energy Trading and Eliminations   (630 ) (180 ) (147 )  
Total   4 700   4 847   5 674    
Cash flow from (used in) operations(1)                
  Oil Sands   4 556   4 407   4 572    
  Exploration and Production   2 316   2 227   2 846    
  Refining and Marketing   2 618   3 138   2 574    
  Corporate, Energy Trading and Eliminations   (78 ) (39 ) (246 )  
Total   9 412   9 733   9 746    
(1)
Non-GAAP financial measures. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    19

2. SUNCOR OVERVIEW

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. We are strategically focused on developing one of the world's largest petroleum resource basins – Canada's Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil and natural gas in Canada and internationally; we transport and refine crude oil, and we market petroleum and petrochemical products primarily in Canada. Periodically, we market third-party petroleum products. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts. For a description of Suncor's business segments, refer to the Segment Results and Analysis section of this MD&A.

Suncor's Strategy

We are committed to delivering competitive and sustainable returns to shareholders by focusing on capital discipline, operational excellence and long-term profitable growth, and by leveraging our competitive differentiators; an industry-leading Oil Sands resource base, a proven integrated model, financial strength, industry expertise and a commitment to sustainability. Key components of Suncor's strategy include:

•
Profitably operate and develop our resources – Suncor's growth portfolio is focused on projects that are expected to provide long-term profitability for the company. The company's significant resource base and industry expertise at Oil Sands has laid the groundwork for achieving this growth. Suncor's economies of scale have also allowed us to focus on near-term oil sands growth through low-cost debottlenecking and expansion projects.

•
Optimize value through integration – From the ground to the gas station, Suncor optimizes its profit through each step of the value chain. As upstream production grows, securing access to global pricing through the company's refining operations and midstream logistics network helps to maximize profit on each upstream barrel.

•
Achieve industry leading unit costs in each business segment – Through our focus on operational excellence, we're aiming to get the most out of our operations. Driving down costs and a continued focus on reliability will help to achieve this.

•
Industry leader in sustainable development – We're focused on delivering triple bottom line sustainability, which means leadership in environmental performance, social responsibility and creating a strong economy. We are committed to our environmental goals that go beyond compliance in the areas of land reclamation, air emissions, freshwater use and energy efficiency.

2013 Highlights

Suncor reports strong financial results.

•
Net earnings for 2013 were $3.911 billion, compared to $2.740 billion in 2012.

•
Operating earnings(1) for 2013 were $4.700 billion, compared to $4.847 billion in 2012.

•
Cash flow from operations(1) for 2013 was $9.412 billion, compared to $9.733 billion in 2012.

•
ROCE(1) (excluding major projects in progress) was 11.5% for the twelve months ended December 31, 2013, compared to 7.2% for the twelve months ended December 31, 2012. ROCE for the twelve months ended December 31, 2013 increased over the same period of 2012 primarily due to an after-tax impairment charge of $1.487 billion relating to the Voyageur upgrader project that reduced ROCE for the twelve months ended December 31, 2012 by approximately 4%.

Return of cash to shareholders increases by over 25%.

Suncor shareholders received approximately $2.8 billion in cash from the company during 2013 through share repurchases and dividends, a 25% increase over the prior year, reinforcing Suncor's commitment to its shareholders.

•
The company returned $1.1 billion in dividends, reflecting the 54% increase to Suncor's quarterly dividend announced in early 2013, and $1.7 billion through the repurchase of 49.5 million common shares in 2013, at a weighted average price of $33.84 per share.

•
On February 3, 2014, Suncor's Board of Directors approved a 15% increase to its quarterly dividend to $0.23 per common share and authorized additional share repurchases of up to $1 billion.

20   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Suncor's integrated model and relentless focus on capital discipline have delivered consistent cash flows in a volatile price environment

Suncor's well-established operating model and focus on capital discipline as well as long-term profitable growth have resulted in significant free cash flow(1).

•
Cash flow from operations for 2013 exceeded capital and exploration expenditures by more than $2.6 billion, and was higher than net debt at year end by $3.2 billion.

•
The company's solid financial position reaffirmed its ability to deliver reliable and sustainable returns to its shareholders and fund its 2013 capital program with cash flow from operations.
(1)
Operating earnings, cash flow from operations, ROCE and free cash flow are non-GAAP financial measures. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

Record Oil Sands production achieved through important milestones and strong operational performance.

In 2013, the Oil Sands business delivered another record-setting year, resulting in an 11% increase in annual production at Oil Sands Operations and record annual SCO production. These results were achieved despite a major turnaround in the second quarter and third-party outages that impacted Oil Sands Operations during the year.

•
Strong project execution has allowed the company to nearly triple its production at Firebag in three years. The fourth quarter of 2013 marked the completion of the ramp up at Firebag, with daily production rates reaching approximately 95% of capacity.

•
Suncor has facilitated this growth by building strong midstream capabilities while also increasing operational flexibility. The commissioning of the hot bitumen infrastructure in 2013, including the ability to import third-party diluent, has increased the takeaway capacity of bitumen and unlocked production in mining.

Capitalizing on low-cost growth opportunities to steadily increase returns.

•
Following a decade of large expansions at Oil Sands Base and Firebag, Oil Sands Operations has the opportunity for production growth through low-cost debottlenecking, expansions and increased reliability.

•
The company plans to advance a number of debottlenecking initiatives across Oil Sands Operations and expansions at In Situ, building on the recent success of the hot bitumen infrastructure.

•
These initiatives are expected to grow production at existing Oil Sands Operations sites to approximately 500,000 bbls/d by the end of 2018.

Key decisions that are aligned with the company's strategy to focus on long-term profitable growth.

•
The sanctioning of the Fort Hills mining project, the sale of the company's conventional natural gas business, and the decision not to proceed with the Voyageur upgrader project have re-positioned Suncor's portfolio, building a strong foundation for long-term profitable growth.

•
With a significant reserves and resources base, Suncor continues to assess potential in situ growth prospects at MacKay River, Meadow Creek, Firebag and Lewis.

•
In addition to Golden Eagle and Hebron, the company is advancing a number of extension opportunities while expanding its offshore exploration prospects in Norway.

Investing in integration and market access.

As North American commodity prices remain volatile and Suncor's Oil Sands production continues to rise, enhancing access to global markets helps to maximize profitability and operational flexibility.

•
Suncor commenced rail shipments of inland crudes to its Montreal refinery in the fourth quarter of 2013, enabling the company to take advantage of the price differentials between inland and Brent crudes.

•
In early 2014, Suncor commenced shipments of heavy crude on the Gulf Coast Pipeline, providing the company with more than 50,000 bbls/d of heavy crude shipping capacity to the U.S. Gulf Coast, a profitable outlet for the growing bitumen production at Firebag.

•
Suncor's flexible model allows it to take advantage of fluctuating North American crude price differentials. In 2013, discounted crudes were being supplied to the Montreal refinery via rail or ship, while projects were also underway to enable the Montreal refinery to process heavier crude feedstock.

A continued focus on operational excellence and improved reliability.

•
Suncor achieved an annual refinery utilization rate of 94% and record upgrading reliability, despite planned maintenance and third-party outages in 2013.

•
Demonstrated reliability and continuous improvements at Suncor's refineries resulted in a nameplate capacity increase for the Edmonton refinery for a second year in a row. The company's total refining nameplate capacity of 462,000 bbls/d represents a 4% increase since 2011.

•
Suncor successfully executed planned maintenance across its operations, including a seven-week turnaround at Upgrader 1, a ten-week off-station maintenance program at Terra Nova and planned maintenance at each of its refineries.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    21

3. FINANCIAL INFORMATION

Net Earnings

Suncor's net earnings for 2013 were $3.911 billion, compared to $2.740 billion in 2012. Net earnings were affected by the same factors that influenced operating earnings, which are described in this section of the MD&A. Items affecting net earnings in 2013, compared with 2012, included:

•
The after-tax unrealized foreign exchange loss on the revaluation of U.S. dollar denominated debt was $521 million in 2013, compared with a gain of $157 million in 2012.

•
In 2013, the company recorded after-tax impairment charges of $563 million in the Exploration and Production segment against its assets in Syria, Libya and North America Onshore. Concurrent with the impairment of its Syrian assets, the company recognized after-tax risk mitigation proceeds of $223 million, previously recorded as a long-term provision.

•
In 2013, the company recorded an after-tax charge of $58 million as a result of not proceeding with the Voyageur upgrader project.

•
In 2013, the company recorded an after-tax gain of $130 million relating to the sale of the company's conventional natural gas business.

•
In 2012, the company recorded an after-tax impairment charge of $1.487 billion against the Voyageur upgrader project.

•
In 2012, the company recorded an after-tax impairment (net of reversals) for assets in Syria of $517 million, in addition to after-tax charges of $172 million, including impairments against assets in North America Onshore and East Coast Canada, and a provision in North America Onshore for estimated future commitments relating to unutilized pipeline capacity.

•
In 2012, the Province of Ontario approved a budget that froze the general corporate income tax rate at 11.5%, instead of the planned reduction to 10% by 2014. As a result, the company adjusted its deferred income tax balances, leading to a charge to net earnings of $88 million.

22   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Operating Earnings

Consolidated Operating Earnings Reconciliation(1)

Year ended December 31 ($ millions)   2013   2012   2011  
Net earnings as reported   3 911   2 740   4 304  
Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt   521   (157 ) 161  
Impairments (net of reversals), write-offs, and provisions(2)   563   2 176   629  
Recognition of risk mitigation proceeds   (223 ) —   —  
Net impact of not proceeding with the Voyageur upgrader project   58   —   —  
(Gain) loss on significant disposals(3)   (130 ) —   107  
Impact of income tax rate adjustments on deferred income taxes(4)   —   88   442  
Adjustments to provisions for assets acquired through the merger(5)   —   —   31  
Operating earnings(1)   4 700   4 847   5 674  
(1)
Non-GAAP financial measure. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

(2)
In 2011, the company recorded net impairment charges of $503 million ($514 million initial impairment, net of $11 million of subsequent impairment reversals) against assets pertaining to its operations in Libya, which were shut-in as a result of political unrest. The company also recorded $68 million of after-tax impairment charges against certain North America Onshore assets and after-tax write-offs of crude inventories of $58 million.

(3)
In 2011, the company disposed of assets resulting in after-tax losses of $107 million, consisting of $99 million on the partial disposition of interests in the Voyageur upgrader and Fort Hills projects, and $8 million for the sale of non-core Exploration and Production assets.

(4)
In the first quarter of 2011, the U.K. government announced an increase in the tax rate on oil and gas profits in the North Sea that increased the statutory tax rate on Suncor's earnings in the U.K. from 50% to 59.3% in 2011 and to 62% in future years, resulting in an increase to deferred income tax expense of $442 million.

(5)
In 2011, Suncor recorded an after-tax provision of $31 million in the Exploration and Production segment related to a royalty dispute concerning the deductibility of certain costs for a period before the merger with Petro-Canada. GRAPHIC


(1)
For an explanation of the construction of this bridge analysis, see the Advisories – Non-GAAP Financial Measures section of this MD&A.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    23

Suncor's consolidated operating earnings for 2013 were $4.700 billion, compared to $4.847 billion in 2012. Factors that positively impacted operating earnings in 2013, compared to 2012, included:

•
Average price realizations for production from Oil Sands Operations were higher in 2013 due primarily to strength in WTI and the impact of the weaker Canadian dollar, which more than offset wider light/heavy differentials, that placed downward pressure on prices for sour SCO and bitumen. Exploration and Production price realizations were positively impacted in 2013 by higher natural gas prices and the weaker Canadian dollar. Refining margins were slightly lower in 2013 due to narrower crude differentials and lower crack spreads compared to 2012.

•
Total upstream production volumes rose to an average of 562,400 boe/d in 2013, compared to 549,100 boe/d in 2012, reflecting record production in Oil Sands, which more than offset the reduced production from the sale of the company's conventional natural gas business and the shut-in of production in Libya. In Refining and Marketing, strong utilization rates and more favourable feedstock mix and product yield had a positive impact on operating earnings in 2013 compared to 2012.

•
Royalties were lower in 2013 compared with 2012, due primarily to the impact of lower production from Libya, partially offset by higher production at Oil Sands.

The following factors had a negative impact on operating earnings in 2013 compared to 2012:

•
Operating expenses increased in 2013 primarily due to increased operating costs in Oil Sands, largely associated with increased production, additional mine maintenance, and higher natural gas costs and consumption, as well as increased transportation expense in Oil Sands and Refining and Marketing.

•
DD&A and exploration expenses were higher in 2013, due mainly to a larger asset base, partially offset by lower production in Exploration and Production.

•
Financing expense and other income increased primarily due to higher interest expense associated with additional capital leases and lower capitalized interest.

Cash Flow from Operations

Consolidated cash flow from operations for 2013 was $9.412 billion, compared to $9.733 billion in 2012. Cash flow from operations decreased due primarily to incremental current income tax expense related to the company's Canadian operations recorded in 2013 and higher operating expenses, partially offset by higher production volumes and higher price realizations.

Results for 2012 compared with 2011

Net earnings for 2012 were $2.740 billion, compared to $4.304 billion in 2011. The decrease in net earnings was due mainly to the same factors impacting operating earnings and by the operating earnings adjustments described above.

Operating earnings for 2012 were $4.847 billion compared to $5.674 billion in 2011. The decrease in operating earnings was due mainly to higher DD&A and exploration expenses, higher operating expenses driven by a larger share-based compensation charge, increased royalty expense due to higher production from Libya, and lower price realizations for upstream production that were largely offset by strong refining margins. Lower production in the Exploration and Production segment was offset by the increase in production from the Oil Sands segment.

Consolidated cash flow from operations for 2012 was $9.733 billion, compared to $9.746 billion in 2011. Cash flow from operations was impacted by lower price realizations in the Oil Sands segment, partially offset by strong refining margins.

24   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Business Environment

Commodity prices, refining crack spreads and foreign exchange rates are important factors that affect the results of Suncor's operations.

Year ended December 31   2013   2012   2011  
WTI crude oil at Cushing (US$/bbl)   97.95   94.20   95.10  
Dated Brent crude oil at Sullom Voe (US$/bbl)   108.75   111.70   111.15  
Dated Brent/Maya FOB price differential (US$/bbl)   11.65   12.15   12.50  
Canadian 0.3% par crude oil at Edmonton (Cdn$/bbl)   93.90   86.60   95.75  
WCS at Hardisty (US$/bbl)   72.75   73.15   77.95  
Light/heavy differential for WTI at Cushing less WCS at Hardisty (US$/bbl)   25.20   21.05   17.15  
Condensate at Edmonton (US$/bbl)   101.70   100.75   105.30  
Natural gas (Alberta spot) at AECO (Cdn$/mcf)   3.15   2.40   3.65  
New York Harbor 3-2-1 crack(1) (US$/bbl)   23.90   32.90   27.00  
Chicago 3-2-1 crack(1) (US$/bbl)   21.40   27.40   24.65  
Portland 3-2-1 crack(1) (US$/bbl)   24.00   33.40   28.40  
Gulf Coast 3-2-1 crack(1) (US$/bbl)   20.55   29.00   24.80  
Exchange rate (US$/Cdn$)   0.97   1.00   1.01  
Exchange rate (end of period) (US$/Cdn$)   0.94   1.01   0.98  
(1)
3-2-1 crack spreads are indicators of the refining margin generated by converting three barrels of WTI into two barrels of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

Suncor's sweet SCO price realizations are influenced primarily by the price of WTI at Cushing and by the supply and demand of sweet SCO from Western Canada. Price realizations for sweet SCO were positively impacted by an increase in the price for WTI to US$97.95/bbl in 2013, compared to US$94.20/bbl in 2012. Stronger price realizations for sweet SCO also reflected lower industry supplies of SCO volumes due to planned maintenance by large producers in the second and third quarters of 2013, partially offset by strengthening supply, takeaway capacity constraints and lower refinery demand late in 2013.

Suncor produces a specific grade of sour SCO, the price realizations for which are influenced by various crude benchmarks including, but not limited to: Canadian par crude at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for Canadian par crude at Edmonton increased while the average for WCS at Hardisty held relatively constant in 2013 compared to 2012, resulting in consistent realizations for sour SCO.

Bitumen production that Suncor does not upgrade is blended with diluent to facilitate delivery on pipeline systems. Net bitumen price realizations are, therefore, influenced by both prices for Canadian heavy crude oil (WCS at Hardisty is a common reference) and prices for diluent (Condensate at Edmonton and SCO). Bitumen price realizations can also be affected by bitumen quality and spot sales. Average prices for WCS at Hardisty held relatively constant in 2013 compared to 2012, resulting in consistent realizations for bitumen.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing decreased over the prior year and averaged US$108.75/bbl in 2013, compared to US$111.70/bbl in 2012.

Suncor's price realizations for North America Onshore natural gas production are primarily referenced to Alberta spot at AECO. Natural gas is also used in the company's Oil Sands and Refining operations. The average AECO benchmark increased to $3.15/mcf in 2013, from $2.40/mcf in 2012.

Suncor's refining margins are influenced by 3-2-1 crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates, and by light/heavy and light/sour crude differentials. More complex refineries can earn greater margins by processing less expensive, heavier crudes. Crack spreads do not necessarily reflect the margins of a specific refinery. Crack spreads are based on current crude feedstock prices whereas actual refining margins are based on first-in, first-out inventory accounting (FIFO),

SUNCOR ENERGY INC. ANNUAL REPORT 2013    25


where a delay exists between the time that feedstock is purchased and when it is processed and sold to a third party. Specific refinery margins are further impacted by actual crude purchase costs, refinery configuration and refined products sales markets unique to that refinery. In 2013, crack spreads declined significantly, which had an adverse impact on refining margins compared to the prior year.

The majority of Suncor's revenues from the sale of oil and natural gas commodities are based on prices that are determined by, or referenced to, U.S. dollar benchmark prices. The majority of Suncor's expenditures are realized in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease revenue received from the sale of commodities. A decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of commodities.

In 2013, the Canadian dollar weakened in relation to the U.S. dollar as the average exchange rate decreased to 0.97 from 1.00, which had a positive impact on price realizations for the company in 2013.

Conversely, many of Suncor's assets and liabilities, notably most of the company's debt, are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. A decrease in the value of the Canadian dollar relative to the U.S. dollar from the previous balance sheet date increases the amount of Canadian dollars required to settle U.S. dollar denominated obligations.

Economic Sensitivities(1)(2)

The following table illustrates the estimated effects that changes in certain factors would have had on 2013 net earnings and cash flow from operations if the listed changes had occurred.

(Estimated change, in $ millions)   Net
Earnings		   Cash Flow
From
Operations		    
Crude oil +US$1.00/bbl   98   98    
Natural gas +Cdn$0.10/mcf   (8 ) (8 )  
Light/heavy differential +US$1.00/bbl   4   4    
3-2-1 crack spreads +US$1.00/bbl   113   113    
Foreign exchange +$0.01 US$/Cdn$(3)   (52 ) (131 )  
Foreign exchange on U.S. denominated debt +$0.01 US$/Cdn$(3)   79   —    
(1)
Each line item in this table shows the effects of a change in that variable only, with other variables being held consistent.

(2)
Changes for a variable imply that all such similar variables are impacted, such that Suncor's average price realizations increase uniformly. For instance, "Crude oil +US$1.00/bbl" implies that price realizations influenced by WTI, Brent, SCO, WCS, par crude at Edmonton and condensate all increase by US$1.00/bbl.

(3)
The difference between estimates for net earnings and cash flow from operations are due primarily to the revaluation of U.S. dollar denominated debt that is included within net earnings but not within cash flow from operations.

26   SUNCOR ENERGY INC. ANNUAL REPORT 2013

4. SEGMENT RESULTS AND ANALYSIS

Suncor has classified its operations into the following segments:

OIL SANDS

Suncor's Oil Sands segment, with assets located in the Wood Buffalo region of northeast Alberta, recovers bitumen from mining and in situ operations and either upgrades this production into SCO for refinery feedstock and diesel fuel, or blends the bitumen with diluent for direct sale to market. The Oil Sands segment includes:

•
Oil Sands Operations refer to Suncor's wholly owned and operated mining, extraction, upgrading, in situ and related logistics and storage assets in the Athabasca oil sands. Oil Sands Operations consist of:

•
Oil Sands Base operations include the Millennium and North Steepbank mining and extraction operations, integrated upgrading facilities known as Upgrader 1 and Upgrader 2, and the associated infrastructure for these assets – including utilities, energy and reclamation facilities, such as Suncor's tailings management (TRO™) assets.

•
In Situ operations include oil sands bitumen production from Firebag and MacKay River and supporting infrastructure, such as central processing facilities, cogeneration units and hot bitumen infrastructure, including an insulated pipeline, diluent import capabilities and a cooling and blending facility, and related storage assets. In Situ production is either upgraded by Oil Sands Base or blended with diluent and marketed directly to customers.

•
The Oil Sands segment also includes the company's interests in significant growth projects, including its 40.8% interest in the Fort Hills mining project where Suncor is the operator and its 36.8% interest in the Joslyn North mining project. The company also holds a 12.0% interest in the Syncrude oil sands mining and upgrading operation (these assets were formerly known as Oil Sands Ventures prior to an internal reorganization effective January 1, 2014).

EXPLORATION AND PRODUCTION

Suncor's Exploration and Production segment consists of offshore operations off the east coast of Canada and in the North Sea, and onshore operations in North America, Libya and Syria.

•
East Coast Canada operations include Suncor's 37.675% working interest in Terra Nova, which Suncor operates. Suncor also holds a 20% interest in the Hibernia base project and a 19.5% interest in the Hibernia Southern Extension Unit (HSEU), a 27.5% interest in the White Rose base project and a 26.125% interest in the White Rose Extensions, and a 22.729% interest in Hebron, all of which are operated by other companies.

