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EXHIBIT 99.1
2013 Annual Report to Shareholders for the period ended December 31, 2013

| CONTENTS 2 Message to Shareholders 6 Our Competitive Differentiators 8 Suncor’s Integrated Business Model 10 Our 2013 Goals 12 Our 2014 Targets 14 Disclaimers 16 Management’s Discussion and Analysis 84 Management’s Statement of Responsibility for Financial Reporting 85 Management’s Report on Internal Control over Financial Reporting 86 Independent Auditor’s Report 88 Audited Consolidated Financial Statements and Notes 137 148 Supplemental Financial and Operating Information Share Trading Information FINANCIAL HIGHLIGHTS Earnings ($ millions) 2009 2010 2011 2012 2013 Net earnings 1 146 3 829 4 304 2 740 3 911 Operating earnings 1 115 2 634 5 674 4 847 4 700 Capital Expenditures and Cash Flow from Operations ($ millions) 2009 2010 2011 2012 2013 Capital expenditures 4 131 5 709 6 291 6 370 6 380 Cash flow from operations 2 799 6 656 9 746 9 733 9 412 Production (mboe/d) 2009 2010 2011 2012 2013 Exploration and production 149.3 296.9 206.7 189.9 169.9 Oil Sands 306.7 318.2 339.3 359.2 392.5 Total 456.0 615.1 546.0 549.1 562.4 Return on Capital Employed (%) 2009 2010 2011 2012 2013 Excluding the impact of the Voyageur impairment, ROCE for 2012 was 11.4% 13.8 11.5 11.4 7.2 2.6

| AT A GLANCE Suncor’s vision is to be trusted stewards of valuable natural resources. Guided by our values, we will lead the way to deliver economic prosperity, improved social well-being and a healthy environment for today and tomorrow. SUNCOR ENERGY INC. ANNUAL REPORT 2013 SUNCOR ENERGY INC. ANNUAL REPORT 2013 4 3 Oil Sands Production Growth (excluding Syncrude) (mbbls/d) 283.0 304.7 324.8 360.5 2013 2012 2011 2010 2009 290.6 250 Our integrated model allowed us to access global pricing for 88% of production in 2013. With four refineries, we continued to achieve industry-leading utilization rates. We have investments in six operating wind farms with a gross generating capacity of 255 megawatts. We are now 99% crude oil-weighted following the divestment of non-core assets in our Exploration and Production business. Supply Trading and Corporate Development provides marketing, supply and trading services to the company. Our renewables business includes investments in six operating wind farms. KEY HIGHLIGHTS • Increased midstream flexibility through additional tankage, rail and pipeline access • Secured capacity on TransCanada’s Gulf Coast Pipeline for shipments that have begun in early 2014 • Regulatory approval received for Adelaide wind project SUPPLY AND TRADING $188million Operating earnings $301million Cash flow from operations 3:1 Three barrels traded for every barrel produced WHERE WE OPERATE Head office Regional office Operated Non-operated Proposed Refining capacity Circles are scaled to relative net capacity OUR RESERVES AND RESOURCES 7.7 billion boe Proved plus probable reserves(1) 23.2 billion boe Contingent resources(1) • 58% In Situ and 23% Mining (1) Please see the Disclaimers section for more information on reserves and resources. Libya Norway United Kingdom Tripoli London Stavanger Beta Aberdeen Buzzard Golden Eagle East Coast Canada Edmonton Calgary Denver / Commerce City Sarnia Mississauga Hebron Terra Nova Hibernia St. John’s White Rose Montreal Oil Sands Joslyn MacKay River Syncrude Fort Hills Base Plant & Millennium Fort McMurray Firebag 88% 94% 255MW 99% OVERVIEW AT A GLANCE Suncor’s vision is to be trusted stewards of valuable natural resources. Guided by our values, we will lead the way to deliver economic prosperity, improved social well-being and a healthy environment for today and tomorrow. OIL SANDS Our Oil Sands business unit is responsibly developing one of the world’s largest petroleum resource basins – the Athabasca Oil Sands – through both mining and in situ technologies. Our Exploration and Production business unit is focused on delivering value and growth through high margin crude oil producing and development assets. Our Refining and Marketing business unit further unlocks the value of the upstream barrel through our strong refining and marketing network. The bulk of our petroleum and lubricants products are marketed globally under the Petro-Canada brand. KEY HIGHLIGHTS • Oil Sands production (excluding Syncrude) increased by 11% from 2012 to approximately 360,500 bbls/d • Successful ramp up of Firebag complex and commissioning of hot bitumen infrastructure • Fort Hills mining project sanctioned KEY HIGHLIGHTS • Portfolio repositioned for high value and profitable growth • Golden Eagle project approximately 90% complete and on budget, with first oil expected in late 2014 or early 2015 • Current portfolio of development projects expected to provide value into the next decade KEY HIGHLIGHTS • Rail offloading facility opened in Montreal, providing access to lower-cost inland crudes • Continuous reliability improvements led to an increase in the nameplate capacity at the Edmonton refinery • Maintained #1 share of retail gasoline market in Canada EXPLORATION AND PRODUCTION REFINING AND MARKETING $1.2 billion Operating earnings $2.3 billion Cash flow from operations 169,900 boe/d Production volumes $2.0 billion Operating earnings $2.6 billion Cash flow from operations 431,300 bbls/d Crude oil processed $2.1 billion Operating earnings $4.6 billion Cash flow from operations 392,500 bbls/d Production volumes

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 1 WELCOME Suncor is Canada’s leading integrated energy company. Suncor’s operations include oil sands development and upgrading, conventional and offshore oil and gas production, petroleum refining, product marketing under the Petro-Canada brand and a renewable energy portfolio. This Annual Report contains forward-looking information based on Suncor’s current expectations, estimates, projections and assumptions. Refer to the Disclaimers section of this Annual Report for information on the material risk factors and assumptions underlying our forward-looking information. For assumptions underlying certain statements made throughout this Annual Report, refer to the Disclaimers section of this Annual Report. Certain financial measures in this Annual Report – namely operating earnings, cash flow from operations, free cash flow, return on capital employed (ROCE) and Oil Sands cash operating costs – are non-GAAP financial measures and therefore not prescribed by GAAP. Refer to the Advisories section of the Management’s Discussion and Analysis dated February 28, 2014 (MD&A) of this Annual Report for definitions of these non-GAAP measures, reconciliations to the relevant GAAP measures and certain other advisories 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. Crude oil and natural gas liquids (NGL) volumes have been converted to mcfe or mmcfe on a one bbl to six mcf basis in this Annual Report. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Refer to the Disclaimers section of this Annual Report. For a list of abbreviations that may be used in this Annual Report, refer to the Advisories section of the MD&A. Amounts in this Annual Report relating to 2010 to 2013 are based on information prepared in accordance with International Financial Reporting Standards. Effective January 1, 2013, Suncor adopted new and amended accounting standards, defined in the Accounting Policies and Critical Accounting Estimates section of the MD&A. Comparative figures presented in this Annual Report 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. Amounts for 2009 are presented in accordance with a previous GAAP in effect prior to January 1, 2011. Users of this information are cautioned that 2009 results may not be directly comparable with those for 2010 through 2013. Figures for part of 2009 (January 1 to July 31) represent Suncor’s results prior to the merger with Petro-Canada and do not reflect the results of Petro-Canada. Key Indicators Year ended December 31 2009 2010 2011 2012 2013 Financial (dollars per common share) Net earnings 0.96 2.45 2.74 1.77 2.61 Operating earnings 0.93 1.69 3.61 3.14 3.13 Cash flow from operations 2.34 4.25 6.20 6.30 6.27 Dividend 0.30 0.40 0.43 0.50 0.73 Financial ($ millions) Operating revenues (net of royalties) 17 459 31 315 38 339 38 107 39 593 Total assets 69 746 68 607 74 741 76 401 78 315 Key Metrics Total debt to total debt plus shareholders’ equity (%) 29 26 22 22 22 Net debt to cash flow from operations (times) 4.8 1.7 0.7 0.7 0.7

| THE PRESIDENT AND CHIEF EXECUTIVE OFFICER SUNCOR ENERGY INC. ANNUAL REPORT 2013 2 MESSAGE TO SHAREHOLDERS “ 2013 was a year of significant progress for our company. Thanks to a well-defined plan focused on operational excellence, capital discipline and profitable growth, we continued to deliver results for our shareholders.” Steve Williams

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 3 The end of one year and the start of another is always a time to reflect. Perhaps one of the things I am most struck by is how we are all connected through the global supply of and demand for energy. In 2013, the world’s population continued to expand and current growth trends show our globe growing to nine billion people before the middle of this century. With that growing population comes an increased demand for energy. In fact, the International Energy Agency predicts that, by 2035, demand for energy will increase by over 30%. Suncor is uniquely positioned to provide a portion of the energy that the world needs. History has demonstrated that access to energy increases quality of life, and we will need all forms of energy as we seek to provide that quality of life to the world’s population. As the CEO of Suncor, I am committed to ensuring Suncor develops the resources we steward in the most responsible way possible. We can do this while creating value for shareholders, employees, the communities in which we operate and for Canada as a whole. In Canada, we are blessed with a strong regulatory regime. Together, with this regime, we are committed to continually improving our industry’s environmental performance by dedicating people and financial resources to technology and innovation. It is within this context that I believe Suncor can remain trusted stewards of our natural resources. Suncor has an enviable resource base – including an unparalleled position in Canada’s oil sands, one of the largest resource basins in the world. Suncor is also one of very few energy companies to operate across the value chain – from resource extraction and upgrading to midstream logistics to refining and marketing. This breadth allows us to maximize the value of our production and effectively respond to changing market conditions, geopolitics and the global economy. 2013: Building Shareholder Value Suncor’s integrated business model, along with a strong focus on execution, continued to generate significant shareholder value in 2013. Operating earnings for the year were $4.700 billion and cash flow from operations was $9.412 billion. The last quarter of the year marked the tenth consecutive quarter in which our cash flow from operations topped $2.2 billion. With free cash flow of more than $2.6 billion, Suncor once again led its Canadian industry peers by a wide margin in 2013. Performance Highlights: $6.4 billion 2013 actual capital expenditures (excluding capitalized interest) • $900 million less than our original budget. • The third consecutive year our capital program spending has come in under budget. >$2.6 billion free cash flow for three consecutive years • We have generated in excess of $8 billion in free cash flow over the last three years, allowing Suncor to steadily increase its return of cash to shareholders. 600 mboe/d market access and takeaway capacity • By the end of 2014, we expect to have the ability to move more than 600,000 boe/d to our refineries and other globally priced markets across North America. By focusing on our core operations, cost management and prudent, low-risk growth, we continued to maintain a rock solid balance sheet, with a decreasing net debt balance and improving return on capital employed. Suncor achieved production of 562,400 boe/d in 2013, which included 392,500 bbls/d from Oil Sands and 169,900 boe/d from Exploration and Production. After safely completing a large turnaround on our Upgrader 1, Oil Sands production (excluding Syncrude) in the fourth quarter of 2013 reached record levels of 409,600 bbls/d. In 2013, Suncor’s integrated model allowed us to capture approximately 88% of global commodity pricing for our production. As we commenced 2014, Suncor’s market access was further enhanced by the addition of rail facilities at the Montreal refinery and the commencement of shipping on TransCanada’s Gulf Coast Pipeline. Our offshore and international production continues to be sold into premium-priced markets. The end result is that Suncor remains strongly positioned to fund growth from internal resources while steadily increasing the return of cash to shareholders. Operational Excellence Safe, reliable and environmentally responsible operations are integral to our success. Operational excellence is about doing the right work, the right way, every time – and I believe it’s key to creating sustainable long-term shareholder value. At Suncor, we’ve been working hard to continually raise the bar on all aspects of operational performance using consistently applied standards and practices.

| THE PRESIDENT AND CHIEF EXECUTIVE OFFICER SUNCOR ENERGY INC. ANNUAL REPORT 2013 4 Safety is a core value for us – in fact, it’s above all else. Eliminating all workplace incidents is a goal reflected in our Journey to Zero safety program. In 2013, we continued to reduce lost time injuries and recordable injury frequencies across the company during a year of intense planned maintenance activity. However, a fatality at our Oil Sands site in January 2014 was a sad reminder that we can never let up on our journey towards ensuring every employee goes home safely at the end of the day. Suncor achieved step changes in both reliability and productivity in 2013. The commissioning of new hot bitumen facilities allowed us to begin blending Firebag bitumen for direct shipment to market. This, in turn, allowed us to ramp up bitumen production from our mine to feed the upgraders. The net result was an increase of approximately 40,000 bbls/d of bitumen production. We’ve also improved the reliability of our upgraders. Following the planned spring maintenance in 2013, we began to achieve daily upgrader utilization rates above 90%. Together with average utilization rates at our four refineries of 94% last year, it’s a clear indication that we’re improving reliability across our operations. Thanks to ongoing process improvements, we’ve added over 4% to the nameplate capacity of our refineries in the past two years. With debottlenecking projects ongoing and no major turnaround maintenance at Oil Sands planned until 2016, I’m confident Suncor is well-positioned for a lengthy run of continued production growth. Operational excellence is not only about improving safety, reliability and production – it’s at the heart of becoming a more sustainable energy company. Every barrel of water we conserve and every emission we reduce at our operations means lower input costs while also supporting our social licence to operate and grow. Environmental integrity is directly linked to our long-term business success. Technology and innovation are also key drivers of sustainable energy development. It’s how we’ve cut per barrel greenhouse gas (GHG) emissions at our mining operations by more than half since 1990 and reduced our freshwater intake by more than 30% over the past six years. We’ve also used tailings reduction technology to accelerate reclamation and cancel plans for five additional tailings ponds. We continue to focus on achieving goals we have announced for 2015 on water consumption, reclamation of disturbed land, energy efficiency and air emissions. And, we’re in the process of drawing up an equally ambitious set of post-2015 performance goals. We are also collaborating with industry peers through Canada’s Oil Sands Innovation Alliance (COSIA), a network of 13 companies, on water, land, tailings and greenhouse gases. I firmly believe COSIA is the kind of collaboration that’s needed to drive sustainability across our industry. Capital Discipline Allocating capital in a way that creates value for every dollar spent is another one of my top priorities – one I believe is critical to the company’s future. This means focusing on projects that deliver the best possible returns for shareholders and, just as important, knowing when to rein in investments that no longer match our strategic objectives. We did both in 2013. Relatively low-risk, low-cost projects like our ongoing debottlenecking initiatives at Oil Sands are excellent examples of delivering increased value. So, too, is the rail offloading investment we made in 2013 to allow our Montreal refinery to receive more than 30,000 bbls/d of lower cost inland crude. Our decision not to proceed with the Voyageur upgrader project was another example of capital discipline. It allowed us to deploy resources to other areas aimed at improving reliability, productivity and returns. We’ve also focused on our core assets and identified those not meeting profitability thresholds. In 2013, we sold the remaining portion of our conventional natural gas business in Western Canada, part of a four-year divestment program from which we received gross proceeds of $4.5 billion. From a capital spending perspective, 2013 expenditures came in under $6.4 billion, representing a reduction of more than $900 million from our original budget. This is the third consecutive year we’ve delivered our capital program while spending less than our budget. We continue to make progress in managing our operating costs, yet more work needs to be done. We remain steadfast in our efforts to manage costs and are confident in our ability to reach guidance targets for 2014. Suncor’s strong balance sheet provides us with a significant degree of flexibility. We are well positioned to execute on Operational excellence is about doing the right thing, the right way, every time – and I believe it’s key to creating sustainable long-term shareholder value.

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 5 our capital priorities – funding the base business, investing in profitable growth and returning more cash to shareholders. We have repurchased over 7% of Suncor’s outstanding shares since 2011 and also increased our dividend to shareholders twice in the past year, first in May 2013 by 54% and again in February 2014 by another 15%; moving from 13 cents per share in early 2013 to 23 cents per share. Going forward, our view on dividends is clearcut: they should be meaningful, competitive and sustainable. Our dividend, combined with our share buyback program, provides an attractive return for our shareholders and demonstrates our confidence in Suncor’s ability to generate strong cash flow. 2009 2010 2011 2012 2013 Cash dividends(1) $0.30 $0.40 $0.43 $0.50 $0.73 Share repurchases(1) – – $0.32 $0.94 $1.12 (1) The figures provided are calculated based on the average shares outstanding in each year Profitable Growth Shortly after I became CEO in May 2012, I set some clear growth objectives. Our focus needs to be on smart, profitable growth. Cost and quality, rather than schedules, should drive our decisions. Our decision to sanction the Fort Hills joint venture project fits well within our profitable growth strategy. One of the best undeveloped oil sands mining assets in the Athabasca region, Fort Hills is expected to be a significant source of cash flow and contribute strong returns over the long term. More projects are underway at our Oil Sands Operations to increase the capacity and reliability of our existing facilities and enhance our logistics infrastructure. Our plan is to reach approximately 500,000 bbls/d of production at Oil Sands over four years – with relatively modest capital investment through debottlenecking projects across our Oil Sands Operations and expansions at In Situ. We are well positioned for sustained and profitable growth from our Exploration and Production division – including our working interest in the Golden Eagle project in the U.K. North Sea and the Hebron project off the east coast of Canada. Both projects are on budget and on schedule, with first oil from Golden Eagle expected in late 2014 or early 2015 and first oil from Hebron in 2017. Looking further out, our resource base provides us with a rich suite of development opportunities to choose from. We are continuing to invest in technology and innovation that we expect will lower the costs and energy intensity associated with production. Our in situ resources represent just over half of our resource base, and we are working on replication strategies to develop these resources through standardized facilities and processes. In short, I am very confident that we are well positioned for sustainable and profitable growth for decades into the future. A Team Approach Suncor’s success requires a day-to-day commitment by everyone involved to strive for excellence and integrity in all we do. That’s the kind of culture we’re building in the company, and I feel truly privileged to work with such a dedicated team of smart and talented people. I am indebted to Suncor’s Board of Directors, who are outstanding stewards of stakeholders’ interests. I particularly value the strong leadership and guidance that John Ferguson, our Board chairman has provided over his time with Suncor. We wish him the very best as he retires from the Board this year. From the ground to the gas station, Suncor’s integrated model is delivering superior value. When I look at our people, assets and strategy, I’m confident Suncor can continue to be an industry leader in the energy we generate for the world and the value we create for our communities, our employees and for you, our shareholders. Thank you for your continued support. Steve Williams President and Chief Executive Officer Return of Cash to Shareholders ($ per share)

| WHAT MAKES SUNCOR UNIQUE SUNCOR ENERGY INC. ANNUAL REPORT 2013 SUNCOR ENERGY INC. ANNUAL REPORT 2013 7 6 3 4 5 Suncor has been an industry leader in sustainable development, with a focus on delivering triple bottom line results in environmental, social and economic performance. We have four public “beyond compliance” environmental goals, focused on land reclamation, air emissions, freshwater use and energy efficiency, and we are currently developing new long-term environmental and social goals. We are a founding member and proud leader of COSIA, which is driving environmental performance improvements across the industry. Suncor supports the development of strong, sustainable communities and contributed over $130 million in 2013. Suncor’s ability to generate significant free cash flow has contributed to a very strong balance sheet, effectively positioning the company to take advantage of growth opportunities and maximize shareholder value. Our focus on capital discipline has resulted in capital expenditures that are well below our cash flow from operations for the past four years. We increased our dividend to shareholders twice in the past year, first in May 2013 by 54% and again in February 2014 by 15%. We have repurchased over 7% of Suncor’s outstanding shares since 2011. Suncor pioneered commercial oil sands development and continues to advance technology through innovation to improve efficiencies, lower costs and through industry collaboration by enhancing environmental performance. We continue to make significant investments in research and development to progress our portfolio of promising technologies. Our Refining and Marketing operations have consistently led our North American peers on a net earnings per barrel of crude capacity basis. Industry expertise Sustainable development Financial strength For more information on our sustainable development refer to Suncor’s 2013 Report on Sustainability. OUR COMPETITIVE DIFFERENTIATORS Suncor continues to develop and execute on the elements of our business that make us unique in our industry. Capitalizing and executing on these differentiators has contributed to our industry-leading position and provided the foundation for delivering long-term value for shareholders. 1 2 Suncor is focused on the development of one of the largest reserves and resources bases in the oil sands. Our industry expertise in both mining and in situ has laid the groundwork for increased profitability in developing these resources. With 7.7 billion boe of proved plus probable reserves, we have over 35 years of production at current rates. Our established asset base and economies of scale have also allowed us to focus on near-term oil sands growth through low-cost debottlenecking and expansion projects. From the ground to the gas station, we optimize profits through each link in the value chain. We have demonstrated the strength of our integrated model through consistent and strong cash flows. In 2013, Suncor leveraged the integrated model to obtain approximately 88% of global pricing on our upstream production. As upstream production grows, we continue to strengthen the degree of integration among our assets and expand our market access. Reserves and resources base A proven integrated model For more information on our reserves and resources base refer to our Annual Information Form dated February 28, 2014.

| SUNCOR’S VALUE CHAIN SUNCOR ENERGY INC. ANNUAL REPORT 2013 8 SUNCOR’S INTEGRATED BUSINESS MODEL Suncor’s integrated, diversified business model aims to maximize the market price received and net margins realized for upstream production. Suncor has operations in all stages of the oil and gas industry – from resource extraction through to refining and retail. How is Suncor’s business model integrated? Through mining and in situ technology, we extract oil sands and upgrade a large portion of bitumen production into more valuable light products. With the addition of hot bitumen assets at Oil Sands, we have increased our flexibility and ability to sell bitumen directly to market. We process synthetic and heavy crude oil into more valuable refined petroleum products. We optimize price realizations for oil sands barrels by leveraging midstream infrastructure. Our remaining crude oil production in the Exploration and Production business receives Brent-based pricing. We market refined fuels and specialty products to consumers through our broad network of retail, wholesale and lubricants channels.

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 9 How did Suncor’s integrated model perform in 2013? We leveraged our integrated model and captured prices tied to global crude markets on over 88% of our upstream crude production. We delivered yet another year of strong cash flow from operations in 2013 by leveraging our integrated model, which largely sheltered the company from fluctuating crude differentials in 2013. How is Suncor’s integrated strategy positioned for the future? In 2013, our Oil Sands production exceeded our inland refining capacities. Enhancing integration between our assets and expanding our midstream capabilities to reach global markets remains an important focus. In 2014, we will continue to advance projects to increase our access to global markets, including increasing rail shipments to the Montreal refinery and transporting crude to the U.S. Gulf Coast. We also hold a position in every major planned pipeline project in North America to further expand our access to global pricing. 2013 Upstream Crude Production (1) Includes natural gas liquids and crude oil production from North America Onshore. 35,000 bbls/d expansion of our integration capacity through the commissioning of a rail facility in Montreal. >50,000 bbls/d additional market access to the U.S. Gulf Coast, which began in early 2014.