•
International operations include Suncor's 29.89% working interest in Buzzard and its 26.69% interest in Golden Eagle. Both projects are located in the U.K. sector of the North Sea and are not operated by Suncor. Suncor also holds interests in several exploration licences offshore the U.K. and Norway. Suncor owns, pursuant to Exploration and Production Sharing Agreements (EPSAs), working interests in the exploration and development of oilfields in the Sirte Basin in Libya. As at February 28, 2014, production in Libya is shut-in due to political unrest. Suncor also owns, pursuant to a Production Sharing Contract (PSC), an interest in the Ebla gas development in the Ash Shaer and Cherrife areas in Syria. Due to political unrest in Syria, the company has declared force majeure under its contractual obligations, and Suncor's operations in Syria have been suspended indefinitely.

•
North America Onshore operations include Suncor's working interests in unconventional natural gas and crude oil assets in Western Canada, including unconventional oil and natural gas properties in central Alberta and northeast B.C.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    27

REFINING AND MARKETING

Suncor's Refining and Marketing segment consists of two primary operations:

•
Refining and Supply operations refine crude oil into a broad range of petroleum and petrochemical products. Eastern North America operations include refineries located in Montreal, Québec and Sarnia, Ontario, and a lubricants business located in Mississauga, Ontario that manufactures, blends and markets products worldwide. Western North America operations include refineries located in Edmonton, Alberta and Commerce City, Colorado. Other Refining and Supply assets include interests in a petrochemical plant, pipelines and product terminals in Canada and the U.S.

•
Downstream Marketing operations sell refined petroleum products and lubricants to retail, commercial and industrial customers through a combination of company-owned, branded-dealer and other retail stations in Canada and Colorado, a nationwide commercial road transport network in Canada, and a bulk sales channel in Canada.

CORPORATE, ENERGY TRADING AND ELIMINATIONS

The grouping Corporate, Energy Trading and Eliminations includes the company's investments in renewable energy projects, results related to energy marketing, supply and trading activities, and other activities not directly attributable to any other operating segment.

•
Renewable Energy interests include six operating wind power projects across Canada, two wind power projects under development in Ontario, and the St. Clair ethanol plant in Ontario.

•
Energy Trading activities primarily involve the marketing, supply and trading of crude oil, natural gas and byproducts, and the use of midstream infrastructure and financial derivatives to optimize related trading strategies.

•
Corporate activities include stewardship of Suncor's debt and borrowing costs, expenses not allocated to the company's businesses, and the company's captive insurance activities that self-insure a portion of the company's asset base.

•
Intersegment revenues and expenses are removed from consolidated results in Group Eliminations. Intersegment activity includes the sale of product between the company's segments and the provision of insurance for a portion of the company's operations by the Corporate captive insurance entity.

28   SUNCOR ENERGY INC. ANNUAL REPORT 2013

OIL SANDS

2013 Highlights

•
In 2013, the Oil Sands business delivered another record-setting year for production driven by strong project execution and improved reliability, representing an 11% increase in annual production and record annual SCO production at Oil Sands Operations.

•
Completion of the Firebag ramp up contributed to a 38% increase in annual production at Firebag over the prior year, reflecting strong project execution and successful project ramp up.

•
Suncor is now the largest In Situ producer, with more than 210,000 bbls/d of production capacity from its Firebag and Mackay River operations.

•
Installation of the hot bitumen infrastructure enhanced the company's operational flexibility and, coupled with improved reliability, helped to partially mitigate the adverse effects of third-party outages in 2013. These outages reduced annual production by 16,000 bbls/d in 2013.

•
Upgrader 1 turnaround was successfully completed in 2013. With no major turnaround event planned until 2016, Oil Sands Operations is well positioned for continued production growth.

•
Key decisions in 2013, including the sanctioning of the Fort Hills mining project and the decision not to proceed with the Voyageur upgrader project are aligned with Suncor's strategic objective to focus on projects that will provide long-term profitable growth.

Strategy and Investment Update

Oil Sands Operations has established a large physical asset base providing the opportunity for production growth through low-cost debottlenecks, expansions and increased reliability. In 2013, Suncor focused on advancing these projects and began to realize the benefits of these initiatives through the commissioning of the hot bitumen infrastructure in the third quarter of 2013. The hot bitumen infrastructure has added operational flexibility by enabling the transportation of hot bitumen from Firebag to Suncor's cooling and blending facilities, where the bitumen is blended with either internally produced or imported third-party diluent, and sold directly to market without the need for upgrading. The infrastructure has increased the takeaway capacity of bitumen and unlocked production in mining.

Growth capital for Oil Sands Operations in 2014 is focused on advancing debottlenecking projects and progressing expansions and early stage initiatives. The company anticipates a sanction decision in the second half of 2014 for the MacKay River expansion project, which is targeted to have an initial design capacity of approximately 20,000 bbls/d with first oil expected in 2017. Certain synergies of key processes and utility systems with the existing MacKay River facility are expected. The company also expects to substantially complete the Mackay River facility debottleneck in 2014, which is intended to increase production capacity by approximately 20% for a total capacity of 38,000 bbls/d by the end of 2015. In addition, Suncor plans to focus on validating all other early stage initiatives which involve debottlenecks of logistics infrastructure and Firebag facilities, collectively expected to grow production from existing sites at Oil Sands Operations to approximately 500,000 bbls/d by the end of 2018.

In support of the company's production growth, Suncor continued to expand its storage and logistics network in 2013, including the addition of storage capacity in the Athabasca region and in Hardisty, Alberta.

The company also continues to progress development drilling programs at both Firebag and MacKay River and infill drilling at Firebag, an area of focus in 2014 in support of steady production growth and sustainment.

Oil Sands Operations continues to focus on safe, reliable operations that achieve steady production growth while reducing operating costs. The company's operational excellence initiatives continue to focus on improving facility utilization and workforce productivity. Projects such as the turnaround of Upgrader 1 in the second quarter of 2013 are expected to contribute to further reliability improvements.

Suncor continues to evaluate growth prospects at MacKay River, Meadow Creek, Firebag and Lewis. Furthermore, Suncor's portfolio of technology projects is expected to not only drive improvements and efficiencies in current production, but aid in developing these future opportunities. This portfolio focuses on both subsurface and surface challenges, such as reducing steam-to-oil ratios and improving operational efficiency, as well as replication

SUNCOR ENERGY INC. ANNUAL REPORT 2013    29


strategies to obtain economies of scale for properties with similar geological characteristics.

Suncor continues to work closely with project co-owners on evaluating and progressing growth projects, including the Fort Hills and Joslyn North mining projects, respectively.

The Fort Hills mining project received sanction in the fourth quarter of 2013. As operator of the project, Suncor plans to develop the mine using traditional open-pit truck and shovel techniques, and solvent-based extraction technology that will allow the mine to produce a final marketable bitumen product. The project is expected to provide Suncor with approximately 73,000 bbls/d of bitumen, with first oil expected in the fourth quarter of 2017. Project activities in 2014 are expected to focus on detailed engineering, procurement and the ramp up of field construction activities.

Earlier in the year, Suncor announced that the company was not proceeding with the Voyageur upgrader project. The decision was a result of a strategic and economic review in response to changes in market conditions that challenged the economics of the project. As part of the decision, Suncor acquired Total E&P Canada Ltd's (Total E&P) interest in the Voyageur Upgrader Limited Partnership (VULP) to gain full control over the partnerships assets, which are used to provide added logistics flexibility and storage capacity for the company's growing Oil Sands Operations.

Suncor and the co-owners of the Joslyn mining project continue to evaluate the project and plan to provide an update on the targeted timing of a sanction decision when available.

Financial Highlights

Year ended December 31 ($ millions)   2013   2012   2011    
Gross revenues   13 089   11 502   12 003    
Less: Royalties   (859 ) (684 ) (799 )  
Operating revenues, net of royalties   12 230   10 818   11 204    
Net earnings   2 040   468   2 603    
Operating earnings(1)                
  Oil Sands Operations   1 870   1 807   2 425    
  Oil Sands Ventures   228   218   312    
    2 098   2 025   2 737    
Cash flow from operations(1)   4 556   4 407   4 572    
(1)
Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

Oil Sands segment net earnings for 2013 were $2.040 billion, compared to $468 million in 2012. Net earnings in 2013 included a net after-tax charge of $58 million as a result of not proceeding with the Voyageur upgrader project. Net earnings in 2012 included an after-tax impairment charge of $1.487 billion against the Voyageur upgrader project and a deferred tax adjustment of $70 million related to an income tax rate change.

Oil Sands Operations contributed $1.870 billion to operating earnings, while Oil Sands Ventures contributed $228 million. Operating earnings for Oil Sands Operations increased compared to the prior year due primarily to higher production volumes and higher price realizations, partially offset by higher royalty, operating and DD&A expenses. Operating earnings for Oil Sands Ventures increased from 2012, due primarily to higher price realizations, partially offset by lower production volumes and higher DD&A expense.

Cash flow from operations for the Oil Sands segment was $4.556 billion in 2013, compared to $4.407 billion in 2012. The increase was primarily due to higher production volumes and higher price realizations, partially offset by higher royalty and operating expenses.

30   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)   2013   2012   2011  
Net earnings as reported   2 040   468   2 603  
Net impact of not proceeding with the Voyageur upgrader project   58   —   —  
Impairments and write-offs   —   1 487   35  
Impact of income tax rate adjustments on deferred income taxes   —   70   —  
Loss on significant disposals   —   —   99  
Operating earnings(1)   2 098   2 025   2 737  
(1)
Non-GAAP financial measure. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

GRAPHIC

(1)
For an explanation of the construction of this bridge analysis, see the Advisories – Non-GAAP Financial Measures section of this MD&A.

Production Volumes(1)

Year ended December 31
(mbbls/d)		   2013   2012   2011  
Upgraded product (SCO)   282.6   276.7   279.7  
Non-upgraded bitumen   77.9   48.1   25.0  
Oil Sands Operations   360.5   324.8   304.7  
Oil Sands Ventures – Syncrude   32.0   34.4   34.6  
Total   392.5   359.2   339.3  
(1)
Bitumen from Oil Sands Base operations is upgraded, while bitumen from In Situ operations is upgraded or sold directly to customers. Yields of SCO from Suncor's upgrading processes are approximately 79% of bitumen feedstock input.

The Oil Sands segment achieved a third consecutive year of record production with an average of 392,500 bbls/d in 2013, increasing from 359,200 bbls/d in 2012.

The increase in Oil Sands Operations was primarily due to the ramp up of production at Firebag and the hot bitumen assets commissioned in the third quarter of 2013. These assets are comprised of an insulated pipeline from Firebag to Suncor's Athabasca terminal, bitumen cooling and blending facilities, and capacity to import third-party diluents. Record production was achieved despite a number of third-party outages in the year that contributed to lost annual production of 16,000 bbls/d, as well as major maintenance, including a seven-week turnaround of Upgrader 1 in the second quarter of 2013 and planned maintenance of the Upgrader 2 vacuum tower and related units in the third and fourth quarters of 2013.

The increase in bitumen production was complemented by strong upgrading reliability in 2013. Production of upgraded product was the highest on record and averaged

SUNCOR ENERGY INC. ANNUAL REPORT 2013    31


282,600 bbls/d in 2013, compared to 276,700 bbls/d in 2012. Record SCO production was achieved despite planned maintenance and a number of third-party outages.

The third-party outages consisted of a shutdown of a cogeneration facility, which resulted in limited steam availability and required a three-day shutdown of Upgrader 2 in early May and constrained production until early June. Shortly thereafter, a precautionary shutdown of third-party pipelines in response to flooding in northern Alberta required the company to scale back production in the latter part of June and into mid-July. Further, a third-party natural gas outage in the Fort McMurray region in October impacted Suncor's steam generation and upgrading capabilities. Natural gas supply continued to be curtailed intermittently for the remainder of the year, impacting the company's steam generation capabilities. Intermittent curtailments of natural gas supply are expected to continue through the first quarter of 2014 while the third-party operator completes its investigations and restoration activities.

Production of upgraded product in 2012 was impacted by planned maintenance on various coker units and hydrotreating units in Upgrader 1 and 2, as well as unplanned maintenance relating to primary and secondary upgrading at Upgrader 2.

Non-upgraded bitumen production increased to an average of 77,900 bbls/d in 2013, compared to 48,100 bbls/d in 2012, primarily as a result of the ramp up of Firebag and the hot bitumen infrastructure.

Bitumen from Operations

Year ended December 31   2013   2012   2011  
Oil Sands Base              
  Bitumen Production (mbbls/d)   269.8   266.2   287.1  
  Bitumen ore mined (thousands of tonnes per day)   413.6   412.3   441.1  
  Bitumen ore grade quality (bbls/tonne)   0.65   0.65   0.65  
In Situ bitumen production (mbbls/d)      
  Firebag   143.4   104.0   59.5  
  MacKay River   28.5   27.0   30.0  
  Total In Situ production   171.9   131.0   89.5  
In Situ steam-to-oil ratio              
  Firebag   3.3   3.4   3.6  
  MacKay River   2.6   2.4   2.2  

Bitumen production from Oil Sands Base operations increased to an average of 269,800 bbls/d in 2013, compared to 266,200 bbls/d in 2012, primarily due to strong bitumen production in the latter half of the year. The commissioning of the hot bitumen infrastructure increased the takeaway capacity of bitumen and unlocked production in mining. However, planned maintenance required the company to scale back mine production particularly in the second quarter of 2013 to coincide with limited upgrader availability during the Upgrader 1 turnaround. In 2012, mining activity was also constrained by low upgrader availability and lower ore grade quality of the Millennium mining area.

Bitumen from In Situ operations averaged 171,900 bbls/d in 2013, increasing from 131,000 bbls/d in 2012 due primarily to the ramp up of Firebag production. By the fourth quarter of 2013, production from the Firebag complex had fully ramped up, with daily production rates reaching approximately 95% of capacity during periods that were not impacted by the third-party natural gas outage and curtailment. Production was reduced in the year due to planned maintenance of a central processing facility and a third-party cogeneration outage in the second quarter of 2013. Production from MacKay River averaged 28,500 bbls/d in 2013, compared to 27,000 bbls/d in 2012, and increased primarily due to the commissioning of replacement well pads in 2013 and increased planned maintenance in the prior year, partially offset by the impact of third-party outages in 2013.

Suncor's share of Syncrude production and sales averaged 32,000 bbls/d in 2013, compared to 34,400 bbls/d in 2012. Production in 2013 was impacted by longer than planned shutdowns of one of three cokers, the LC Finer and secondary upgrading units, resulting in the acceleration of planned maintenance for the coker as well as the LC Finer. In addition, unplanned maintenance in upgrading was greater in 2013 compared to 2012.

Sales Volumes and Mix

Year ended December 31   2013   2012   2011  
Oil Sands sales volumes (mbbls/d)      
  Sweet SCO   91.5   93.8   85.5  
  Diesel   23.5   24.5   24.3  
  Sour SCO   166.0   161.1   170.6  
Upgraded Product (SCO)   281.0   279.4   280.4  
Non-upgraded bitumen   76.0   44.5   24.0  
    357.0   323.9   304.4  

Sales volumes for Oil Sands Operations increased to 357,000 bbls/d in 2013, compared to 323,900 bbls/d in 2012.

Sales volumes of sweet SCO and diesel decreased slightly compared to 2012. SCO sales mix was impacted by planned maintenance of the Upgrader 1 hydrogen plant and hydrotreating units in the second quarter of 2013 and unplanned maintenance of a diesel hydrotreater in the first quarter of 2013.

32   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Sales volumes of non-upgraded bitumen increased in 2013, compared to 2012, mainly due to higher production at Firebag and the increased takeaway capacity for non-upgraded bitumen.

Inventory

The Inventory variance factor decreased operating earnings primarily due to an increase in the company's average inventory levels in 2013, as a result of new infrastructure added to the company's storage and logistics network to support the growth in production.

Price Realizations

Year ended December 31
Net of transportation costs, but before royalties ($/bbl)		   2013   2012   2011    
Oil Sands                
  Sweet SCO and diesel   104.22   96.95   103.95    
  Sour SCO and non-upgraded bitumen   72.67   72.93   80.17    
  Crude sales basket (all products)   82.83   81.69   88.74    
  Crude sales basket, relative to WTI   (18.09 ) (12.44 ) (5.35 )  
Oil Sands Ventures                
  Syncrude – Sweet SCO   99.82   92.69   101.80    
  Syncrude, relative to WTI   (1.10 ) (1.50 ) 7.71    

Sweet SCO and diesel price realizations for Oil Sands Operations increased to $104.22/bbl in 2013 from $96.95/bbl in 2012, primarily due to an increase in the WTI benchmark and the impact of a weaker Canadian dollar. Sour SCO and bitumen prices increased marginally as the weaker Canadian dollar more than offset the wider WCS to WTI differential. These increases more than offset the impacts of a higher proportion of bitumen sales and resulted in average price realizations for Oil Sands Operations of $82.83/bbl in 2013, compared to $81.69/bbl in 2012.

Suncor's average price realization for Syncrude sales in 2013 was $99.82/bbl, compared to $92.69/bbl in 2012, due to an increase in WTI and the impact of the weaker Canadian dollar in 2013.

Royalties

Royalties were higher in 2013 relative to 2012, primarily due to higher production and slightly higher benchmark prices for WCS that influenced the company's regulated bitumen valuation methodology used to determine royalties. In December 2013, Suncor reached an agreement with the Government of Alberta concerning several outstanding issues under the Royalty Amending Agreements (RAA) entered into in 2008. The impacts of the final settlements were not material to the company's results.

Expenses and Other Factors

Operating expenses for 2013 were higher relative to 2012. Factors contributing to the change in operating expenses included:

•
An increase in cash operating costs for Oil Sands Operations. See the Cash Operating Costs Reconciliation for further details.

•
Non-production costs were lower in 2013 compared to 2012, due primarily to lower share-based compensation expense and lower costs related to remobilizing certain growth projects.

•
Operating expenses at Syncrude were higher for 2013 than 2012, as a result of higher natural gas prices and higher maintenance expenditures.

Transportation expense increased in 2013 relative to 2012 primarily due to increased bitumen production and sales, including incremental costs associated with higher diluent imports.

DD&A expense for 2013 was higher than 2012, due mainly to a larger asset base as a result of assets commissioned in 2013, including Firebag Stage 4 well pads, the hot bitumen infrastructure, the Upgrader 1 turnaround completed in the second quarter of 2013, and other assets commissioned in the latter part of 2012, including Firebag Stage 4 facilities and the Millennium Naptha Unit. The company also derecognized certain assets relating to projects no longer being considered for advancement.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    33

Cash Operating Costs Reconciliation(1)(2)

Year ended December 31   2013   2012   2011    
Operating, selling and general expense (OS&G)   5 837   5 365   5 169    
  Syncrude OS&G   (536 ) (513 ) (529 )  
  Non-production costs(3)   (267 ) (328 ) (275 )  
  Other(4)   (165 ) (129 ) (10 )  
Oil Sands cash operating costs ($ millions)   4 869   4 395   4 355    
Oil Sands cash operating costs ($/bbl)   37.00   37.05   39.05    
(1)
Cash operating costs and cash operating costs per barrel are non-GAAP financial measures. See the Advisories – Non-GAAP Financial Measures section of this document.

(2)
Effective as of the first quarter of 2012, the calculation of cash operating costs was revised to better reflect the ongoing cash costs of production, and 2011 figures were redetermined accordingly. See the Advisories – Non-GAAP Financial Measures section of this document.

(3)
Significant non-production costs include, but are not limited to, share-based compensation adjustments, costs related to the remobilization or deferral of growth projects, research, the expense recorded as part of a non-monetary arrangement involving a third-party processor and feedstock costs for natural gas used to create hydrogen for secondary upgrading processes.

(4)
Other includes the impacts of changes in inventory valuation and operating revenues associated with excess power from cogeneration units.

Oil Sands cash operating costs per barrel averaged $37.00/bbl, compared to $37.05/bbl in 2012 due to higher production volumes offset by higher total cash operating costs. Total cash operating costs were higher in 2013 due to incremental costs associated with larger operations, including Firebag Stage 4, incremental costs associated with increased production in mining, higher maintenance costs, higher natural gas prices and consumption, partially offset by an increase in the net benefit of power sales due to higher power prices and volumes. The increase in maintenance costs included an acceleration of maintenance programs in 2013 designed to facilitate and ensure reliable and efficient mining operations. The impact on production volumes of the third-party outages resulted in an increase to cash costs per barrel of $1.60/bbl in 2013.

Voyageur Upgrader Project

Given the challenging economic outlook for the Voyageur upgrader project, the company performed an impairment test in the fourth quarter of 2012. Based on an assessment of expected future net cash flows, the company recorded an after-tax impairment charge of $1.487 billion.

In the first quarter of 2013, Suncor announced that the company was not proceeding with the Voyageur upgrader project. The decision was a result of a change in market conditions that challenged the economics of the project. Suncor acquired Total E&P's interest in VULP for $515 million to gain full control over the partnership assets, which are currently being used to provide added logistics flexibility and storage capacity for the company's growing Oil Sands operations.

As a result, Suncor recorded an after-tax charge to net earnings of $58 million in 2013 representing the expected costs of not proceeding with the project, including costs related to decommissioning and restoration of the Voyageur site and contract cancellations.

Planned Maintenance

There are no major turnarounds planned for 2014. The company plans to complete routine maintenance on three coker units, in addition to seasonal maintenance throughout 2014. The impact of this maintenance has been reflected in the company's 2014 guidance.

34   SUNCOR ENERGY INC. ANNUAL REPORT 2013

EXPLORATION AND PRODUCTION

2013 Highlights

•
The Exploration and Production segment continued to generate significant cash flow for Suncor. Under its current portfolio of assets, the segment is realizing Brent-based pricing for almost all of its production, compared to approximately 70% in 2012.

•
In 2013, Suncor completed the sale of the remaining portion of its conventional natural gas business for $1 billion, before closing adjustments and other closing costs, which represented a major milestone in the repositioning of the Exploration and Production portfolio.

•
Suncor successfully completed a ten-week off-station maintenance event at Terra Nova, which included preventive maintenance that is expected to contribute to improved reliability in 2014.

•
The company's Libyan operations were impacted by political unrest, which limited production and liftings in 2013. Suncor continued to progress its exploration program and continued field activities throughout 2013.

•
Operations in Syria remained suspended throughout 2013 as a result of continued political unrest and international sanctions against that country.

•
Growth projects progressed well in 2013, including major milestones reached for the Golden Eagle project such as the installation of both jackets and the wellhead topside, as well as the installation of the subsea infrastructure. Following the sanction decision for the Hebron project in 2012, construction of the gravity-based structure and topsides began in 2013.

Strategy and Investment Update

With a suite of high-return development projects, Suncor has earmarked almost half of its total growth capital towards advancing projects within the Exploration and Production segment. Building on the major milestones reached in 2013, growth capital targeted towards the Golden Eagle project is expected to take the project to first oil by late 2014 or early 2015. Drilling operations are expected to commence in early 2014. The Hebron project remains on target for first oil in 2017; detailed engineering and construction of the gravity-based structure and topsides will continue in 2014.

The company has multiple field extension projects underway which leverage existing facilities and infrastructure. Following the completion of subsea installation for the HSEU in 2013, drilling activities began in early 2014. The project is expected to increase overall production and extend the productive life of the Hibernia field starting in 2015. The subsea installation for the South White Rose Extension (SWRX) project commenced in 2013 and first oil is expected in late 2014 or early 2015. A sanction decision for further expansion into the western portion of the White Rose field is targeted for 2014.

The company continues to evaluate offshore exploration prospects in the U.K. North Sea, Norway, and East Coast Canada basins. The company's exploration strategy is primarily concentrated on reviewing and evaluating concentric growth opportunities around existing infrastructure. The company continues to increase its presence in Norway with a current portfolio of 19 licences, where Suncor is operator for eight of these licences. Significant discoveries currently under appraisal include the Beta project where Suncor is the operator and the Butch project where Suncor is a non-operator. Appraisal wells for both projects are planned for 2014.

In 2013, Suncor received extensions on exploration commitments under its EPSAs in Libya to reflect the period that the contracts were suspended due to force majeure. In early 2014, an additional one-year extension to April 2015 was approved by the NOC, with formal extension agreements to follow later in 2014. The terms of the EPSAs allow for further extensions to be negotiated.

Following the disposition of the remaining portion of the company's conventional natural gas business in 2013, properties in the North America Onshore business include high-quality unconventional oil and natural gas properties in central Alberta and northeast B.C.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    35

Financial Highlights

Year ended December 31 ($ millions)   2013   2012   2011    
Gross revenues   6 363   6 476   6 784    
Less: Royalties   (1 146 ) (1 631 ) (1 472 )  
Operating revenues, net of royalties   5 217   4 845   5 312    
Net earnings   1 000   138   306    
Operating earnings(1)                
  East Coast Canada   563   422   694    
  International   567   538   708    
  North America Onshore   80   (110 ) (44 )  
    1 210   850   1 358    
Cash flow from operations(1)   2 316   2 227   2 846    
(1)
Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

Exploration and Production net earnings for 2013 were $1.000 billion, compared to $138 million for 2012. Net earnings for 2013 included after-tax impairment charges of $563 million against assets in Syria, Libya and North America Onshore, partially offset by the recognition of after-tax risk mitigation proceeds of $223 million related to the company's assets in Syria. Net earnings for 2013 were positively impacted by an after-tax gain on sale of $130 million related to the disposition of the company's conventional natural gas business. Net earnings for 2012 included after-tax impairments (net of reversals) of $517 million for assets in Syria, after-tax charges of $172 million, including impairments against assets in North America Onshore and East Coast Canada, and a provision in North America Onshore for estimated future commitments relating to unutilized pipeline capacity.

Operating earnings in 2013 for East Coast Canada were $563 million, compared to $422 million for 2012, and were higher primarily due to larger planned off-station maintenance programs in the prior year. Operating earnings for International were $567 million for 2013, compared to $538 million for 2012, and were higher primarily due to increased production in the U.K., partially offset by lower production volumes in Libya. Operating earnings for North America Onshore were $80 million for 2013, compared with an operating loss of $110 million for 2012, primarily due to the cessation of DD&A on properties that were classified as held for sale since February 2013 and subsequently sold in September 2013, partially offset by lower production volumes.

Cash flow from operations was $2.316 billion in 2013, compared to $2.227 billion in 2012, and increased primarily due to higher production volumes at East Coast Canada, partially offset by lower production in Libya and incremental current income tax expense relating to the company's Canadian operations in 2013.

36   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)   2013   2012   2011  
Net earnings as reported   1 000   138   306  
Impairments (net of reversals) and provisions   563   689   571  
Recognition of risk mitigation proceeds   (223 ) —   —  
(Gain) loss on significant disposals   (130 ) —   8  
Impact of income tax rate adjustments on deferred income taxes   —   23   442  
Adjustments to provisions for assets acquired through the merger   —   —   31  
Operating earnings(1)   1 210   850   1 358  
(1)
Non-GAAP financial measure. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

GRAPHIC

(1)
For an explanation of the construction of this bridge analysis, see the Advisories – Non-GAAP Financial Measures section of this MD&A.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    37

Production Volumes

Year ended December 31   2013   2012   2011  
Production volumes (mboe/d)   169.9   189.9   206.7  
  East Coast Canada (mbbls/d)   56.2   46.5   65.6  
  International (mboe/d)   76.4   89.5   76.4  
  North America Onshore (mmcfe/d)   224   323   388  
Production Mix (liquids/gas) (%)   80/20   74/26   64/36  
  East Coast Canada   100/0   100/0   100/0  
  International   98/2   99/1   82/18  
  North America Onshore   14/86   10/90   8/92  

East Coast Canada production averaged 56,200 bbls/d in 2013, compared to 46,500 bbls/d in 2012.

•
Production from Terra Nova averaged 14,200 bbls/d in 2013, compared to 8,800 bbls/d in 2012. In 2013, Suncor completed a ten-week off-station maintenance program to repair a mooring chain, perform preventive maintenance on the remaining eight chains and complete routine planned maintenance. In 2012, production was shut-in for 27 weeks for the dockside maintenance program to replace the floating production storage and offloading (FPSO) platform water injection swivel and perform work on subsea infrastructure to help mitigate hydrogen sulphide issues.

•
Production from Hibernia averaged 27,100 bbls/d in 2013, compared to 26,100 bbls/d in 2012. Production increased over the prior year due in part to a four-week shut-in for planned maintenance in 2012. Natural declines from older wells were partially offset by production increases from ongoing development drilling.

•
Production from White Rose averaged 14,900 bbls/d in 2013, compared to 11,600 bbls/d in 2012. Production increased over the prior year as production in 2012 was shut-in for 15 weeks for an off-station maintenance program to repair the FPSO propulsion system, in addition to other routine planned maintenance activities.

International production averaged 76,400 boe/d in 2013, compared to 89,500 boe/d in 2012.

•
Production from Buzzard averaged 55,800 boe/d in 2013, compared to 48,000 boe/d in 2012. Production increased due to higher maintenance activity in 2012, and improved reliability and reservoir performance in 2013.

•
Production from Libya averaged 20,600 bbls/d in 2013, compared to 41,500 bbls/d in 2012. Production was shut-in for the latter half of 2013 due to political unrest that resulted in the closure of export terminal operations at eastern Libyan seaports. Production was also impacted by a temporary shut-in at one field throughout the second quarter of 2013 to facilitate the establishment of field security.

North America Onshore production averaged 224 mmcfe/d in 2013, compared to 323 mmcfe/d in 2012, and decreased primarily due to the sale of the conventional natural gas business.

Sale of Natural Gas Business

On April 15, 2013, Suncor announced it had reached an agreement to sell its conventional natural gas business in Western Canada, with an effective date of January 1, 2013. The transaction closed on September 26, 2013 for proceeds of $1 billion, before closing adjustments and other closing costs, resulting in an after-tax gain on sale of $130 million. Suncor's unconventional oil and natural gas properties in central Alberta and northeast B.C. were excluded from the sale.

Price Realizations

Year ended December 31
Net of transportation costs, but before royalties		   2013   2012   2011  
Exploration and Production ($/boe)   91.44   84.05   79.95  
  East Coast Canada ($/bbl)   112.39   112.15   108.42  
  International ($/boe)   107.57   108.22   100.89  
  North America Onshore ($/mcfe)   4.74   3.28   4.39  

Average price realizations for crude oil from East Coast Canada and International were consistent with 2012 due to the positive impact of the weaker Canadian dollar being offset by lower benchmark prices for Brent crude.

Average price realizations for North America Onshore were higher due primarily to higher benchmark prices for natural gas and a higher proportion of crude oil and natural gas liquids sales.

38   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Royalties

Royalties were lower in 2013, compared with 2012, due primarily to lower production from Libya and North America Onshore, and lower royalty rates at East Coast Canada due to higher deductible costs related to planned maintenance activities in both 2013 and 2012, partially offset by higher production in East Coast Canada.

Expenses and Other Factors

Operating expenses were lower in 2013 than in 2012 due primarily to lower production volumes in North America Onshore, partially offset by an after-tax expense of $14 million at East Coast Canada associated with the mooring chain repair at Terra Nova, and higher production volumes. The prior year also included an after-tax impact of $14 million, net of insurance proceeds, associated with a fire at an exploratory natural gas well in B.C.

DD&A and exploration expenses were lower in 2013 due to the cessation of DD&A on natural gas properties that were classified as held for sale since February 2013 and subsequently sold in September 2013, partially offset by higher production volumes at East Coast Canada. Exploration expenses were lower in 2013, as the company expensed $82 million in exploration activities ($46 million after-tax) primarily related to wells in the U.K. and Libya, compared to $145 million in exploration expenditures ($42 million after-tax) in 2012, primarily associated with a second appraisal well for the Beta discovery and an exploration well for the Cooper prospect.

Financing expense and other income increased in 2013 relative to 2012, primarily due to foreign exchange gains in International and lower accretion on the decommissioning and restoration provision in North America Onshore following the sale of the company's conventional natural gas business.

Impairments and Adjustments to Related Provisions

Syria

Since December 2011, Suncor's operations in Syria and its contractual obligations have been suspended under a period of force majeure due to political unrest and international sanctions. As there has been no resolution of the political situation and rising uncertainty with respect to the company's return to operations in the country, Suncor impaired the remaining carrying value of its Syrian's assets resulting in an after-tax impairment charge of $422 million in the fourth quarter of 2013. The carrying value had previously been impaired in the second quarter of 2012 and a portion subsequently reversed in the fourth quarter of 2012, for after-tax impairments (net of reversals) of $517 million in 2012.

The company received risk mitigation proceeds in the fourth quarter of 2012, at which time the proceeds were recorded as a non-current provision to reflect potential repayment if operations in Syria were to resume. Suncor recognized the risk mitigation proceeds of $300 million ($223 million after-tax) in net earnings in the fourth quarter of 2013, as the likelihood of return in the foreseeable future is undeterminable.

Libya

Recent political unrest resulted in the closure of export terminal operations at eastern Libyan seaports, requiring the shut-in of production for the latter half of 2013. As the situation persisted at the end of 2013, an impairment test was performed based on an assessment of future net cash flows over a range of possible outcomes. Based on this assessment, the company recorded an after-tax impairment charge of $101 million in the fourth quarter of 2013.

The carrying value of the company's net assets in Libya as at December 31, 2013 was approximately $570 million.

Other

During the fourth quarter of 2013, the company recognized an after-tax impairment charge of $40 million relating to its properties in North America Onshore based on an assessment of future net cash flows incorporating recent drilling activity, updated reserves data, cost assumptions and price forecasts.

In 2012, the company recorded after-tax impairment charges of $172 million, including impairments against assets in North America Onshore and East Coast Canada, and a provision in North America Onshore for estimated future commitments relating to unutilized pipeline capacity.

Planned Maintenance

Routine annual planned maintenance has been scheduled for Terra Nova and White Rose in the third quarter of 2014, and for Buzzard in the second and third quarters of 2014. The impact of this maintenance has been reflected in the company's 2014 guidance.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    39

REFINING AND MARKETING

2013 Highlights

•
The refining and marketing segment continued to deliver value by generating more than $2 billion in operating earnings for the second consecutive year, through integration and strong reliability in 2013.

•
With 460,000 bbls/d of crude processing capacity in 2013, the refining operations sheltered the company from the volatility in crude differentials by optimizing the profit realized on the majority of Suncor's upstream production.

•
Building on the nameplate capacity increases at the Edmonton, Sarnia and Commerce City refineries in 2012 and 2013, the company again increased the nameplate capacity of the Edmonton refinery as a result of continuous reliability improvements to 142,000 bbls/d as at January 1, 2014.

•
Overall refinery utilization reached 94%, while planned maintenance activities were completed at each refinery in 2013.

•
Suncor continued to maximize value by sourcing approximately 70% of its refining feedstock from inland crude sources, compared to higher cost coastal crudes.

•
The company completed a rail offloading facility located adjacent to the Montreal refinery and entered into firm commitments for rail cars and terminalling services to increase inland crude supply to the Montreal refinery.

Strategy and Investment Update

Suncor continues to invest in profitable growth and optimize overall integration, including market access initiatives to supply the Montreal refinery with discounted North American crudes. Rail transportation to Quebec commenced in the fourth quarter of 2013 and is expected to increase to approximately 35,000 bbls/d of inland crude by the first quarter of 2014. Suncor has also started a project to modify the hydrocracking unit at the Montreal refinery, which is expected to improve energy efficiency and product yield, by 2015, and contribute to the company's integration strategies. Suncor continues to evaluate further investment opportunities to increase the heavy crude processing capability at the Montreal refinery, in addition to actively monitoring the regulatory process for future pipeline access.

Suncor's Petro-Canada branded outlets continue to be a leading retailer by market share in major urban areas of Canada. Increased competition and softening demand in key retail markets are expected to be offset by growth in wholesale channels. Refining and Marketing will continue to leverage the strong brand to increase non-petroleum revenues through the company's network of convenience stores and car washes, and expand the lubricants product offering, including global expansion in the U.S., Europe and China.

Financial Highlights

Year ended December 31 ($ millions)   2013   2012   2011  
Operating revenues   26 658   26 220   25 713  
Net earnings   2 022   2 137   1 726  
Operating earnings(1)              
  Refining and Product Supply   1 758   1 877   1 413  
  Marketing   264   275   313  
    2 022   2 152   1 726  
Cash flow from operations(1)   2 618   3 138   2 574  
(1)
Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

40   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Refining and Marketing recorded net and operating earnings of $2.022 billion in 2013, compared to net earnings of $2.137 billion and operating earnings of $2.152 billion in 2012.

Refining and Supply operations contributed $1.758 billion to operating earnings in 2013, a decrease compared with 2012, primarily due to lower crack spreads, higher operating expenses and higher DD&A, partially offset by the impact of FIFO inventory accounting relative to an estimated LIFO basis of accounting, which had a positive impact to net earnings of approximately $79 million after-tax, compared to a negative impact of approximately $153 million after-tax in 2012. Marketing operations contributed $264 million to operating earnings in 2013, compared to $275 million in 2012, primarily due to higher operating expenses, partially offset by higher margins for lubricants and the retail channel.

Cash flow from operations was $2.618 billion in 2013, compared to $3.138 billion in 2012, and decreased primarily due to incremental current income tax expense relating to the company's Canadian operations recorded in 2013, in addition to the majority of the factors that impacted operating earnings.

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)   2013   2012   2011  
Net earnings as reported   2 022   2 137   1 726  
Impact of income tax rate adjustments on deferred income taxes   —   15   —  
Operating earnings(1)   2 022   2 152   1 726  
(1)
Non-GAAP financial measure. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

GRAPHIC

(1)
For an explanation of the construction of this bridge analysis, see the Advisories – Non-GAAP Financial Measures section of this MD&A.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    41

Volumes

Year ended December 31   2013   2012   2011  
Crude oil processed (mbbls/d)      
  Eastern North America   201.7   197.7   201.3  
  Western North America   229.6   233.7   206.4  
Total   431.3   431.4   407.7  
Refinery utilization(1)(2) (%)      
  Eastern North America   91   89   94  
  Western North America   96   100   91  
Total   94   95   92  
Refined Product Sales (mbbls/d)      
  Gasoline   247.4   252.8   249.5  
  Distillate   209.8   195.0   190.7  
  Other   85.7   90.7   82.5  
    542.9   538.5   522.7  
(1)
Effective January 1, 2013, the company increased the nameplate capacity of the Edmonton refinery from 135,000 bbls/d to 140,000 bbls/d. Effective January 1, 2012, the company increased the nameplate capacity of the Montreal refinery from 130,000 bbls/d to 137,000 bbls/d and the nameplate capacity of the Commerce City refinery from 93,000 bbls/d to 98,000 bbls/d. Prior years' utilization rates have not been recalculated and reflect the lower nameplate capacities.

(2)
Refinery utilization is the amount of crude oil run through crude distillation units, expressed as a percentage of the capacity of these units.

Refinery utilization in Eastern North America averaged 91% in 2013, compared to 89% in 2012. Refinery utilization increased over the prior year due to significantly less unplanned maintenance in 2013, partially offset by planned maintenance at the Sarnia and Montreal refineries. Refinery utilization in 2012 was impacted by an unplanned outage of a crude unit at the Sarnia refinery, a reduction in feedstock availability in the second quarter due to an unplanned Oil Sands upgrader outage and a scheduled maintenance event at the Sarnia refinery in the fourth quarter of 2012.

Refinery utilization in Western North America averaged 96% in 2013, compared to 100% in 2012. The decrease from the prior year is primarily due to more maintenance activities occurring in 2013, including a four-week planned maintenance event at the Edmonton refinery of the heavy sour crude train and unplanned maintenance in the second and fourth quarters of 2013, partially offset by higher utilization at the Commerce City refinery due to stronger overall reliability in 2013. Despite this unplanned maintenance, overall demonstrated reliability improvements resulted in an increase to the nameplate capacity of the Edmonton refinery to 142,000 bbls/d from 140,000 bbls/d effective January 1, 2014.

Total sales of refined petroleum products increased to an average of 542,900 bbls/d in 2013, compared to 538,500 bbls/d in 2012. Distillate sales increased from the prior year due to higher production and increasing diesel sales through Suncor's retail and supply sales channels. Gasoline sales decreased from the prior year due to economic conditions and competitive pressures primarily in Eastern North America.

Prices and Margins

For Refining and Product Supply, prices and margins for refined products were lower in 2013 compared to 2012.

•
The narrowing differential between Brent and WTI throughout 2013 relative to the prior year contributed to a decline in benchmark crack spreads across all regions in which the company sells refined products compared to the prior year.

•
Average inland crude differentials to WTI were relatively consistent year-over-year for SCO. However, the wider light/heavy crude oil differential positively impacted earnings for the inland refineries.

•
In 2013, the impact of FIFO inventory accounting, as used by the company, relative to an estimated LIFO basis of accounting had a positive impact to net earnings of approximately $79 million after-tax, compared to a negative impact of approximately $153 million after-tax in 2012.

Marketing margins increased primarily due to higher margins for lubricants and the retail channels.

Expenses and Other Factors

Operating expenses were higher in 2013 than in 2012, due to higher energy costs and consumption, higher transportation costs associated with increased asphalt volumes and overall delivery rates, and higher repairs and maintenance expense, partially offset by lower share-based compensation expense.

42   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Planned Maintenance

The company has scheduled a planned maintenance event at the Commerce City refinery in the first quarter of 2014 with an expected duration of three weeks. The Montreal refinery has a five-week planned maintenance event in the second quarter of 2014 as well as an eight-week planned maintenance event beginning late in the third quarter of 2014. The Edmonton refinery has a seven-week planned maintenance event in the second quarter of 2014 as well as a four-week planned maintenance event in the third quarter of 2014.

The impact of this maintenance has been reflected in the company's 2014 guidance.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    43

CORPORATE, ENERGY TRADING AND ELIMINATIONS

2013 Highlights

•
The Energy Trading business continued to expand Suncor's logistics network by securing market access into Canadian and U.S. Coastal markets, positioning the company to capture global prices on both its current production and future growth.

•
In addition to the rail projects supporting the Refining and Marketing segment, the company increased its heavy crude capacity to the U.S. Gulf Coast through the Gulf Coast Pipeline, which began shipments in early 2014. Suncor also has positions on a number of major proposed pipeline projects, subject to various approvals and conditions.

•
The company continued to progress the Adelaide and Cedar Point wind projects. The Adelaide project received regulatory approval in December 2013.

Strategy and Investment Update

The Energy Trading business supports the company's production by securing market access, optimizing price realizations, managing inventory levels during unplanned outages at Suncor's facilities and managing the impacts of external market factors, such as pipeline disruptions or outages at refining customers, while generating trading earnings through established strategies.

The company expects to complete the Adelaide wind project by the fourth quarter of 2014. The Cedar Point project continues to progress through the regulatory process. The two projects, based in Ontario, are expected to add 140 MW of gross installed capacity, increasing the gross installed capacity of Suncor's wind projects by 55%. The focus for the ethanol operations will be to maintain safe and reliable operations and improve plant profitability through technology improvements.

Financial Highlights

Year ended December 31 ($ millions)   2013   2012   2011    
Net loss   (1 151 ) (3 ) (331 )  
Operating (loss) earnings(1)                
  Renewable Energy   72   57   72    
  Energy Trading   116   147   149    
  Corporate   (785 ) (468 ) (346 )  
  Group Eliminations   (33 ) 84   (22 )  
    (630 ) (180 ) (147 )  
Cash flow used in operations(1)   (78 ) (39 ) (246 )  
(1)
Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

Net loss for Corporate, Energy Trading and Eliminations for 2013 was $1.151 billion, compared to a net loss of $3 million for 2012. In 2013, the Canadian dollar weakened in relation to the U.S. dollar, resulting in an after-tax unrealized foreign exchange loss on U.S. dollar denominated debt of $521 million. In 2012, the Canadian dollar strengthened in relation to the U.S. dollar, resulting in an after-tax unrealized foreign exchange gain on U.S. dollar denominated debt of $157 million. Net earnings for 2012 also included a deferred tax reduction of $20 million related to an income tax rate change.