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 10 OUR SCORECARD OUR 2013 GOALS How we delivered Suncor continued to make progress in delivering on its strategy in 2013. We successfully leveraged our integrated business model, generating incremental revenues in both the upstream and downstream in response to changing market conditions. Continue to advance Suncor’s journey to Operational Excellence Suncor’s operational excellence focus helped deliver total average production of 562,400 boe/d in 2013, versus 549,100 boe/d in 2012. Disciplined execution of our capital projects is another example of our commitment to operational excellence; we’ve delivered almost $20 billion worth of capital expenditures at or below projected cost in the past four years. We continue to make progress on incorporating our Operational Excellence Management System (OEMS) into our operations. Safety performance continued to improve due to Suncor’s Journey to Zero program. Recordable Injury Frequency (RIF) improved to 0.56 versus 0.59 for 2012. Lost Time Injury Frequency (LTIF) metrics improved to 0.05 versus 0.06 for 2012. However, the death of an employee at our Oil Sands operations in early 2014 is a sad reminder that we must be diligent in our safety journey. Improve maintenance and reliability across Suncor’s operations We completed a major turnaround in Oil Sands at our Upgrader 1 and also set an SCO production record. Suncor also reduced unplanned maintenance across the entire business. Reliability gains contributed to strong production from Oil Sands and an overall refinery utilization rate of 94%. We completed a preventive maintenance program at Terra Nova, which is expected to contribute to improved reliability. Through our continuous improvement initiatives, we are steadily improving reliability at our upgraders. In 2013, we achieved an annual SCO production record in excess of 280,000 bbls/d. 0.56 Recordable Injury Frequency Rate in 2013 0.05 Lost Time Injury Frequency Rate in 2013

| Total Shareholder Return Performance SUNCOR ENERGY INC. ANNUAL REPORT 2013 11 Generate and sustain industry leading returns Suncor’s refineries posted impressive utilization rates and our Refining and Marketing business remains first among its North American peers for net earnings per barrel of crude capacity. As of the fourth quarter 2013, the company had generated cash flow at approximately $2.2 billion for ten consecutive quarters. We returned approximately $2.8 billion in cash to shareholders through share repurchases and dividends, a 25% increase over the prior year. In 2013, Suncor delivered total shareholder return (share appreciation plus dividend) of 16.1%, significantly outperforming the Canadian energy index. We’re laying the groundwork for future profitable growth through major projects including Fort Hills, Golden Eagle and Hebron. Attract and engage employees in support of Suncor’s business strategy Suncor remains an employer of choice, recognized by the Financial Post’s Ten Best Companies to Work For. Our mission, vision and value statements highlight the commitment of Suncor employees to deliver results. Every employee’s performance goals are aligned with our strategy. Achieve long-term sustainability targets We continue to make progress toward our four environmental performance goals targeted at land reclamation, air emissions, freshwater use and energy efficiency. We’ve made meaningful performance improvements, including a 47% reduction in GHG emissions per barrel of SCO at our mining operations since 1990 and a reduction in freshwater intake by more than 30% over the past six years. We’re also proud members of COSIA, which is driving environmental performance improvements across the industry. >47% Reduction in GHG emissions per barrel of SCO at mining operations since 1990. >30% Reduction in freshwater intake over the past six years. Suncor is a proud member of COSIA. Suncor employees are focused on technology initiatives that target higher production, enhanced profitability and lower environmental impacts. TSX Energy 13.6% -0.6% Suncor 16.3% 13.1% TSX 13.0% 7.2% 2013 2012

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 12 OUR SCORECARD continued OUR 2014 TARGETS How we will get there Suncor has established a set of goals to drive operational performance, profitability and growth now and in the years ahead. Continue to advance Operational Excellence through improvements in personal and process safety performance, key business processes and implementation of the Operational Excellence Management System. Operational excellence continues to be our foundation to embed a culture of operational discipline and collaboration among employees and partners. We continue our commitment to personal and process safety. And, our management system will strengthen our governance, standards and measures to support and sustain performance. Improve maintenance and reliability across Suncor’s operations by delivering reliable operations and leveraging integration to maximize value. Suncor will build on the work done in 2013 to improve maintenance and reliability across our operations. A focus on the implementation of low-cost, high return projects will continue, as will efforts to control cash operating costs per barrel across our operations. Technology and productivity will support our efforts to increase profitability. We will focus on reducing unplanned maintenance, further setting the stage for solid operational performance. We’re working hard to manage cash operating costs and are confident in our ability to reach our guidance targets for 2014. Oil Sands Technology Suncor has targeted $175 million in research and development spending in 2014, with a focus on incremental and game-changing technologies. Solvent extraction Membrane de-oiling and water treatment Non-condensable gas co-injection Autonomous haul trucks Steam-quality technology Waterless extraction Reduction in GHGs Lower operating costs Higher reliability SOR reduction Longer well life

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 13 The Fort Hills project is one of the best undeveloped oil sands mining assets in the Athabasca region and is an excellent fit with Suncor’s diversified production portfolio. Generate and sustain industry leading returns by improving profitability and effective execution of the Fort Hills project. The decision to sanction the Fort Hills project is a clear demonstration of our company’s commitment to profitable growth. With high ore grade quality, a mine life of 50 years based on current reserve estimates, and a planned production capacity of 180,000 bbls/d, the project is expected to provide strong, stable cash flow. Suncor will leverage existing Oil Sands infrastructure to control costs, including fuel, labour and maintenance to ensure profitability of the Fort Hills project. We will continue to monitor key metrics, including return on capital employed, total shareholder return, annual growth and reliability, and cost targets to guide our efforts. Enhance culture and workforce performance through improvements in work force productivity and competence. Suncor will continue to engage employees through our mission, vision and values, ensuring employees have a line of sight to our company’s strategy. This will be accomplished through well-developed onboarding programs, a robust goal alignment process, and employee development programs. Our progress will be measured through ongoing employee engagement surveys and management reviews of organizational culture and productivity. Achieve sustainability targets by improving environmental performance towards long-term company and industry goals. We will continue with our efforts to meet or exceed publicly announced 2015 environmental goals on air emissions, water withdrawals, land reclamation and energy efficiency. We will also continue goal planning for the post-2015 period. Suncor will leverage this effort, working with the Oil Sands CEO Council and COSIA in support of environmental performance improvements across the industry. 73,000 bbls/d Suncor’s portion of planned production capacity in the Fort Hills project. 50 years Fort Hills mine life of 50 years is expected to generate strong stable cash flow over the long-term. 1.2 billion bbls Suncor’s portion of Fort Hills’ proved plus probable reserves. Suncor will continue to advance efforts on its 2015 environmental performance goals on water, land, energy efficiency and air.

| DISCLAIMERS SUNCOR ENERGY INC. ANNUAL REPORT 2013 14 DISCLAIMERS This Annual Report 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 and other information in this Annual Report include those statements identified in the Advisories – Forward-Looking Information section of the MD&A contained in this Annual Report as well as the following: • Suncor’s current portfolio of development projects in its Exploration and Production segment is expected to provide value into the next decade; • Suncor is well-positioned: (i) to fund growth from internal resources while steadily increasing the return of cash to shareholders; (ii) for a lengthy run of continued production growth; (iii) to execute on its capital priorities; and (iv) sustained profitable growth for decades into the future; • Suncor’s expectation that, by the end of 2014, it will have the ability to move more than 600,000 bbls/d to the company’s refineries and other globally priced markets across North America; • Suncor’s investments in technology and innovation are expected to lower the costs and energy intensity associated with production; • Suncor’s expectation that preventive maintenance at Terra Nova will contribute to improved reliability; • Suncor’s 2014 goals and its expectation that it will meets its guidance targets; • Suncor’s expectation that 7.7 billion boe of proved plus probable reserves will provide over 35 years of production at current rates; • Suncor’s expectation that Fort Hills will be a significant and strong, stable source of cash flow and contribute to strong returns over the long-term and that the Fort Hills mine life will be 50 years assuming all of the reserves are produced; and • Suncor development plans in 2014. 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. Many of these risk factors and other assumptions related to Suncor’s forward-looking statements and information are discussed in further detail throughout the MD&A, including under the heading Risk Factors, and the company’s most recent Annual Information Form/Form 40-F dated February 28, 2014 available at www.sedar.com and www.sec.gov, which risk factors are incorporated by reference herein. 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. References to Suncor’s industry-leading position in terms of free cash flow are based on Bloomberg data for the following Canadian peers: Canadian Natural Resources, Canadian Oil Sands, Cenovus, Encana, Husky, Imperial Oil, and Talisman. References to Suncor’s leading position on a net earnings per barrel of crude capacity basis for its R&M operations amongst its North American peers is applicable for the period between 2010 and 2013, and was compiled by Suncor using publicly reported company information for the following peers: Alon, Chevron (US

| SUNCOR ENERGY INC. ANNUAL REPORT 2013 15 Downstream), Phillips 66 (ConocoPhillips’ US R&M prior to Q2 2012), ExxonMobil (US Downstream), HollyFrontier, Husky (Downstream), Imperial Oil (Downstream), Marathon Petroleum, Tesoro, United Refining, Valero, Western Refining, Hess (up to Q1 2013), Murphy Oil (US R&M up to Q4 2011) and Sunoco (up to Q4 2011). Imperial Oil and US-based companies report Net Earnings using a LIFO inventory valuation method. Suncor and Husky report using a FIFO inventory valuation method. R&M Net Earnings per barrel of crude capacity for Alon, HollyFrontier, and Western Refining are based on their respective results for the first three quarters of 2013. 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 represent a 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. Reserves and contingent resource information presented herein is presented as Suncor’s working interest (operating and non-operating) before deduction of royalties, and without including any royalty interests of Suncor, and is at December 31, 2013, except in the case of the contingent resources attributed to the Montney shale formation of northeast British Columbia (approximately 8.1 TCF, which is at June 30, 2013), and in the case of resources attributable to Syria (approximately 206 mmboe, which is at December 31, 2011). For more information on Suncor’s reserves and contingent resources, including definitions of proved and probable reserves, Suncor’s interest, and location of the reserves and resources and the product types reasonably expected, please see Suncor’s most recent Annual Information Form/Form 40-F dated February 28, 2014 available at www.sedar.com and www.sec.gov. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty as to timing of development or that it will be commercially viable to produce the contingent resources. The contingent resource estimates provided herein are best estimates of the quantities that are potentially recoverable. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. The best estimate of potentially recoverable volumes is generally prepared independent of the risks associated with achieving commercial production. There are numerous uncertainties inherent in estimating quantities and quality of these proved and probable reserves and contingent resources, including many factors beyond our control. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or lack of infrastructure or markets.

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.
(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.

(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.

(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.

(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.

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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.

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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

MANAGEMENT'S STATEMENT
OF RESPONSIBILITY FOR FINANCIAL REPORTING

The management of Suncor Energy Inc. is responsible for the presentation and preparation of the accompanying consolidated financial statements of Suncor Energy Inc. and all related financial information contained in the Annual Report, including Management's Discussion and Analysis.

The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles applicable to publically accountable enterprises, which is within the framework of International Financial Reporting Standards as issued by the International Accounting Standards Board incorporated into the CICA Handbook Part 1. They include certain amounts that are based on estimates and judgments.

In management's opinion, the consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies adopted by management. If alternate accounting methods exist, management has chosen those policies it deems the most appropriate in the circumstances. In discharging its responsibilities for the integrity and reliability of the financial statements, management maintains and relies upon a system of internal controls designed to ensure that transactions are properly authorized and recorded, assets are safeguarded against unauthorized use or disposition and liabilities are recognized. These controls include quality standards in hiring and training of employees, formalized policies and procedures, a corporate code of conduct and associated compliance program designed to establish and monitor conflicts of interest, the integrity of accounting records and financial information among others, and employee and management accountability for performance within appropriate and well-defined areas of responsibility.

The system of internal controls is further supported by the professional staff of an internal audit function who conduct periodic audits of the company's financial reporting.

The Audit Committee of the Board of Directors, currently composed of five independent directors, reviews the effectiveness of the company's financial reporting systems, management information systems, internal control systems and internal auditors. It recommends to the Board of Directors the external auditor to be appointed by the shareholders at each annual meeting and reviews the independence and effectiveness of their work. In addition, it reviews with management and the external auditor any significant financial reporting issues, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of management that may be material for financial reporting purposes. The Audit Committee appoints the independent reserve consultants. The Audit Committee meets at least quarterly to review and approve interim financial statements prior to their release, as well as annually to review Suncor's annual financial statements and Management's Discussion and Analysis, Annual Information Form/Form 40-F, and annual reserves and resource estimates, and recommend their approval to the Board of Directors. The internal auditors and the external auditor, PricewaterhouseCoopers LLP, have unrestricted access to the company, the Audit Committee and the Board of Directors.

Steve W. Williams | Stephen D.L. Reynish
President and Chief Executive Officer | Interim Chief Financial Officer

February 28, 2014

SUNCOR ENERGY INC. ANNUAL REPORT 2013 83

The following report is provided by management in respect of the company's internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the U.S. Securities Exchange Act of 1934):

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

1.
  Management is responsible for establishing and maintaining adequate internal control over the company's financial reporting.
2.
  Management has used the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework (1992) in Internal Control – Integrated Framework to evaluate the effectiveness of the company's internal control over financial reporting.
3.
  Management has assessed the effectiveness of the company's internal control over financial reporting as at December 31, 2013, and has concluded that such internal control over financial reporting was effective as of that date. Additionally, based on this assessment, management determined that there were no material weaknesses in internal control over financial reporting as at December 31, 2013. Because of inherent limitations, systems of internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
4.
  The effectiveness of the company's internal control over financial reporting as at December 31, 2013 has been audited by PricewaterhouseCoopers LLP, independent auditor, as stated in their report which appears herein.

Steve W. Williams | Stephen D.L. Reynish
President and Chief Executive Officer | Interim Chief Financial Officer

February 28, 2014

84 SUNCOR ENERGY INC. ANNUAL REPORT 2013

INDEPENDENT AUDITOR'S REPORT

To the Shareholders of
Suncor Energy Inc.

We have completed integrated audits of Suncor Energy Inc.'s 2013 and 2012 consolidated financial statements and its internal control over financial reporting as at December 31, 2013. Our opinions, based on our audits are presented below.

Report on the consolidated financial statements

We have audited the accompanying consolidated financial statements of Suncor Energy Inc., which comprise the consolidated balance sheets as at December 31, 2013, December 31, 2012 and January 1, 2012 and the consolidated statements of comprehensive income, changes in shareholders' equity and cash flows for each of the two years in the period ended December 31, 2013, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards also require that we comply with ethical requirements.

An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Suncor Energy Inc. as at December 31, 2013, December 31, 2012 and January 1, 2012 and its financial performance and its cash flows for each of the two years in the period ended December 31, 2013 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 85

Report on internal control over financial reporting

We have also audited Suncor Energy Inc.'s internal control over financial reporting as at December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Management's responsibility for internal control over financial reporting

Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting.

Auditor's responsibility

Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances.

We believe that our audit provides a reasonable basis for our audit opinion on the company's internal control over financial reporting.

Definition of internal control over financial reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Inherent limitations

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Opinion

In our opinion, Suncor Energy Inc. maintained, in all material respects, effective internal control over financial reporting as at December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by COSO.

Chartered Accountants |
Calgary, Alberta |

February 28, 2014

86 SUNCOR ENERGY INC. ANNUAL REPORT 2013

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the years ended December 31 ($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Revenues and Other Income |  |  |  |  |  |
| Operating revenues, net of royalties (note 7) |  | 39 593 |  | 38 107 |  |
| Other income (note 8) |  | 704 |  | 419 |  |
|  | 40 297 |  | 38 526 |  |
Expenses |  |  |  |  |  |
| Purchases of crude oil and products |  | 17 293 |  | 17 047 |  |
| Operating, selling and general (notes 9 and 26) |  | 9 447 |  | 8 897 |  |
| Transportation |  | 845 |  | 685 |  |
| Depreciation, depletion, amortization and impairment (notes 10 and 17) |  | 4 892 |  | 6 446 |  |
| Exploration |  | 322 |  | 309 |  |
| Gain on disposal of assets (note 34) |  | (137 | ) | (44 | ) |
| Project start-up costs |  | 15 |  | 60 |  |
| Voyageur upgrader project charges (note 33) |  | 82 |  | — |  |
| Financing expenses (note 11) |  | 1 162 |  | 142 |  |
|  | 33 921 |  | 33 542 |  |
Earnings before Income Taxes |  | 6 376 |  | 4 984 |  |
Income Taxes (note 12) |  |  |  |  |  |
| Current |  | 2 083 |  | 1 515 |  |
| Deferred |  | 382 |  | 729 |  |
|  | 2 465 |  | 2 244 |  |
Net Earnings |  | 3 911 |  | 2 740 |  |
Other Comprehensive Income (Loss) |  |  |  |  |  |
| Items That May be Subsequently Reclassified to Profit or Loss: |  |  |  |  |  |
|  | Foreign currency translation adjustment |  | 325 |  | (16 | ) |
|  | Cash flow hedges reclassified to net earnings |  | — |  | (1 | ) |
| Items That Will Not be Reclassified to Profit or Loss: |  |  |  |  |  |
|  | Actuarial gain (loss) on employee retirement benefit plans, net of income taxes |  | 579 |  | (134 | ) |
Other Comprehensive Income (Loss) |  | 904 |  | (151 | ) |
Total Comprehensive Income |  | 4 815 |  | 2 589 |  |
Per Common Share (dollars) (notes 6 and 13) |  |  |  |  |  |
| Net earnings – basic |  | 2.61 |  | 1.77 |  |
| Net earnings – diluted |  | 2.60 |  | 1.76 |  |
| Cash dividends |  | 0.73 |  | 0.50 |  |

The accompanying notes are an integral part of the consolidated financial statements.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 87

CONSOLIDATED BALANCE SHEETS

($ millions) |  | December 31 2013 |  | December 31 2012 |  | January 1 2012 |
|  |  |  | (restated – note 6) |  | (restated – note 6) |
Assets |  |  |  |  |  |  |
| Current assets |  |  |  |  |  |  |
|  | Cash and cash equivalents (note 14) |  | 5 202 |  | 4 385 |  | 3 781 |
|  | Accounts receivable |  | 5 254 |  | 5 201 |  | 5 383 |
|  | Inventories (note 16) |  | 3 944 |  | 3 697 |  | 4 169 |
|  | Income taxes receivable |  | 294 |  | 799 |  | 704 |
| Total current assets |  | 14 694 |  | 14 082 |  | 14 037 |
| Property, plant and equipment, net (notes 17, 33 and 34) |  | 57 270 |  | 55 434 |  | 52 563 |
| Exploration and evaluation (note 18) |  | 2 772 |  | 3 284 |  | 4 554 |
| Other assets (note 19) |  | 422 |  | 419 |  | 413 |
| Goodwill and other intangible assets (note 20) |  | 3 092 |  | 3 104 |  | 3 114 |
| Deferred income taxes (note 12) |  | 65 |  | 78 |  | 60 |
| Total assets |  | 78 315 |  | 76 401 |  | 74 741 |
Liabilities and Shareholders' Equity |  |  |  |  |  |  |
| Current liabilities |  |  |  |  |  |  |
|  | Short-term debt (note 21) |  | 798 |  | 775 |  | 761 |
|  | Current portion of long-term debt (note 21) |  | 457 |  | 311 |  | 12 |
|  | Accounts payable and accrued liabilities |  | 7 090 |  | 6 446 |  | 7 742 |
|  | Current portion of provisions (note 24) |  | 998 |  | 856 |  | 811 |
|  | Income taxes payable |  | 1 263 |  | 1 165 |  | 964 |
| Total current liabilities |  | 10 606 |  | 9 553 |  | 10 290 |
| Long-term debt (note 21) |  | 10 203 |  | 9 938 |  | 10 004 |
| Other long-term liabilities (note 22) |  | 1 464 |  | 2 319 |  | 2 402 |
| Provisions (note 24) |  | 4 078 |  | 4 932 |  | 3 751 |
| Deferred income taxes (note 12) |  | 10 784 |  | 10 444 |  | 9 702 |
| Shareholders' equity |  | 41 180 |  | 39 215 |  | 38 592 |
| Total liabilities and shareholders' equity |  | 78 315 |  | 76 401 |  | 74 741 |

The accompanying notes are an integral part of the consolidated financial statements.