The operating loss for Corporate, Energy Trading and Eliminations in 2013 was $630 million, compared with an operating loss of $180 million in 2012. Operating earnings are discussed below.

44   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)   2013   2012   2011    
Net loss as reported   (1 151 ) (3 ) (331 )  
Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt   521   (157 ) 161    
Impact of income tax rate adjustments on deferred income taxes   —   (20 ) —    
Impairments and write-offs   —   —   23    
Operating loss(1)   (630 ) (180 ) (147 )  
(1)
Non-GAAP financial measure. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

Renewable Energy

Year ended December 31   2013   2012   2011  
Power generation marketed (gigawatt hours)   430   429   245  
Ethanol production (thousands of m3)   415   413   382  

Suncor's renewable energy assets contributed operating earnings of $72 million in 2013, compared to $57 million in 2012, and increased primarily due to stronger margins on ethanol sales driven by lower feedstock prices, and higher average power prices in 2013.

Energy Trading

Energy Trading activities contributed operating earnings of $116 million in 2013, compared to $147 million in 2012. Energy trading continued to contribute to operating earnings, primarily through its heavy crude trading strategies, which were adversely impacted by fluctuating crude differentials in the latter half of 2013.

Corporate

Corporate had an operating loss of $785 million in 2013, compared with an operating loss of $468 million in 2012. The increase in operating loss was due primarily to higher interest expense due to lower capitalized interest and increased financing expense associated with additional capital leases, higher share-based compensation expense and incremental expenditures relating to a company-wide process improvement initiative. The company capitalized $397 million of its borrowing costs in 2013 as part of the cost of major projects, compared to $587 million in the prior year, reflecting fewer major projects in 2013.

Group Eliminations

Group Eliminations reflect the elimination of profit on crude oil sales from Oil Sands and East Coast Canada to Refining and Marketing. Consolidated profits are only realized when the company sells the products produced from intersegment purchases of crude feedstock to third parties. In 2013, $33 million of after-tax intersegment profit was eliminated, compared to $84 million after-tax of previously eliminated intersegment profit that was recognized in 2012.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    45

5. FOURTH QUARTER 2013 ANALYSIS

Financial and Operational Highlights

Three months ended December 31
($ millions, except as noted)		   2013   2012    
Net earnings (loss)            
  Oil Sands   469   (1 037 )  
  Exploration and Production   (101 ) 148    
  Refining and Marketing   458   450    
  Corporate, Energy Trading and Eliminations   (383 ) (135 )  
Total   443   (574 )  
Operating earnings (loss)(1)            
  Oil Sands   400   450    
  Exploration and Production   239   143    
  Refining and Marketing   458   450    
  Corporate, Energy Trading and Eliminations   (124 ) (55 )  
Total   973   988    
Cash flow from (used in) operations(1)            
  Oil Sands   1 110   1 090    
  Exploration and Production   552   529    
  Refining and Marketing   534   634    
  Corporate, Energy Trading and Eliminations   154   (25 )  
Total   2 350   2 228    
Production volumes (mboe/d)            
  Oil Sands   446.5   378.7    
  Exploration and Production   111.6   177.8    
Total   558.1   556.5    
(1)
Non-GAAP financial measures. Operating earnings and cash flow from operations are reconciled below. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

Segment Analysis

Oil Sands

For the fourth quarter of 2013, Oil Sands segment net earnings were $469 million, compared with a net loss of $1.037 billion for the fourth quarter of 2012. Net earnings in the quarter included a favourable after-tax adjustment of $69 million relating to not proceeding with the Voyageur upgrader project to reduce the previous cost estimate recorded in the first quarter of 2013. Due to acceleration of project closure activities and a redeployment of resources, the company has reduced the costs associated with not proceeding with the project. The net loss in the fourth quarter of 2012 included an after-tax impairment charge of $1.487 billion against the Voyageur upgrader project.

Operating earnings for the fourth quarter of 2013 were $400 million, compared to $450 million in the prior year quarter. Despite record production volumes, operating earnings for Oil Sands Operations decreased due to higher operating, royalty and DD&A expenses, and lower average price realizations.

Cash operating costs per barrel for Oil Sands Operations in the fourth quarter of 2013 averaged $36.85/bbl compared to $38.00/bbl in the fourth quarter of 2012, reflecting higher production volumes, partially offset by higher total cash operating costs. Total cash operating costs were higher partially due to the acceleration of maintenance programs designed to facilitate and ensure reliable and efficient mining operations. Total cash operating costs also increased relative to the prior year quarter due to incremental costs associated with larger operations, including Firebag Stage 4, incremental costs associated with increased production in mining, higher natural gas prices and consumption, and a decrease in the net benefit of power sales due to lower power prices.

Cash flow from operations for the Oil Sands segment in the fourth quarter of 2013 was $1.110 billion, compared to $1.090 billion in the fourth quarter of 2012, and increased due to higher production volumes, which was partially offset by higher operating and royalty expenses.

Oil Sands Operations continued to set quarterly records in the fourth quarter of 2013, with average production volumes of 409,600 bbls/d, compared to 342,800 bbls/d in the prior year quarter. The increase was primarily due to the ramp up of production at Firebag and the hot bitumen infrastructure commissioned in the third quarter of 2013. Production was reduced throughout the quarter due to a third-party natural gas outage and subsequent curtailments that impacted the Fort McMurray region and resulted in approximately 15,000 bbls/d of lost production in the fourth quarter of 2013. Suncor's share of Syncrude production averaged 36,900 bbls/d in the fourth quarter of 2013, consistent with production of 35,900 bbls/d in the fourth quarter of 2012.

Exploration and Production

The net loss in Exploration and Production was $101 million for the fourth quarter of 2013, compared with net earnings of $148 million for the fourth quarter of 2012. The net loss for the fourth quarter of 2013 includes

46   SUNCOR ENERGY INC. ANNUAL REPORT 2013

after-tax impairment charges of $563 million against assets in Syria, Libya and North America Onshore, partially offset by the recognition of after-tax risk mitigation proceeds of $223 million related to the company's assets in Syria. Net earnings for the fourth quarter of 2012 included a net after-tax recovery of $177 million related to an impairment reversal for assets in Syria, which was almost fully offset by after-tax charges of $172 million including impairments against assets in North America Onshore and East Coast Canada, and a provision in North America Onshore for estimated future commitments relating to unutilized pipeline capacity.

Exploration and Production operating earnings were $239 million in the fourth quarter of 2013, compared to $143 million in the fourth quarter of 2012. Operating earnings increased primarily due to higher price realizations and lower royalty expenses, partially offset by lower production volumes due to the sale of the conventional natural gas business and the shut-in of Libya production.

Cash flow from operations was $552 million for the fourth quarter of 2013, compared to $529 million for the fourth quarter of 2012, and increased due to the same factors that impacted operating earnings, partially offset by incremental current income tax expense relating to the company's Canadian operations recorded in the fourth quarter of 2013.

Production volumes were 111.6 mboe/d in the fourth quarter of 2013, compared to 177.8 mboe/d in the fourth quarter of 2012. The decrease in production volumes was due mainly to the sale of the conventional natural gas business, the shut-in of production in Libya and planned maintenance programs, partially offset by increased production at Buzzard due to strong reliability and reservoir performance in the fourth quarter of 2013 and more planned maintenance activity in the prior year quarter.

Refining and Marketing

For the fourth quarter of 2013, Refining and Marketing net and operating earnings were $458 million, compared to net and operating earnings of $450 million for the fourth quarter of 2012. The increase was due to significantly wider inland crude differentials that were partially offset by lower benchmark crack spreads resulting from the narrowing of the WTI to Brent differential and lower throughput volumes.

Refining and Marketing cash flow from operations was $534 million in the fourth quarter of 2013, compared to $634 million in the fourth quarter of 2012, and decreased primarily due to incremental current income tax expense related to the company's Canadian operations recorded in the quarter.

Overall refinery utilization decreased to 91% in the fourth quarter of 2013, compared to 96% in the fourth quarter of 2012, due to planned maintenance at both the Sarnia and Montreal refineries and unplanned maintenance at the Edmonton refinery in the fourth quarter of 2013. However, the impact of lower throughput was partially offset by more favourable product mix, as mix in the prior year quarter was adversely impacted by unplanned maintenance at the Sarnia refinery.

Corporate, Energy Trading and Eliminations

The net loss for Corporate, Energy Trading and Eliminations in the fourth quarter of 2013 was $383 million, compared to a net loss of $135 million in the fourth quarter of 2012. In the fourth quarter of 2013, the Canadian dollar weakened in relation to the U.S. dollar, resulting in an after-tax unrealized foreign exchange loss on U.S. dollar denominated debt of $259 million, compared to $80 million in the prior year quarter.

Operating loss for Corporate, Energy Trading and Eliminations in the fourth quarter of 2013 was $124 million, compared to a $55 million loss in the fourth quarter of 2012. The increase in operating loss was due primarily to losses on the company's crude trading strategies in the fourth quarter of 2013, compared to gains in the prior year quarter, higher share-based compensation expense in the quarter, higher financing expense associated with additional capital leases and lower capitalized interest, and incremental expenditures relating to a company-wide process improvement initiative.

Corporate, Energy Trading and Eliminations cash flow from operations increased to $154 million in the fourth quarter of 2013, compared to cash flow used in operations of $25 million in the fourth quarter of 2012, due primarily to realized gains on trading strategies in Energy Trading and incremental current income tax recoveries related to the company's Canadian operations recorded in the quarter.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    47

Operating Earnings(1)

Three months ended December 31               Oil Sands               Exploration and
            Production		               Refining and
            Marketing		               Corporate,
            Energy Trading
            and Eliminations		               Total    
($ millions)   2013   2012   2013   2012   2013   2012   2013   2012   2013   2012    
Net earnings (loss) as reported   469   (1 037 ) (101 ) 148   458   450   (383 ) (135 ) 443   (574 )  
Unrealized foreign exchange loss on U.S. dollar denominated debt   —   —   —   —   —   —   259   80   259   80    
Net impact of not proceeding with the Voyageur upgrader project   (69 ) —   —   —   —   —   —   —   (69 ) —    
Impairments (net of reversals), write-offs and provisions   —   1 487   563   (5 ) —   —   —   —   563   1 482    
Recognition of risk mitigation proceeds   —   —   (223 ) —   —   —   —   —   (223 ) —    
Operating earnings (loss)   400   450   239   143   458   450   (124 ) (55 ) 973   988    
 

Cash Flow from Operations(1)

Three months ended December 31               Oil Sands               Exploration and
            Production		               Refining and
            Marketing		               Corporate,
            Energy Trading
            and Eliminations		               Total    
($ millions)   2013   2012   2013   2012   2013   2012   2013   2012   2013   2012    
Net earnings (loss)   469   (1 037 ) (101 ) 148   458   450   (383 ) (135 ) 443   (574 )  
Adjustments for:                                            
  Depreciation, depletion, amortization and impairment   680   2 552   915   300   149   127   31   35   1 775   3 014    
  Deferred income taxes   35   (357 ) —   2   (84 ) 68   41   (39 ) (8 ) (326 )  
  Accretion of liabilities   30   26   10   15   2   1   2   3   44   45    
  Unrealized foreign exchange loss on U.S. dollar denominated debt   —   —   —   —   —   —   304   91   304   91    
  Change in fair value of derivative contracts   1   —   1   1   2   (1 ) 154   (20 ) 158   (20 )  
  Gain on disposal of assets   —   —   —   —   (3 ) (5 ) —   —   (3 ) (5 )  
  Share-based compensation   17   17   7   3   10   10   47   13   81   43    
  Exploration expenses   —   —   23   21   —   —   —   —   23   21    
  Settlement of decommissioning and restoration liabilities   (75 ) (70 ) 1   (10 ) (7 ) (8 ) —   —   (81 ) (88 )  
  Other   (47 ) (41 ) (304 ) 49   7   (8 ) (42 ) 27   (386 ) 27    
Cash flow from (used in) operations   1 110   1 090   552   529   534   634   154   (25 ) 2 350   2 228    
(Increase) decrease in non-cash working capital   (963 ) 35   91   (117 ) 340   (489 ) 518   (481 ) (14 ) (1 052 )  
Cash flow provided by (used in) operating activities   147   1 125   643   412   874   145   672   (506 ) 2 336   1 176    
(1)
Non-GAAP financial measure. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

48   SUNCOR ENERGY INC. ANNUAL REPORT 2013

6. QUARTERLY FINANCIAL DATA

Financial Summary

Three months ended
($ millions, unless otherwise noted)		   Dec 31
2013		   Sept 30
2013		   June 30
2013		   Mar 31
2013		   Dec 31
2012		   Sept 30
2012		   June 30
2012		   Mar 31
2012		  
Total production (mboe/d)                                  
  Oil Sands   446.5   423.6   309.4   389.0   378.7   378.9   337.8   341.1  
  Exploration and Production   111.6   171.4   190.7   207.1   177.8   156.4   204.6   221.2  
    558.1   595.0   500.1   596.1   556.5   535.3   542.4   562.3  
Revenues and other income                                  
  Operating revenues, net of royalties   9 814   10 288   9 648   9 843   9 396   9 488   9 584   9 639  
  Other income   380   85   66   173   92   88   123   116  
    10 194   10 373   9 714   10 016   9 488   9 576   9 707   9 755  
Net earnings (loss)   443   1 694   680   1 094   (574 ) 1 544   324   1 446  
  per common share – basic (dollars)   0.30   1.13   0.45   0.72   (0.38 ) 1.01   0.21   0.93  
  per common share – diluted (dollars)   0.30   1.13   0.45   0.71   (0.38 ) 1.00   0.20   0.92  
Operating earnings(1)   973   1 426   934   1 367   988   1 292   1 249   1 318  
  per common share – basic(1) (dollars)   0.66   0.95   0.62   0.90   0.65   0.84   0.80   0.84  
Cash flow from operations(1)   2 350   2 528   2 250   2 284   2 228   2 743   2 347   2 415  
  per common share – basic(1) (dollars)   1.58   1.69   1.49   1.50   1.46   1.79   1.51   1.55  
ROCE(1) (%) for the twelve months ended   11.5   8.6   8.1   7.1   7.2   12.4   14.2   14.7  
Common share information (dollars)                                  
  Dividend per common share   0.20   0.20   0.20   0.13   0.13   0.13   0.13   0.11  
  Share price at the end of trading                                  
    Toronto Stock Exchange (Cdn$)   37.24   36.83   31.00   30.44   32.71   32.34   29.44   32.59  
    New York Stock Exchange (US$)   35.05   35.78   29.49   30.01   32.98   32.85   28.95   32.70  
(1)
Non-GAAP financial measures. See the Advisories – Non-GAAP Financial Measures section of this document. ROCE excludes capitalized costs related to major projects in progress. Operating earnings for each quarter of 2013 and 2012 is defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of each respective quarterly Report to Shareholders issued in respect of the relevant quarter for 2013 (Quarterly Reports). Cash flow from operations and ROCE are defined and reconciled to GAAP measures in the Advisories – Non-GAAP Financial Measures section of each respective Quarterly Report.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    49

Business Environment

Three months ended
(average for the period ended, except as noted)		   Dec 31
2013		   Sept 30
2013		   June 30
2013		   Mar 31
2013		   Dec 31
2012		   Sept 30
2012		   June 30
2012		   Mar 31
2012		  
WTI crude oil at Cushing   US$/bbl   97.45   105.85   94.20   94.35   88.20   92.20   93.50   102.95  
Dated Brent crude oil at Sullom Voe   US$/bbl   109.35   109.70   103.35   112.65   110.10   109.50   108.90   118.35  
Dated Brent/Maya FOB price differential   US$/bbl   20.05   10.35   5.50   10.60   17.30   11.90   9.85   9.45  
Canadian 0.3% par crude oil at Edmonton   Cdn$/bbl   89.05   105.25   92.90   88.45   84.35   84.70   84.45   92.80  
WCS at Hardisty   US$/bbl   65.25   88.35   75.05   62.40   70.05   70.45   70.60   81.50  
Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty   US$/bbl   32.20   17.50   19.15   31.95   18.15   21.75   22.90   21.45  
Condensate at Edmonton   US$/bbl   94.20   103.80   103.30   107.20   98.10   96.00   99.40   110.00  
Natural gas (Alberta spot) at AECO   Cdn$/mcf   3.15   2.80   3.60   3.05   3.05   2.20   1.85   2.50  
New York Harbor 3-2-1 crack(1)   US$/bbl   19.60   19.25   25.60   31.20   35.95   37.80   31.95   25.80  
Chicago 3-2-1 crack(1)   US$/bbl   12.00   15.80   30.70   27.10   27.85   35.15   27.85   18.80  
Portland 3-2-1 crack(1)   US$/bbl   15.35   19.60   30.60   30.55   29.85   38.15   37.90   27.70  
Gulf Coast 3-2-1 crack(1)   US$/bbl   13.45   15.95   24.00   28.80   27.35   33.95   29.30   25.45  
Exchange rate   US$/Cdn$   0.95   0.96   0.98   0.99   1.00   1.00   0.99   1.00  
Exchange rate (end of period)   US$/Cdn$   0.94   0.97   0.95   0.98   1.01   1.02   0.98   1.00  
(1)
3-2-1 crack spreads are indicators of the refining margin generated by converting three barrels of WTI into two barrels of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

50   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Significant or Unusual Items Impacting Net Earnings

Trends in Suncor's quarterly earnings and cash flow from operations are driven primarily by production volumes, which can be significantly impacted by major maintenance events – such as the maintenance that occurred at Upgrader 1 in Oil Sands in the second quarter of 2013 and the maintenance that occurred at Terra Nova in the fourth quarter of 2013 and at many Exploration and Production assets in the third and fourth quarters of 2012, as well as third-party outages that impacted Oil Sands in the second, third and fourth quarters of 2013.

Trends in Suncor's quarterly earnings and cash flow from operations are also affected by changes in commodity prices, refining crack spreads and foreign exchange rates, as described in the Financial Information – Business Environment – Economic Sensitivities section of this MD&A.

In addition to the impacts of changes in production volumes and business environment, net earnings over the last eight quarters were affected by the following events or significant one-time adjustments:

•
The fourth quarter of 2013 included after-tax impairment charges of $563 million in the Exploration and Production segment against its assets in Syria, Libya and North America Onshore. Concurrent with the impairment of its Syrian assets, the company recognized after-tax risk mitigation proceeds of $223 million, previously recorded as a long-term provision.

•
The first and fourth quarters of 2013 included a net after-tax charge of $58 million as a result of not proceeding with the Voyageur upgrader project, which included costs related to decommissioning and restoration of the Voyageur site and contract cancellations.

•
The third quarter of 2013 included an after-tax gain of $130 million relating to the sale of the company's conventional natural gas business.

•
The fourth quarter of 2012 included an after-tax impairment charge of $1.487 billion relating to the Voyageur upgrader project. Given Suncor's view of the challenging economic environment, the company performed an impairment test based on an assessment of expected future net cash flows.

•
The fourth quarter of 2012 included an after-tax impairment reversal of $177 million of the impairment charges recorded against the company's assets in Syria in the second quarter of 2012, due to a revised assessment of the net recoverable value of the underlying assets following the receipt of risk mitigation proceeds.

•
The fourth quarter of 2012 included total after-tax impairment charges of $172 million for certain exploration, development and production assets in the Exploration and Production segment, and a provision in North America Onshore for estimated future commitments relating to unutilized pipeline capacity.

•
The second quarter of 2012 included after-tax impairment charges and write-offs of $694 million against assets in Syria, which reflected the shut-in of production due to political unrest and international sanctions. The company ceased recording all production and revenue from its Syrian assets in the fourth quarter of 2011.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    51

7. CAPITAL INVESTMENT UPDATE

The Capital Investment Update section contains forward-looking information. See the Advisories – Forward-Looking Information section of this MD&A for the material risks and assumptions underlying this forward-looking information.

Capital and Exploration Expenditures by Segment

Year ended December 31 ($ millions)   2013   2012   2011    
Oil Sands   4 311   4 957   5 100    
Exploration and Production   1 483   1 261   874    
Refining and Marketing   890   644   633    
Corporate, Energy Trading and Eliminations   93   95   243    
Total   6 777   6 957   6 850    
Less: capitalized interest on debt   (397 ) (587 ) (559 )  
    6 380   6 370   6 291    

Capital and Exploration Expenditures by Type(1)(2)(3)

Year ended December 31, 2013 ($ millions)   Sustaining   Growth   Total  
Oil Sands   2 729   1 267   3 996  
  Oil Sands Base   1 516   71   1 587  
  In Situ   814   381   1 195  
  Oil Sands Ventures   399   815   1 214  
Exploration and Production   151   1 250   1 401  
Refining and Marketing   770   120   890  
Corporate, Energy Trading and Eliminations   75   18   93  
    3 725   2 655   6 380  
(1)
Capital expenditures in this table exclude capitalized interest on debt.

(2)
Growth capital expenditures include capital investments that result in i) an increase in production levels at existing Oil Sands Operations and Refining and Marketing operations; ii) new facilities or operations that increase overall production; iii) new infrastructure and logistics that are required to support higher production levels; iv) new reserves or a positive change in the company's reserves profile in Exploration and Production operations; or v) margin improvement, by increasing revenues or reducing costs.

(3)
Sustaining capital expenditures include capital investments that i) ensure compliance or maintain relations with regulators and other stakeholders; ii) improve efficiency and reliability of operations or maintain productive capacity by replacing component assets at the end of their useful lives; iii) deliver existing proved developed reserves for Exploration and Production operations; or iv) maintain current production capacities at existing Oil Sands Operations and Refining and Marketing operations.

In 2013, Suncor spent $6.380 billion on capital for property, plant and equipment and exploration activities, and capitalized $397 million of interest on debt towards major development assets and construction projects. Activity in 2013 included the following:

Oil Sands Base

Oil Sands Base capital expenditures were $1.587 billion, of which $1.516 billion was directed towards sustaining activities. Sustaining capital expenditures related primarily to planned maintenance events, including the Upgrader 1 turnaround completed in the second quarter of 2013 and planned maintenance of the Upgrader 2 vacuum tower and related units completed in the third and fourth quarters of 2013. Suncor continued to progress reliability and sustainment projects, including the construction of assets to support the TROTM process and activities aimed at reducing freshwater use, including the construction of a water treatment plant.

Oil Sands Base growth capital focused on infrastructure required to support growth in production from Oil Sands Operations, including the commissioning of two new storage tanks in Hardisty, Alberta connected to the Enbridge mainline system. Growth capital was also directed towards debottlenecking projects, including a recently completed project in secondary extraction that has increased operational flexibility.

52   SUNCOR ENERGY INC. ANNUAL REPORT 2013


In Situ

In Situ capital and exploration expenditures were $1.195 billion, of which $381 million was directed towards growth projects. Growth capital in 2013 was focused on well pad development which contributed to the completion of the Firebag 4 ramp up in the fourth quarter of 2013. The company commissioned the hot bitumen infrastructure, including an insulated pipeline to flow hot bitumen from the Firebag site to Suncor's Athabasca terminal for cooling and blending with internal and imported third-party diluent. To support this infrastructure, the company entered into a finance lease for interconnects and additional tankage. The company's growth capital was also focused on debottlenecking projects at MacKay River, including a project that is intended to increase production capacity of the MacKay River facility by approximately 20% for a total capacity of 38,000 bbls/d by the end of 2015.

Sustaining capital expenditures of $814 million were directed towards ongoing design, engineering, procurement and construction of well pads that are expected to maintain existing production levels at Firebag and MacKay River in future years. The company expects to start steaming a well pad at MacKay River in the second quarter of 2014. Capital expenditures were also directed towards the infill well program at Firebag.

Oil Sands Ventures

Oil Sands Ventures growth capital expenditures were $815 million in 2013. The Fort Hills mining project expenditures were directed towards design engineering, site preparation and procurement of long-lead items.

On October 30, 2013, Suncor announced that the project co-owners had voted unanimously to proceed with the Fort Hills mining project. Suncor has a 40.8% interest and is the operator of the project.

Suncor and the co-owners of the Joslyn mining project continue to focus on design engineering and regulatory work.

Suncor's share of capital expenditures for the Syncrude joint operation in 2013 was $399 million, which included the completion of two mine train relocations at the Aurora mining area which started operating in July and October 2013, respectively. Capital expenditures were also focused on the mine train replacement at the Mildred Lake mining area and the construction of a centrifuge plant.

Growth capital also included the construction of midstream assets that are currently being used to support production in Oil Sands Operations, including hot bitumen cooling and blending, and related storage assets.

Exploration and Production

Exploration and Production capital and exploration expenditures were $1.401 billion in 2013, of which $1.250 billion was directed towards growth and exploration.

Growth spending included $190 million for Golden Eagle, which focused on the installation of two platform jackets, the wellhead topside, and subsea infrastructure. Growth spending for Hebron was $517 million in 2013, which focused on detailed engineering and construction of the gravity-based structure and topsides.

Growth spending of approximately $263 million focused on advancing extension projects which leverage existing facilities and infrastructure at East Coast Canada. Detailed engineering and subsea installation activities were completed in 2013 for the HSEU and subsea drilling activities commenced in early 2014. For the SWRX project, detailed engineering and procurement activities progressed while subsea installation activities commenced in 2013.

Other growth capital included development drilling for Hibernia, White Rose, Terra Nova and Buzzard, and for North America Onshore in the Cardium oil formation in Western Canada.

During 2013, Suncor participated in the Butch East appraisal well offshore Norway. Drilling and evaluation of the Butch East well will continue into 2014, with drilling for a second appraisal scheduled for the middle of 2014. The company also completed the drilling and evaluation of the Romeo exploration well, and participated in the Scotney and Lily exploration wells in the U.K. sector of the North Sea – which were all deemed to be dry holes and charged to exploration expense in 2013.

The company continued to progress its exploration drilling program in Libya and drilled six exploration wells in 2013. Three of the six wells were assessed as dry holes and charged to exploration expense in 2013.

Sustaining capital expenditures focused primarily on the planned maintenance programs for East Coast Canada assets.

Refining and Marketing

Refining and Marketing spent $890 million on capital expenditures in 2013, largely focused on planned maintenance at the Edmonton, Sarnia and Montreal refineries. Growth spending was also directed towards projects to enhance integration with the company's Oil Sands operations, including early engineering and design work for facilities to prepare the Montreal refinery for the receipt and processing of inland crudes. Construction of a rail offloading facility to enable rail receipt of inland crudes to the Montreal refinery was completed in the fourth quarter of 2013.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    53

Significant Growth Projects Update(1)

At December 31, 2013   Working
Interest
(%)		   Description   Cost Estimate
($ millions)		   Project
Spend to date
($ millions)		   Expected
First Oil
Date(3)		  
Operated                      
  Fort Hills   40.80   73.4 mbbls/d (net)   5 500   115   Q4 2017  
Non-operated(2)                      
  Golden Eagle   26.69   18.7 mboe/d (net)   1 000
(+/-10%)		   470   Q4 2014/
Q1 2015		  
  Hebron   22.73   34.2 mboe/d (net)   2 800
(+/-10%)		   517   Q4 2017  
(1)
Cost Estimate and Project Spend to date figures reflect post-sanction estimates and expenditures.

(2)
Cost estimates are based on the most recent estimate provided by the operator.

(3)
Expenditures to complete the project may extend beyond the first oil date.

The table above provides a review and update at December 31, 2013 of major growth projects that have been sanctioned for development by the company. Other growth projects, such as the Joslyn North oil sands mining project and the MacKay River expansion, have not yet received a final investment decision by the company or its Board of Directors and the respective co-owners, in the case of the Joslyn mining project.

The Fort Hills mining project will be developed using traditional open-pit truck and shovel techniques, and solvent-based extraction technology that will allow the mine to produce a marketable bitumen product. The project is scheduled to produce first oil in the fourth quarter of 2017 and achieve 90% of its planned gross production capacity of 180,000 bbls/d within twelve months. Project activity in 2014 includes the detailed engineering, procurement and ramp up of field construction activities. Suncor's share of the estimated post-sanction project cost is $5.5 billion, of which total expenditures incurred since project sanction are $115 million.

The field development plan for Golden Eagle includes stand-alone facilities designed for 70,000 boe/d of gross production. Activity in 2014 will focus on achieving first oil by late 2014 or early 2015, including installation of the production, utility and quarters platform, and development drilling. Total project expenditures to date are $470 million, with Suncor's share of the post-sanction project cost estimate being $1 billion.

The co-owners for the Hebron project sanctioned development on December 31, 2012. The Hebron field includes a gravity-based structure design supporting an oil production rate of 150,000 bbls/d. Project activity in 2014 is expected to focus on detailed engineering and construction of the gravity-based post-sanction structure and topsides. Suncor's share of the estimated project cost is $2.8 billion, of which Suncor's share of total project expenditures since sanction is $517 million.

Other Capital Projects

Suncor also anticipates 2014 capital expenditures to be focused on the following projects and initiatives:

Oil Sands Base and In Situ

The company plans to focus growth capital efforts on optimizing the existing asset base and focusing on low-cost debottlenecking and expansion projects. These projects will be less capital intensive, but are expected to result in high returns and efficiencies throughout the Oil Sands operations. Suncor continues to work towards a 2014 sanction decision of the MacKay River expansion project, which is targeted to have an initial design capacity of approximately 20,000 bbls/d and first oil expected in 2017. The company also expects to substantially complete the Mackay River facility debottleneck in 2014, which is intended to increase production capacity by approximately 20% for a total capacity of 38,000 bbls/d by the end of 2015. Suncor plans to focus on validating all other debottlenecking initiatives of logistics infrastructure and Firebag facilities.

Sustaining capital includes planned maintenance but to a lesser degree than previous years as there is no major turnaround planned until 2016. Sustaining capital in 2014 continues to focus on the construction of assets to support the TROTM process and activities aimed at reducing freshwater use, including the construction of a water treatment plant, which is expected to be commissioned in early 2014.

54   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Suncor plans to focus on the completion of the well pads that are intended to offset natural production declines in Firebag and Mackay River. The company also plans to progress infill drilling programs at Firebag.

Oil Sands Ventures

Capital expenditures in 2014 for Syncrude are expected to focus on completing the mine train replacement for the Mildred Lake mining area and progress the tailings management program, including the construction of a centrifuge plant.

Suncor and the co-owners of the Joslyn mining project continue to focus on design engineering and regulatory work, and plan to provide an update on the targeted timing for a project sanction decision when available.

Exploration and Production

The company has multiple field extension projects underway which leverage existing facilities and infrastructure.

Subsea drilling commenced for the HSEU in early 2014. Overall production increases from the Hibernia field are expected to begin in 2015. For the SWRX, detailed engineering and procurement activities are expected to continue and subsea installation is planned for completion in late 2014. First oil is expected in late 2014 or early 2015. A sanction decision for further expansion into the western portion of the White Rose field is targeted for the second half of 2014. The current project plan consists of a wellhead platform, including a concrete gravity structure with topsides, drilling facilities and support services that will tie back into the existing White Rose FPSO for processing, storage and offloading.

In the North Sea, the company plans to continue evaluating the operated Beta prospect and plans to commence further appraisal drilling in 2014. In addition, the company plans to participate in four non-operated exploration wells in 2014. With respect to the non-operated Butch licence, drilling and evaluation activities of the Butch East well are expected to be complete in the first half of 2014 with plans for a second exploration well in mid-2014. Suncor continues to evaluate further exploration opportunities for its remaining licences, including four newly acquired licences in Norway, where Suncor is the operator on two of the licences. Exploration activity on the new licences will primarily involve acquisition or processing of seismic data, some of which will commence in 2014.

Refining and Marketing

The company expects that sustaining capital will focus on planned maintenance events and routine asset replacement, and that growth capital is expected to be deployed on projects to prepare the Montreal refinery to receive and process heavier crudes, including integration with the company's Oil Sands operations.

Renewable Energy

Growth capital will be focused on progressing projects within the company's renewable business. The Adelaide project received regulatory approval in December 2013 and has an expected completion date of late 2014. The Cedar Point project will continue to progress through the regulatory process in 2014. The two projects, based in Ontario, are expected to add 140 MW of gross installed capacity, increasing the gross installed capacity of Suncor's wind projects by 55%.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    55

8. FINANCIAL CONDITION AND LIQUIDITY

Indicators

At December 31 ($ millions, except as noted)   2013   2012   2011  
Return on Capital Employed (%)(1)(2)              
  Excluding major projects in progress   11.5   7.2   13.8  
  Including major projects in progress   9.9   5.8   10.1  
Net debt to cash flow from operations(2) (times)   0.7   0.7   0.7  
Interest coverage on long-term debt (times)              
  Earnings basis(3)   9.5   7.9   10.7  
  Cash flow from operations basis(2)(4)   16.8   17.7   16.4  
(1)
Non-GAAP financial measure. ROCE is reconciled in the Advisories – Non-GAAP Financial Measures section of this MD&A.

(2)
Cash flow from operations and metrics that use cash flow from operations are non-GAAP financial measures. See the Advisories – Non-GAAP Financial Measures section of this MD&A.

(3)
Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.

(4)
Cash flow from operations plus current income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.

Capital Resources

Suncor's capital resources consist primarily of cash flow from operations, cash and cash equivalents, and available lines of credit. Suncor's management believes the company will have the capital resources to fund its planned 2014 capital spending program of $7.8 billion and meet working capital requirements through existing cash balances and short-term investments, cash flow from operations, available committed credit facilities, issuing commercial paper and issuing long-term notes or debentures. The company's cash flow from operations depends on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates. If additional capital is required, Suncor's management believes adequate additional financing will be available to the company in debt capital markets at commercial terms and rates.

The company has invested excess cash in short-term financial instruments that are presented as cash and cash equivalents on the Consolidated Balance Sheets. The objectives of the company's short-term investment portfolio are to ensure the preservation of capital, maintain adequate liquidity to meet Suncor's cash flow requirements and deliver competitive returns consistent with the quality and diversification of investments within acceptable risk parameters. The maximum weighted average term to maturity of the short-term investment portfolio does not exceed six months, and all investments are with counterparties with investment grade debt ratings.

Available Sources of Liquidity

Cash and Cash Equivalents

Cash and cash equivalents increased by $817 million to $5.202 billion during 2013.

As at December 31, 2013, the weighted average term to maturity of the short-term investment portfolio was approximately 57 days. In 2013, the company earned approximately $26 million of interest income on this portfolio.

Financing Activities

Management of debt levels continues to be a priority for Suncor given the company's long-term growth plans. Suncor's management believes a phased and flexible approach to existing and future growth projects should assist Suncor in maintaining its ability to manage project costs and debt levels.

Suncor's interest on debt (before capitalized interest) in 2013 was $703 million, compared to $640 million in 2012. The increase in interest expense relates to new finance leases in 2013, partially offset by the repayment of debentures in 2013.

Unutilized lines of credit at December 31, 2013 were $4.536 billion, compared to $4.735 billion at December 31, 2012.

56   SUNCOR ENERGY INC. ANNUAL REPORT 2013

A summary of available and utilized credit facilities is as follows:

At December 31, 2013 ($ millions)      
Fully revolving for a period of one year after term-out date (November 2014)   2 000  
Fully revolving and expires in 2015   900  
Fully revolving for a period of three years and expires in 2016   3 000  
Can be terminated at any time at the option of the lenders   288  
Total available credit facilities   6 188  
Less:      
Credit facilities supporting outstanding commercial paper   798  
Credit facilities supporting standby letters of credit   854  
Total unutilized credit facilities   4 536  

Total Debt to Total Debt Plus Shareholders' Equity

Suncor is subject to financial and operating covenants related to its bank debt and public market debt. Failure to meet the terms of one or more of these covenants may constitute an Event of Default as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. The company is in compliance with its financial covenant that requires total debt to not exceed 65% of its total debt plus shareholders' equity. At December 31, 2013, total debt to total debt plus shareholders' equity was 22% (December 31, 2012 – 22%). The company is also currently in compliance with all operating covenants.

At December 31
($ millions, except as noted)		   2013   2012  
  Short-term debt   798   775  
  Current portion of long-term debt   457   311  
  Long-term debt   10 203   9 938  
Total debt   11 458   11 024  
  Less: Cash and cash equivalents   5 202   4 385  
Net debt   6 256   6 639  
Shareholders' equity   41 180   39 215  
Total debt plus shareholders' equity   52 638   50 239  
Total debt to total debt plus shareholders' equity (%)   22   22  

Change in Net Debt

($ millions)        
Net debt – December 31, 2012   6 639    
Decrease in net debt   (383 )  
Net debt – December 31, 2013   6 256    
Decrease in net debt        
  Cash flow from operations   9 412    
  Capital and exploration expenditures and other investments   (6 795 )  
  Acquisition   (515 )  
  Proceeds from divestitures   943    
  Divestiture of pipeline contract   (76 )  
  Dividends less proceeds from exercise of share options   (983 )  
  Repurchase of common shares   (1 675 )  
  Change in non-cash working capital   598    
  Foreign exchange on cash, debt and other balances   (526 )  
    383    

At December 31, 2013, Suncor's net debt was $6.256 billion, compared to $6.639 billion at December 31, 2012. During 2013, net debt decreased by $383 million, largely due to cash flow from operations that exceeded capital and exploration expenditures, proceeds from the sale of the conventional natural gas business, partially offset by cash returned to shareholders in the form of share repurchases and dividends, the acquisition of Total E&P's interest in VULP and the impact of the weakening Canadian dollar relative to the U.S. dollar on the valuation of U.S. denominated debt.

For the year ended December 31, 2013, the company's net debt to cash flow from operations measure was 0.7 times, which met management's target of less than 2.0 times.

Credit Ratings

The following information regarding the company's credit ratings is provided as it relates to the company's cost of funds and liquidity and indicates whether or not the company's credit ratings have changed. In particular, the company's ability to access unsecured funding markets and to engage in certain collateralized business activities on a cost-effective basis is primarily dependent upon maintaining competitive credit ratings. A lowering of the company's credit rating may also have potentially adverse consequences for the company's funding capacity or access to the capital markets, may affect the company's ability, and the cost, to enter into normal course derivative or

SUNCOR ENERGY INC. ANNUAL REPORT 2013    57

hedging transactions, and may require the company to post additional collateral under certain contracts.

The company's long-term senior debt ratings are:

Long-Term Senior Debt   Rating   Long-Term
Outlook		  
Standard & Poor's   BBB+   Stable  
Dominion Bond Rating Service   A (low ) Stable  
Moody's Investors Service   Baa1   Stable  

The company's commercial paper ratings are:

Commercial Paper   Cdn Program
Rating		   US Program
Rating		    
Standard & Poor's   A-1 (low ) A-2    
Dominion Bond Rating Service   R-1 (low ) R-1 (low )  
Moody's Investors Service   Not rated   P-2    

Refer to the Description of Capital Structure – Credit Ratings section of Suncor's 2013 AIF for a description of credit ratings listed above.

Common Shares

Outstanding Shares

December 31, 2013 (thousands)      
Common shares   1 478 315  
Common share options – exercisable and non-exercisable   34 997  
Common share options – exercisable   27 104  

As at February 24, 2014, the total number of common shares outstanding was 1,471,044,559, and the total number of exercisable and non-exercisable common share options outstanding was 38,992,223. Once exercisable, each outstanding common share option is convertible into one common share.

Share Repurchases

In the third quarter of 2012, the company obtained regulatory approval for a Normal Course Issuer Bid (the 2012 NCIB) with the Toronto Stock Exchange (TSX), authorizing the purchase for cancellation of up to $1 billion of Suncor's common shares, commencing September 20, 2012 and ending on September 19, 2013. On April 29, 2013, Suncor received regulatory approval to amend its 2012 NCIB, authorizing the purchase for cancellation of up to an additional $2 billion worth of its common shares, commencing May 2, 2013 and ending September 19, 2013.

Subsequently, on August 5, 2013, Suncor cancelled the 2012 NCIB and commenced a new normal course issuer bid (the 2013 NCIB) through the facilities of the Toronto Stock Exchange, New York Stock Exchange and/or alternative trading platforms. The 2013 NCIB was amended effective on February 21, 2014, to permit the company to purchase for cancellation additional shares. Pursuant to the 2013 NCIB, Suncor is permitted to purchase for cancellation up to approximately $2.8 billion worth of its common shares between August 5, 2013 and August 4, 2014, and has agreed that it will not purchase more than 111,121,897 common shares, which equals approximately 7.4% of the issued and outstanding common shares in the public float as at July 29, 2013.

Shareholders may obtain a copy of the company's Notice of Intention to make a Normal Course Issuer Bid in relation to both the 2012 NCIB and the 2013 NCIB, without charge, by contacting Investor Relations.

Under the 2012 NCIB, the company repurchased 25,075,100 common shares during 2013 at an average price of $31.17 per share, for a total repurchase cost of $781 million. Under the 2013 NCIB and as at December 31, 2013, the company repurchased 24,417,157 common shares during 2013 at an average price of $36.59 per share, for a total repurchase cost of $894 million.

Subsequent to December 31, 2013, the company has repurchased an additional 8,771,116 shares under the 2013 NCIB at an average price of $36.72 per share, for a total repurchase cost of $322 million, as of February 24, 2013.

58   SUNCOR ENERGY INC. ANNUAL REPORT 2013

At December 31
($ millions, except as noted)		   2013   2012    
Share repurchase activities (thousands of common shares)            
  Shares repurchased directly   49 492   46 862    
  Shares repurchased through exercise of put options   —   —    
    49 492   46 862    
Share repurchase cost ($ millions)            
  Repurchase cost   1 675   1 452    
  Option premiums received   —   (1 )  
    1 675   1 451    
Weighted average repurchase price per share, net of option premiums (dollars per share)   33.84   30.96    

Contractual Obligations, Commitments, Guarantees, and Off-Balance Sheet Arrangements

In addition to the enforceable and legally binding obligations in the table below, Suncor has other obligations for goods and services that were entered into in the normal course of business, which may terminate on short notice, including commitments for the purchase of commodities for which an active, highly liquid market exists, and which are expected to be re-sold shortly after purchase.

The company does not believe it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company's financial condition or financial performance, including liquidity and capital resources.

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments.

    Payments Due by Period  
($ millions)   2014   2015 to 2016   2017 to 2018   Thereafter   Total  
Fixed and revolving term debt(1)   1 849   1 180   3 848   13 524   20 401  
Finance lease obligations   110   222   216   2 222   2 770  
Decommissioning and restoration costs(2)   334   740   584   6 373   8 031  
Operating lease agreements, pipeline capacity and energy services commitments   1 721   2 411   2 019   6 989   13 140  
Exploration work commitments   165   405   —   2   572  
Other long-term obligations(3)   294   64   —   —   358  
Total   4 473   5 022   6 667   29 110   45 272  
(1)
Includes debt that is redeemable at Suncor's option and interest payments on fixed-term debt.

(2)
Represents the undiscounted amount of obligations associated with land and tailings reclamation, and site restoration and decommissioning costs.

(3)
Includes the Libya ESPA signature bonus and merger consent, and Fort Hills purchase obligations. See the Other Long-Term Liabilities note to the audited Consolidated Financial Statements.

(4)
The company has also entered into various pipeline commitments which are awaiting regulatory approval. In the event regulatory approval is not obtained, Suncor has committed to reimbursing certain costs to the service provider.

Transactions with Related Parties

The company enters into transactions with related parties in the normal course of business. These transactions primarily include sales to associated entities in the company's Refining and Marketing segment. For more information on these transactions and for a summary of Compensation of Key Management Personnel, refer to note 31 to the 2013 audited Consolidated Financial Statements.