Approved on behalf of the Board of Directors:

Steve W. Williams |  | Michael W. O'Brien
Director |  | Director

February 28, 2014

88 SUNCOR ENERGY INC. ANNUAL REPORT 2013

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31 ($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Operating Activities |  |  |  |  |  |
Net earnings |  | 3 911 |  | 2 740 |  |
Adjustments for: |  |  |  |  |  |
| Depreciation, depletion, amortization and impairment |  | 4 892 |  | 6 446 |  |
| Deferred income taxes |  | 382 |  | 729 |  |
| Accretion |  | 192 |  | 182 |  |
| Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt |  | 605 |  | (181 | ) |
| Change in fair value of derivative contracts |  | 95 |  | 10 |  |
| Gain on disposal of assets |  | (137 | ) | (44 | ) |
| Share-based compensation |  | 214 |  | 214 |  |
| Exploration |  | 82 |  | 145 |  |
| Settlement of decommissioning and restoration liabilities |  | (423 | ) | (433 | ) |
| Recognition of risk mitigation proceeds |  | (300 | ) | — |  |
| Other |  | (101 | ) | (75 | ) |
Decrease (increase) in non-cash working capital (note 15) |  | 688 |  | (874 | ) |
Cash flow provided by operating activities |  | 10 100 |  | 8 859 |  |
Investing Activities |  |  |  |  |  |
Capital and exploration expenditures |  | (6 777 | ) | (6 957 | ) |
Acquisitions (note 33) |  | (515 | ) | — |  |
Proceeds from disposal of assets |  | 943 |  | 67 |  |
Proceeds from risk mitigation instruments |  | — |  | 300 |  |
Divestiture of pipeline contract (note 24) |  | (76 | ) | — |  |
Other investments |  | (18 | ) | (3 | ) |
Increase in non-cash working capital (note 15) |  | (90 | ) | (51 | ) |
Cash flow used in investing activities |  | (6 533 | ) | (6 644 | ) |
Financing Activities |  |  |  |  |  |
Net change in short-term debt |  | (32 | ) | 13 |  |
Net change in long-term debt |  | 170 |  | 414 |  |
Repayment of long-term debt |  | (312 | ) | — |  |
Issuance of common shares under share option plans |  | 112 |  | 188 |  |
Purchase of common shares for cancellation, net of option premiums (note 25) |  | (1 675 | ) | (1 451 | ) |
Dividends paid on common shares |  | (1 095 | ) | (756 | ) |
Cash flow used in financing activities |  | (2 832 | ) | (1 592 | ) |
Increase in Cash and Cash Equivalents |  | 735 |  | 623 |  |
Effect of foreign exchange on cash and cash equivalents |  | 82 |  | (19 | ) |
Cash and cash equivalents at beginning of year |  | 4 385 |  | 3 781 |  |
Cash and Cash Equivalents at End of Year |  | 5 202 |  | 4 385 |  |
Supplementary Cash Flow Information |  |  |  |  |  |
Interest paid |  | 711 |  | 642 |  |
Income taxes paid |  | 1 339 |  | 1 510 |  |

The accompanying notes are an integral part of the consolidated financial statements.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 89

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

($ millions) |  | Share Capital |  | Contributed Surplus |  | Foreign Currency Translation |  | Cash Flow Hedge |  | Retained Earnings |  | Total (restated – note 6) |  | Number of Common Shares (thousands) |  |
At January 1, 2012 |  | 20 303 |  | 545 |  | (207 | ) | 14 |  | 17 937 |  | 38 592 |  | 1 558 636 |  |
Net earnings |  | — |  | — |  | — |  | — |  | 2 740 |  | 2 740 |  | — |  |
Foreign currency translation adjustment |  | — |  | — |  | (16 | ) | — |  | — |  | (16 | ) | — |  |
Net changes in cash flow hedges |  | — |  | — |  | — |  | (1 | ) | — |  | (1 | ) | — |  |
Actuarial loss on employee retirement benefit plans, net of income taxes of $49 |  | — |  | — |  | — |  | — |  | (134 | ) | (134 | ) | — |  |
Total comprehensive income (loss) |  | — |  | — |  | (16 | ) | (1 | ) | 2 606 |  | 2 589 |  | — |  |
Issued under share option plans |  | 255 |  | (49 | ) | — |  | — |  | — |  | 206 |  | 10 804 |  |
Issued under dividend reinvestment plan |  | 15 |  | — |  | — |  | — |  | (15 | ) | — |  | 479 |  |
Purchase of common shares for cancellation, net of option premiums |  | (609 | ) | — |  | — |  | — |  | (842 | ) | (1 451 | ) | (46 862 | ) |
Liability for share purchase commitment |  | (19 | ) | — |  | — |  | — |  | (29 | ) | (48 | ) | — |  |
Share-based compensation |  | — |  | 83 |  | — |  | — |  | — |  | 83 |  | — |  |
Dividends paid on common shares |  | — |  | — |  | — |  | — |  | (756 | ) | (756 | ) | — |  |
At December 31, 2012 |  | 19 945 |  | 579 |  | (223 | ) | 13 |  | 18 901 |  | 39 215 |  | 1 523 057 |  |
Net earnings |  | — |  | — |  | — |  | — |  | 3 911 |  | 3 911 |  | — |  |
Foreign currency translation adjustment |  | — |  | — |  | 325 |  | — |  | — |  | 325 |  | — |  |
Actuarial gain on employee retirement benefit plans, net of income taxes of $201 |  | — |  | — |  | — |  | — |  | 579 |  | 579 |  | — |  |
Total comprehensive income |  | — |  | — |  | 325 |  | — |  | 4 490 |  | 4 815 |  | — |  |
Issued under share option plans |  | 159 |  | (32 | ) | — |  | — |  | — |  | 127 |  | 4 750 |  |
Issued under dividend reinvestment plan |  | 28 |  | — |  | — |  | — |  | (28 | ) | — |  | — |  |
Purchase of common shares for cancellation (note 25) |  | (648 | ) | — |  | — |  | — |  | (1 027 | ) | (1 675 | ) | (49 492 | ) |
Change in liability for share purchase commitment (note 25) |  | (89 | ) | — |  | — |  | — |  | (169 | ) | (258 | ) | — |  |
Share-based compensation |  | — |  | 51 |  | — |  | — |  | — |  | 51 |  | — |  |
Dividends paid on common shares |  | — |  | — |  | — |  | — |  | (1 095 | ) | (1 095 | ) | — |  |
At December 31, 2013 |  | 19 395 |  | 598 |  | 102 |  | 13 |  | 21 072 |  | 41 180 |  | 1 478 315 |  |

The accompanying notes are an integral part of the consolidated financial statements.

90 SUNCOR ENERGY INC. ANNUAL REPORT 2013

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. REPORTING ENTITY AND DESCRIPTION OF THE BUSINESS

Suncor Energy Inc. (Suncor or the company) is an integrated energy company headquartered in Canada. Suncor's operations include oil sands development and upgrading, onshore and offshore oil and gas production, petroleum refining, and product marketing primarily under the Petro-Canada brand. The consolidated financial statements of the company comprise the company and its subsidiaries and the company's interests in associates and joint arrangement entities.

The address of the company's registered office is 150 – 6th Avenue S.W., Calgary, Alberta, Canada, T2P 3E3.

2. BASIS OF PREPARATION

(a) Statement of Compliance

These consolidated financial statements have 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.

The policies applied in these consolidated financial statements are based on IFRS issued and outstanding as at February 28, 2014, the date the Board of Directors approved the consolidated financial statements.

(b) Basis of Measurement

The consolidated financial statements are prepared on a historical cost basis except as detailed in the accounting policies disclosed in note 3. The accounting policies described in note 3 have been applied consistently to all periods presented in these financial statements.

(c) Functional Currency and Presentation Currency

These consolidated financial statements are presented in Canadian dollars, which is the company's functional currency.

(d) Use of Estimates and Judgment

The timely preparation of financial statements requires that management make estimates and assumptions and use judgment. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates and judgment used in the preparation of the consolidated financial statements are described in note 4.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Principles of Consolidation

The company consolidates its interest in entities it controls. Control comprises the power to govern an entity's financial and operating policies to obtain benefits from its activities, and is a matter of judgment. Suncor recognizes its share of assets, liabilities, income and expenses, on a line-by-line basis, of its joint operations. Joint ventures are investments in entities over which the company has significant influence and are accounted for using the equity method. All intercompany balances and transactions are eliminated.

(b) Foreign Currency Translation

Functional currencies of the company's individual entities are the currency of the primary economic environment in which the entity operates. Transactions in foreign currencies are translated to the appropriate functional currency at foreign exchange rates that approximate those on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the appropriate functional currency at foreign exchange rates at the balance sheet date. Foreign exchange differences arising on translation are recognized in earnings. Non-monetary assets that are measured in a foreign currency at historical cost are translated using the exchange rate at the date of the transaction.

In preparing the company's consolidated financial statements, the financial statements of each entity are translated into Canadian dollars. The assets and liabilities of foreign operations are translated into Canadian dollars at exchange rates at the balance sheet date. Revenues and expenses of foreign operations are translated into Canadian dollars using foreign exchange rates that approximate those on the date of the underlying transaction. Foreign exchange differences are recognized in Other Comprehensive Income.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 91

If the company or any of its entities dispose of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign operation are recognized in net earnings.

(c) Revenues

Revenue from the sale of crude oil, natural gas, natural gas liquids, purchased products and refined petroleum products is recorded when title passes to the customer and collection is reasonably assured. Revenue from properties in which the company has an interest with other producers is recognized on the basis of the company's net working interest. For operations not pursuant to production sharing contracts (PSCs), crude oil and natural gas sold below or above the company's working interest share of production results in production underlifts or overlifts, respectively. Underlifts are recorded as a receivable at market value with a corresponding increase to revenues, while overlifts are recorded as a payable at market value with a corresponding decrease to revenues. Revenue from oil and natural gas production is recorded net of royalty expense.

International operations conducted pursuant to PSCs are reflected in the consolidated financial statements based on the company's working interest. Each PSC establishes the exploration, development and operating costs the company is required to fund and establishes specific terms for the company to recover these costs (Cost Recovery Oil) and to share in the production profits (Profit Oil). Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each fiscal year. Profit Oil is that portion of production remaining after deducting Cost Recovery Oil and is shared between the company and the respective government. Cost Recovery Oil and Profit Oil are reported as revenue when the sale of product to a third party occurs. Revenue also includes income taxes paid on our behalf by our government joint venture partners.

(d) Cash and Cash Equivalents

Cash and cash equivalents consist primarily of cash in banks, term deposits, certificates of deposit and all other highly liquid investments at the time of purchase.

(e) Inventories

Inventories of crude oil and refined products, other than inventories held for trading purposes, are valued at the lower of cost, using the first-in, first-out method, and net realizable value. Costs include direct and indirect expenditures incurred in bringing an item or product to its existing condition and location. Materials and supplies are valued at the lower of average cost and net realizable value.

Inventories held for trading purposes in the company's energy trading operations are carried at fair value less costs of disposal, and any changes in fair value are recognized within Other Income.

(f) Exploration and Evaluation Assets

The costs to acquire non-producing oil and gas properties or licences to explore, drill exploratory wells and the costs to evaluate the commercial potential of underlying resources, including related borrowing costs, are initially capitalized as Exploration and Evaluation assets. Certain exploration costs, including geological, geophysical, seismic, and delineation on oil sands properties, are charged to Exploration expense as incurred.

Exploration and evaluation assets are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. If an area or exploration well is no longer considered commercially viable, the related capitalized costs are charged to Exploration expense.

When management determines with reasonable certainty that an exploration and evaluation asset will be developed, as evidenced by the classification of proved or probable reserves and the appropriate internal and external approvals, the asset is transferred to Property, Plant and Equipment.

(g) Property, Plant and Equipment

Property, Plant and Equipment are recorded at cost.

The costs to acquire developed or producing oil and gas properties, and to develop oil and gas properties, including completing geological and geophysical surveys and drilling development wells, and the costs to construct and install development infrastructure, such as wellhead equipment, well platforms, well pairs, offshore platforms and subsea structures, are capitalized as oil and gas properties within Property, Plant and Equipment.

92 SUNCOR ENERGY INC. ANNUAL REPORT 2013

The costs to construct, install and commission, or acquire, oil and gas production equipment, including oil sands upgraders, extraction plants, mine equipment, processing and power generation facilities, utility plants, and all renewable energy, refining, and marketing assets, are capitalized as plant and equipment within Property, Plant and Equipment.

Stripping activity required to access oil sands mining resources incurred in the initial development phase is capitalized as part of the construction cost of the mine. Stripping costs incurred in the production phase are charged to expense as they normally relate to production for the current period.

The costs of planned major inspection, overhaul and turnaround activities that maintain Property, Plant and Equipment and benefit future years of operations are capitalized. Recurring planned maintenance activities performed on shorter intervals are expensed as operating costs. Replacements outside of a major inspection, overhaul or turnaround are capitalized when it is probable that future economic benefits will flow to the company and the associated carrying amount of the replaced asset (or part of a replaced asset) is derecognized.

Leases that transfer substantially all the benefits and risks of ownership to the company are recorded as finance lease assets within Property, Plant and Equipment. Costs for all other leases are recorded as operating expense as incurred.

Borrowing costs relating to assets that take a substantial period of time to construct are capitalized as part of the asset. Capitalization of borrowing costs ceases when the asset is in the location and condition necessary for its intended use, and is suspended when construction of an asset is ceased for extended periods.

(h) Depreciation, Depletion and Amortization

Exploration and Evaluation assets are not subject to depreciation, depletion and amortization. Once transferred to oil and gas properties within Property, Plant and Equipment and commercial production commences, these costs are depleted on a unit-of-production basis over proved developed reserves, with the exception of exploration and evaluation costs associated with oil sand mines which are depreciated on a straight-line basis over the life of the mine and property acquisition costs which are depleted over proved reserves.

Capital expenditures are not depleted until assets are substantially complete and ready for their intended use.

Costs to develop oil and gas properties other than oil sands properties, including costs of dedicated infrastructure, such as well pads and wellhead equipment, are depleted on a unit-of-production basis over proved developed reserves. A portion of these costs may not be depleted if they relate to undeveloped reserves. Costs to develop and construct oil sands mines are depreciated on a straight-line basis over the life of the mine.

Major components of Property, Plant and Equipment are depreciated on a straight-line basis over their expected useful lives.

Natural gas processing plants |  | 15 years
Oil sands upgraders, extraction plants and mine facilities |  | 20 to 40 years
Oil sands mine equipment |  | 5 to 15 years
Oil sands in situ processing facilities |  | 30 years
Power generation and utility plants |  | 30 to 40 years
Refineries, ethanol and lubricants plants |  | 20 to 40 years
Marketing and other distribution assets |  | 20 to 40 years

The costs of major inspection, overhaul and turnaround activities that are capitalized are depreciated on a straight-line basis over the period to the next scheduled activity, which varies from two to five years.

Depreciation, depletion and amortization rates are reviewed annually, or when events or conditions occur that impact capitalized costs, reserves or estimated service lives.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 93

(i) Goodwill and Other Intangible Assets

The company accounts for business combinations using the acquisition method. The excess of the purchase price over the fair value of the identifiable net assets represents goodwill, and is allocated to the cash-generating units (CGUs) or groups of CGUs expected to benefit from the business combination.

Other intangible assets include acquired customer lists and brand value.

Goodwill and brand value have indefinite useful lives and are not subject to amortization. Customer lists are amortized over their expected useful lives, which range from five to ten years. Expected useful lives of goodwill and other intangible assets are reviewed on an annual basis.

(j) Impairment of Assets

Non-Financial Assets

Property, Plant and Equipment and Exploration and Evaluation assets are reviewed quarterly to assess whether there is any indication of impairment. Goodwill and intangible assets that have an indefinite useful life are tested for impairment annually. Exploration and Evaluation assets are also tested for impairment immediately prior to being transferred to Property, Plant and Equipment.

If any indication of impairment exists, an estimate of the asset's recoverable amount is calculated as the higher of the fair value less costs of disposal and value-in-use. In determining fair value less costs of disposal, recent market transactions are taken into account, if available. In the absence of such transactions, an appropriate valuation model is used. Value-in-use is assessed using the present value of the expected future cash flows of the relevant asset. If the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, the asset is tested as part of a CGU, which is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. An impairment loss is the amount by which the carrying amount of the individual asset or CGU exceeds its recoverable amount.

Impairments are reversed for all CGUs and individual assets, other than goodwill, if there has been a change in the estimates and judgments used to determine the asset's recoverable amount. If such indication exists, the carrying amount of the CGU or asset is increased to its revised recoverable amount which cannot exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, had no impairment been recognized.

Impairments and impairment reversals are recognized within Depreciation, Depletion, Amortization and Impairment.

Financial Assets

At each reporting date, the company assesses whether there is evidence that financial assets that are carried at amortized cost are impaired. If a financial asset carried at amortized cost is impaired, the impairment is recognized in Operating, Selling and General expense.

(k) Assets Held For Sale

Assets and liabilities are classified as held for sale if their carrying amounts are expected to be recovered through a disposition rather than through continuing use. The assets or disposal groups are measured at the lower of their carrying amount and fair value less costs of disposal. Impairment losses on initial classification as well as subsequent gains or losses on remeasurement are recognized in Depreciation, Depletion, Amortization and Impairment. However, when the assets or disposal groups are sold, the gains or losses on sale are recognized in (Gain) Loss on Disposal of Assets. Assets classified as held for sale are not depreciated, depleted or amortized.

(l) Provisions

Provisions are recognized by the company when it has a legal or constructive obligation as a result of past events, it is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.

Provisions are recognized for decommissioning and restoration obligations associated with the company's Exploration and Evaluation assets and Property, Plant and Equipment. Provisions for decommissioning and restoration obligations are measured at the present value of management's best estimate of the future cash flows required to settle the present obligation, using the credit-adjusted risk-free interest rate. The value of the obligation is added to the carrying amount of the associated asset and amortized over the useful life of the asset. The provision is accreted over time through Financing Expenses with actual expenditures charged against the accumulated obligation. Changes in the future cash flow estimates

94 SUNCOR ENERGY INC. ANNUAL REPORT 2013

resulting from revisions to the estimated timing or amount of undiscounted cash flows are recognized as a change in the decommissioning and restoration provision and related asset.

(m) Income Taxes

The company follows the liability method of accounting for income taxes whereby deferred income taxes are recorded for the effect of differences between the accounting and income tax basis of an asset or liability. Deferred income tax assets and liabilities are measured using enacted or substantively enacted income tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are anticipated to be recovered or settled. Changes to these balances are recognized in earnings or in Other Comprehensive Income in the period they occur. Investment tax credits are recorded as an offset to the related expenditures.

The company recognizes the financial statement impact of a tax filing position when it is probable, based on the technical merits, that the position will be sustained upon audit. The company assesses possible outcomes and their associated probabilities. If the company determines payment is probable, it measures the tax position at the best estimate of the amount of tax payable.

(n) Pensions and Other Post-Retirement Benefits

The company sponsors defined benefit pension plans, defined contribution pension plans and other post-retirement benefits.

The cost of pension benefits earned by employees in the defined contribution pension plan are expensed as incurred. The cost of defined benefit pension plans and other post-retirement benefits are actuarially determined using the projected unit credit method based on present pay levels and management's best estimates of demographic and financial assumptions. Pension benefits earned during the current year are recorded in Operating, Selling and General expense. Interest costs on the net unfunded obligation are recorded in Financing Expenses. Any actuarial gains or losses are recognized immediately through Other Comprehensive Income and transferred directly to Retained Earnings.

The liability recognized on the balance sheet is the present value of the defined benefit obligations less the fair value of plan assets.

(o) Share-Based Compensation Plans

Under the company's share-based compensation plans, share-based awards are granted to executives, employees and non-employee directors. Compensation expense is recorded in Operating, Selling and General expense.

Share-based compensation awards that settle in cash or have the option to settle in cash or shares are accounted for as cash-settled plans. These are measured at fair value each reporting period using the Black-Scholes options pricing model, with the exception of performance share units, which are measured at fair value using the Monte-Carlo simulation approach. The expense is recognized over the vesting period, with a corresponding adjustment to liabilities. When awards are surrendered for cash, the cash settlement paid reduces the outstanding liability. When awards are exercised for common shares, consideration paid by the holder and the previously recognized liability associated with the options are recorded to Share Capital.

Stock options that give the holder the right to purchase common shares are accounted for as equity-settled plans. The expense is based on the fair value of the options at the time of grant using the Black-Scholes options pricing model and is recognized over the vesting periods of the respective options. A corresponding increase is recorded to Contributed Surplus. Consideration paid to the company on exercise of options is credited to Share Capital and the associated amount in Contributed Surplus is reclassified to Share Capital.

(p) Financial Instruments

The company classifies its financial instruments into one of the following categories: fair value through profit or loss; assets available for sale; held-to-maturity investments; loan and receivables and financial liabilities measured at amortized cost. All financial instruments are initially recognized at fair value on the balance sheet, net of any transaction costs except for financial instruments classified as fair value through profit and loss, where transaction costs are expensed as incurred. Subsequent measurement of financial instruments is based on their classification. The company classifies derivative financial instruments as fair value through profit and loss, cash and cash equivalents and accounts receivable as loans and receivables, financial instruments included in other assets as available for sale, and accounts payable and accrued liabilities, debt, and other long-term liabilities as other financial liabilities.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 95

The company uses derivative financial instruments, such as physical and financial contracts, either to manage certain exposures to fluctuations in interest rates, commodity prices and foreign exchange rates, as part of its overall risk management program, or to earn trading revenues. Earnings impacts from derivatives used to manage a particular risk are reported as part of Other Income in the related operating segment. Gains or losses from trading activities are reported in Other Income as part of Corporate, Energy Trading and Eliminations.

Certain physical commodity contracts are deemed to be derivative financial instruments for accounting purposes. Physical commodity contracts entered into for the purpose of receipt or delivery in accordance with the company's expected purchase, sale or usage requirements are not considered to be derivative financial instruments.

Derivatives embedded in other financial instruments or other host contracts are recorded as separate derivatives when their risks and characteristics are not closely related to those of the host contract.

(q) Hedging Activities

The company may apply hedge accounting to arrangements that qualify for designated hedge accounting treatment. Documentation is prepared at the inception of a hedge relationship in order to qualify for hedge accounting. Designated hedges are assessed at each reporting date to determine if the relationship between the derivative and the underlying hedged exposure is still effective and to quantify any ineffectiveness in the relationship.

If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and in the fair value of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in Other Comprehensive Income and are recognized in earnings when the hedged item is realized. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings immediately. Changes in the fair value of a derivative designated in a fair value or cash flow hedge are recognized in the same line item as the underlying hedged item.

(r) Share Capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any tax effects. When the company repurchases its own common shares, share capital is reduced by the average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as a deduction from Retained Earnings. Shares are cancelled upon purchase.

(s) Dividend Distributions

Dividends on common shares are recognized in the period in which the dividends are declared by the company's Board of Directors.

(t) Earnings per Share

Basic earnings per share is calculated by dividing the net earnings for the period by the weighted average number of common shares outstanding during the period.

Diluted earnings per share is calculated by adjusting the weighted average number of common shares outstanding for dilutive common shares related to the company's share-based compensation plans. The number of shares included is computed using the treasury stock method. Options with tandem stock appreciation rights or cash payment alternatives are accounted for as cash-settled plans. As these awards can be exchanged for common shares of the company, they are considered potentially dilutive and are included in the calculation of the company's diluted net earnings per share if they have a dilutive impact in the period.

4. SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGMENTS

The preparation of financial statements in accordance with IFRS requires management to make estimates and judgments that affect reported assets, liabilities, revenues, expenses, gains, losses, and disclosures of contingencies. These estimates

96 SUNCOR ENERGY INC. ANNUAL REPORT 2013

and judgments are subject to change based on experience and new information. The financial statement areas that require significant estimates and judgments are as follows:

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. All reserves and certain resources have been evaluated at December 31, 2013 by independent qualified reserves evaluators. 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

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.

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 operating activities.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 97

In addition, these provisions are based on estimated costs, which take into account the anticipated method and extent of 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.

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.

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.

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.

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 and estimates of the expected settlement amount, timing of reversals, and the tax laws in the jurisdictions in which the company operates.

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.

98 SUNCOR ENERGY INC. ANNUAL REPORT 2013

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.

5. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

The standards and interpretations that are issued but not yet effective up to the date of issuance of the company's financial statements, and that 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 International Accounting Standard (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.

6. ADOPTION OF NEW AND AMENDED IFRS STANDARDS

Effective January 1, 2013, the company adopted the following new and amended IFRS standards and interpretations.

New and/or amended IFRS standards that resulted in restatements to comparative figures

Impact of the application of IFRS 11 Joint Arrangements

IFRS 11 establishes a principle-based approach to accounting for joint arrangements by assessing the rights and obligations of the arrangement and limits the application of proportionate consolidation accounting to arrangements where sufficient rights and obligations are passed to the partners. As a result, two existing joint arrangements in the Refining and Marketing segment were reclassified as joint ventures, and are now being accounted for using the equity

SUNCOR ENERGY INC. ANNUAL REPORT 2013 99

method of accounting rather than the proportionate consolidation method. This change did not have a material impact to the consolidated financial statements, but did result in the netting of revenues and expenses for these entities into Other Income, the netting of equity pick-up and cash distribution within Other in the Consolidated Statements of Cash Flows, and the company's net investment in these entities is now presented in Other Assets.