Financial Instruments

Suncor periodically enters into derivative contracts for risk management purposes. The derivative contracts hedge risks related to purchases and sales of commodities, to manage exposure to interest rates and to hedge risks specific to

SUNCOR ENERGY INC. ANNUAL REPORT 2013    59

individual transactions. For the year ended December 31, 2013, the pre-tax earnings impact for risk management activities was a loss of $18 million (2012 – pre-tax gain of $1 million).

The company's Energy Trading business uses crude oil, natural gas, refined products and other derivative contracts to generate net earnings. For the year ended December 31, 2013, the pre-tax earnings impact for Energy Trading activities was a gain of $176 million (2012 – pre-tax gain of $246 million).

Gains or losses related to derivatives are recorded as Other Income in the Consolidated Statements of Comprehensive Income.

($ millions)   Risk
Management		   Energy
Trading		   Total    
Fair value of contracts, outstanding – January 1, 2012   —   (34 ) (34 )  
Fair value of contracts realized during the year   (2 ) (255 ) (257 )  
Changes in fair value during the year   1   246   247    
Fair value of contracts, outstanding – December 31, 2012   (1 ) (43 ) (44 )  
Fair value of contracts realized during the year   18   (271 ) (253 )  
Changes in fair value during the year   (18 ) 176   158    
Fair value of contracts, outstanding – December 31, 2013   (1 ) (138 ) (139 )  

The fair value of derivative contracts are recorded in the Consolidated Balance Sheets.

Fair value of derivative contracts at
December 31 ($ millions)		   2013   2012    
Accounts receivable   225   53    
Accounts payable   (364 ) (97 )  
    (139 ) (44 )  

Risks Associated with Derivative Financial Instruments

Suncor may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to fulfil their obligations under these contracts. The company minimizes this risk by entering into agreements with investment grade counterparties. Risk is also minimized through regular management review of the potential exposure to and credit ratings of such counterparties. Suncor's exposure is limited to those counterparties holding derivative contracts with net positive fair values at a reporting date.

Suncor's risk management activities are subject to periodic reviews by management to determine appropriate hedging requirements based on the company's tolerance for exposure to market volatility, as well as the need for stable cash flow to finance future growth. Energy Trading activities are governed by a separate risk management group that reviews and monitors practices and policies and provides independent verification and valuation of these activities.

For further details on our derivative financial instruments, including assumptions made in the calculation of fair value, a sensitivity analysis of the effect of changes in commodity prices on our derivative financial instruments, and additional discussion of exposure to risks and mitigation activities, see the Financial Instruments and Risk Management note in our 2013 audited Consolidated Financial Statements.

60   SUNCOR ENERGY INC. ANNUAL REPORT 2013

9. ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

Changes in Accounting Policies

Suncor's significant accounting policies are described in notes 3 to the audited Consolidated Financial Statements for the year ended December 31, 2013.

Effective January 1, 2013, the company adopted IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities and IFRS 13 Fair Value Measurement, and amendments to International Accounting Standard (IAS) 19 Employee Benefits, IFRS 7 Financial Instruments: Disclosure and IAS 36 Impairment of Assets.

Scope of a Reporting Entity

IFRS 10 creates a single consolidation model by revising the definition of control in order to apply the same control criteria to all types of entities, including joint arrangements, associates and structured entities. IFRS 11 establishes a principle-based approach to the accounting for joint arrangements by focusing on the rights and obligations of the arrangement and limits the application of proportionate consolidation accounting to arrangements that meet the definition of a joint operation, where sufficient rights and obligations are passed to the partners. Arrangements that meet the definition of a joint venture are required to apply the equity method of accounting. IFRS 12 is a comprehensive disclosure standard for all forms of interests in other entities, including subsidiaries, joint arrangements, associates and unconsolidated structured entities.

The company identified two existing joint arrangements in the Refining and Marketing segment that have been retrospectively reclassified as joint ventures as a result of IFRS 11, and are now being accounted for using the equity method of accounting rather than the proportionate consolidation method. This change does not have a material impact to the Consolidated Financial Statements, but does result in the netting of revenues and expenses for these entities into Other Income. Cash flow from operations from these joint arrangements is now recognized based on cash distributions received in the period, where previously it was recognized based on the company's proportionate share of cash flow from operations. In addition, the company's net investment in these entities is now presented in Other Assets. The company determined that the adoption of IFRS 10 did not result in changes to the consolidation conclusions of any of its subsidiaries and investees. See note 29 for additional disclosures regarding the company's interest in associates and joint arrangements as a result of adopting IFRS 12.

Employee Benefits

The revised standard resulted in changes to the calculation and presentation of pension interest cost, which is now calculated on the net unfunded obligation, applying the discount rate used to measure the employee benefit obligation at the beginning of the annual period. Previously, pension interest cost was net of interest income on plan assets (using the expected return on plan assets) and interest expense on the plan obligation (using the discount rate). The net pension interest expense was reclassified to Financing Expenses from Operating, Selling and General expense. The change to the pension interest cost calculation also resulted in the refundable tax accounts (RTA) being present valued, resulting in an immaterial adjustment to the Consolidated Balance Sheets.

Fair Value Measurements

IFRS 13 establishes a single source of guidance for most fair value measurements, clarifies the definition of fair value, and enhances the disclosures on fair value measurements. The adoption of IFRS 13 did not require any adjustments to the valuation techniques used by the company to measure fair value and did not result in any fair value measurement adjustments as at January 1, 2013. The adoption of this standard resulted in additional disclosures regarding the fair value measurement of the company's financial instruments. See note 27 to the audited Consolidated Financial Statements for the year ended December 31, 2013.

Offsetting Financial Assets and Liabilities

The amendments to IFRS 7 clarify the offsetting model and develop common disclosure requirements to enhance the understanding of the potential effects of offsetting arrangements. The adoption of this amendment resulted in additional disclosure for the company's offsetting financial assets and financial liabilities. See note 27 to the audited Consolidated Financial Statements for the year ended December 31, 2013.

Recoverable Amount Disclosures for Non-Financial Assets

The company early adopted amendments to IAS 36 Impairment of Assets. The amendments clarified the recoverable amount is disclosed only when an asset or cash generating unit is impaired. The adoption of this amended standard also resulted in expanded disclosure for recoverable amounts of impaired assets that are calculated based on fair value less costs of disposal methodology and for cash-generating units with goodwill that are not impaired, including the disclosure of the fair value

SUNCOR ENERGY INC. ANNUAL REPORT 2013    61

measurement level input. See note 27 to the audited Consolidated Financial Statements for the year ended December 31, 2013.

The effects of the application of IFRS 11 and the IAS 19 amendment to consolidated net earnings, operating earnings and cash flow from operations for the twelve months ended December 31, 2012 are shown in the table below and reflect the application of relevant transitional provisions.

($ millions)   Year ended
December 31,
2012		    
Net earnings before accounting changes   2 783    
Adjustments to net earnings:        
  Recognition of interest costs on net unfunded obligation (IAS 19)   (43 )  
Net earnings after accounting changes   2 740    
Operating earnings before accounting changes   4 890    
Adjustments to operating earnings:        
  Recognition of interest costs on net unfunded obligation (IAS 19)   (43 )  
Operating earnings after accounting changes   4 847    
Cash flow from operations before accounting changes   9 745    
Adjustments to cash flow from operations:        
  Proportionate consolidation to equity accounting (IFRS 11)   (5 )  
  Recognition of interest costs on net unfunded obligation (IAS 19)   (7 )  
Cash flow from operations after accounting changes   9 733    

Recently Announced Accounting Standards

The standards and interpretations that are issued but not yet effective up to the date of issuance of the company's financial statements, and may have an impact on the disclosures and financial position of the company, are disclosed below. The company intends to adopt these standards and interpretations, if applicable, when they become effective.

Offsetting Financial Assets and Financial Liabilities

In December 2011, the IASB issued amendments to IAS 32 Financial Instruments: Presentation to clarify the requirements for offsetting financial assets and liabilities. The amendments clarify that the right to offset must be available on the current date and cannot be contingent on a future event. Retrospective application of amendments to IAS 32 are effective for annual periods beginning on or after January 1, 2014 with earlier application permitted. The adoption of this amended standard is not expected to have a material impact on the company's financial statements.

Levies

In May 2013, the IASB issued International Financial Reporting Interpretation Committee (IFRIC) 21 Levies. This clarifies that an entity recognizes a liability for a levy when the activity that triggers payment occurs.

For a levy that is triggered upon reaching a minimum threshold, the interpretation clarifies that no liability should be anticipated before the minimum threshold is reached. Retrospective application of this interpretation is effective for annual periods beginning on or after January 1, 2014, with earlier application permitted. The company is assessing the impact of this interpretation on royalties and property taxes.

Financial Instruments: Recognition and Measurement

In November 2009, as part of the IASB project to replace IAS 39 Financial Instruments: Recognition and Measurement, the IASB issued the first phase of IFRS 9 Financial Instruments. It contained requirements for the classification and measurement of financial assets, and was updated in October 2010 to incorporate financial liabilities. In November 2013, the IASB issued amendments to include the new general hedge accounting model and to postpone the mandatory effective date of this standard indefinitely. The full impact of this standard will not be known until the amendments addressing impairments, classification and measurement have been completed. When these projects are completed, an effective date will be added by the IASB.

Critical Accounting Estimates and Judgments

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues, expenses, gains, losses, and disclosures of contingencies. These estimates and judgments are subject to change based on experience and new information.

Critical accounting estimates are those estimates that require management to make assumptions about matters that are highly uncertain at the time the estimate is made, and those estimates where changes in critical assumptions that are within a range of reasonably possible outcomes would have a material impact on the company's financial condition, changes in financial condition or financial performance.

62   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Critical judgments are those judgments made by management in the process of applying the company's accounting policies and that have the most significant impact on the amounts recognized in the Consolidated Financial Statements.

Critical accounting estimates and judgments are reviewed annually by the Audit Committee of the Board of Directors. The following are the critical accounting estimates used in the preparation of Suncor's December 31, 2013 audited Consolidated Financial Statements.

Oil and Gas Reserves and Resources

Measurements of depletion, depreciation, impairment, and decommissioning and restoration obligations are determined in part based on the company's estimate of oil and gas reserves and resources. The estimation of reserves and resources is an inherently complex process and involves the exercise of professional judgment. The reserves and resources estimates are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook and are reviewed on an annual basis by qualified reserves evaluators in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

Oil and gas reserves and resources estimates are based on a range of geological, technical and economic factors, including projected future rates of production, projected future commodity prices, engineering data, and the timing and amount of future expenditures, all of which are subject to uncertainty. Estimates reflect market and regulatory conditions existing at December 31, 2013, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Oil and Gas Activities

The company is required to apply judgment when designating the nature of oil and gas activities as exploration, evaluation, development or production, and when determining whether the initial costs of these activities are capitalized.

Exploration and Evaluation Costs

Certain exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. The company is required to make judgments about future events and circumstances and applies estimates to assess the economic viability of extracting the underlying resources. The costs are subject to technical, commercial and management review to confirm the continued intent to develop the project. Level of drilling success, or changes to project economics, resource quantities, expected production techniques, production costs and required capital expenditures are important judgments when making this determination.

Development Costs

Management uses judgment to determine when exploration and evaluation assets are reclassified to Property, Plant and Equipment. This decision considers several factors, including the existence of reserves, appropriate approvals from regulatory bodies and the company's internal project approval processes.

Determination of Cash Generating Units (CGU)

A CGU is defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructures, and the way in which management monitors the operations.

Asset Impairment and Reversals

Management applies judgment in assessing the existence of impairment and impairment reversal indicators based on various internal and external factors.

The recoverable amount of CGUs and individual assets is determined based on the higher of fair value less costs of disposal or value-in-use calculations. The key estimates the company applies in determining the recoverable amount normally include estimated future commodity prices, expected production volumes, future operating and development costs, discount rates, tax rates, and refining margins. In determining the recoverable amount, management may also be required to make judgments regarding the likelihood of occurrence of a future event. Changes to these estimates and judgments will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value.

Regardless of any indication of impairment, the company must complete an annual impairment assessment for any CGU, or group of CGUs, whose net carrying value includes indefinite-life intangible assets or an allocation of goodwill. For Suncor, this includes impairment assessments of the Oil Sands segment and the Refining and Marketing segment. For 2013, the company completed this review as at October 31, 2013, and determined that the underlying CGUs were not impaired.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    63

The following significant impairment assessments were completed during 2013:

Syria

Since December 2011, Suncor's operations in Syria and its contractual obligations have been suspended under a period of force majeure due to political unrest and international sanctions. The company impaired the remaining carrying value of its Syrian assets, resulting in an after-tax impairment charge of $422 million in the fourth quarter of 2013, under management's view that the ongoing political situation has led to increasing uncertainty with respect to the company's return to operations in the country.

The company received risk mitigation proceeds in the fourth quarter of 2012, at which time the proceeds were recorded as a non-current provision to reflect potential repayment if operations in Syria were to resume. Suncor recognized the risk mitigation proceeds of $300 million ($223 million after-tax) in net earnings in the fourth quarter of 2013, as the likelihood of return in the foreseeable future is undeterminable.

Libya

Recent political unrest has resulted in the closure of export terminal operations at eastern Libyan seaports, requiring the shut-in of production for the latter half of 2013. As the situation persisted at the end of 2013, management performed an impairment test at December 31, 2013.

The impairment test was performed based on an assessment of future net cash flows over a range of possible outcomes, resulting in an after-tax impairment charge of $101 million in the fourth quarter of 2013.

The carrying value of the company's net assets in Libya as at December 31, 2013 was approximately $570 million.

The carrying value as at December 31, 2013 was based on a net recoverable amount that was estimated under a value-in-use methodology and determined using an expected cash flow approach, under probability weighted scenarios representing i) future cash flows assuming the development of the company's proved plus probable reserves evaluated as at December 31, 2013, ii) future cash flows incorporating additional growth in accordance with managements strategic growth plans, and iii) suspension of all activity at the end of 2014. The first two scenarios were equally weighted at 45% each and the final scenario was assigned a weighting of 10% based on the company's best estimates. All scenarios assumed the restart of production on April 1, 2014.

The estimates used in calculating the net recoverable amounts were based on current forecasts for the price of commodities, the company's estimate of price realizations, estimates of operating and development expenditures based on the field development anticipated by Suncor's business plans, and a discount rate of 17% that represented management's best estimate of the ongoing risk involved with operating in Libya.

Fort Hills

On October 30, 2013, the co-owners of Fort Hills announced project sanction. As a result, the accumulated capital costs in Exploration and Evaluation were transferred to oil and gas properties in Property, Plant and Equipment and an impairment test was required in accordance with IFRS 6 Exploration for and Evaluation of Mineral Resources. A fair value less costs of disposal methodology was used to determine the recoverable amount and, as it exceeded the carrying amount, no impairment was recorded.

The significant estimates used in calculating the net recoverable amounts included current forecasts for the price of bitumen, future capital costs and discount rate. The assumptions used by management to calculate the recoverable amount may change. Changes in these assumptions will have an impact on the recoverable amount and could result in impairment. Refer to note 17 of the Consolidated Financial Statements for further details.

Decommissioning and Restoration Costs

The company recognizes liabilities for the future decommissioning and restoration of Exploration and Evaluation assets and Property, Plant and Equipment. Management applies judgment in assessing the existence and extent, as well as the expected method of reclamation of the company's decommissioning and restoration obligations at the end of each reporting period. Management also uses judgment to determine whether the nature of the activities performed are related to decommissioning and restoration activities or normal restoration, technological advances and the possible future use of the site. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience, prices and closure plans. The estimated timing of future decommissioning and restoration may change due to certain factors, including reserve life. Changes to estimates related to future expected costs, discount rates and timing may have a material impact on the amounts presented.

Suncor's provision for decommissioning and restoration costs decreased by $450 million in 2013 to $4.238 billion. The most significant change in the provision related to decommissioning and restoration liabilities related to the sale of the company's natural gas business, which was partially offset by increased disturbance in other areas of the company's operations and increase in certain cost estimates. The provision also decreased due to an increase

64   SUNCOR ENERGY INC. ANNUAL REPORT 2013


in the average credit-adjusted discount rate (2013 – 4.51%; 2012 – 3.75%).

Employee Future Benefits

The company provides benefits to employees, including pensions and other post-retirement benefits. The cost of defined benefit pension plans and other post-retirement benefits received by employees is estimated based on actuarial valuation methods that require professional judgment. Estimates typically used in determining these amounts include, as applicable, rates of employee turnover, future claim costs, discount rates, future salary and benefit levels, the return on plan assets, mortality rates and future medical costs. Changes to these estimates may have a material impact on the amounts presented.

The fair value of plan assets is determined using market values. The estimated rate of return on plan assets in the portfolio considers the current level of returns on fixed income assets, the historical level of risk premium associated with other asset classes and the expected future returns on all asset classes. The discount rate assumption is based on the year-end interest rates for high-quality bonds that mature at times concurrent with the company's benefit obligations. The estimated rate for compensation increases is based on management's judgment.

Actuarial valuations are subject to management's judgment. Actuarial gains and losses comprise changes to assumptions related to discount rates, expected return on plan assets and annual rates for compensation increases. They are accounted for on a prospective basis and may have a material impact on the amounts presented.

Other Provisions

The determination of other provisions, including, but not limited to, provisions for royalty disputes, onerous contracts, litigation and constructive obligations, is a complex process that involves judgments about the outcomes of future events, the interpretation of laws and regulations, and estimates on timing and amount of expected future cash flows and discount rates.

In December 2013, Suncor reached an agreement with the Government of Alberta concerning several outstanding issues under the RAA entered into in 2008. The impacts of the final settlements were not material to the company's results. The company is no longer recording a provision related to royalty disputes under the RAA.

The company is involved in litigation and claims in the normal course of operations. As at December 31, 2013, management believes the result of any settlements related to such litigation or claims would not materially affect the financial position of the company.

Income Taxes

Management evaluates tax positions, annually or when circumstances require, which involves judgment and could be subject to differing interpretations of applicable tax legislation. The company recognizes a tax provision when a payment to tax authorities is considered probable. However, the results of audits and reassessments and changes in the interpretations of standards may result in changes to those positions and potentially a material increase or decrease in the company's assets, liabilities and net earnings.

In January 2013, the company received a proposal letter from the Canada Revenue Agency (CRA) relating to the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts. Following Suncor's response to a number of information requests in 2013, the CRA informed the company that it has not changed its original proposed position.

In the event that the CRA issues a formal Notice of Reassessment (NOR), Suncor plans to file a Notice of Objection to dispute this matter. However, notwithstanding the filing of an objection, the company would be required to make a minimum payment of 50% of the amount payable under the NOR, estimated to be $600 million, which would remain on account until the dispute is resolved.

Suncor strongly disagrees with the CRA's position and firmly believes it will be able to successfully defend its original filing position so that, ultimately, no increased income tax payable will result from the CRA's actions. If the company is unsuccessful in defending its tax filing position, it could be subject to an earnings impact of up to $1.2 billion.

Deferred Income Taxes

Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing tax laws in each jurisdiction differ significantly from the company's estimate, the ability of the company to realize the deferred tax assets could be impacted.

Deferred tax liabilities are recognized when there are taxable temporary differences that will reverse and result in a future outflow of funds to a taxation authority. The company records a provision for the amount that is expected to be settled, which requires judgment as to the ultimate outcome. Deferred tax liabilities could be impacted by changes in the company's judgment of the likelihood of a future outflow, estimates of the expected settlement amount, timing of reversals, and the tax laws in the jurisdictions in which the company operates.

SUNCOR ENERGY INC. ANNUAL REPORT 2013    65


Control and Significant Influence

Control is defined as the power to govern the financial and operating decisions of an entity so as to obtain benefits from its activities, and significant influence is defined as the power to participate in the financial and operating decisions of the investee. The assessment of whether the company has control, joint control, or significant influence over another entity requires judgment of the impact it has over the financial and operating decisions of the entity and the extent of the benefits it obtains.

Joint Arrangements

The classification of joint arrangements structured through separate vehicles as either joint ventures or joint operations requires significant judgment and depends on the legal form and contractual terms of the arrangement as well as other facts and circumstances. These include whether there is exclusive dependence on the parties to the joint arrangement for cash flows through the sale of product and funding of operations, and to assess the rights of the economic benefits of the assets and obligation for funding the liabilities of the arrangements. A joint arrangement whereby the parties take their share of substantially all of the output of the joint arrangement would be an indicator for classification as a joint operation, regardless of structure of the arrangement, and accounted for by recognizing the company's share of assets and liabilities jointly owned and incurred, and the recognition of its share of revenue and expenses of the joint operation.

Fair Value of Financial Instruments

The fair value of financial instruments is determined whenever possible based on observable market data. If not available, the company uses third-party models and valuation methodologies that utilize observable market data, including forward commodity prices, foreign exchange rates and interest rates to estimate the fair value of financial instruments, including derivatives. In addition to market information, the company incorporates transaction-specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk.

66   SUNCOR ENERGY INC. ANNUAL REPORT 2013

10. RISK FACTORS

Suncor is committed to a proactive program of enterprise risk management intended to enable decision-making through consistent identification of risks inherent to its assets, activities and operations. Some of these risks are common to operations in the oil and gas industry as a whole, while some are unique to Suncor. The company's enterprise risk committee (ERC), comprised of senior representatives from business and functional groups across Suncor, oversees entity-wide processes to identify, assess and report on the company's principal risks. A principal risk is an exposure that has the potential to materially impact the ability of one of our businesses or functions to meet or support a Suncor objective. The realization of any of the following principle risk factors could have a material adverse effect on our business, financial condition, results of operations and cash flow:

Volatility of Commodity Prices

Our financial performance is closely linked to prices for crude oil in our upstream business and prices for refined petroleum products in our downstream business, and, to a lesser extent, to natural gas prices in our upstream business, where natural gas is both an input and output of production processes. The prices for all of these commodities can be influenced by global and regional supply and demand factors, which are factors that are beyond our control and can result in a high degree of price volatility

Crude oil prices are also affected by, among other things, global economic health and global economic growth (particularly in emerging markets), pipeline constraints, regional and international supply and demand imbalances, political developments, compliance or non-compliance with quotas imposed on Organization of Petroleum Exporting Countries (OPEC) members, access to markets for crude oil and weather. These factors impact the various types of crude oil and refined products differently and can impact differentials between light and heavy grades of crude oil (including blended bitumen), and between conventional and synthetic crude oil.

Refined petroleum product prices and refining margins are also affected by, among other things, crude oil prices, the availability of crude oil and other feedstock, levels of refined product inventories, regional refinery availability, marketplace competitiveness, and other local market factors. Natural gas prices in North America are affected primarily by supply and demand, and by prices for alternative energy sources.

Commodity prices and refining margins have fluctuated widely in recent years. Given the recent global economic uncertainty, we expect continued volatility and uncertainty in commodity prices in the near term. A prolonged period of low prices could affect the value of our upstream and downstream assets and the level of spending on growth projects, and could result in the curtailment of production from some properties and/or the impairment of that property's carrying value. Accordingly, low commodity prices, particularly for crude oil, could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow, and may also lead to impairments or write-offs of the values of Suncor's assets or projects in development.

Operational Outages and Major Environmental or Safety Incidents

Each of Suncor's primary operating businesses – Oil Sands, Exploration and Production, and Refining and Marketing – demand significant levels of investment in the design, operation and maintenance of facilities, and, therefore, carry the additional economic risk associated with operating reliably or enduring a protracted operational outage. These businesses also carry the risks associated with environmental and safety performance, which is closely scrutinized by governments, the public and the media, and could result in a suspension of or inability to obtain regulatory approvals and permits, or, in the case of a major environmental or safety incident, civil suits or charges against the company.

Generally, Suncor's operations are subject to operational hazards and risks such as fires, explosions, blow-outs, power outages, severe winter climate conditions and the migration of harmful substances such as oil spills, gaseous leaks or a release of tailings into water systems, any of which can interrupt operations or cause personal injury or death, or damage to property, equipment, the environment, and information technology systems and related data and control systems.

The reliable operation of production and processing facilities at planned levels and Suncor's ability to produce higher value products can also be impacted by failure to follow operating procedures or operate within established operating parameters, equipment failure through inadequate maintenance, unanticipated erosion or corrosion of facilities, manufacturing and engineering flaws, and labour shortage or interruption. The company is also subject to operational risks such as sabotage, terrorism, trespass, theft and malicious software or network attacks.

The efficient operation of Suncor's business is dependent on computer hardware and software systems. Information systems are vulnerable to security breaches by computer hackers and cyberterrorists. We rely on industry-accepted

SUNCOR ENERGY INC. ANNUAL REPORT 2013    67


security measures and technology to securely maintain confidential and proprietary information stored on our information systems. However, these measures and technology may not adequately prevent security breaches. In addition, the unavailability of the information systems or the failure of these systems to perform as anticipated for any reason could disrupt our business and could result in decreased performance and increased costs, causing our business and results of operations to suffer. Any significant interruption or failure of our information systems or any significant breach of security could adversely affect our business, financial condition, results of operations and cash flow.

For Suncor's Oil Sands operations, mining oil sands ore, extracting bitumen from mined ore, producing bitumen through in situ methods, and upgrading bitumen into SCO and other products involve particular risks and uncertainties. Oil Sands operations are susceptible to loss of production, slowdowns, shutdowns or restrictions on our ability to produce higher value products, due to the interdependence of its component systems.

For Suncor's upstream businesses, there are risks and uncertainties associated with drilling for oil and natural gas, the operation and development of such properties and wells (including encountering unexpected formations, pressures, ore grade qualities, or the presence of H2S), premature declines of reservoirs, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, other accidents, and pollution and other environmental risks.

Suncor's Exploration and Production operations include drilling offshore of Newfoundland and Labrador and in the North Sea offshore of the U.K. and Norway, which are areas subject to hurricanes and other extreme weather conditions. Drilling rigs in these regions may be exposed to damage or total loss by these storms, some of which may not be covered by insurance. The consequence of catastrophic events, such as blow-outs, occurring in offshore operations can be more difficult and time-consuming to remedy. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death of rig personnel. Successful remediation of these events may be adversely affected by the water depths, pressures and cold temperatures encountered in the ocean, shortages of equipment and specialists required to work in these conditions, or the absence of appropriate technology to resolve the event. Damage to the environment, particularly through oil spillage or extensive, uncontrolled fires or death, could result from these offshore operations. Suncor's offshore operations could also be affected by the actions of Suncor's contractors and agents that could result in similar catastrophic events at their facilities, or could be indirectly affected by catastrophic events occurring at other third-party offshore operations. In either case, this could give rise to liability, damage to the company's equipment, harm to individuals, force a shutdown of our facilities or operations, or result in a shortage of appropriate equipment or specialists required to perform our planned operations.

In particular, East Coast Canada operations can be impacted by winter storms, pack ice, icebergs and fog. During the winter storm season (October to March), the company may have to reduce production rates at its offshore facilities as a result of limited storage capacity and the inability to offload to shuttle tankers due to wave height restrictions. During the spring, pack ice and icebergs drifting in the area of our offshore facilities have resulted in precautionary shut in of FPSO production and drilling delays. In late spring and early summer, fog also impacts our ability to transfer personnel to the offshore facilities by helicopter.

Suncor's Refining and Marketing operations are subject to all of the risks normally inherent in the operation of refineries, terminals, pipelines and other distribution facilities and service stations, including loss of product, slowdowns due to equipment failures, unavailability of feedstock, price and quality of feedstock or other incidents.

Losses resulting from the occurrence of any of these risks identified above could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow. Although the company maintains a risk management program, which includes an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable. It is possible that our insurance coverage will not be sufficient to address the costs arising out of the allocation of liabilities and risk of loss arising from offshore operations.

Project Execution

There are certain risks associated with the execution of our major projects and the commissioning and integration of new facilities within our existing asset base, the occurrence of which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Project execution risk consists of three related primary risks:

•
Engineering – a failure in the specification, design or technology selection;

•
Construction – a failure to build the project in the approved time and at the agreed cost; and

•
Commissioning and start-up – a failure of the facility to meet agreed performance targets, including operating costs, efficiency, yield and maintenance costs.

68   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Management believes the execution of major projects presents issues that require prudent risk management. Suncor may provide cost estimates for major projects at the conceptual stage, prior to commencement or completion of the final scope design and detailed engineering necessary to reduce the margin of error of such cost estimates. Accordingly, actual costs can vary from estimates, and these differences can be material. Project execution can also be impacted by:

•
Failure to comply with Suncor's project implementation model;

•
The availability, scheduling and cost of materials, equipment and qualified personnel;

•
The complexities associated with integrating and managing contractor staff and suppliers in a confined construction area;

•
Our ability to obtain the necessary environmental and other regulatory approvals;

•
The impact of general economic, business and market conditions;

•
The impact of weather conditions;

•
Our ability to finance growth if commodity prices were to decline and stay at low levels for an extended period;

•
Risks relating to restarting projects placed in safe mode, including increased capital costs;

•
The effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment; and

•
Risk associated with offshore fabrication and logistics.

In addition, there are certain risks associated with the execution of our exploration, production and refining projects. These risks include, but are not limited to:

•
Our ability to obtain the necessary environmental and regulatory approvals;

•
Risks relating to scheduling, resources and costs, including the availability and cost of materials, equipment and qualified personnel;

•
The impact of general economic, business and market conditions;

•
The impact of weather conditions;

•
The accuracy of project cost estimates;

•
Our ability to finance growth;

•
Our ability to source or complete strategic transactions;

•
The effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment; and

•
The commissioning and integration of new facilities within our existing asset base could cause delays in achieving guidance, targets and objectives.

The failure to sanction or build a project could result in additional costs, including abandonment and reclamation costs, to shut down the project, and such costs could be material to Suncor.

Cost Management

Production from oil sands through mining, upgrading and in situ recovery is, relative to most major conventional hydrocarbon reserves, a higher cost resource to develop and produce. Suncor is exposed to the risk of escalating operating costs in both its oil sands business and other businesses, which could reduce profitability and cash flow, and materially adversely affect Suncor's business, financial condition and results of operations, and may reduce cash flow available for growth or dividends and major project capital costs. This may constrain Suncor's ability to execute high-quality projects that deliver lower operating costs. Factors contributing to these risks include, but are not limited to, the skills and resource shortage, the long-term success of existing and new in situ technologies, and the geology and reserves characterization of in situ reserves that can lead to higher steam-to-oil ratios and lower production.

Government Policy

Suncor operates under federal, provincial, state and municipal legislation in numerous countries. The company is also subject to regulation and intervention by governments in oil and gas industry matters, such as land tenure, royalties, taxes (including income taxes), government fees, production rates, environmental protection controls, safety performance, the reduction of greenhouse gas (GHG) and other emissions, the export of crude oil, natural gas and other products, the company's interactions with foreign governments, the awarding or acquisition of exploration and production rights, oil sands leases or other interests, the imposition of specific drilling obligations, control over the development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights.

Changes in government policy or regulation or interpretation thereof, have a direct impact on Suncor's business, financial condition, results of operations and cash flow, as evidenced by such initiatives as the Alberta government's royalty review program in 2007, and, more recently, by trade sanctions in Libya (which have since been lifted) and Syria imposed by Canadian and other international governments, and increased production taxes in the U.K. Changes in government policy or regulation can also have an indirect impact on Suncor, including

SUNCOR ENERGY INC. ANNUAL REPORT 2013    69


opposition to new North American pipeline systems, such as the Keystone XL or the Northern Gateway proposals, or incrementally over time, through increasingly stringent environmental regulations or unfavourable income tax and royalty regimes. The result of such changes can also lead to additional compliance costs and staffing and resource levels, and also increase exposure to other principal risks of Suncor, including environmental or safety non-compliance and permit approvals.

Environmental Regulation

Changes in environmental regulation could have a material adverse effect on our business, financial condition, results of operations and cash flow by impacting the demand, formulation or quality of our products, or by requiring increased capital expenditures or distribution costs, which may or may not be recoverable in the marketplace. The complexity and breadth of changes in environmental regulation make it extremely difficult to predict the potential impact to Suncor. Suncor positions itself to be ahead of proposed changes or engages in the discussion on proposed changes to ensure Suncor's interests are recognized.

The company anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Failure to comply with environmental regulation may result in the imposition of significant fines and penalties, liability for cleanup costs and damages, and the loss of important licences and permits, which may, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flow. Through industry associations, Suncor participates, both directly and indirectly, in the consultation process for the design of proposed regulations and other efforts to harmonize regulations across jurisdictions within North America.

Some of the issues that are or may in the future be subject to environmental regulation include:

•
The possible cumulative regional impacts of oil sands development;

•
The manufacture, import, storage, treatment and disposal of hazardous or industrial waste and substances;

•
The need to reduce or stabilize various emissions to air;

•
Withdrawals, use of, and discharges to water;

•
The use of hydraulic fracturing to assist in the recovery and production of oil and natural gas;

•
Issues relating to land reclamation, restoration and wildlife habitat protection;

•
Issues related to offset requirements for various land disturbances;

•
Reformulated gasoline to support lower vehicle emissions;

•
U.S. state or federal calculation and regulation of fuel life-cycle carbon content; and

•
Regulation or policy by foreign governments or other organizations to limit purchases of oil produced from unconventional sources, such as the oil sands.

Climate Change Regulation

Future laws and regulations may impose significant liabilities on a failure to comply with their requirements; however, Suncor expects the cost of meeting new environmental and climate change regulations will not be so high as to cause material disadvantage to the company or material damage to its competitive positioning. While it currently appears that GHG regulations and targets will continue to become more stringent, and while Suncor will continue efforts to reduce the intensity of its GHG emissions, the absolute GHG emissions of our company will continue to rise as we pursue a prudent and planned growth strategy.

As part of its ongoing business planning, Suncor assesses potential costs associated with carbon dioxide emissions in its evaluation of future projects, based on the company's current understanding of pending and possible GHG regulations. Both the U.S. and Canada have indicated that climate change policies that may be implemented will attempt to balance economic, environmental and energy security concerns. In the future, the company expects that regulation will evolve with a moderate carbon price signal, and that the price regime will progress cautiously. Suncor will continue to review the impact of future carbon constrained scenarios on its strategy, using a price range of $15 to $60 per tonne of carbon dioxide equivalent as a base case, applied against a range of regulatory policy options and price sensitivities.

The Canadian federal government has indicated a preference for a sector-specific approach to climate change regulation; however, it is unclear what form any regulation will take for the oil and gas sector, and what type of compliance mechanisms will be available to large emitters. At this time, the company does not believe it is possible to predict the nature of any requirements or the impact on Suncor's business, financial condition, results of operations and cash flow. The impact of developing regulations cannot be quantified at this time in the absence of detail on how systems will operate.

Although Suncor does not actively market into California, the implications of other states or countries adopting similar Low Carbon Fuel Standard legislation could pose a

70   SUNCOR ENERGY INC. ANNUAL REPORT 2013


significant barrier to its exports of oil sands crude if the importing jurisdictions do not acknowledge efforts undertaken by the oil sands industry to meet the emissions intensity reductions legislated by the Government of Alberta.

Land Reclamation

There are risks associated specifically with the company's ability to reclaim tailings ponds containing mature fine tailings, with TROTM or other methods and technologies. Suncor expects that TROTM will help the company reclaim existing tailings ponds by reducing the volumes of fluid fine tailings. The success of TROTM or any other methods of technology and the time to reclaim tailings ponds could increase or decrease Suncor's decommissioning and restoration cost estimates. The company's failure or inability to adequately implement its reclamation plans could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Alberta's Land-Use Framework

Alberta's Land-Use Framework (LUF) has been implemented under the Alberta Land Stewardship Act (ALSA), which sets out the Government of Alberta's approach to managing Alberta's land and natural resources to achieve long-term economic, environmental and social goals. ALSA contemplates the amendment or extinguishment of previously issued consents such as regulatory permits, licences, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan.

On August 22, 2012, the Government of Alberta approved the Lower Athabasca Regional Plan (LARP), the first regional plan under the LUF. The LARP includes management frameworks for air, land, and water quality that incorporate cumulative limits and triggers. As well, the LARP identifies areas related to conservation, tourism and recreation.

A management framework for water quantity (water withdrawals from the Athabasca River) has recently been announced. A management framework for biodiversity is under development.

The implementation of, and compliance with, the terms of the LARP may adversely impact our current properties and projects in northern Alberta due to, among other things, environmental limits and thresholds. Due to the cumulative nature of the plan, the impact of the LARP on Suncor's operations may be outside of the control of the company, as Suncor's operations could be impacted as a result of restrictions imposed due to the cumulative impact of development, by the operators in the area and not solely in relation to Suncor's direct impact.

Alberta Environment Water Licences

We currently rely on fresh water, which is obtained under licences from Alberta Environment to provide domestic and utility water at our Oil Sands operations. Water licences, like all regulatory approvals, contain conditions to be met in order to maintain compliance with the licence. Although there can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences, without evidence of an environmental impact associated with the licence and providing compliance is maintained, this is not likely to occur. There can be no assurance that the company will not have to pay a fee for the use of water in the future or that any such fees will be reasonable, although there is currently no evidence that governments are contemplating such a fee at this time. In addition, the expansion of the company's projects may rely on securing licences for additional water withdrawal, and there can be no assurance that these licences will be granted or that they will be granted on terms favourable to Suncor.

Income Taxes

In January 2013, the company received a proposal letter from the CRA relating to the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts. Following Suncor's response to a number of information requests in 2013, the CRA informed the company that it has not changed its original proposed position.

In the event that the CRA issues a formal Notice of Reassessment (NOR), Suncor plans to file a Notice of Objection to dispute this matter. However, notwithstanding the filing of an objection, the company would be required to make a minimum payment of 50% of the amount payable under the NOR, estimated to be $600 million, which would remain on account until the dispute is resolved.

Suncor strongly disagrees with the CRA's position and firmly believes it will be able to successfully defend its original filing position so that, ultimately, no increased income tax payable will result from the CRA's actions. If the company is unsuccessful in defending its tax filing position, it could be subject to an earnings impact of up to $1.2 billion.

Skills and Resource Shortage

The successful operation of Suncor's businesses and our ability to expand operations will depend upon the availability of, and competition for, skilled labour and materials supply. There is a risk that we may have difficulty sourcing the required labour for current and future operations. The risk could manifest itself primarily through an inability to recruit new staff without a dilution of talent, to train, develop and retain high-quality and experienced

SUNCOR ENERGY INC. ANNUAL REPORT 2013    71

staff without unacceptably high attrition, and to satisfy an employee's work/life balance and desire for competitive compensation. The labour market in Alberta is particularly tight due to the growth of the oil sands industry. The increasing age of our existing workforce adds further pressure to this situation. Materials may also be in short supply due to smaller labour forces in many manufacturing operations. Our ability to operate safely and effectively and complete all our projects on time and on budget has the potential to be significantly impacted by these risks.

Change Capacity

In order to achieve Suncor's business objectives, the company must operate efficiently, reliably and safely, and, at the same time, deliver growth and sustaining projects safely, on budget and on schedule. The ability to balance these two sets of objectives is critically important to Suncor to deliver value to shareholders and stakeholders. These objectives also demand a large number of improvement initiatives that compete for resources, and may negatively impact the company should there be inadequate consideration of the cumulative impacts of prior and parallel initiatives on people, processes and systems. There is a risk that these objectives may exceed Suncor's capacity to adopt and implement change.

Other Risk Factors

A detailed discussion of additional risk factors is presented in our most recent Annual Information Form / Form 40-F, filed with securities regulators.


11. OTHER ITEMS

Control Environment

Based on their evaluation as of December 31, 2013, Suncor's Chief Executive Officer and Interim Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as of December 31, 2013, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the year ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting. Management will continue to periodically evaluate the company's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

As a result of political unrest in Syria, Suncor is not able to monitor the status of the Syrian assets, including whether certain facilities have suffered damages. Suncor is continually assessing the control environment in Syria to the extent permitted by applicable law and does not consider the changes in the country to have had a material impact on the company's overall internal control over financial reporting.

The effectiveness of our internal control over financial reporting as at December 31, 2013 was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2013.

Based on their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Corporate Guidance

Detailed guidance on the company's outlook for 2014 production, capital expenditures and other items can be found in Suncor's press release dated February 3, 2014, available on www.sedar.com and on the Suncor website at www.suncor.com/guidance. The press release provides updates to the guidance that was previously issued on November 20, 2013.

72   SUNCOR ENERGY INC. ANNUAL REPORT 2013

12. ADVISORIES

Non-GAAP Financial Measures

Certain financial measures in this MD&A – namely operating earnings, ROCE, cash flow from operations, free cash flow, Oil Sands cash operating costs and LIFO – are not prescribed by GAAP. These non-GAAP financial measures are included because management uses the information to analyze operating performance, leverage and liquidity. These non-GAAP financial measures do not have any standardized meaning and, therefore, are unlikely to be comparable to similar measures presented by other companies. Therefore, these non-GAAP financial measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Except as otherwise indicated, these non-GAAP measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

Effective January 1, 2013, Suncor adopted new and amended accounting standards; as such, non-GAAP measures for 2012 have been restated while comparative figures pertaining to Suncor's results prior to and including 2011 have not been restated in accordance with the respective transitional provisions of the new and amended standards.

Non-GAAP measures for 2009 are reported under a previous GAAP.

Operating Earnings

Operating earnings is a non-GAAP financial measure that adjusts net earnings for significant items that are not indicative of operating performance. Management uses operating earnings to evaluate operating performance, because management believes it provides better comparability between periods. Operating earnings are reconciled to net earnings in the Financial Information section of the MD&A.

The following is a reconciliation of net earnings to operating earnings for Suncor's last five years of operations. Operating earnings for 2009 have been adjusted from operating earnings previously reported to include the effect of project start-up costs and mark-to-market valuations of stock-based compensation, which were previously excluded when calculating operating earnings.

($ millions)   2013   2012   2011   2010   2009    
Net earnings as reported   3 911   2 740   4 304   3 829   1 146    
Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt   521   (157 ) 161   (372 ) (798 )  
Impairments and write-offs, net of reversals   563   2 176   629   306   42    
Recognition of risk mitigation proceeds   (223 ) —   —   —   —    
(Gain) loss on significant disposals   (130 ) —   107   (826 ) 39    
Net impact of not proceedings with the Voyageur upgrader project   58   —   —   —   —    
Impact of income tax rate adjustment on deferred income taxes   —   88   442   —   4    
Adjustments to provisions for assets acquired through the merger   —   —   31   68   97    
Change in fair value of commodity derivatives used for risk management, net of realizations   —   —   —   (233 ) 499    
Redetermination of working interests in Terra Nova   —   —   —   (166 ) 24    
Modification of the bitumen valuation methodology   —   —   —   (51 ) 50    
Merger and integration costs   —   —   —   79   151    
Gain on effective settlement of pre-existing contract with Petro-Canada   —   —   —   —   (438 )  
Costs related to deferral of growth projects   —   —   —   —   299    
Operating earnings   4 700   4 847   5 674   2 634   1 115    

SUNCOR ENERGY INC. ANNUAL REPORT 2013    73

Bridge Analyses of Operating Earnings

Throughout this MD&A, the company presents charts that illustrate the change in operating earnings from the comparative period through key variance factors. These factors are analyzed in the Operating Earnings narratives following the bridge analyses in a particular section of the MD&A. These bridge analyses are presented because management uses this presentation to analyze performance.

•
The factor for Volumes and Mix is calculated based on production volumes and mix for the Oil Sands and Exploration and Production segments and throughput volumes and mix for the Refining and Marketing segment.