Impact of the application of IAS 19 Employee Benefits amendments

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 noted below.

IFRS 11 and the amendments to IAS 19 have been applied retroactively, and the effects of the application of IFRS 11 and IAS 19 amendments on the comparative periods are shown in the tables below.

Adjustments to Consolidated Statements of Comprehensive Income(1):

|  | For the year ended December 31, 2012 |  |
($ millions, increase/(decrease)) |  | IFRS 11 |  | IAS 19 |  | Total |  |
Revenues and Other Income |  |  |  |  |  |  |  |
| Operating revenues, net of royalties |  | (101 | ) | — |  | (101 | ) |
| Other income |  | 11 |  | — |  | 11 |  |
Expenses |  |  |  |  |  |  |  |
| Purchases of crude oil and products |  | (54 | ) | — |  | (54 | ) |
| Operating, selling and general |  | (29 | ) | (22 | ) | (51 | ) |
| Depreciation, depletion, amortization and impairment |  | (4 | ) | — |  | (4 | ) |
| Financing expenses |  | (3 | ) | 79 |  | 76 |  |
Income Taxes |  |  |  |  |  |  |  |
| Deferred |  | — |  | (14 | ) | (14 | ) |
Net Loss |  | — |  | (43 | ) | (43 | ) |
| Actuarial gain on employee retirement benefit plans |  | — |  | 43 |  | 43 |  |
Total Comprehensive Income |  | — |  | — |  | — |  |
Per Common Share (dollars) |  |  |  |  |  |  |  |
| Basic |  | — |  | (0.03 | ) | (0.03 | ) |
| Diluted |  | — |  | (0.03 | ) | (0.03 | ) |

(1)
  The impact of the IAS 19 adjustments for the year ended December 31, 2013 was an increase to Financing Expenses of $49 million with a corresponding actuarial gain of $36 million, net of income taxes of $13 million, resulting in a $nil impact to the Consolidated Statements of Comprehensive Income.

100 SUNCOR ENERGY INC. ANNUAL REPORT 2013

Adjustments to Consolidated Balance Sheets:

($ millions, increase/(decrease)) |  | Dec 31 2012 |  | Jan 1 2012 |  |
Cash and cash equivalents |  | (8 | ) | (22 | ) |
Accounts receivable |  | (43 | ) | (29 | ) |
Inventories |  | (46 | ) | (36 | ) |
Property, plant and equipment, net |  | (24 | ) | (26 | ) |
Other assets |  | 99 |  | 102 |  |
Goodwill and other intangible assets |  | (24 | ) | (25 | ) |
Deferred income taxes |  | (2 | ) | — |  |
Total assets |  | (48 | ) | (36 | ) |
Short-term debt |  | (1 | ) | (2 | ) |
Accounts payable and accrued liabilities |  | (23 | ) | (13 | ) |
Income taxes payable |  | (5 | ) | (5 | ) |
Other long-term liabilities(2) |  | 9 |  | 10 |  |
Provisions |  | (1 | ) | (1 | ) |
Deferred income taxes(2) |  | (19 | ) | (17 | ) |
Shareholders' equity(2) |  | (8 | ) | (8 | ) |
Total liabilities and shareholders' equity |  | (48 | ) | (36 | ) |

(2)
  At December 31, 2012, the adjustment related to IAS 19 resulted in an increase of $11 million to Other long-term liabilities, offset by a decrease of $3 million and $8 million, respectively, to Deferred income taxes and Shareholders' equity. The remaining adjustments relate to IFRS 11.

Adjustments to Consolidated Statements of Cash Flow:

($ millions, increase/(decrease)) |  | For the year ended December 31, 2012 |  |
Operating activities |  |  |  |
| Cash flow from operating activities before change in non-cash working capital |  | (12 | ) |
| Decrease in non-cash working capital |  | 25 |  |
Cash flow from operating activities |  | 13 |  |
Cash flow from investing activities |  | 1 |  |
Cash flow from financing activities |  | — |  |
Increase in cash and cash equivalents |  | 14 |  |

Other new IFRS standards

Joint Arrangements

IFRS 12 Disclosures of Interests in Other Entities is a comprehensive disclosure standard for all forms of interests in other entities, including subsidiaries, joint arrangements, associates and unconsolidated structured entities. The adoption of this standard had no material impact on the company's consolidated financial statements, but did result in increased disclosures on the company's material subsidiaries and interest in associates and joint arrangements. Refer to note 29 and 30.

Offsetting Financial Assets and Financial Liabilities Disclosures

IFRS 7 Financial Instruments: Disclosures amendments added disclosure requirements to enhance the understanding of the potential effects of offsetting arrangements. Refer to note 27.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 101

Fair Value Measurements

IFRS 13 Fair Value Measurement establishes a single source of guidance for most fair value measurements, clarifies the definition of fair value, and enhances the disclosures on fair value measurement. The adoption of this standard had no material impact on the company's consolidated financial statements, but did result in increased disclosures on the fair value measurement of the company's financial instruments. Refer to note 27.

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 CGU is impaired. The amended standard also requires expanded disclosure, including the fair value measurement input level, for CGUs with goodwill and assets that are impaired based on fair value less costs of disposal methodology. Refer to notes 10 and 20.

7. SEGMENTED INFORMATION

The company's operating segments are reported based on the nature of their products and services and management responsibility. The following summary describes the operations in each of the segments:

•
  Oil Sands includes the company's operations in northeast Alberta to develop and produce synthetic crude oil and related products, through the recovery and upgrading of bitumen from mining and in situ operations. This segment also includes the company's joint interest in Fort Hills (40.8%) and Joslyn North (36.75%) mining projects as well as its 12% ownership interest in the Syncrude oil sands mining and upgrading joint venture, located near Fort McMurray, Alberta.
•
  Exploration and Production includes exploration and production of natural gas, crude oil and natural gas liquids in Western Canada, offshore activity in East Coast Canada, with interests in the Hibernia, Terra Nova, White Rose and Hebron oilfields, and the exploration and production of crude oil and natural gas in the United Kingdom (U.K.), Norway, Libya and Syria. Due to unrest in Syria, the company has declared force majeure under its contractual obligations, and Suncor's operations in Syria have been suspended indefinitely.
•
  Refining and Marketing includes the refining of crude oil products, and the distribution and marketing of these and other purchased products through retail stations located in Canada and the United States (U.S.), as well as a lubricants plant located in Eastern Canada.

The company also reports activities not directly attributable to an operating segment under Corporate, Energy Trading and Eliminations. This includes investments in renewable energy projects.

Intersegment sales of crude oil and natural gas are accounted for at market values and included, for segmented reporting, in revenues of the segment making the transfer and expenses of the segment receiving the transfer. Intersegment balances are eliminated on consolidation. Intersegment profit will not be eliminated until the related product has been sold to third parties.

102 SUNCOR ENERGY INC. ANNUAL REPORT 2013

The company had no customer that individually represented 10% or more of the consolidated revenues for the year ended December 31, 2013 and 2012.

For the years 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 |  |
|  | (restated – note 6) |  |  |  |  |  | (restated – note 6) |  | (restated – note 6) |  | (restated – note 6) |  |
Revenues and Other Income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gross revenues |  | 9 063 |  | 8 378 |  | 5 931 |  | 5 947 |  | 26 495 |  | 26 008 |  | 109 |  | 89 |  | 41 598 |  | 40 422 |  |
Intersegment revenues |  | 4 026 |  | 3 124 |  | 432 |  | 529 |  | 163 |  | 212 |  | (4 621 | ) | (3 865 | ) | — |  | — |  |
Less: Royalties |  | (859 | ) | (684 | ) | (1 146 | ) | (1 631 | ) | — |  | — |  | — |  | — |  | (2 005 | ) | (2 315 | ) |
Operating revenues, net of royalties |  | 12 230 |  | 10 818 |  | 5 217 |  | 4 845 |  | 26 658 |  | 26 220 |  | (4 512 | ) | (3 776 | ) | 39 593 |  | 38 107 |  |
Other income |  | 64 |  | 20 |  | 381 |  | 71 |  | 22 |  | 38 |  | 237 |  | 290 |  | 704 |  | 419 |  |
|  | 12 294 |  | 10 838 |  | 5 598 |  | 4 916 |  | 26 680 |  | 26 258 |  | (4 275 | ) | (3 486 | ) | 40 297 |  | 38 526 |  |
Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchases of crude oil and products |  | 460 |  | 211 |  | 568 |  | 444 |  | 20 807 |  | 20 341 |  | (4 542 | ) | (3 949 | ) | 17 293 |  | 17 047 |  |
Operating, selling and general |  | 5 837 |  | 5 365 |  | 676 |  | 795 |  | 2 307 |  | 2 249 |  | 627 |  | 488 |  | 9 447 |  | 8 897 |  |
Transportation |  | 482 |  | 337 |  | 127 |  | 182 |  | 278 |  | 204 |  | (42 | ) | (38 | ) | 845 |  | 685 |  |
Depreciation, depletion, amortization and impairment |  | 2 439 |  | 3 964 |  | 1 804 |  | 1 857 |  | 530 |  | 464 |  | 119 |  | 161 |  | 4 892 |  | 6 446 |  |
Exploration |  | 115 |  | 71 |  | 207 |  | 238 |  | — |  | — |  | — |  | — |  | 322 |  | 309 |  |
Gain on disposal of assets |  | — |  | (29 | ) | (130 | ) | (1 | ) | (7 | ) | (13 | ) | — |  | (1 | ) | (137 | ) | (44 | ) |
Project start-up costs |  | 15 |  | 57 |  | — |  | — |  | — |  | 3 |  | — |  | — |  | 15 |  | 60 |  |
Voyageur upgrader project charges |  | 82 |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | 82 |  | — |  |
Financing expenses (income) |  | 135 |  | 127 |  | 33 |  | 81 |  | 5 |  | 2 |  | 989 |  | (68 | ) | 1 162 |  | 142 |  |
|  | 9 565 |  | 10 103 |  | 3 285 |  | 3 596 |  | 23 920 |  | 23 250 |  | (2 849 | ) | (3 407 | ) | 33 921 |  | 33 542 |  |
Earnings (Loss) before Income Taxes |  | 2 729 |  | 735 |  | 2 313 |  | 1 320 |  | 2 760 |  | 3 008 |  | (1 426 | ) | (79 | ) | 6 376 |  | 4 984 |  |
Income Taxes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current |  | 331 |  | 1 |  | 1 443 |  | 1 154 |  | 674 |  | 342 |  | (365 | ) | 18 |  | 2 083 |  | 1 515 |  |
Deferred |  | 358 |  | 266 |  | (130 | ) | 28 |  | 64 |  | 529 |  | 90 |  | (94 | ) | 382 |  | 729 |  |
|  | 689 |  | 267 |  | 1 313 |  | 1 182 |  | 738 |  | 871 |  | (275 | ) | (76 | ) | 2 465 |  | 2 244 |  |
Net Earnings (Loss) |  | 2 040 |  | 468 |  | 1 000 |  | 138 |  | 2 022 |  | 2 137 |  | (1 151 | ) | (3 | ) | 3 911 |  | 2 740 |  |
Capital and Exploration Expenditures |  | 4 311 |  | 4 957 |  | 1 483 |  | 1 261 |  | 890 |  | 644 |  | 93 |  | 95 |  | 6 777 |  | 6 957 |  |

Geographical Information

Operating Revenues, net of Royalties

($ millions) |  | 2013 |  | 2012 |
|  |  |  | (restated – note 6) |
Canada |  | 31 407 |  | 30 074 |
Foreign |  | 8 186 |  | 8 033 |
|  | 39 593 |  | 38 107 |

SUNCOR ENERGY INC. ANNUAL REPORT 2013 103

Non-Current Assets(1)

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |
|  |  |  | (restated – note 6) |  | (restated – note 6) |
Canada |  | 57 235 |  | 55 817 |  | 53 845 |
Foreign |  | 6 321 |  | 6 424 |  | 6 799 |
|  | 63 556 |  | 62 241 |  | 60 644 |

(1)
  Excludes deferred income tax assets.

8. OTHER INCOME

Other Income consists of the following:

($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Energy trading activities |  |  |  |  |  |
| Change in fair value of contracts |  | 176 |  | 246 |  |
| Gains (losses) on inventory valuation |  | 15 |  | (13 | ) |
Risk management activities |  | (18 | ) | 1 |  |
Risk mitigation and insurance proceeds |  | 342 |  | 27 |  |
Investment and interest income |  | 85 |  | 91 |  |
Renewable energy grants |  | 47 |  | 59 |  |
Change in value of pipeline commitments and other |  | 57 |  | 8 |  |
|  | 704 |  | 419 |  |

9. OPERATING, SELLING AND GENERAL

Operating, Selling and General expense consists of the following:

($ millions) |  | 2013 |  | 2012 |
|  |  |  | (restated – note 6) |
Contract services |  | 4 412 |  | 4 067 |
Employee costs(1) |  | 2 654 |  | 2 664 |
Materials |  | 932 |  | 720 |
Energy |  | 915 |  | 608 |
Equipment rentals and leases |  | 335 |  | 329 |
Travel, marketing and other |  | 199 |  | 509 |
|  | 9 447 |  | 8 897 |

(1)
  The company incurred $3.3 billion of employee costs for the year ended December 31, 2013 (2012 – $3.2 billion), of which $2.7 billion (2012 – $2.7 billion) was recorded as employee benefits in Operating, Selling and General expense. Employee costs includes salaries, benefits and share-based compensation.

104 SUNCOR ENERGY INC. ANNUAL REPORT 2013

10. ASSET IMPAIRMENT

All impairments and impairment reversals were recorded as part of Depreciation, Depletion, Amortization and Impairment expense. Asset impairments during the period are as follows.

Exploration and Production

Libya

Political unrest in Libya resulted in the closure of export terminal operations at certain Libyan seaports in late July 2013 and production was essentially shut-in for the last five months of 2013. As a result, the company performed an impairment test on its Libyan assets using a value-in-use methodology to determine the recoverable amount, and an after-tax impairment charge of $101 million was recognized in the fourth quarter of 2013 and charged against Property, Plant and Equipment.

The impairment test used an expected cash flow approach based on 2013 year-end reserves data with a risk-adjusted discount rate of 17% to reflect uncertainty related to continued political unrest in the region, with three scenarios representing i) future cash flows based on the 2013 year-end reserves information, ii) future operations incorporating the company's strategic growth plan, 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 incorporated the restart of production on April 1, 2014 and were based on an average price of US$104.00 per barrel through 2014 – 2019 escalated at an average of 2% per year thereafter.

The calculation of the recoverable amount is sensitive to the likelihood and timing of production restart, the discount rate, and prices. A three-month delay in the resumption of production restart would impact after-tax earnings by approximately $50 million. A 2% change in discount rate would impact after-tax earnings by approximately $80 million. A 5% change in price would impact after-tax earnings by approximately $75 million.

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

Syria

Since December 2011, the company's operations and its contractual obligations in Syria have been suspended under a period of force majeure due to political unrest and international sanctions affecting that country. As there has been no resolution of the political situation and increasing uncertainty with respect to the company's return to operations in the country, during the fourth quarter of 2013, using a value-in-use methodology, the company impaired the remaining carrying value of its Syrian property, plant and equipment and working capital, resulting in an after-tax impairment charge of $422 million. The company also recognized $300 million ($223 million after-tax) of risk mitigation proceeds in Other Income that had been received in the fourth quarter of 2012 as the likelihood of return in the foreseeable future is remote. These proceeds are subject to a provisional repayment should the company recover any or all of its investment in Syria.

In the second quarter of 2012, the company recognized after-tax impairment charges and a bad debt provision of $694 million related to its Syrian assets. An impairment test was performed since there was no resolution to the political situation and international sanctions continued to affect the country. The impairment losses were charged against Property, Plant and Equipment ($604 million) and other current assets ($23 million). The company also recognized a bad debt provision for the remainder of its Syrian receivables ($67 million).

In the fourth quarter of 2012, a valuation assessment was performed. After receipt of the $300 million of risk mitigation proceeds, an impairment reversal of $177 million was recorded.

Other

In the fourth quarter of 2013, the company recognized an after-tax impairment charge of $40 million to reflect the recoverable amount of its unconventional oil properties in the Wilson Creek area of central Alberta. The recoverable amount was determined using a fair value less costs of disposal methodology, with the expected cash flow approach based on 2013 year-end reserves information and a risk-adjusted discount rate of 10% (Level 3 fair value inputs).

In the fourth quarter of 2012, the company recognized an after-tax impairment charge of $65 million related primarily to certain East Coast Canada exploration and evaluation assets as well as natural gas Arctic land leases as a result of future

SUNCOR ENERGY INC. ANNUAL REPORT 2013 105

development uncertainty. In addition, the company also recognized an after-tax impairment charge of $63 million related to certain natural gas properties due to a decline in price forecasts.

Oil Sands

Voyageur Upgrader Project

In the fourth quarter of 2012, the company recognized after-tax impairment charges of $1.487 billion related to its 51% interest in the Voyageur upgrader project. As a result of the challenging economic outlook for the Voyageur upgrader, an impairment test was performed at December 31, 2012, using a fair value less costs of disposal methodology. A risk-adjusted discount rate of 10% was used to perform the calculation.

11. FINANCING EXPENSES

($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Interest on debt and finance leases |  | 703 |  | 640 |  |
Capitalized interest at 6.1% (2012 – 6.0%) |  | (397 | ) | (587 | ) |
| Interest expense |  | 306 |  | 53 |  |
| Interest on pension and other post-retirement benefits |  | 68 |  | 79 |  |
| Accretion |  | 192 |  | 182 |  |
| Foreign exchange loss (gain) on U.S. dollar denominated debt |  | 605 |  | (181 | ) |
| Foreign exchange and other |  | (9 | ) | 9 |  |
|  | 1 162 |  | 142 |  |

12. INCOME TAXES

Income Tax Expense

($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Current: |  |  |  |  |  |
| Current year |  | 2 093 |  | 1 483 |  |
| Adjustments for prior years |  | (10 | ) | 32 |  |
Deferred: |  |  |  |  |  |
| Origination and reversal of temporary differences |  | 410 |  | 687 |  |
| Adjustments for prior years |  | (28 | ) | (46 | ) |
| Changes in tax rates and legislation |  | — |  | 88 |  |
|  | 2 465 |  | 2 244 |  |

There was no income tax recognized directly in equity during 2013 and 2012.

106 SUNCOR ENERGY INC. ANNUAL REPORT 2013

Reconciliation of Effective Tax Rate

The provision for income taxes reflects an effective tax rate that differs from the statutory tax rate. A reconciliation of the difference is as follows:

($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Earnings before income tax |  | 6 376 |  | 4 984 |  |
Canadian statutory tax rate |  | 25.64% |  | 25.67% |  |
Statutory tax |  | 1 635 |  | 1 279 |  |
Add (deduct) the tax effect of: |  |  |  |  |  |
| Non-taxable component of capital gains and losses |  | 71 |  | (22 | ) |
| Share-based compensation and other permanent items |  | 5 |  | 15 |  |
| Assessments and adjustments |  | (38 | ) | — |  |
| Impact of income tax rate and legislative changes(1) |  | — |  | 88 |  |
| Canadian tax rate differential |  | 4 |  | 1 |  |
| Foreign tax rate differential |  | 691 |  | 763 |  |
| Non-taxable impairment charge |  | 134 |  | 127 |  |
| Other |  | (37 | ) | (7 | ) |
|  | 2 465 |  | 2 244 |  |

(1)
  In the second quarter of 2012, the Ontario government substantively enacted legislation to freeze the general corporate income tax rate at 11.5% instead of the planned reduction to 10%. Accordingly, the company recognized an increase in deferred tax expense of $88 million related to the revaluation of deferred income tax balances.

Deferred Income Tax Balances

Deferred income tax expense and net liabilities in the company's consolidated financial statements were comprised of the following:

|  | Consolidated Statements of Comprehensive Income |  | Consolidated Balance Sheets (2) |  |
($ millions) |  | 2013 |  | 2012 |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |  |
|  |  |  | (restated – note 6) |  |  |  | (restated – note 6) |  | (restated – note 6) |  |
Property, plant and equipment |  | 758 |  | 1 266 |  | 12 134 |  | 11 991 |  | 10 725 |  |
Decommissioning and restoration provision |  | (54 | ) | (625 | ) | (1 017 | ) | (1 132 | ) | (507 | ) |
Employee retirement benefit plans |  | (103 | ) | (69 | ) | (541 | ) | (636 | ) | (521 | ) |
Tax loss carry-forwards |  | 136 |  | 391 |  | (31 | ) | (167 | ) | (558 | ) |
Partnership deferral reserve |  | (213 | ) | (189 | ) | 192 |  | 405 |  | 594 |  |
Other |  | (142 | ) | (45 | ) | (18 | ) | (95 | ) | (91 | ) |
|  | 382 |  | 729 |  | 10 719 |  | 10 366 |  | 9 642 |  |

(2)
  The current and non-current portion of the deferred income tax liability and asset are as follows:

SUNCOR ENERGY INC. ANNUAL REPORT 2013 107

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |  |
|  |  |  | (restated – note 6) |  | (restated – note 6) |  |
Current deferred income tax liability |  | 103 |  | 141 |  | 6 |  |
Current deferred income tax asset |  | (4 | ) | (9 | ) | (13 | ) |
Non-current deferred income tax liability |  | 10 681 |  | 10 303 |  | 9 696 |  |
Non-current deferred income tax asset |  | (61 | ) | (69 | ) | (47 | ) |
Net deferred income tax liability |  | 10 719 |  | 10 366 |  | 9 642 |  |

Change in Deferred Income Tax Balances

($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Beginning of year |  | 10 366 |  | 9 642 |  |
Recognized in deferred income tax expense |  | 382 |  | 729 |  |
Recognized in other comprehensive income |  | 201 |  | (49 | ) |
Foreign exchange, disposition, and other |  | (230 | ) | 44 |  |
End of year |  | 10 719 |  | 10 366 |  |

No deferred tax liability has been recognized at December 31, 2013 on temporary differences of approximately $11.2 billion (2012 – $9.9 billion) associated with earnings retained in our investments in foreign subsidiaries, as the company is able to control the timing of the reversal of these differences. Based on current plans, repatriation of funds in excess of foreign reinvestment will not result in material additional income tax expense. Deferred distribution taxes associated with international business operations have not been recorded.

Canada Revenue Agency Proposal Letter

In January 2013, the company received a proposal letter from the Canada Revenue Agency (CRA) relating to the income tax treatment of the realized losses in 2007 on the settlement of certain derivative contracts. Following the company's response to the letter and subsequent information requests in 2013, 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), the company 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.