•
The factor for Price, Margin and Other Revenue includes upstream price realizations before royalties, refining and marketing margins, other operating revenues, and the net impacts of sales and purchases of third-party crude, including product purchased for use as diluent in the company's Oil Sands operations and subsequently sold as part of diluted bitumen.

•
The factor for Royalties includes royalties in Libya that represent the difference between gross revenues, which is based on the company's working-interest share of production, and the net revenue attributable to Suncor under the terms of the respective contracts.

•
The factor for Inventory reflects the opportunity cost of building production volumes in inventory or the additional margin earned by drawing down inventory produced in previous periods. The calculation of the Inventory factor in a bridge analysis permits the company to present the factor for Volumes and Mix based on production volumes, rather than based on sales volumes.

•
The factor for Operating and Transportation Expense includes project start-up costs, operating, selling and general expense (adjusted for impacts of changes in inventory), and transportation expense.

•
The factor for Financing Expense and Other Income includes financing expenses, other income, operational foreign exchange gains and losses, changes in gains and losses on disposal of assets that are not operating earnings adjustments, changes in statutory income tax rates, and other income tax adjustments.

Return on Capital Employed (ROCE)

ROCE is a non-GAAP financial measure that management uses to analyze operating performance and the efficiency of Suncor's capital allocation process. Average capital employed is calculated as a thirteen-month average of the capital employed balance at the beginning of the twelve-month period and the month-end capital employed balances throughout the remainder of the twelve-month period. Figures for capital employed at the beginning and end of the twelve-month period are presented to show the changes in the components of the calculation over the twelve-month period.

74   SUNCOR ENERGY INC. ANNUAL REPORT 2013

The company presents two ROCE calculations – one including and one excluding the impacts on capital employed of major projects in progress. Major projects in progress includes accumulated capital expenditures and capitalized interest for significant projects still under construction or in the process of being commissioned, and acquired assets that are still being evaluated. Management uses ROCE excluding the impacts of major projects in progress on capital employed to assess performance of operating assets.

Year ended December 31
($ millions, except as noted)		       2013   2012   2011   2010   2009    
Adjustments to net earnings                            
  Net earnings       3 911   2 740   4 304   3 829   1 146    
  Add after-tax amounts for:                            
    Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt   521   (157 ) 161   (372 ) (858 )  
    Net interest expense       228   42   83   327   349    
    A   4 660   2 625   4 548   3 784   637    
Capital employed – beginning of twelve-month period                        
  Net debt       6 639   6 976   11 254   13 516   7 226    
  Shareholders' equity       39 215   38 592   35 192   32 485   14 523    
    D   45 854   45 568   46 446   46 001   21 749    
Capital employed – end of twelve-month period                        
  Net debt       6 256   6 639   6 976   11 254   13 377    
  Shareholders' equity       41 180   39 215   38 600   35 192   34 111    
        47 436   45 854   45 576   46 446   47 488    
Average capital employed   B   46 981   45 353   44 956   46 075   35 128    
ROCE – including major projects in progress (%)   A/B   9.9   5.8   10.1   8.2   1.8    
Average capitalized costs related to major projects in progress   C   6 502   8 729   12 106   12 890   10 655    
ROCE – excluding major projects in progress (%)   A/(B-C)   11.5   7.2   13.8   11.4   2.6    

SUNCOR ENERGY INC. ANNUAL REPORT 2013    75

Cash Flow from Operations and Free Cash Flow

Cash flow from operations is a non-GAAP financial measure that adjusts a GAAP measure – cash flow provided by operating activities – for changes in non-cash working capital, which management uses to analyze operating performance and liquidity. Changes to non-cash working capital can include, among other factors, the timing of offshore feedstock purchases and payments for fuel and income taxes, which management believes reduces comparability between periods.

    Oil Sands   Exploration and Production   Refining and Marketing    
Year ended December 31 ($ millions)   2013   2012   2011   2013   2012   2011   2013   2012   2011    
Net earnings (loss)   2 040   468   2 603   1 000   138   306   2 022   2 137   1 726    
Adjustments for:                                        
  Depreciation, depletion, amortization and impairment   2 439   3 964   1 374   1 804   1 857   2 035   530   464   444    
  Deferred income taxes   358   266   895   (130 ) 28   354   64   529   494    
  Accretion of liabilities   114   109   85   60   62   69   6   4   3    
  Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt   —   —   —   —   —   —   —   —   —    
  Change in fair value of derivative contracts   —   —   —   —   —   —   1   (1 ) 3    
  (Gain) loss on disposal of assets   —   (29 ) 122   (130 ) (1 ) 31   (7 ) (13 ) (16 )  
  Share-based compensation   7   95   (35 ) 28   14   (4 ) 19   48   (21 )  
  Exploration expenses   —   —   —   82   145   28   —   —   —    
  Settlement of decommissioning and restoration liabilities   (388 ) (380 ) (458 ) (15 ) (32 ) (19 ) (20 ) (21 ) (19 )  
  Other   (14 ) (86 ) (14 ) (383 ) 16   46   3   (9 ) (40 )  
Cash flow from (used in) operations   4 556   4 407   4 572   2 316   2 227   2 846   2 618   3 138   2 574    
Decrease (increase) in non-cash working capital   1 225   (781 ) (676 ) 656   (205 ) 398   566   (460 ) 600    
Cash flow provided by (used in) operating activities   5 781   3 626   3 896   2 972   2 022   3 244   3 184   2 678   3 174    

76   SUNCOR ENERGY INC. ANNUAL REPORT 2013

 
                Corporate, Energy
Trading and Eliminations		   Total    
Year ended December 31 ($ millions)               2013   2012   2011   2013   2012   2011    
Net (loss) earnings               (1 151 ) (3 ) (331 ) 3 911   2 740   4 304    
Adjustments for:                                        
  Depreciation, depletion, amortization and impairment               119   161   99   4 892   6 446   3 952    
  Deferred income taxes               90   (94 ) (99 ) 382   729   1 644    
  Accretion of liabilities               12   7   —   192   182   157    
  Unrealized foreign exchange loss (gain)
on U.S. dollar denominated debt		               605   (181 ) 183   605   (181 ) 183    
  Change in fair value of derivative contracts               94   11   (43 ) 95   10   (40 )  
  Loss (gain) on disposal of assets               —   (1 ) (1 ) (137 ) (44 ) 136    
  Share-based compensation               160   57   (42 ) 214   214   (102 )  
  Exploration expenses               —   —   —   82   145   28    
  Settlement of decommissioning and restoration liabilities               —   —   —   (423 ) (433 ) (496 )  
  Other               (7 ) 4   (12 ) (401 ) (75 ) (20 )  
Cash flow (used in) from operations               (78 ) (39 ) (246 ) 9 412   9 733   9 746    
Decrease (increase) in non-cash working capital               (1 759 ) 572   (80 ) 688   (874 ) 242    
Cash flow (used in) provided by operating activities               (1 837 ) 533   (326 ) 10 100   8 859   9 988    

The following is a reconciliation of cash flow from operations for Suncor's last five years of operations.

($ millions)   2013   2012   2011   2010   2009  
Cash flow provided by operating activities   10 100   8 859   9 988   5 486   2 575  
(Decrease) increase in non-cash working capital   (688 ) 874   (242 ) 1 170   224  
Cash flow from operations   9 412   9 733   9 746   6 656   2 799  

Free cash flow is a non-GAAP financial measure that is calculated by deducting capital and exploration expenditures from cash flow from operations. Free cash flow reflects cash available for distribution to shareholders and to fund financing activities. Management uses free cash flow to measure financial performance and liquidity. The following is a reconciliation of free cash flow for Suncor's last three years of operations.

($ millions)   2013   2012   2011    
Cash flow from operations   9 412   9 733   9 746    
Capital and exploration expenditures   (6 777 ) (6 957 ) (6 850 )  
Free Cash Flow   2 635   2 776   2 896    

Oil Sands Cash Operating Costs

Oil Sands cash operating costs and cash operating costs per barrel are non-GAAP financial measures, which are calculated by adjusting Oil Sands segment operating, selling and general expense (a GAAP measure based on sales volumes) for i) costs pertaining to Syncrude operations; ii) non-production costs that management believes do not relate to the production performance of Oil Sands Operations, including, but not limited to, share-based compensation adjustments, costs related to the remobilization or deferral of growth projects, research, the expense recorded as part of a

SUNCOR ENERGY INC. ANNUAL REPORT 2013    77

non-monetary arrangement involving a third-party processor, and feedstock costs for natural gas used to create hydrogen for secondary upgrading processes; iii) excess power generated and sold that is recorded in operating revenue; and iv) the impacts of changes in inventory levels, such that the company is able to present cost information based on production volumes.

Effective 2012, the calculation of Oil Sands cash operating costs has been updated to better reflect the ongoing cash cost of production, and prior period figures have been redetermined. The cost of natural gas feedstock for secondary upgrading processes, the cost of diluent purchased for transportation of product to markets, and non-cash costs related to the accretion of liabilities for decommissioning and restoration provisions are no longer included in cash operating costs. Certain cash costs relating to safety programs, which were previously considered non-production costs, are included in cash operating costs. The following table reconciles amounts previously reported to those presented in this MD&A:

Year ended December 31 ($ millions)   2011    
Cash operating costs, as previously reported   4 479    
Elements added to cash operating costs definition:        
Safety programs   33    
Elements removed from cash operating costs definition:        
Natural gas feedstock for secondary upgrading processes   (53 )  
Accretion of liabilities   (64 )  
Purchased diluent   (40 )  
Cash operating costs, as restated in this MD&A   4 355    
Cash operating costs, as previously reported ($/bbl)   40.20    
Cash operating costs, as restated in this MD&A ($/bbl)   39.05    

Impact of First-in, First-out Inventory Valuation on Refining and Marketing Net Earnings

GAAP requires the use of a FIFO valuation methodology. For Suncor, this results in a disconnect between the sales prices for refined products, which reflect current market conditions, and the amount recorded as the cost of sale for the related refinery feedstock, which reflect market conditions at the time when the feedstock was purchased. This lag between purchase and sale can be anywhere from several weeks to several months, and is influenced by the time to receive crude after purchase (which can be several weeks for foreign offshore crude purchases), regional crude inventory levels, the completion of refining processes, transportation time to distribution channels, and regional refined products inventory levels.

Suncor prepares and presents an estimate of the impact of using a FIFO inventory valuation methodology compared to a LIFO methodology, because management uses the information to analyze operating performance and compare itself against refining peers that are permitted to use LIFO inventory valuation under United States GAAP (U.S. GAAP).

The company's estimate is not derived from a standardized calculation and, therefore, may not be directly comparable to similar measures presented by other companies, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP or U.S. GAAP.

Measurement Conversions

Certain crude oil and natural gas liquids volumes have been converted to mcfe or mmcfe on the basis of one bbl to six mcf. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Any figure presented in mcfe, mmcfe, boe or mboe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or natural gas liquids to six mcf of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, conversion on a 6:1 basis may be misleading as an indication of value.

78   SUNCOR ENERGY INC. ANNUAL REPORT 2013

Common Abbreviations

The following is a list of abbreviations that may be used in this MD&A:

Measurement
     
bbl   barrel
bbls/d   barrels per day
mbbls/d   thousands of barrels per day
     
boe   barrels of oil equivalent
boe/d   barrels of oil equivalent per day
mboe   thousands of barrels of oil equivalent
mboe/d   thousands of barrels of oil equivalent per day
     
mcf   thousands of cubic feet of natural gas
mcfe   thousands of cubic feet of natural gas equivalent
mmcf   millions of cubic feet of natural gas
mmcf/d   millions of cubic feet of natural gas per day
mmcfe   millions of cubic feet of natural gas equivalent
mmcfe/d   millions of cubic feet of natural gas equivalent per day
     
MW   megawatts

Places and Currencies
     
U.S.   United States
U.K.   United Kingdom
B.C.   British Columbia
     
$ or Cdn$   Canadian dollars
US$   United States dollars
£   Pounds sterling
€   Euros

Financial and Business Environment
     
DD&A   Depreciation, depletion and amortization
     
WTI   West Texas Intermediate
WCS   Western Canadian Select
SCO   Synthetic crude oil

Forward-Looking Information

The MD&A contains certain forward-looking statements within the meaning of applicable Canadian and U.S. Securities laws and other information based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of information available at the time the statement was made and consider Suncor's experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves and resources estimates; commodity prices and interest and foreign exchange rates; capital efficiencies and cost-savings; applicable royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; and the receipt, in a timely manner, of regulatory and third-party approvals. In addition, all other statements and other information that address expectations or projections about the future, and other statements and information about Suncor's strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results, future financing and capital activities, and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements and information may be identified by words like "expects", "anticipates", "will", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue", "should", "may" and similar expressions.

Forward-looking statements in this MD&A include references to:

Suncor's expectations about production volumes and the performance of its existing assets, including that:

•
An increase in capacity by 20% to 38,000 bbls/d by the end of 2015 at the MacKay River facility as a result of debottlenecking activities, which are expected to be substantially completed by 2014;

•
Extension projects at Hibernia are expected to extend productive life and increase overall production starting in 2015;

•
The expectation to start steaming a well pad at MacKay River in the second quarter of 2014; and

•
Rail transport to Quebec is expected to increase to approximately 35,000 bbls/d in the first quarter of 2014.

The anticipated duration and impact of planned maintenance events, including that:

•
No major turnarounds planned at Oil Sands Operations until 2016. The company plans to complete routine maintenance on three coker units, in addition to seasonal maintenance throughout 2014 in Oil Sands Operations;

•
Routine annual planned maintenance has been scheduled at Terra Nova and White Rose in the third quarter of 2014, and in the second and third quarters of 2014 at Buzzard; and

•
Planned maintenance events at Commerce City refinery in the first quarter of 2014 with an expected duration of three weeks, a five-week maintenance in the second

SUNCOR ENERGY INC. ANNUAL REPORT 2013    79

    quarter of 2014 and an eight-week maintenance event beginning late in the third quarter of 2014 at the Montreal refinery, and a seven-week maintenance event in the second quarter of 2014 and a four-week maintenance event in the third quarter of 2014 at the Edmonton refinery.

Suncor's expectations about capital expenditures, and growth and other projects, including:

•
The company's plans to advance a number of debottlenecking initiatives across Oil Sands Operations and expansions at In Situ which are expected to grow production at Oil Sands Operations sites to approximately 500,000 bbls/d by the end of 2018;

•
A sanction decision for the MacKay River expansion project is expected for the second half of 2014, which is targeted to have an initial design capacity of approximately 20,000 bbls/d with first oil expected in 2017. Certain synergies of key processes and utility systems with the existing MacKay River facility are expected;

•
Development drilling programs at both Firebag and MacKay River and infill drilling at Firebag are expected to be an area of focus in 2014 in support of steady production growth and sustainment;

•
Projects such as the turnaround of Upgrader 1 in the second quarter of 2013 are expected to contribute to further reliability improvements;

•
Suncor's portfolio of technology projects is expected to not only drive improvements and efficiencies in current production, but aid in developing future opportunities;

•
Suncor plans to develop the Fort Hills mining area using traditional open-pit truck and shovel techniques, and solvent-based extraction technology that will allow the mine to produce a final marketable bitumen product. The project is expected to provide Suncor with approximately 73,000 bbls/d of bitumen, with first oil expected in the fourth quarter of 2017. Project activities in 2014 are expected to focus on detailed engineering, procurement and the ramp up of field construction activities;

•
Plans to provide an update on the targeted timing of a sanction decision for the Joslyn mining area when available;

•
The subsea installation for the SWRX project is planned for 2014, as well as completion of detailed engineering and procurement activities, with first oil expected in late 2014 or early 2015;

•
Maintenance on Terra Nova completed in 2013 is expected to contribute to improved reliability in 2014;

•
A sanction decision for further expansion in the western portion of the White Rose field is targeted for the second half of 2014;

•
First oil at Hebron is expected in 2017 and detailed engineering and construction of the gravity-based structure and topsides will continue in 2014;

•
Golden Eagle will achieve first oil in late 2014 or early 2015, with drilling operations expected to commence in early 2014;

•
Plans to continue evaluating the operated Beta prospect and commence further appraisal drilling in 2014, in addition, the company plans to participate in four non-operated exploration wells 2014 in the North Sea;

•
With respect to the non-operated Butch licence, drilling and evaluation activities of the Butch East well are expected to be complete in the first half of 2014 with plans for a second exploration well in mid-2014;

•
Exploration activity on four new licences in Norway are expected to involve primarily acquisition or processing of seismic data, some of which will commence in 2014;

•
The project to modify hydrocracking at the Montreal refinery is expected to improve energy efficiency and product yield by 2015 and contribute to the company's integration strategies;

•
The company expects to complete the Adelaide wind project by the fourth quarter of 2014. The Cedar Point project continues to progress through the regulatory process. The two projects, based in Ontario, are expected to add 140 MW of gross installed capacity, increasing the gross installed capacity of Suncor's wind projects by 55%;

•
Cost estimates, target completion dates and project details provided in the Capital Investment Update – Significant Growth Projects Update section of this MD&A;

•
Plans in 2014 to focus on the construction of assets to support the TRO™ process and activities aimed at reducing freshwater use, including the construction of a water treatment plant, which is expected to be commissioned in early 2014;

•
Completion of well pads at Firebag and MacKay River are expected to offset natural production declines;

•
Plans for Syncrude to focus on completing the mine train replacement for the Mildred Lake mining area and progress the tailings management program, including the construction of a centrifuge plant;

•
HSEU is expected to provide overall production increases to the Hibernia field beginning in 2015;

80   SUNCOR ENERGY INC. ANNUAL REPORT 2013

•
Exploration activity on the new licences in Norway will primarily involve acquisition or processing of seismic data, some of which is expected to commence in 2014; and

•
Plans to focus on planned maintenance events and routine asset replacement in Refining and Marketing, and that growth capital is expected to be deployed on projects to prepare the Montreal refinery to receive and process heavier crudes, including integration with the company's Oil Sands operations.

Also:

•
Suncor's projects in its growth portfolio are expected to provide long-term profitability to the company;

•
Intermittent curtailments of natural gas supply are expected to continue through the first quarter of 2014 while the third-party operator completes its investigations and restoration activities;

•
The company's assessment of the situation in Libya and Syria, including the amounts recorded as impairment charges and that formal extension agreements in relation to its EPSAs will follow later in 2014;

•
Management's belief that Suncor will have the capital resources to fund its planned 2014 capital spending program of $7.8 billion and to meet working capital requirements through existing cash balances and short-term investments, cash flow from operations, available committed credit facilities, issuing commercial paper, and issuing long-term notes or debentures, and that, if additional capital is required, adequate additional financing will be available to Suncor in the debt capital markets at commercial terms and rates;

•
Management's belief that a phased and flexible approach to existing and future growth projects should assist Suncor in maintaining its ability to manage project costs and debt levels; and

•
The company's belief that it does not have any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company's financial condition or financial performance, including liquidity and capital resources.

Forward-looking statements and information are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them.

The financial and operating performance of the company's reportable operating segments, specifically Oil Sands, Exploration and Production, and Refining and Marketing, may be affected by a number of factors.

Factors that affect our Oil Sands segment include, but are not limited to, volatility in the prices for crude oil and other production, and the related impacts of fluctuating light/heavy and sweet/sour crude oil differentials; changes in the demand for refinery feedstock and diesel fuel, including the possibility that refiners that process our proprietary production will be closed, experience equipment failure or other accidents; our ability to operate our Oil Sands facilities reliably in order to meet production targets; the output of newly commissioned facilities, the performance of which may be difficult to predict during initial operations; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; our dependence on pipeline capacity and other logistical constraints, which may affect our ability to distribute our products to market; our ability to finance Oil Sands growth and sustaining capital expenditures; the availability of bitumen feedstock for upgrading operations, which can be negatively affected by poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage, and in situ reservoir and equipment performance, or the unavailability of third-party bitumen; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes; our ability to complete projects, including planned maintenance events, both on time and on budget, which could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on infrastructure in Alberta's Wood Buffalo region and the surrounding area (including housing, roads and schools); risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; changes to royalty and tax legislation and related agreements that could impact our business; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and changes to environmental regulations or legislation.

Factors that affect our Exploration and Production segment include, but are not limited to, volatility in crude oil and natural gas prices; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, and pollution and other environmental risks; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; adverse weather conditions, which could disrupt output from producing assets or impact drilling programs,

SUNCOR ENERGY INC. ANNUAL REPORT 2013    81

resulting in increased costs and/or delays in bringing on new production; political, economic and socio-economic risks associated with Suncor's foreign operations, including the unpredictability of operating in Libya and that operations in Syria continue to be impacted by sanctions or political unrest; risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and market demand for mineral rights and producing properties, potentially leading to losses on disposition or increased property acquisition costs.

Factors that affect our Refining and Marketing segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; our ability to reliably operate refining and marketing facilities in order to meet production or sales targets; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.

Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of taxes or changes to fees and royalties, such as Suncor's current disagreement with the Canada Revenue Agency relating to the settlement of certain derivative contracts, including the risk that Suncor may not be able to successfully defend its original filing position if it is reassessed and ultimately be required to pay increased taxes as a result; changes in environmental and other regulations; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; outages to third-party infrastructure that could cause disruptions to production; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor's information systems by computer hackers or cyberterrorists, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; our ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor's reserves, resources and future production estimates; market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; maintaining an optimal debt to cash flow ratio; the success of the company's risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws; risks and uncertainties associated with closing a transaction for the purchase or sale of an oil and gas property, including estimates of the final consideration to be paid or received, the ability of counterparties to comply with their obligations in a timely manner and the receipt of any required regulatory or other third-party approvals outside of Suncor's control that are customary to transactions of this nature; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.

Many of these risk factors and other assumptions related to Suncor's forward-looking statements and information are discussed in further detail throughout this MD&A, including under the heading Risk Factors, and the company's 2013 AIF dated February 28, 2014 and Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

82   SUNCOR ENERGY INC. ANNUAL REPORT 2013



QuickLinks

Management's Discussion and Analysis for the fiscal year ended December 31, 2013, dated February 28, 2014