The company 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.

108 SUNCOR ENERGY INC. ANNUAL REPORT 2013

13. EARNINGS PER COMMON SHARE

($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Net earnings |  | 3 911 |  | 2 740 |  |
Dilutive impact of accounting for awards as equity-settled(1) |  | — |  | (7 | ) |
Net earnings – diluted |  | 3 911 |  | 2 733 |  |
(millions of common shares) |  |  |  |  |  |
Weighted average number of common shares |  | 1 501 |  | 1 545 |  |
Dilutive securities: |  |  |  |  |  |
| Effect of share options |  | 1 |  | 4 |  |
Weighted average number of diluted common shares |  | 1 502 |  | 1 549 |  |
(dollars per common share) |  |  |  |  |  |
Basic earnings per share |  | 2.61 |  | 1.77 |  |
Diluted earnings per share |  | 2.60 |  | 1.76 |  |

(1)
  Options with tandem stock appreciation rights or cash payment alternatives are accounted for as cash-settled plans. As these awards can be exchanged for common shares of the company, they are considered potentially dilutive and are included in the calculation of the company's diluted net earnings per share calculation if they have a dilutive impact in the period. Accounting for these awards as equity-settled was determined to have a dilutive impact for the year ended December 31, 2012.

14. CASH AND CASH EQUIVALENTS

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |
|  |  |  | (restated – note 6) |  | (restated – note 6) |
Cash |  | 1 184 |  | 628 |  | 810 |
Cash equivalents |  | 4 018 |  | 3 757 |  | 2 971 |
|  | 5 202 |  | 4 385 |  | 3 781 |

SUNCOR ENERGY INC. ANNUAL REPORT 2013 109

15. SUPPLEMENTAL CASH FLOW INFORMATION

The (increase) decrease in non-cash working capital is comprised of:

($ millions) |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |
Accounts receivable |  | (60 | ) | 193 |  |
Inventories |  | (220 | ) | 460 |  |
Accounts payable and accrued liabilities |  | 69 |  | (1 729 | ) |
Current portion of provisions |  | 206 |  | 45 |  |
Income taxes payable (net) |  | 603 |  | 106 |  |
|  | 598 |  | (925 | ) |
Relating to: |  |  |  |  |  |
| Operating activities |  | 688 |  | (874 | ) |
| Investing activities |  | (90 | ) | (51 | ) |

16. INVENTORIES

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |
|  |  |  | (restated – note 6) |  | (restated – note 6) |
Crude oil |  | 1 269 |  | 1 091 |  | 1 321 |
Refined products |  | 1 695 |  | 1 523 |  | 1 705 |
Materials, supplies and merchandise |  | 594 |  | 597 |  | 592 |
Energy trading commodity inventories |  | 386 |  | 486 |  | 551 |
|  | 3 944 |  | 3 697 |  | 4 169 |

During 2013, product inventories of $18.0 billion (2012 – $17.7 billion) were expensed. There was no inventory write-down during 2013 (2012 – $45 million).

110 SUNCOR ENERGY INC. ANNUAL REPORT 2013

17. PROPERTY, PLANT AND EQUIPMENT

($ millions) |  | Oil and Gas Properties |  | Plant and Equipment |  | Total |  |
|  |  |  |  |  | (restated – note 6) |  |
Cost |  |  |  |  |  |  |  |
At January 1, 2012 |  | 20 289 |  | 45 107 |  | 65 396 |  |
| Additions |  | 1 739 |  | 4 955 |  | 6 694 |  |
| Transfers from exploration and evaluation |  | 1 598 |  | — |  | 1 598 |  |
| Changes in decommissioning and restoration |  | 899 |  | 92 |  | 991 |  |
| Disposals |  | (49 | ) | (185 | ) | (234 | ) |
| Foreign exchange adjustments |  | (22 | ) | (55 | ) | (77 | ) |
At December 31, 2012 |  | 24 454 |  | 49 914 |  | 74 368 |  |
| Additions |  | 2 094 |  | 4 475 |  | 6 569 |  |
| Transfers from exploration and evaluation |  | 644 |  | — |  | 644 |  |
| Acquisitions (note 33) |  | — |  | 374 |  | 374 |  |
| Changes in decommissioning and restoration |  | 358 |  | 18 |  | 376 |  |
| Disposals |  | (2 578 | ) | (921 | ) | (3 499 | ) |
| Foreign exchange adjustments |  | 551 |  | 166 |  | 717 |  |
At December 31, 2013 |  | 25 523 |  | 54 026 |  | 79 549 |  |
Accumulated provision |  |  |  |  |  |  |  |
At January 1, 2012 |  | (4 706 | ) | (8 127 | ) | (12 833 | ) |
| Depreciation and depletion |  | (1 634 | ) | (2 058 | ) | (3 692 | ) |
| Impairment (note 10) |  | (204 | ) | (2 484 | ) | (2 688 | ) |
| Impairment reversal (note 10) |  | 34 |  | 143 |  | 177 |  |
| Disposals |  | 42 |  | 57 |  | 99 |  |
| Foreign exchange adjustments |  | (25 | ) | 28 |  | 3 |  |
At December 31, 2012 |  | (6 493 | ) | (12 441 | ) | (18 934 | ) |
| Depreciation and depletion |  | (2 056 | ) | (2 181 | ) | (4 237 | ) |
| Impairment (note 10) |  | (155 | ) | (444 | ) | (599 | ) |
| Disposals |  | 997 |  | 744 |  | 1 741 |  |
| Foreign exchange adjustments |  | (189 | ) | (61 | ) | (250 | ) |
At December 31, 2013 |  | (7 896 | ) | (14 383 | ) | (22 279 | ) |
Net property, plant and equipment |  |  |  |  |  |  |  |
| December 31, 2012 |  | 17 961 |  | 37 473 |  | 55 434 |  |
| December 31, 2013 |  | 17 627 |  | 39 643 |  | 57 270 |  |

SUNCOR ENERGY INC. ANNUAL REPORT 2013 111

|  | Dec 31, 2013 |  | Dec 31, 2012 |
($ millions) |  | Cost |  | Accumulated provision |  | Net book value |  | Cost |  | Accumulated provision |  | Net book value |
|  |  |  |  |  |  |  |  |  |  |  | (restated – note 6) |
Oil Sands |  | 52 127 |  | (12 125 | ) | 40 002 |  | 47 337 |  | (10 440 | ) | 36 897 |
Exploration and Production |  | 15 660 |  | (6 704 | ) | 8 956 |  | 16 335 |  | (5 691 | ) | 10 644 |
Refining and Marketing |  | 10 449 |  | (2 883 | ) | 7 566 |  | 9 462 |  | (2 355 | ) | 7 107 |
Corporate, Energy Trading and Eliminations |  | 1 313 |  | (567 | ) | 746 |  | 1 234 |  | (448 | ) | 786 |
|  | 79 549 |  | (22 279 | ) | 57 270 |  | 74 368 |  | (18 934 | ) | 55 434 |

At December 31, 2013, the balance of assets under construction, and not subject to depreciation or depletion, was $11.1 billion (December 31, 2012 – $12.2 billion; January 1, 2012 – $16.2 billion).

At December 31, 2013, Property, Plant and Equipment included finance leases with a net book value of $997 million (December 31, 2012 – $831 million; January 1, 2012 – $425 million).

Fort Hills Project Sanction

On October 30, 2013, the co-owners of Fort Hills announced project sanction. As a result, the accumulated capital costs in exploration and evaluation assets 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. Key assumptions used in the calculation of the recoverable amount were bitumen price, 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 may result in impairment.

For purposes of calculating the recoverable amount at the date of sanction, the company applied a risk-adjusted discount rate of 8%, assumed bitumen price of $64.00 per barrel at first oil in 2017, escalated at an average of 2% per year thereafter, for the remaining life of the mine, and go forward capital costs of $5.5 billion (Level 3 fair value inputs).

A 1% increase in discount rate would have resulted in a decrease to the recoverable amount of $1.0 billion. Bitumen prices were based on third party published price curves adjusted for the company's view on long-term pricing economics and marketing information. A 5% decrease in prices would have resulted in a decrease to the recoverable amount of $800 million. Future capital costs of the mine are derived from company experience and adjusted for specific attributes of the project and expected cost savings due to new technologies. A 15% increase to this estimate (over the construction period) would have resulted in a decrease to the recoverable amount of $700 million.

18. EXPLORATION AND EVALUATION ASSETS

($ millions) |  | 2013 |  | 2012 |  |
Beginning of year |  | 3 284 |  | 4 554 |  |
Additions |  | 225 |  | 478 |  |
Transfers to oil and gas assets |  | (644 | ) | (1 598 | ) |
Dry hole expenses |  | (82 | ) | (145 | ) |
Disposals |  | (11 | ) | — |  |
Impairment |  | — |  | (88 | ) |
Amortization |  | (13 | ) | (24 | ) |
Foreign exchange adjustments |  | 13 |  | 107 |  |
End of year |  | 2 772 |  | 3 284 |  |

112 SUNCOR ENERGY INC. ANNUAL REPORT 2013

19. OTHER ASSETS

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |
|  |  |  | (restated – note 6) |  | (restated – note 6) |
Investments |  | 325 |  | 309 |  | 265 |
Prepaids and other |  | 97 |  | 110 |  | 148 |
|  | 422 |  | 419 |  | 413 |

20. GOODWILL AND OTHER INTANGIBLE ASSETS

|  | Oil Sands |  | Refining and Marketing |  |  |  |
($ millions) |  | Goodwill |  | Goodwill |  | Brand name |  | Customer lists |  | Total |  |
|  |  |  | (restated – note 6) |  |  |  |  |  | (restated – note 6) |  |
At January 1, 2012 |  | 2 752 |  | 149 |  | 166 |  | 47 |  | 3 114 |  |
Derecognition of goodwill |  | — |  | (1 | ) | — |  | — |  | (1 | ) |
Additions |  | — |  | — |  | — |  | 5 |  | 5 |  |
Amortization |  | — |  | — |  | — |  | (14 | ) | (14 | ) |
At December 31, 2012 |  | 2 752 |  | 148 |  | 166 |  | 38 |  | 3 104 |  |
Amortization |  | — |  | — |  | — |  | (12 | ) | (12 | ) |
At December 31, 2013 |  | 2 752 |  | 148 |  | 166 |  | 26 |  | 3 092 |  |

The company performed its most recent goodwill impairment test at October 31, 2013. Recoverable amounts for the Oil Sands CGUs were based on fair value less costs of disposal calculated using the present value of the CGUs' expected future cash flows. The primary sources of cash flow information are derived from business plans approved by executives of the company, which were developed based on macroeconomic factors such as forward price curves for benchmark commodities, inflation rates and industry supply-demand fundamentals. When required, the projected cash flows in the business plan have been updated to reflect current market assessments of key assumptions, including long-term forecasts of commodity prices, inflation rates, foreign exchange rates and discount rates specific to the asset (Level 3 fair value inputs).

Cash flow forecasts are also based on past experience, historical trends and third-party evaluations of the company's reserves and resources to determine production profiles and volumes, operating costs, maintenance and capital expenditures. Production profiles, reserves volumes, operating costs, maintenance and capital expenditures are consistent with the estimates approved through the company's annual reserves evaluation process and determine the duration of the underlying cash flows used in the discounted cash flow test.

Future cash flow estimates are discounted using after-tax risk-adjusted discount rates. The discount rates are calculated based on the weighted average cost of capital that is implicit in current market transactions for similar assets. The after-tax discount rate applied to cash flow projections was 10% at October 31, 2013 (July 31, 2012 – 10%). The company based its cash flow projections on an average West Texas Intermediate (WTI) price of US$ 97.50 per barrel through 2014-2019 escalated at an average of 2% per year thereafter, adjusted for applicable quality and location differentials depending on the underlying CGU. The forecasted cash flow period ranged from 20 years to 55 years based on the reserve life of the respective CGU. As a result of this analysis, management did not identify impairment within the Oil Sands operating segment and the associated allocated goodwill.

The company also performed a goodwill impairment test at October 31, 2013 of its Refining and Marketing operating segment, and no impairment was identified within the operating segment or the associated allocated goodwill.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 113

21. DEBT AND CREDIT FACILITIES

Debt and credit facilities are comprised of the following:

Short-Term Debt

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |
|  |  |  | (restated – note 6) |  | (restated – note 6) |
Commercial paper (1) |  | 798 |  | 775 |  | 761 |

(1)
  The commercial paper is supported by a revolving credit facility with a separate lender. The company is authorized to issue commercial paper to a maximum of $2.5 billion having a term not to exceed 365 days. The weighted-average interest rate as at December 31, 2013 was 0.3% (December 31, 2012 – 0.4%; January 1, 2012 – 0.4%).

Long-Term Debt

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |  |
Fixed-term debt, redeemable at the option of the company |  |  |  |  |  |  |  |
| 6.85% Notes, due 2039 (US$750) |  | 798 |  | 746 |  | 763 |  |
| 6.80% Notes, due 2038 (US$900) |  | 983 |  | 921 |  | 942 |  |
| 6.50% Notes, due 2038 (US$1150) |  | 1 223 |  | 1 144 |  | 1 170 |  |
| 5.95% Notes, due 2035 (US$600) |  | 596 |  | 556 |  | 566 |  |
| 5.95% Notes, due 2034 (US$500) |  | 532 |  | 498 |  | 509 |  |
| 5.35% Notes, due 2033 (US$300) |  | 279 |  | 259 |  | 263 |  |
| 7.15% Notes, due 2032 (US$500) |  | 532 |  | 498 |  | 509 |  |
| 6.10% Notes, due 2018 (US$1250) |  | 1 330 |  | 1 244 |  | 1 271 |  |
| 6.05% Notes, due 2018 (US$600) |  | 646 |  | 606 |  | 621 |  |
| 5.00% Notes, due 2014 (US$400) |  | 427 |  | 402 |  | 413 |  |
| 4.00% Notes, due 2013 (US$300) |  | — |  | 299 |  | 305 |  |
| 7.00% Debentures, due 2028 (US$250) |  | 274 |  | 256 |  | 263 |  |
| 7.875% Debentures, due 2026 (US$275) |  | 321 |  | 303 |  | 312 |  |
| 9.25% Debentures, due 2021 (US$300) |  | 378 |  | 361 |  | 376 |  |
| 5.39% Series 4 Medium Term Notes, due 2037 |  | 600 |  | 600 |  | 600 |  |
| 5.80% Series 4 Medium Term Notes, due 2018 |  | 700 |  | 700 |  | 700 |  |
Total unsecured long-term debt |  | 9 619 |  | 9 393 |  | 9 583 |  |
Secured long-term debt |  | 13 |  | 13 |  | 13 |  |
Finance leases (2) |  | 1 071 |  | 894 |  | 476 |  |
Deferred financing costs |  | (43 | ) | (51 | ) | (56 | ) |
|  | 10 660 |  | 10 249 |  | 10 016 |  |
Current portion of long-term debt |  |  |  |  |  |  |  |
| Finance leases |  | (17 | ) | (12 | ) | (12 | ) |
| Secured long-term debt |  | (13 | ) | — |  | — |  |
| 4.00% Notes, due July 2013 (US$300) |  | — |  | (299 | ) | — |  |
| 5.00% Notes, due 2014 (US$400) |  | (427 | ) | — |  | — |  |
|  | (457 | ) | (311 | ) | (12 | ) |
Total long-term debt |  | 10 203 |  | 9 938 |  | 10 004 |  |

(2)
  Interest rates range from 4.6% to 13.4% and maturity dates range from 2017 to 2052.

114 SUNCOR ENERGY INC. ANNUAL REPORT 2013

Scheduled Debt Repayments

Scheduled principal repayments for finance leases, short-term debt and long-term debt are as follows:

($ millions) |  | Repayment |
2014 |  | 1 255 |
2015 |  | 22 |
2016 |  | 24 |
2017 |  | 23 |
2018 |  | 2 690 |
Thereafter |  | 7 437 |
|  | 11 451 |

Credit Facilities

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

($ millions) |  | 2013 |  |
Fully revolving for a period of one year after term-out date (Nov 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 credit facilities |  | 6 188 |  |
Credit facilities supporting outstanding commercial paper |  | (798 | ) |
Credit facilities supporting standby letters of credit(3) |  | (854 | ) |
Total unutilized credit facilities |  | 4 536 |  |

(3)
  The company supported certain credit facilities with $585 million of cash collateral as at December 31, 2013 (December 31, 2012 – $150 million).

22. OTHER LONG-TERM LIABILITIES

($ millions) |  | Dec 31 2013 |  | Dec 31 2012 |  | Jan 1 2012 |
|  |  |  | (restated – note 6) |  | (restated – note 6) |
Pensions and other post-retirement benefits (note 23) |  | 926 |  | 1 645 |  | 1 694 |
Share-based compensation plans (note 26) |  | 335 |  | 242 |  | 187 |
Deferred revenue |  | 72 |  | 77 |  | 84 |
Fort Hills purchase obligation(1) |  | — |  | 223 |  | 275 |
Libya EPSAs signature bonus(2) |  | 64 |  | 72 |  | 73 |
Other |  | 67 |  | 60 |  | 89 |
|  | 1 464 |  | 2 319 |  | 2 402 |

(1)
  As part of the 2009 acquisition of Petro-Canada, the company assumed an obligation relating to Petro-Canada's acquisition of an additional 5% interest in the Fort Hills project. To pay for this investment, the company will fund $375 million of expenditures in excess of its working interest. At December 31, 2013, the carrying amount of the Fort Hills obligation, based on the discounted estimated payout pattern for the funding, was $230 million (December 31, 2012 – $300 million), of which the entire portion is classified as current (December 31, 2012 – $77 million) and is recorded in Accounts Payable and Accrued Liabilities.
(2)
  The company also assumed the remaining US$500 million obligation for a signature bonus relating to Petro-Canada's ratification of six Exploration and Production Sharing Agreements (EPSAs) in Libya payable in several instalments through 2014. At December 31, 2013, the carrying amount of the Libya EPSAs signature bonus was $78 million (December 31, 2012 – $86 million). The current portion is $14 million (December 31, 2012 – $14 million) and is recorded in Accounts Payable and Accrued Liabilities.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 115

23. PENSIONS AND OTHER POST-RETIREMENT BENEFITS

The company's defined benefit pension plans provide pension benefits at retirement based on years of service and final average earnings (if applicable). These obligations are met through funded registered retirement plans and through unregistered supplementary pensions that are voluntarily funded through retirement compensation arrangements, and/or paid directly to recipients. The amount and timing of future funding for these supplementary plans is subject to the funding policy as approved by the Board of Directors. The company's contributions to the funded plans are deposited with independent trustees who act as custodians of the plans' assets, as well as the disbursing agents of the benefits to recipients. Plan assets are managed by a pension committee on behalf of beneficiaries. The committee retains independent managers and advisors.

Asset-Liability matching studies are performed by a third-party consultant to set the asset mix by quantifying the risk-and-return characteristics of possible asset mix strategies. Investment and contribution policies are integrated within this study, and areas of focus include asset mix as well as interest rate sensitivity.

Funding of the registered retirement plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, or more, depending on funding status, and every year in the United States. The most recent valuations were performed as at December 31, 2013. The company uses a measurement date of December 31 to value the plan assets and accrued benefit obligation for accounting purposes.

The company's other post-retirement benefits programs are unfunded and include certain health care and life insurance benefits provided to retired employees and eligible surviving dependants.

The company also provides a number of defined contribution plans, including a U.S. 401(k) savings plan, that provide for an annual contribution of 5% to 11.5% of each participating employee's pensionable earnings.

Effective January 1, 2014, Petro-Canada Retirement Plan and Suncor Energy Pension Plan were merged. There was no impact to the consolidated results as a result of this transaction.

116 SUNCOR ENERGY INC. ANNUAL REPORT 2013

Defined Benefit Obligations and Funded Status

|  | Pension Benefits |  | Other Post-Retirement Benefits |  |
($ millions) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |  |  |  |  |
Change in benefit obligation |  |  |  |  |  |  |  |  |  |
| Benefit obligation at beginning of year |  | 4 137 |  | 3 698 |  | 545 |  | 510 |  |
| Current service costs |  | 160 |  | 143 |  | 13 |  | 11 |  |
| Past service costs |  | 13 |  | — |  | — |  | — |  |
| Plan participants' contributions |  | 14 |  | 14 |  | — |  | — |  |
| Benefits paid |  | (186 | ) | (172 | ) | (16 | ) | (18 | ) |
| Interest costs |  | 159 |  | 163 |  | 21 |  | 22 |  |
| Foreign exchange |  | 17 |  | 2 |  | 2 |  | — |  |
| Settlements |  | 2 |  | 2 |  | — |  | — |  |
| Actuarial remeasurement: |  |  |  |  |  |  |  |  |  |
|  | Experience loss (gain) arising on plan liabilities |  | 25 |  | 18 |  | (5 | ) | (13 | ) |
|  | Actuarial loss (gain) arising from changes in demographic assumptions |  | 38 |  | — |  | (1 | ) | — |  |
|  | Actuarial (gain) loss arising from changes in financial assumptions |  | (488 | ) | 269 |  | (70 | ) | 33 |  |
Benefit obligation at end of year |  | 3 891 |  | 4 137 |  | 489 |  | 545 |  |
Change in plan assets |  |  |  |  |  |  |  |  |  |
| Fair value of plan assets at beginning of year |  | 2 832 |  | 2 488 |  | — |  | — |  |
| Employer contributions |  | 220 |  | 267 |  | — |  | — |  |
| Plan participants' contributions |  | 14 |  | 14 |  | — |  | — |  |
| Benefits paid |  | (178 | ) | (172 | ) | — |  | — |  |
| Foreign exchange |  | 14 |  | 3 |  | — |  | — |  |
| Settlements |  | 2 |  | 2 |  | — |  | — |  |
| Administrative costs |  | (2 | ) | — |  | — |  | — |  |
| Interest income on plan assets |  | 112 |  | 106 |  | — |  | — |  |
| Actuarial remeasurement: |  |  |  |  |  |  |  |  |  |
|  | Return on plan assets (excluding amounts included in net interest expense) |  | 279 |  | 124 |  | — |  | — |  |
Fair value of plan assets at end of year |  | 3 293 |  | 2 832 |  | — |  | — |  |
Net unfunded obligation |  | 598 |  | 1 305 |  | 489 |  | 545 |  |

Of the total net unfunded obligation as at December 31, 2013, 86% relates to Canadian pension and other post-retirement benefits obligation (excluding Syncrude) (December 31, 2012 – 88%). The weighted average duration of the Canadian pension and other post-retirement plans (excluding Syncrude) is 14.0 years (2012 – 14.2 years).

SUNCOR ENERGY INC. ANNUAL REPORT 2013 117

The net unfunded obligation is recorded in Accounts Payable and Accrued Liabilities and Other Long-Term Liabilities (note 22) in the Consolidated Balance Sheets.

|  | Pension Benefits |  | Other Post-Retirement Benefits |
($ millions) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |
|  |  |  | (restated – note 6) |  |  |  |  |
Analysis of amount charged to earnings: |  |  |  |  |  |  |  |  |
| Current service costs |  | 160 |  | 143 |  | 13 |  | 11 |
| Past service costs |  | 13 |  | — |  | — |  | — |
| Interest costs |  | 47 |  | 57 |  | 21 |  | 22 |
Defined benefit plans expense |  | 220 |  | 200 |  | 34 |  | 33 |
Defined contribution plans expense |  | 62 |  | 53 |  | — |  | — |
Total benefit plans expense charged to earnings |  | 282 |  | 253 |  | 34 |  | 33 |

Components of defined benefit costs recognized in Other Comprehensive Income:

|  | Pension Benefits |  | Other Post-Retirement Benefits |  |
($ millions) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |  |
|  |  |  | (restated – note 6) |  |  |  |  |  |
Return on plan assets (excluding amounts included in net interest expense) |  | (279 | ) | (124 | ) | — |  | — |  |
Experience loss (gain) arising on plan liabilities |  | 25 |  | 18 |  | (5 | ) | (13 | ) |
Actuarial loss (gain) arising from changes in demographic assumptions |  | 38 |  | — |  | (1 | ) | — |  |
Actuarial (gain) loss arising from changes in financial assumptions |  | (488 | ) | 269 |  | (70 | ) | 33 |  |
Actuarial (gain) loss recognized in other comprehensive income |  | (704 | ) | 163 |  | (76 | ) | 20 |  |

Actuarial Assumptions

The cost of the defined benefit pension plans and other post-retirement benefits received by employees is actuarially determined using the projected unit credit method of valuation that includes employee service to date and present pay levels, as well as projection of salaries and service to retirement.

The significant weighted average actuarial assumptions were as follows:

|  | Pension Benefits |  | Other Post-Retirement Benefits |
(%) |  | Dec 31 2013 |  | Dec 31 2012 |  | Dec 31 2013 |  | Dec 31 2012 |
Discount rate |  | 4.70 |  | 3.90 |  | 4.70 |  | 3.90 |
Rate of compensation increase |  | 3.45 |  | 3.65 |  | 3.30 |  | 3.75 |

The discount rate assumption is based on the interest rate on high-quality bonds with maturity terms equivalent to the benefit obligations.

The defined benefit obligation reflects the best estimate of the mortality of plan participants both during and after their employment. The mortality assumption is based on a standard mortality table adjusted for actual experience over the past five years.

118 SUNCOR ENERGY INC. ANNUAL REPORT 2013

In order to measure the expected cost of other post-retirement benefits, it was assumed for 2013 that the health care costs would increase annually by 7% per person (2012 – 7%). This rate will remain constant in 2014 and will decrease 0.5% annually to 5% by 2018, and remain at that level thereafter.

Assumed discount rates, longevity rates and health care cost trend rates may have a significant effect on the amounts reported for pensions and other post-retirement benefit obligations for the company's Canadian plans (excluding Syncrude). A 1% change of these assumed assumptions would have the following effects:

|  | Pension Benefits |  |
($ millions) |  | Increase |  | Decrease |  |
Discount rate |  |  |  |  |  |
| Effect on the aggregate service and interest costs |  | (13 | ) | 16 |  |
| Effect on the benefit obligations |  | (411 | ) | 514 |  |
Longevity rate |  |  |  |  |  |
| Effect on the aggregate service and interest costs |  | 6 |  | (6 | ) |
| Effect on the benefit obligations |  | 79 |  | (82 | ) |

|  | Other Post-Retirement Benefits |  |
($ millions) |  | Increase |  | Decrease |  |
Discount rate |  |  |  |  |  |
| Effect on the benefit obligations |  | (56 | ) | 70 |  |
Health care cost |  |  |  |  |  |
| Effect on the aggregate service and interest costs |  | 2 |  | (1 | ) |
| Effect on the benefit obligations |  | 32 |  | (27 | ) |

Plan Assets and Investment Objectives

The company's long-term investment objective is to secure the defined pension benefits while managing the variability and level of its contributions. The portfolio is rebalanced periodically, as required, while ensuring that the maximum equity content is 65% at any time. Plan assets are restricted to those permitted by legislation, where applicable. Investments are made through pooled, mutual, segregated or exchange traded funds.

The company's weighted average pension plan asset allocation, based on market values as at December 31, are as follows:

(%) |  | 2013 |  | 2012 |
Equities, comprised of: |  |  |  |  |
| – Canada |  | 18 |  | 18 |
| – United States |  | 22 |  | 20 |
| – Foreign |  | 20 |  | 20 |
|  | 60 |  | 58 |
Fixed income, comprised of: |  |  |  |  |
| – Canada |  | 40 |  | 42 |
Total |  | 100 |  | 100 |

Equity securities do not include any direct investments in Suncor shares.

The company expects to make cash contributions to its defined benefit pension plans in 2014 of $427 million.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 119

24. PROVISIONS

($ millions) |  | Decommissioning and Restoration(1) |  | Royalties(2) |  | Other(3) |  | Total |  |
|  |  |  |  |  | (restated – note 6) |  | (restated – note 6) |  |
At January 1, 2012 |  | 3 801 |  | 355 |  | 406 |  | 4 562 |  |
Liabilities incurred |  | 378 |  | 317 |  | 408 |  | 1 103 |  |
Changes in estimates |  | 783 |  | 51 |  | (14 | ) | 820 |  |
Liabilities settled |  | (433 | ) | (356 | ) | (73 | ) | (862 | ) |
Accretion |  | 163 |  | — |  | 6 |  | 169 |  |
Foreign exchange |  | (4 | ) | — |  | — |  | (4 | ) |
At December 31, 2012 |  | 4 688 |  | 367 |  | 733 |  | 5 788 |  |
Less: current portion |  | (395 | ) | (367 | ) | (94 | ) | (856 | ) |
|  | 4 293 |  | — |  | 639 |  | 4 932 |  |
At December 31, 2012 |  | 4 688 |  | 367 |  | 733 |  | 5 788 |  |
Liabilities incurred |  | 398 |  | 224 |  | 97 |  | 719 |  |
Changes in estimates |  | 82 |  | (15 | ) | (392 | ) | (325 | ) |
Liabilities settled |  | (423 | ) | (52 | ) | (132 | ) | (607 | ) |
Accretion |  | 174 |  | — |  | 5 |  | 179 |  |
Asset divestitures |  | (714 | ) | — |  | — |  | (714 | ) |
Foreign exchange |  | 33 |  | — |  | 3 |  | 36 |  |
At December 31, 2013 |  | 4 238 |  | 524 |  | 314 |  | 5 076 |  |
Less: current portion |  | (362 | ) | (524 | ) | (112 | ) | (998 | ) |
|  | 3 876 |  | — |  | 202 |  | 4 078 |  |

(1)
  Represents decommissioning and restoration provisions associated with the retirement of Property, Plant and Equipment and Exploration and Evaluation assets. The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2013 was approximately $8.0 billion (December 31, 2012 – $8.1 billion). A weighted average credit-adjusted risk-free interest rate of 4.51% was used to discount the provision recognized at December 31, 2013 (December 31, 2012 – 3.75%). The credit-adjusted risk-free rate used reflects the expected time frame of the provisions. Payments to settle the decommissioning and restoration provisions occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed fifty years.
(2)
  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. Subsequent to December 31, 2013, the company settled $196 million related to these provisions.
(3)
  For the year ended December 31, 2013, the company's provisions decreased by $300 million as a result of a recognition of risk mitigation proceeds to earnings. In addition, the company divested one of its pipeline commitments to a third party, resulting in a $76 million decrease to provisions.

120 SUNCOR ENERGY INC. ANNUAL REPORT 2013

25. SHARE CAPITAL

Authorized

Common Shares

The company is authorized to issue an unlimited number of common shares without nominal or par value.

Preferred Shares

The company is authorized to issue an unlimited number of preferred shares in series, without nominal or par value.

Normal Course Issuer Bid

Pursuant to the company's normal course issuer bid (the 2012 NCIB) that commenced in the third quarter of 2012, the company repurchased a total of 38.9 million common shares for a total consideration of $1.2 billion. Under the 2012 NCIB, the company repurchased 25.1 million common shares during 2013 for total consideration of $781 million.

On August 5, 2013, the company 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 on February 3, 2014 to permit the company to purchase for cancellation additional shares. Pursuant to the 2013 NCIB, the company 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, of which the company had repurchased a total of 24.4 million common shares for a total consideration of $894 million as at December 31, 2013.

During the year ended December 31, 2013, the company purchased 49.5 million (2012 – 46.9 million) common shares for total consideration of $1,675 million (2012 – $1,451 million). Of the amount recognized, $648 million (2012 – $609 million, net of $1.3 million options premiums) was charged to share capital and $1,027 million (2012 – $842 million) to retained earnings.

The company had also recorded a liability of $306 million at December 31, 2013 for share purchases that may take place during its internal blackout period under an automatic repurchase plan agreement with an independent broker. Of the liability recognized, $108 million was charged to share capital and $198 million to retained earnings.

26. SHARE-BASED COMPENSATION

Equity-Settled Plans

Stock options that give the holder the right to purchase common shares at the grant date market price, subject to fulfilling vesting terms, are accounted for as equity-settled plans.

(i) Suncor Energy Inc. Stock Options

This plan replaced the pre-merger stock option plans of legacy Suncor and legacy Petro-Canada. Outstanding options that are cancelled, expire or otherwise result in no underlying common share being issued will be available for issuance as options under this plan. Options granted have a seven-year life and vest annually over a three-year period.

The weighted average fair values of the options granted during the period and the weighted average assumptions used in their determination are as noted below:

|  | 2013 |  | 2012 |
Annual dividend per share |  | $0.73 |  | $0.50 |
Risk-free interest rate |  | 1.40% |  | 1.26% |
Expected life |  | 5 years |  | 5 years |
Expected volatility |  | 48% |  | 50% |
Weighted average fair value per option |  | $11.72 |  | $13.30 |

The expected life is based on historical experience and current expectations. The expected volatility reflects the assumption that the historical volatility over a period similar to the life of the options is indicative of future trends.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 121

(ii) Discontinued Plans

The following plans were in place prior to August 1, 2009: SunShare 2012 Performance Stock Options, Executive Stock Options, and Key Contributor Stock Options. For options granted under these plans, they generally have a seven to ten-year life and vest over periods up to four years.

Cash-Settled Plans

(a) Cash-Settled Stock Option Plans

Stock options that the holder can settle for cash or common shares are accounted for as cash-settled plans.

(i) Suncor Energy Inc. Stock Options with TSARs

Options were granted under this plan between August 1, 2009 and July 31, 2010. Each option included a tandem stock appreciation right (TSAR). Options granted have a seven-year life and vest annually over a three-year period.

(ii) Legacy Petro-Canada Stock Options with CPAs

This plan was discontinued on August 1, 2009. Options were granted to executives and key employees, and can be settled in common shares or exchanged for a cash payment alternative (CPA). Options granted have a seven-year life and vest over periods of up to four years.

Changes in the total outstanding stock options were as follows:

|  | 2013 |  | 2012 |
|  | Number (thousands) |  | Weighted Average Exercise Price ($) |  | Number (thousands) |  | Weighted Average Exercise Price ($) |
Outstanding, beginning of year |  | 47 324 |  | 38.33 |  | 59 178 |  | 35.25 |
Granted |  | 4 209 |  | 32.50 |  | 5 101 |  | 34.50 |
Exercised |  | (4 750 | ) | 23.31 |  | (10 803 | ) | 17.31 |
Forfeited/expired |  | (11 786 | ) | 45.13 |  | (6 152 | ) | 42.08 |
Outstanding, end of year |  | 34 997 |  | 37.47 |  | 47 324 |  | 38.33 |
Exercisable, end of year |  | 27 104 |  | 38.31 |  | 29 834 |  | 36.23 |

Options are exercised regularly throughout the year. Therefore, the weighted average share price during the year of $33.66 (2012 – $31.94) is representative of the weighted average share price at the date of exercise.

For the options outstanding at December 31, 2013, the exercise price ranges and weighted average remaining contractual lives are shown below:

|  | Outstanding |
Exercise Prices ($) |  | Number (thousands) |  | Weighted Average Remaining Contractual Life (years) |
11.99-19.99 |  | 1 885 |  | 2 |
20.00-29.99 |  | 1 793 |  | 3 |
30.00-39.99 |  | 16 066 |  | 4 |
40.00-49.99 |  | 14 423 |  | 3 |
50.00-59.99 |  | 684 |  | 1 |
60.00-72.17 |  | 146 |  | 1 |
Total |  | 34 997 |  | 3 |

122 SUNCOR ENERGY INC. ANNUAL REPORT 2013

Common shares authorized for issuance by the Board of Directors that remain available for the granting of future options:

(thousands) |  | 2013 |  | 2012 |
|  | 29 817 |  | 7 020 |

(b) Share Unit Plans

The company's share unit plans are accounted for as cash-settled plans.

A performance share unit (PSU) is a time-vested award entitling employees to receive varying degrees of cash (0% – 200% of the company's share price at time of vesting) contingent upon Suncor's total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. PSUs vest approximately three years after the grant date.

A restricted share unit (RSU) is a time-vested award entitling employees to receive cash equal to the company's share price at the time of vesting. Typically, RSUs vest approximately three years after the grant date.

A deferred share unit (DSU) is redeemable for cash or a common share for a period of time after a unitholder ceases employment or Board membership. The DSU plan is limited to executives and members of the Board of Directors. Members of the Board of Directors receive one-half or, at their option, all of their compensation in the form of DSUs. Executives may elect to receive one-half, or all, of their annual incentive payment in the form of DSUs.

Changes in the number of outstanding share units were as follows:

(thousands) |  | PSU |  | RSU |  | DSU |  |
Outstanding, January 1, 2012 |  | 4 660 |  | 9 294 |  | 1 702 |  |
| Granted |  | 1 021 |  | 6 803 |  | 198 |  |
| Redeemed for cash |  | (1 168 | ) | (2 666 | ) | (263 | ) |
| Forfeited/expired |  | (135 | ) | (566 | ) | — |  |
Outstanding, December 31, 2012 |  | 4 378 |  | 12 865 |  | 1 637 |  |
| Granted |  | 1 082 |  | 7 365 |  | 165 |  |
| Redeemed for cash |  | (1 684 | ) | (2 526 | ) | (764 | ) |
| Forfeited/expired |  | (135 | ) | (658 | ) | — |  |
Outstanding, December 31, 2013 |  | 3 641 |  | 17 046 |  | 1 038 |  |

(c) Stock Appreciation Rights (SARs)

A SAR entitles the holder to receive a cash payment equal to the difference between the stated exercise price and the market price of the company's common shares on the date the SAR is exercised, and is accounted for as a cash-settled plan.

(i) Suncor Energy Inc. SARs

These SARs have a seven-year life and vest annually over a three-year period.

(ii) Legacy Petro-Canada SARs

This plan was discontinued on August 1, 2009. These SARs have a seven-year life and vest annually over a four-year period.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 123

Changes in the number of outstanding SARs were as follows:

|  | 2013 |  | 2012 |
|  | Number (thousands) |  | Weighted Average Exercise Price ($) |  | Number (thousands) |  | Weighted Average Exercise Price ($) |
Outstanding, beginning of year |  | 7 776 |  | 29.65 |  | 8 752 |  | 29.32 |
Granted |  | 88 |  | 32.60 |  | 101 |  | 34.51 |
Exercised |  | (1 567 | ) | 27.57 |  | (482 | ) | 20.53 |
Forfeited/expired |  | (492 | ) | 35.47 |  | (595 | ) | 32.86 |
Outstanding, end of year |  | 5 805 |  | 29.75 |  | 7 776 |  | 29.65 |
Exercisable, end of year |  | 5 665 |  | 29.61 |  | 6 568 |  | 30.80 |

Share-Based Compensation Expense

The following table summarizes the share-based compensation expense recorded for all plans within Operating, Selling and General expense.

($ millions) |  | 2013 |  | 2012 |
Equity-settled plans |  | 51 |  | 83 |
Cash-settled plans |  | 341 |  | 269 |
Total share-based compensation expense |  | 392 |  | 352 |

Liability Recognized for Share-Based Compensation

The company has recorded a liability of $653 million as at December 31, 2013 (December 31, 2012 – $523 million), of which $318 million was classified as current (December 31, 2012 – $281 million), based on the fair value of awards accounted for as cash-settled. The intrinsic value of the vested awards at December 31, 2013 was $347 million (December 31, 2012 – $237 million).

27. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The company's financial instruments consist of cash and cash equivalents, accounts receivable, derivative contracts, substantially all accounts payable and accrued liabilities, debt, and certain portions of other assets and other long-term liabilities.

Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable, short-term debt, and accounts payable and accrued liabilities approximate their carrying values due to the short-term maturities of those instruments.

The company's long-term debt and long-term financial liabilities are recorded at amortized cost using the effective interest method. At December 31, 2013, the carrying value of fixed-term debt accounted for under amortized cost was $9.6 billion (December 31, 2012 – $9.4 billion) and the fair value at December 31, 2013 was $11.2 billion (December 31, 2012 – $11.8 billion). The estimated fair value of long-term debt is based on pricing sourced from market data, which is considered Level 2 fair value inputs.

Derivative Financial Instruments

(a) Non-Designated Derivative Financial Instruments

•
  Energy Trading Derivatives – The company's Energy Trading group uses physical and financial energy derivative contracts, including swaps, forwards and options to earn trading revenues.

124 SUNCOR ENERGY INC. ANNUAL REPORT 2013

•
  Risk Management Derivatives – The company periodically enters into derivative contracts in order to manage exposure to commodity price and foreign exchange movements and are a component of the company's overall risk management program.

The Changes in the fair value of non-designated Energy Trading and Risk Management derivatives are as follows:

($ millions) |  | Energy Trading |  | Risk Management |  | Total |  |
Fair value of contracts outstanding at January 1, 2012 |  | (34 | ) | — |  | (34 | ) |
| Fair value of contracts realized in earnings during the year |  | (255 | ) | (2 | ) | (257 | ) |
| Changes in fair value during the year (note 8) |  | 246 |  | 1 |  | 247 |  |
Fair value of contracts outstanding at December 31, 2012 |  | (43 | ) | (1 | ) | (44 | ) |
| Fair value of contracts realized in earnings during the year |  | (271 | ) | 18 |  | (253 | ) |
| Changes in fair value during the year (note 8) |  | 176 |  | (18 | ) | 158 |  |
Fair value of contracts outstanding at December 31, 2013 |  | (138 | ) | (1 | ) | (139 | ) |

(b) Fair Value Hierarchy

To estimate fair value of derivatives, the company uses quoted market prices when available, or third-party models and valuation methodologies that utilize observable market data. 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. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

•
  Level 1 transactions consist of instruments with a fair value determined by an unadjusted quoted price in an active market for identical assets or liabilities. An active market is characterized by readily and regularly available quoted prices where the prices are representative of actual and regularly occurring market transactions to assure liquidity.
•
  Level 2 transactions consist of instruments with a fair value that is determined by quoted prices in an inactive market, prices with observable inputs, or prices with insignificant non-observable inputs. The fair value of these positions are determined using observable inputs from exchanges, pricing services, third-party independent broker quotes, and published transportation tolls. The observable inputs may be adjusted using certain methods, which include extrapolation over the quoted price term and quotes for comparable assets and liabilities.
•
  Level 3 transactions consist of instruments with a fair value that is determined by prices with significant unobservable inputs. As at December 31, 2013, the company does not have any derivative instruments measured at fair value Level 3.

In forming estimates, the company utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement.

The following table presents the company's derivative financial instrument assets and liabilities measured at fair value for each hierarchy level as at December 31, 2013 and 2012.

($ millions) |  | Level 1 |  | Level 2 |  | Level 3 |  | Total Fair Value |  |
| Accounts receivable |  | 5 |  | 47 |  | 1 |  | 53 |  |
| Accounts payable |  | (12 | ) | (85 | ) | — |  | (97 | ) |
Balance at December 31, 2012 |  | (7 | ) | (38 | ) | 1 |  | (44 | ) |
| Accounts receivable |  | 137 |  | 88 |  | — |  | 225 |  |
| Accounts payable |  | (165 | ) | (199 | ) | — |  | (364 | ) |
Balance at December 31, 2013 |  | (28 | ) | (111 | ) | — |  | (139 | ) |

SUNCOR ENERGY INC. ANNUAL REPORT 2013 125

During the year ended December 31, 2013, there were no transfers between Level 1 and Level 2 fair value measurements.

The following table presents the company's recurring Level 3 derivative financial instrument assets and liabilities as at December 31, 2013 and 2012:

($ millions) |  | Level 3 Fair Value |  |
Balance at December 31, 2012 |  | 1 |  |
| Realized gains |  | 2 |  |
| Purchases |  | (7 | ) |
| Transfers into Level 2 |  | 4 |  |
Balance at December 31, 2013 |  | — |  |

Offsetting Financial Assets and Liabilities

The company enters into arrangements that allow for offsetting of derivative financial instruments and accounts receivable (payable), which are presented on a net basis on the balance sheet, as shown in the table below as at December 31, 2013 and 2012.

Financial Assets

($ millions) |  | Gross assets |  | Gross liabilities offset |  | Net amounts presented |
Derivatives |  | 440 |  | (387 | ) | 53 |
Accounts receivable |  | 2 567 |  | (732 | ) | 1 835 |
Balance at December 31, 2012 |  | 3 007 |  | (1 119 | ) | 1 888 |
Derivatives |  | 225 |  | (185 | ) | 40 |
Accounts receivable |  | 3 092 |  | (967 | ) | 2 125 |
Balance at December 31, 2013 |  | 3 317 |  | (1 152 | ) | 2 165 |

Financial Liabilities

($ millions) |  | Gross liabilities |  | Gross assets offset |  | Net amounts presented |  |
Derivatives |  | (484 | ) | 387 |  | (97 | ) |
Accounts payable |  | (2 401 | ) | 732 |  | (1 669 | ) |
Balance at December 31, 2012 |  | (2 885 | ) | 1 119 |  | (1 766 | ) |
Derivatives |  | (364 | ) | 185 |  | (179 | ) |
Accounts payable |  | (2 956 | ) | 967 |  | (1 989 | ) |
Balance at December 31, 2013 |  | (3 320 | ) | 1 152 |  | (2 168 | ) |

Risk Management

The company is exposed to a number of different risks arising from financial instruments. These risk factors include market risks, comprising commodity price risk, foreign currency risk and interest rate risk, as well as liquidity risk and credit risk.

The company maintains a formal governance process to manage its financial risks. The company's Commodity Risk Management Committee (CRMC) is charged with the oversight of the company's trading and credit risk management activities. Trading activities are defined as activities intended to enhance the company's operations and enhance profitability through informed market calls, market diversification, economies of scale, improved transportation access, and leverage of assets, both physical and contractual. The CRMC, acting under the authority of the company's Board of

126 SUNCOR ENERGY INC. ANNUAL REPORT 2013

Directors, meets regularly to monitor limits on risk exposures, review policy compliance and validate risk-related methodologies and procedures.

The nature of the risks faced by the company and its policies for managing such risks remains unchanged from December 31, 2012.

1) Market Risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of the business. The market price movements that could adversely affect the value of the company's financial assets, liabilities and expected future cash flows include commodity price risk, foreign currency exchange risk and interest rate risk.

(a) Commodity Price Risk

Suncor's financial performance is closely linked to crude oil prices (including pricing differentials for various product types) and, to a lesser extent, natural gas and refined product prices. The company may reduce its exposure to commodity price risk through a number of strategies. These strategies include committing a portion of expected crude oil production to fixed price contracts and entering into option contracts to limit exposure to changes in crude oil prices.

An increase of US$1.00 per barrel of crude oil as at December 31, 2013 would decrease pre-tax earnings for the company's outstanding derivative financial instruments by approximately $2 million.

(b) Foreign Currency Exchange Risk

The company is exposed to foreign currency exchange risk on revenues, capital expenditures, or financial instruments that are denominated in a currency other than the company's functional currency (Canadian dollars). As crude oil is priced in U.S. dollars, fluctuations in US$/Cdn$ exchange rates may have a significant impact on revenues. This exposure is partially offset through the issuance of U.S. dollar denominated debt. A 1% strengthening in the Cdn$ relative to the US$ as at December 31, 2013 would decrease pre-tax earnings by approximately $90 million.

The company also has foreign operations whose functional currency is different than the company's functional currency. The main exposures relate to foreign operations whose functional currencies are in U.S. dollars, euros (€) or pound sterling (£). A 1% strengthening in the Cdn$ relative to the US$, € and £ as at December 31, 2013 would decrease Other Comprehensive Income by approximately $43 million, $26 million and $21 million, respectively.

(c) Interest Rate Risk

The company is exposed to interest rate risk as changes in interest rates may affect future cash flows and the fair values of its financial instruments. The primary exposure is related to its revolving-term debt of commercial papers.

To manage the company's exposure to interest rate volatility, the company may periodically enter into interest rate swap contracts. The objective of entering into these contracts is to reduce the company's cost of borrowing by managing the mix of fixed and floating interest rate debt. The proportion of floating interest rate exposure at December 31, 2013 was 7.6% of total debt outstanding. The weighted average interest rate on total debt for the year ended December 31, 2013 was 6.3%.

The company's net earnings are sensitive to changes in interest rates on the floating rate portion of the company's debt. To the extent interest expense is not capitalized, if interest rates applicable to floating rate instruments increased by 1%, it is estimated that the company's pre-tax earnings would decrease by approximately $8 million. This assumes that the amount and mix of fixed and floating rate debt remains unchanged from December 31, 2013, and that the change in interest rates is effective from the beginning of the year.

2) Liquidity Risk

Liquidity risk is the risk that Suncor will not be able to meet its financial obligations when due. The company mitigates this risk by forecasting spending requirements and maintaining sufficient cash and credit facilities to meet these requirements. Suncor's cash and cash equivalents and total credit facilities at December 31, 2013 were $5.2 billion and $6.2 billion, respectively.

Surplus cash is invested into a range of short-dated money market securities. Investments are only permitted in high credit quality government or corporate securities. Diversification of these investments is maintained through counterparty credit limits.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 127

The following table shows the timing of cash outflows related to trade and other payables and debt.

|  | December 31, 2013 |
($ millions) |  | Trade and other payables |  | Gross derivative liabilities(1) |  | Debt(2) |
Within one year |  | 6 911 |  | 353 |  | 1 959 |
1 to 3 years |  | 64 |  | 11 |  | 1 402 |
3 to 5 years |  | — |  | — |  | 4 064 |
Over 5 years |  | — |  | — |  | 15 746 |
|  | 6 975 |  | 364 |  | 23 171 |

(1)
  Gross derivative liabilities of $364 million are offset by gross derivative assets of $185 million, resulting in a net amount of $179 million.
(2)
  Debt includes short-term debt, long-term debt, finance leases and interest payments on fixed-term debt and commercial paper.

3) Credit Risk

Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial loss. The company's credit policy is designed to ensure there is a standard credit practice throughout the company to measure and monitor credit risk. The policy outlines delegation of authority, the due diligence process required to approve a new customer or counterparty and the maximum amount of credit exposure per single entity. Before transactions begin with a new customer or counterparty, its creditworthiness is assessed, a credit rating is assigned and a maximum credit limit is allocated. The assessment process is outlined in the credit policy and considers both quantitative and qualitative factors. The company constantly monitors the exposure to any single customer or counterparty along with the financial position of the customer or counterparty. If it is deemed that a customer or counterparty has become materially weaker, the company will work to reduce the credit exposure and lower the credit limit allocated. Regular reports are generated to monitor credit risk and the Credit Committee meets quarterly to ensure compliance with the credit policy and review the exposures.

A substantial portion of the company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risk. At December 31, 2013, substantially all of the company's trade receivables were current.

The company may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The company's exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. At December 31, 2013, the company's exposure was $225 million (December 31, 2012 – $53 million).

28. CAPITAL STRUCTURE FINANCIAL POLICIES

The company's primary capital management strategy is to maintain a conservative balance sheet, which supports a solid investment-grade credit rating profile. This objective affords the company the financial flexibility and access to the capital it requires to execute on its growth objectives.

The company's capital is primarily monitored by reviewing the ratios of net debt to cash flow from operations(1) and total debt to total debt plus shareholders' equity.

Net debt to cash flow from operations is calculated as short-term debt plus total long-term debt less cash and cash equivalents divided by cash flow from operations for the year then ended.

Total debt to total debt plus shareholders' equity is calculated as short-term debt plus total long-term debt divided by short-term debt plus total long-term debt plus shareholders' equity. This financial covenant under the company's various banking and debt agreements shall not be greater than 65%.

The company's financial covenants are reviewed regularly and controls are in place to maintain compliance with these covenants. The company complied with financial covenants for the years ended December 31, 2013 and 2012.

128 SUNCOR ENERGY INC. ANNUAL REPORT 2013

The company's financial measures, as set out in the following schedule, were unchanged from 2012. The company believes that achieving its capital target helps to provide the company access to capital at a reasonable cost by maintaining solid investment-grade credit ratings. The company operates in a fluctuating business environment and ratios may periodically fall outside of management's targets.

($ millions) |  | Capital Measure Target |  | Dec 31, 2013 |  | Dec 31, 2012 |
|  |  |  |  |  | (restated – note 6) |
Components of ratios |  |  |  |  |  |  |
| 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 capitalization (total debt plus shareholders' equity) |  |  |  | 52 638 |  | 50 239 |
| Cash flow from operations(1) |  |  |  | 9 412 |  | 9 733 |
Net debt to cash from operations |  | <2.0 times |  | 0.7 |  | 0.7 |
Total debt to total debt plus shareholders' equity |  |  |  | 22% |  | 22% |

(1)
  Cash flow from operations is expressed before changes in non-cash working capital, and is a non-GAAP financial measure.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 129

29. JOINT ARRANGEMENTS

Joint Operations

The company's material joint operations as at December 31, 2013 are set out below:

Material Joint Operations |  | Principal activity |  | Country of incorporation and principal place of business |  | Ownership % 2013 |  | Ownership % 2012 |
Oil Sands |  |  |  |  |  |  |  |  |
Operated by Suncor: |  |  |  |  |  |  |  |  |
| Fort Hills Energy Limited Partnership |  | Oil sands development |  | Canada |  | 40.80 |  | 40.80 |
Non-operated: |  |  |  |  |  |  |  |  |
| Syncrude |  | Oil sands development |  | Canada |  | 12.00 |  | 12.00 |
| Joslyn |  | Oil sands development |  | Canada |  | 36.75 |  | 36.75 |
Exploration and Production |  |  |  |  |  |  |  |  |
Operated by Suncor: |  |  |  |  |  |  |  |  |
| Terra Nova |  | Oil and gas production |  | Canada |  | 37.68 |  | 37.68 |
Non-operated: |  |  |  |  |  |  |  |  |
| White Rose and the White Rose Extensions |  | Oil and gas production |  | Canada |  | 26.13-27.50 |  | 26.13-27.50 |
| Hibernia and the Hibernia South Extension Unit |  | Oil and gas production |  | Canada |  | 19.51-20.00 |  | 19.51-20.00 |
| Hebron |  | Oil and gas production |  | Canada |  | 22.73 |  | 22.73 |
| Harouge Oil Operations |  | Oil and gas production |  | Libya |  | 49.00 |  | 49.00 |
| Buzzard |  | Oil and gas production |  | United Kingdom |  | 29.89 |  | 29.89 |
| Golden Eagle Area Development |  | Oil and gas production |  | United Kingdom |  | 26.69 |  | 26.69 |

Joint Ventures and Associates

The company does not have any joint ventures or associates that are considered individually material. Summarized aggregate financial information of the joint ventures and associates in the company's refining and marketing operations are shown below:

|  | Joint ventures |  | Associates |
($ millions) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Net earnings |  | 9 |  | 31 |  | 10 |  | 8 |
Other comprehensive (loss) income |  | (2 | ) | 3 |  | — |  | — |
Total comprehensive income |  | 7 |  | 34 |  | 10 |  | 8 |
Carrying amount as at December 31 |  | 120 |  | 121 |  | 46 |  | 37 |

130 SUNCOR ENERGY INC. ANNUAL REPORT 2013

30. SUBSIDIARIES

Material subsidiaries, each of which are wholly owned, either directly or indirectly, by the company as at December 31, 2013, are shown below:

Material Subsidiaries |  | Principal activity |
Canadian Operations |  |  |
Suncor Energy Oil Sands Limited Partnership |  | This partnerships holds most of the company's oil sands and in situ assets. |
Suncor Energy Products Inc. |  | This subsidiary holds interests in the company's energy marketing and renewable energy businesses. |
Suncor Energy Products Partnership |  | This partnership holds substantially all of the company's Canadian refining and marketing assets. |
Suncor Energy Marketing Inc. |  | A subsidiary through which the company's upstream production is marketed, the company's energy trading activities is administered, and the company's refining operations feedstock is procured. |
U.S. Operations |  |  |
Suncor Energy (U.S.A.) Marketing Inc. |  | A subsidiary that procures and markets third-party crude oil, in addition to procuring crude oil feedstock for the company's refining operations. |
Suncor Energy (U.S.A.) Inc. |  | A subsidiary through which the company's U.S. refining and marketing operations are conducted. |
International Operations |  |  |
Suncor Energy UK Limited |  | A subsidiary through which the majority of the company's North Sea operations are conducted. |
Suncor Energy Oil (North Africa) GmbH |  | A subsidiary through which the majority of the company's Libya operations are conducted. |

The table does not include wholly owned subsidiaries that are immediate holding companies of the operating subsidiaries. For certain foreign operations of the company, there are restrictions on the sale or transfer of production licences, which would require approval of the applicable foreign government.

31. RELATED PARTY DISCLOSURES

Related Party Transactions

The company enters into transactions with related parties in the normal course of business, which includes purchases of feedstock, distribution of refined products, and sale of refined products and by-products. These transactions are with joint ventures and associated entities in the company's refining and marketing operations, including pipeline, refined product and petrochemical companies. A summary of the significant related party transactions as at and for the year ended December 31, 2013 and 2012 are as follows:

($ millions) |  | 2013 |  | 2012 |
Sales |  | 1 593 |  | 1 281 |
Purchases |  | 245 |  | 157 |
Accounts receivable |  | 92 |  | 72 |
Accounts payable and accrued liabilities |  | 15 |  | 9 |

SUNCOR ENERGY INC. ANNUAL REPORT 2013 131

Compensation of Key Management Personnel

Compensation of the company's Board of Directors and members of the Executive Leadership Team for the years ended December 31 is as follows:

($ millions) |  | 2013 |  | 2012 |
Short-term benefits |  | 14 |  | 18 |
Pension and other post-retirement benefits |  | 4 |  | 4 |
Share-based compensation |  | 35 |  | 32 |
|  | 53 |  | 54 |

32. COMMITMENTS, CONTINGENCIES AND GUARANTEES

(a) Commitments

Future payments under the company's operating leases for pipeline transportation agreements and for various premises, service stations and other property and equipment are as follows:

|  | Payment due by period |
($ millions) |  | 2014 |  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 and beyond |  | Total |
Commitments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Product transportation and storage |  | 660 |  | 579 |  | 551 |  | 526 |  | 488 |  | 4 015 |  | 6 819 |
| Energy services |  | 237 |  | 183 |  | 178 |  | 180 |  | 182 |  | 1 045 |  | 2 005 |
| Commitments from joint arrangements |  | 3 |  | 2 |  | 2 |  | 1 |  | 1 |  | 1 |  | 10 |
| Exploration work commitments |  | 165 |  | 363 |  | 42 |  | — |  | — |  | 2 |  | 572 |
| Other |  | 276 |  | 41 |  | 9 |  | 4 |  | 4 |  | 25 |  | 359 |
Operating leases |  | 545 |  | 465 |  | 401 |  | 341 |  | 292 |  | 1 903 |  | 3 947 |
|  | 1 886 |  | 1 633 |  | 1 183 |  | 1 052 |  | 967 |  | 6 991 |  | 13 712 |

Significant operating leases expire at various dates through 2035. For the year ended December 31, 2013, operating lease expense was $0.6 billion (2012 – $0.5 billion).

In addition to the operating lease commitments in the above table, the company has other obligations for goods and services and raw materials entered into in the normal course of business, which may terminate on short notice. Such obligations include commodity purchase obligations which are transacted at market prices. The company has also entered into various pipeline commitments of $6.4 billion with contract terms up to 25 years, which are awaiting regulatory approval. In the event regulatory approval is not obtained, the company has committed to reimbursing certain costs to the service provider.

(b) Contingencies

Legal and environmental contingent liabilities

The company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The company believes that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated financial position, except as disclosed in note 12.

The company may also have environmental contingent liabilities, beyond decommissioning and restoration liabilities recognized in note 24, which are reviewed individually and are reflected in the company's consolidated financial statements if material and more likely than not to be incurred. These contingent environmental liabilities primarily relate to the mitigation of contamination at sites where the company has had operations. For any unrecognized environmental

132 SUNCOR ENERGY INC. ANNUAL REPORT 2013

contingencies, the company believes that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated financial position.

Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and to be funded from the company's cash flow from operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, the impact may be material.

Operational risk

The company also has exposure to some operational risks, which is reduced by maintaining a comprehensive insurance program at limits and deductible amounts that management believes to be acceptable.

The company carries property damage and business interruption insurance with varying coverage limits and deductible amounts based on the asset. As of December 31, 2013, Suncor's insurance program includes coverage of up to US$1.2 billion for oil sands risks, up to US$1.3 billion for offshore risks and up to US$594 million for refining risks. These limits are all net of deductible amounts or waiting periods and subject to certain price and volume limits. The company also has primary property insurance for US$300 million that covers all of Suncor's assets. As part of its normal course of operations, Suncor also carries risk mitigation instruments in the aggregate amount of $300 million on certain foreign operations.

Suncor believes its liability, property and business interruption insurance is appropriate to its business, although such insurance will not provide coverage in all circumstances or fully protect against prolonged outages. In the future, the insurance program may change due to market conditions or other business considerations.

(c) Guarantees

At December 31, 2013, the company has various indemnification agreements with third parties as described below and provides loan guarantees to certain retail licensees, wholesale marketers, and the company's subsidiaries.

The company has agreed to indemnify holders of all notes and debentures and the company's credit facility lenders (see note 21) for added costs relating to withholding taxes. Similar indemnity terms apply to certain facility and equipment leases.

There is no limit to the maximum amount payable under the indemnification agreements described above. The company is unable to determine the maximum potential amount payable as government regulations and legislation are subject to change without notice. Under these agreements, the company has the option to redeem or terminate these contracts if additional costs are incurred.

The company also has guaranteed its working-interest share of certain joint venture undertakings related to transportation services agreements entered into with third parties. The guaranteed amount is limited to the company's share in the joint venture. As at December 31, 2013, the probability is remote that these guarantee commitments will impact the company.

33. VOYAGEUR UPGRADER PROJECT

Management applies judgment in determining whether an acquisition meets the definition of a business combination or an asset purchase. When a transaction meets the definition of a business combination, the acquired identifiable assets and assumed liabilities, including contingent liabilities, are measured and recognized at their fair value on the date of the acquisition, including tax assets and liabilities. Associated transaction costs are expensed when occurred.

Effective March 27, 2013, the company acquired Total E&P Canada Ltd.'s (Total E&P) interest in Voyageur Upgrader Limited Partnership (VULP) for $515 million and gained full control over the partnership assets. The transaction was accounted for as a business combination.

As VULP was in the development stage and therefore had no revenues and the majority of costs were capitalized, no significant net earnings were generated.

The allocation of the purchase price was based on current best estimates by the company. The completion of the purchase price allocation may result in further adjustment to the carrying value of the recorded assets and liabilities acquired.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 133

The fair value of consideration transferred and the assets acquired and liabilities assumed at the date of acquisition are summarized below:

($ millions) |  |  |  |
Total purchase price |  | 515 |  |
Allocation of purchase price: |  |  |  |
Property, plant and equipment |  | 374 |  |
Deferred income taxes |  | 312 |  |
Decommissioning and restoration provisions |  | (81 | ) |
Contracts and liabilities acquired |  | (90 | ) |
Net assets acquired |  | 515 |  |

The fair value attributed to the property, plant and equipment acquired was based on an expected future cash flow approach for assets expected to be retained, with a risk-adjusted discount rate of 10%. For assets expected to be sold, the fair value was determined based on management's best estimate of the recoverable amount.

The fair value of the decommissioning and restoration provisions was determined based on management's best estimate of the costs to complete the reclamation activities, the timing of cash outflows, method of reclamation, the discount rate and management's anticipated use of the area in the future.

Following the acquisition, the company announced that it was not proceeding with the Voyageur upgrader project. The decision was a result of a joint strategic and economic review launched by the company and its co-owner, Total E&P, in response to a change in market conditions that challenged the economics of the project. As a result of not proceeding with the upgrading portion of the project, a charge of $82 million was recorded to net earnings during the year, including costs related to the acceleration of certain reclamation activities.

34. SALE OF NATURAL GAS BUSINESS

On September 26, 2013, the company completed the previously announced sale of a significant portion of its natural gas business in Western Canada for proceeds of $1.0 billion before closing adjustments and other closing costs. The sale of these assets resulted in an after-tax gain on disposal of assets of $130 million in its Exploration and Production segment.

35. SUSPENDED EXPLORATORY WELL COSTS

($ millions) |  | 2013 |  | 2012 |  |
Beginning of year |  | 318 |  | 387 |  |
Additions |  | 24 |  | 4 |  |
Capitalized exploratory well costs charged to expense |  | — |  | (73 | ) |
End of year |  | 342 |  | 318 |  |

134 SUNCOR ENERGY INC. ANNUAL REPORT 2013

The following provides an aging of amounts capitalized as suspended exploratory wells at December 31 based on the completion date of the individual well.

($ millions) |  | 2013 |  | 2012 |
Suspended exploratory well costs that have been capitalized for a period less than one year |  | 9 |  | 4 |
Suspended exploratory well costs that have been capitalized for a period greater than one year |  | 333 |  | 314 |
|  | 342 |  | 318 |
Number of suspended exploratory wells that have been capitalized for a period greater than one year |  | 8 |  | 8 |

Suspended capitalized costs for exploratory wells completed prior to the end of 2013 are associated with projects located in i) Norway (three wells), ii) Libya (five wells) and iii) East Coast Canada (one well). The projects are awaiting the completion of economic evaluations including, but not limited to, results of additional appraisal drilling, additional geological and geophysical data, and development plan approval.

36. SUBSEQUENT EVENT

On February 3, 2014, the company's Board of Directors approved a 15% increase to the company's quarterly dividend to $0.23 per common share beginning in the first quarter of 2014. The Board of Directors also approved up to an additional $1.0 billion worth of the company's common shares to be purchased, subject to regulatory approval.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 135

QUARTERLY FINANCIAL SUMMARY
(unaudited)

|  | For the Quarter Ended |  | Total |  | For the Quarter Ended |  | Total |  |
($ millions except per share amounts) |  | Mar 31 2013 |  | June 30 2013 |  | Sept 30 2013 |  | Dec 31 2013 |  | 2013 |  | Mar 31 2012 |  | June 30 2012 |  | Sept 30 2012 |  | Dec 31 2012 |  | 2012 |  |
|  |  |  |  |  |  |  |  |  |  |  | (restated – note 6) |  |
Revenues and other income |  | 10 016 |  | 9 714 |  | 10 373 |  | 10 194 |  | 40 297 |  | 9 755 |  | 9 707 |  | 9 576 |  | 9 488 |  | 38 526 |  |
Net earnings (loss) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  | 326 |  | 294 |  | 951 |  | 469 |  | 2 040 |  | 609 |  | 359 |  | 537 |  | (1 037 | ) | 468 |  |
Exploration and Production |  | 354 |  | 301 |  | 446 |  | (101 | ) | 1 000 |  | 332 |  | (430 | ) | 88 |  | 148 |  | 138 |  |
Refining and Marketing |  | 782 |  | 432 |  | 350 |  | 458 |  | 2 022 |  | 476 |  | 501 |  | 710 |  | 450 |  | 2 137 |  |
Corporate, Energy Trading and Eliminations |  | (368 | ) | (347 | ) | (53 | ) | (383 | ) | (1 151 | ) | 29 |  | (106 | ) | 209 |  | (135 | ) | (3 | ) |
|  | 1 094 |  | 680 |  | 1 694 |  | 443 |  | 3 911 |  | 1 446 |  | 324 |  | 1 544 |  | (574 | ) | 2 740 |  |
Operating earnings (loss) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  | 453 |  | 294 |  | 951 |  | 400 |  | 2 098 |  | 609 |  | 429 |  | 537 |  | 450 |  | 2 025 |  |
Exploration and Production |  | 354 |  | 301 |  | 316 |  | 239 |  | 1 210 |  | 332 |  | 287 |  | 88 |  | 143 |  | 850 |  |
Refining and Marketing |  | 782 |  | 432 |  | 350 |  | 458 |  | 2 022 |  | 476 |  | 516 |  | 710 |  | 450 |  | 2 152 |  |
Corporate, Energy Trading and Eliminations |  | (222 | ) | (93 | ) | (191 | ) | (124 | ) | (630 | ) | (99 | ) | 17 |  | (43 | ) | (55 | ) | (180 | ) |
|  | 1 367 |  | 934 |  | 1 426 |  | 973 |  | 4 700 |  | 1 318 |  | 1 249 |  | 1 292 |  | 988 |  | 4 847 |  |
Cash flow from (used in) operations |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  | 848 |  | 896 |  | 1 702 |  | 1 110 |  | 4 556 |  | 1 118 |  | 943 |  | 1 256 |  | 1 090 |  | 4 407 |  |
Exploration and Production |  | 690 |  | 668 |  | 406 |  | 552 |  | 2 316 |  | 677 |  | 656 |  | 365 |  | 529 |  | 2 227 |  |
Refining and Marketing |  | 1 067 |  | 646 |  | 371 |  | 534 |  | 2 618 |  | 730 |  | 711 |  | 1 063 |  | 634 |  | 3 138 |  |
Corporate, Energy Trading and Eliminations |  | (321 | ) | 40 |  | 49 |  | 154 |  | (78 | ) | (110 | ) | 37 |  | 59 |  | (25 | ) | (39 | ) |
|  | 2 284 |  | 2 250 |  | 2 528 |  | 2 350 |  | 9 412 |  | 2 415 |  | 2 347 |  | 2 743 |  | 2 228 |  | 9 733 |  |
Per common share |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net earnings (loss) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| – basic |  | 0.72 |  | 0.45 |  | 1.13 |  | 0.30 |  | 2.61 |  | 0.93 |  | 0.21 |  | 1.01 |  | (0.38 | ) | 1.77 |  |
| – diluted |  | 0.71 |  | 0.45 |  | 1.13 |  | 0.30 |  | 2.60 |  | 0.92 |  | 0.20 |  | 1.00 |  | (0.38 | ) | 1.76 |  |
Operating earnings – basic |  | 0.90 |  | 0.62 |  | 0.95 |  | 0.66 |  | 3.13 |  | 0.84 |  | 0.80 |  | 0.84 |  | 0.65 |  | 3.14 |  |
Cash flow from operations – basic |  | 1.50 |  | 1.49 |  | 1.69 |  | 1.58 |  | 6.27 |  | 1.55 |  | 1.51 |  | 1.79 |  | 1.46 |  | 6.30 |  |

Non GAAP Financial Measures

Certain financial measures in the remainder of this document – namely operating earnings, cash flow from operations, return on capital employed (ROCE) and Oil Sands cash operating costs – are not prescribed by GAAP. Suncor includes these financial measures because investors may use this information to analyze operating performance, leverage and liquidity. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.

Operating earnings (loss) and Oil Sands cash operating costs for each quarter in 2012 and 2013 are each 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 (used in) operations for each quarter in 2012 and 2013 are defined and reconciled to GAAP measures in the Non GAAP Financial Measures Advisory section of each respective Quarterly Report. Operating earnings, cash flow from (used in) operations, and ROCE for each of 2010 and 2009 are defined and reconciled in Suncor's Management's Discussion and Analysis (MD&A) for the year ended December 31, 2010. Oil Sands cash operating costs per barrel for 2010 and 2009 are defined and reconciled in Suncor's MD&A for the year ended December 31, 2011 and December 31, 2010, respectively. The remainder of the non-GAAP financial measures not otherwise mentioned in this paragraph are defined and reconciled in Suncor's MD&A contained in this Annual Report.

136 SUNCOR ENERGY INC. ANNUAL REPORT 2013

QUARTERLY OPERATING SUMMARY
(unaudited)

|  | For the Quarter Ended |  | Total Year |  | For the Quarter Ended |  | Total Year |
Oil Sands |  | Mar 31 2013 |  | June 30 2013 |  | Sept 30 2013 |  | Dec 31 2013 |  | 2013 |  | Mar 31 2012 |  | June 30 2012 |  | Sept 30 2012 |  | Dec 31 2012 |  | 2012 |
Total Production (mbbls/d) |  | 389.0 |  | 309.4 |  | 423.6 |  | 446.5 |  | 392.5 |  | 341.1 |  | 337.8 |  | 378.9 |  | 378.7 |  | 359.2 |
Oil Sands operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production (mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Upgraded product (sweet SCO, sour SCO and diesel) |  | 308.6 |  | 220.6 |  | 299.0 |  | 301.5 |  | 282.6 |  | 273.1 |  | 253.9 |  | 298.3 |  | 281.1 |  | 276.7 |
| Non-upgraded bitumen |  | 49.2 |  | 56.0 |  | 97.4 |  | 108.1 |  | 77.9 |  | 32.6 |  | 55.3 |  | 43.0 |  | 61.7 |  | 48.1 |
Oil Sands Operations production |  | 357.8 |  | 276.6 |  | 396.4 |  | 409.6 |  | 360.5 |  | 305.7 |  | 309.2 |  | 341.3 |  | 342.8 |  | 324.8 |
Bitumen production (mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 278.9 |  | 181.0 |  | 299.9 |  | 317.4 |  | 269.8 |  | 262.5 |  | 244.5 |  | 287.6 |  | 269.6 |  | 266.2 |
| In Situ – Firebag |  | 137.0 |  | 129.3 |  | 152.7 |  | 154.1 |  | 143.4 |  | 83.6 |  | 95.8 |  | 113.0 |  | 123.4 |  | 104.0 |
| In Situ – MacKay River |  | 28.5 |  | 28.2 |  | 29.2 |  | 28.3 |  | 28.5 |  | 31.0 |  | 32.0 |  | 17.0 |  | 27.9 |  | 27.0 |
Total bitumen production |  | 444.4 |  | 338.5 |  | 481.8 |  | 499.8 |  | 441.7 |  | 377.1 |  | 372.3 |  | 417.6 |  | 420.9 |  | 397.2 |
Sales (mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Light sweet crude oil |  | 112.7 |  | 51.0 |  | 99.0 |  | 103.2 |  | 91.5 |  | 89.5 |  | 98.9 |  | 104.4 |  | 82.3 |  | 93.8 |
| Diesel |  | 9.0 |  | 28.7 |  | 28.6 |  | 27.5 |  | 23.5 |  | 32.8 |  | 27.0 |  | 28.7 |  | 9.7 |  | 24.5 |
| Light sour crude oil |  | 190.6 |  | 147.9 |  | 159.9 |  | 166.1 |  | 166.0 |  | 183.0 |  | 110.9 |  | 175.9 |  | 174.4 |  | 161.1 |
| Bitumen |  | 47.1 |  | 56.4 |  | 84.3 |  | 115.0 |  | 76.0 |  | 27.5 |  | 56.7 |  | 36.4 |  | 57.3 |  | 44.5 |
Total sales |  | 359.4 |  | 284.0 |  | 371.8 |  | 411.8 |  | 357.0 |  | 332.8 |  | 293.5 |  | 345.4 |  | 323.7 |  | 323.9 |
Average sales price(1) (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Light sweet crude oil |  | 95.24 |  | 99.45 |  | 110.80 |  | 88.06 |  | 97.98 |  | 98.57 |  | 88.18 |  | 87.84 |  | 90.76 |  | 91.17 |
| Other (diesel, light sour crude oil and bitumen) |  | 70.72 |  | 80.79 |  | 93.92 |  | 66.15 |  | 77.62 |  | 88.14 |  | 73.79 |  | 77.73 |  | 70.79 |  | 77.83 |
| Average |  | 78.41 |  | 84.14 |  | 98.42 |  | 71.64 |  | 82.83 |  | 90.95 |  | 78.64 |  | 80.79 |  | 75.87 |  | 81.69 |
Operating costs (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash costs |  | 31.95 |  | 42.75 |  | 30.30 |  | 33.90 |  | 34.10 |  | 36.25 |  | 37.60 |  | 31.85 |  | 35.20 |  | 35.15 |
Natural gas |  | 2.85 |  | 3.80 |  | 2.30 |  | 2.95 |  | 2.90 |  | 1.85 |  | 1.40 |  | 1.50 |  | 2.80 |  | 1.90 |
Cash operating costs*(2) |  | 34.80 |  | 46.55 |  | 32.60 |  | 36.85 |  | 37.00 |  | 38.10 |  | 39.00 |  | 33.35 |  | 38.00 |  | 37.05 |
Operating costs – In situ bitumen production only (dollars per barrel) |  |  |  |  |  |  |  |  |
Cash costs |  | 11.40 |  | 10.90 |  | 11.00 |  | 12.05 |  | 11.35 |  | 18.80 |  | 17.75 |  | 14.60 |  | 11.90 |  | 15.50 |
Natural gas |  | 5.40 |  | 5.80 |  | 4.15 |  | 5.45 |  | 5.15 |  | 3.65 |  | 3.05 |  | 3.40 |  | 5.20 |  | 3.90 |
Cash operating costs*(2) |  | 16.80 |  | 16.70 |  | 15.15 |  | 17.50 |  | 16.50 |  | 22.45 |  | 20.80 |  | 18.00 |  | 17.10 |  | 19.40 |
Syncrude |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production (mbbls/d) |  | 31.2 |  | 32.8 |  | 27.2 |  | 36.9 |  | 32.0 |  | 35.4 |  | 28.6 |  | 37.6 |  | 35.9 |  | 34.4 |
Average sales price(1) (dollars per barrel) |  | 95.51 |  | 100.92 |  | 113.57 |  | 92.26 |  | 99.82 |  | 98.82 |  | 90.61 |  | 90.24 |  | 90.90 |  | 92.69 |
Operating costs (dollars per barrel)**** |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash costs |  | 40.45 |  | 40.95 |  | 48.90 |  | 38.20 |  | 41.75 |  | 32.25 |  | 52.15 |  | 33.40 |  | 37.60 |  | 38.10 |
Natural gas |  | 1.60 |  | 1.50 |  | 1.25 |  | 1.45 |  | 1.45 |  | 1.25 |  | 0.95 |  | 0.95 |  | 1.60 |  | 1.20 |
Cash operating costs*(2) |  | 42.05 |  | 42.45 |  | 50.15 |  | 39.65 |  | 43.20 |  | 33.50 |  | 53.10 |  | 34.35 |  | 39.20 |  | 39.30 |

Footnotes and definitions, see page 147.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 137

QUARTERLY OPERATING SUMMARY (continued)
(unaudited)

|  | For the Quarter Ended |  | Total Year |  | For the Quarter Ended |  | Total Year |
Exploration and Production |  | Mar 31 2013 |  | June 30 2013 |  | Sept 30 2013 |  | Dec 31 2013 |  | 2013 |  | Mar 31 2012 |  | June 30 2012 |  | Sept 30 2012 |  | Dec 31 2012 |  | 2012 |
Total Production (mboe/d) |  | 207.1 |  | 190.7 |  | 171.4 |  | 111.6 |  | 169.9 |  | 221.2 |  | 204.6 |  | 156.4 |  | 177.8 |  | 189.9 |
Total Average Sales Price(1) (dollars per barrel) |  | 90.67 |  | 84.28 |  | 88.74 |  | 111.99 |  | 91.44 |  | 91.94 |  | 82.25 |  | 77.33 |  | 83.87 |  | 84.05 |
North America Onshore |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Natural gas (mmcf/d) |  | 263 |  | 251 |  | 238 |  | 17 |  | 192 |  | 323 |  | 294 |  | 279 |  | 264 |  | 290 |
|  | Natural gas liquids and crude oil (mbbls/d) |  | 7.6 |  | 6.2 |  | 5.8 |  | 1.6 |  | 5.3 |  | 5.8 |  | 5.1 |  | 5.5 |  | 5.9 |  | 5.6 |
|  | Total production (mmcfe/d) |  | 309 |  | 289 |  | 273 |  | 27 |  | 224 |  | 358 |  | 325 |  | 312 |  | 299 |  | 323 |
| Average sales price(1) |  |  |  |  |
|  | Natural gas (dollars per mcf) |  | 3.02 |  | 3.46 |  | 2.68 |  | 3.65 |  | 3.42 |  | 2.03 |  | 1.63 |  | 2.15 |  | 2.96 |  | 2.17 |
|  | Natural gas liquids and crude oil (dollars per barrel) |  | 82.77 |  | 78.61 |  | 83.75 |  | 76.71 |  | 81.34 |  | 84.34 |  | 79.25 |  | 72.91 |  | 71.43 |  | 76.93 |
East Coast Canada |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Production (mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Terra Nova |  | 14.2 |  | 16.8 |  | 20.5 |  | 5.6 |  | 14.2 |  | 19.6 |  | 13.3 |  | — |  | 2.2 |  | 8.8 |
|  | Hibernia |  | 27.8 |  | 25.7 |  | 28.8 |  | 25.8 |  | 27.1 |  | 28.7 |  | 31.0 |  | 15.7 |  | 29.1 |  | 26.1 |
|  | White Rose |  | 16.4 |  | 15.3 |  | 13.1 |  | 14.9 |  | 14.9 |  | 17.0 |  | 5.5 |  | 7.0 |  | 17.0 |  | 11.6 |
|  | 58.4 |  | 57.8 |  | 62.4 |  | 46.3 |  | 56.2 |  | 65.3 |  | 49.8 |  | 22.7 |  | 48.3 |  | 46.5 |
| Average sales price(1) (dollars per barrel) |  | 112.57 |  | 103.68 |  | 116.94 |  | 116.48 |  | 112.39 |  | 122.31 |  | 104.25 |  | 108.49 |  | 108.37 |  | 112.15 |
International |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Production (mboe/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | North Sea |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  | Buzzard |  | 55.3 |  | 57.8 |  | 50.4 |  | 59.8 |  | 55.8 |  | 57.0 |  | 57.9 |  | 41.9 |  | 35.3 |  | 48.0 |
|  | Other International |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  | Libya |  | 41.9 |  | 27.0 |  | 13.1 |  | 1.0 |  | 20.6 |  | 39.2 |  | 42.7 |  | 39.8 |  | 44.4 |  | 41.5 |
|  |  | Syria |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
|  | 97.2 |  | 84.8 |  | 63.5 |  | 60.8 |  | 76.4 |  | 96.2 |  | 100.6 |  | 81.7 |  | 79.7 |  | 89.5 |
| Average sales price(1) (dollars per boe) |  |  |  |  |  |  |  |  |  |  |
|  | Buzzard |  | 110.94 |  | 99.77 |  | 111.00 |  | 108.53 |  | 107.44 |  | 111.83 |  | 103.18 |  | 104.06 |  | 104.19 |  | 106.12 |
|  | Other International** |  | 110.36 |  | 104.21 |  | — |  | — |  | 107.94 |  | 118.47 |  | 109.44 |  | 107.32 |  | 108.05 |  | 110.65 |

Footnotes and definitions, see page 147.

138 SUNCOR ENERGY INC. ANNUAL REPORT 2013

QUARTERLY OPERATING SUMMARY (continued)
(unaudited)

|  | For the Quarter Ended |  | Total |  | For the Quarter Ended |  | Total |
Refining and Marketing |  | Mar 31 2013 |  | June 30 2013 |  | Sept 30 2013 |  | Dec 31 2013 |  | 2013 |  | Mar 31 2012 |  | June 30 2012 |  | Sept 30 2012 |  | Dec 31 2012 |  | 2012 |
Total refined product sales (mbbls/d) |  | 542.2 |  | 532.1 |  | 568.6 |  | 528.2 |  | 542.9 |  | 503.8 |  | 550.4 |  | 550.4 |  | 547.2 |  | 538.5 |
Total crude oil processed (mbbls/d) |  | 443.0 |  | 414.5 |  | 448.8 |  | 419.0 |  | 431.3 |  | 419.8 |  | 427.2 |  | 441.4 |  | 437.0 |  | 431.4 |
Total utilization of refining capacity (%)*** |  | 96 |  | 90 |  | 98 |  | 91 |  | 94 |  | 92 |  | 94 |  | 97 |  | 96 |  | 95 |
Eastern North America |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Refined product sales (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
|  | Transportation fuels |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Gasoline |  | 122.0 |  | 96.9 |  | 125.2 |  | 120.1 |  | 116.0 |  | 120.8 |  | 127.1 |  | 127.1 |  | 123.3 |  | 124.5 |
|  | Distillate |  | 84.9 |  | 113.8 |  | 76.1 |  | 81.6 |  | 89.1 |  | 70.4 |  | 67.3 |  | 78.6 |  | 84.3 |  | 75.5 |
|  | Total transportation fuel sales |  | 206.9 |  | 210.7 |  | 201.3 |  | 201.7 |  | 205.1 |  | 191.2 |  | 194.4 |  | 205.7 |  | 207.6 |  | 200.0 |
|  | Petrochemicals |  | 11.3 |  | 15.1 |  | 11.3 |  | 12.8 |  | 12.6 |  | 13.8 |  | 14.5 |  | 10.7 |  | 11.3 |  | 12.6 |
|  | Asphalt |  | 10.1 |  | 13.8 |  | 25.8 |  | 14.9 |  | 16.2 |  | 10.1 |  | 13.8 |  | 22.0 |  | 14.5 |  | 15.1 |
|  | Other |  | 33.3 |  | 32.7 |  | 27.7 |  | 19.5 |  | 28.3 |  | 27.7 |  | 44.0 |  | 30.8 |  | 32.7 |  | 34.0 |
| Total refined product sales |  | 261.6 |  | 272.3 |  | 266.1 |  | 248.9 |  | 262.2 |  | 242.8 |  | 266.7 |  | 269.2 |  | 266.1 |  | 261.7 |
| Crude oil supply and refining |  |  |  |  |  |  |  |  |  |  |
|  | Processed at refineries (mbbls/d) |  | 205.7 |  | 212.1 |  | 206.9 |  | 182.4 |  | 201.7 |  | 190.8 |  | 192.5 |  | 205.0 |  | 202.3 |  | 197.7 |
|  | Utilization of refining capacity (%)*** |  | 93 |  | 96 |  | 93 |  | 82 |  | 91 |  | 86 |  | 87 |  | 92 |  | 91 |  | 89 |
Western North America |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Refined product sales (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
|  | Transportation fuels |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Gasoline |  | 125.8 |  | 128.3 |  | 139.6 |  | 131.3 |  | 131.4 |  | 122.0 |  | 130.8 |  | 134.0 |  | 127.7 |  | 128.3 |
|  | Distillate |  | 129.6 |  | 102.5 |  | 129.6 |  | 121.7 |  | 120.7 |  | 115.8 |  | 118.3 |  | 114.4 |  | 128.9 |  | 119.5 |
|  | Total transportation fuel sales |  | 255.4 |  | 230.8 |  | 269.2 |  | 253.0 |  | 252.1 |  | 237.8 |  | 249.1 |  | 248.4 |  | 256.6 |  | 247.8 |
|  | Asphalt |  | 8.8 |  | 12.0 |  | 14.4 |  | 11.8 |  | 11.8 |  | 7.5 |  | 11.3 |  | 12.0 |  | 9.4 |  | 10.1 |
|  | Other |  | 16.4 |  | 17.0 |  | 18.9 |  | 14.5 |  | 16.8 |  | 15.7 |  | 23.3 |  | 20.8 |  | 15.1 |  | 18.9 |
| Total refined product sales |  | 280.6 |  | 259.8 |  | 302.5 |  | 279.3 |  | 280.7 |  | 261.0 |  | 283.7 |  | 281.2 |  | 281.1 |  | 276.8 |
| Crude oil supply and refining |  |  |  |  |  |  |  |  |  |  |
|  | Processed at refineries (mbbls/d) |  | 237.3 |  | 202.4 |  | 241.9 |  | 236.6 |  | 229.6 |  | 229.0 |  | 234.7 |  | 236.4 |  | 234.7 |  | 233.7 |
|  | Utilization of refining capacity (%)*** |  | 100 |  | 85 |  | 102 |  | 99 |  | 96 |  | 98 |  | 101 |  | 101 |  | 101 |  | 100 |

Footnotes and definitions, see page 147.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 139

QUARTERLY OPERATING SUMMARY (continued)
(unaudited)

|  | For the Quarter Ended |  | Total Year |  | For the Quarter Ended |  | Total Year |  |
Netbacks |  | Mar 31 2013 |  | June 30 2013 |  | Sept 30 2013 |  | Dec 31 2013 |  | 2013 |  | Mar 31 2012 |  | June 30 2012 |  | Sept 30 2012 |  | Dec 31 2012 |  | 2012 |  |
North America Onshore (dollars per mcfe) |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(3) |  | 4.89 |  | 5.58 |  | 4.62 |  | 8.86 |  | 5.07 |  | 3.98 |  | 3.48 |  | 3.81 |  | 4.65 |  | 3.97 |  |
| Royalties |  | (0.58 | ) | (0.49 | ) | (0.37 | ) | (0.52 | ) | (0.54 | ) | (0.24 | ) | (0.20 | ) | (0.28 | ) | (0.38 | ) | (0.27 | ) |
| Transportation costs |  | (0.23 | ) | (0.28 | ) | (0.34 | ) | (1.94 | ) | (0.33 | ) | (0.27 | ) | (0.34 | ) | (0.35 | ) | (0.27 | ) | (0.31 | ) |
| Operating costs |  | (1.43 | ) | (1.82 | ) | (1.84 | ) | (1.75 | ) | (1.69 | ) | (1.48 | ) | (1.56 | ) | (1.63 | ) | (1.39 | ) | (1.51 | ) |
| Operating netback |  | 2.65 |  | 2.99 |  | 2.07 |  | 4.65 |  | 2.51 |  | 1.99 |  | 1.38 |  | 1.55 |  | 2.61 |  | 1.88 |  |
East Coast Canada (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(3) |  | 114.32 |  | 105.83 |  | 118.24 |  | 118.83 |  | 114.25 |  | 123.73 |  | 106.73 |  | 112.91 |  | 110.69 |  | 114.46 |  |
| Royalties |  | (26.61 | ) | (23.70 | ) | (30.23 | ) | (32.77 | ) | (28.16 | ) | (34.72 | ) | (38.83 | ) | (31.16 | ) | (27.17 | ) | (33.40 | ) |
| Transportation costs |  | (1.75 | ) | (2.15 | ) | (1.30 | ) | (2.35 | ) | (1.86 | ) | (1.42 | ) | (2.48 | ) | (4.42 | ) | (2.32 | ) | (2.31 | ) |
| Operating costs |  | (9.05 | ) | (11.44 | ) | (9.46 | ) | (15.90 | ) | (11.21 | ) | (8.53 | ) | (12.71 | ) | (33.17 | ) | (12.00 | ) | (13.57 | ) |
| Operating netback |  | 76.91 |  | 68.54 |  | 77.25 |  | 67.81 |  | 73.02 |  | 79.06 |  | 52.71 |  | 44.16 |  | 69.20 |  | 65.18 |  |
North Sea – Buzzard (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(3) |  | 113.33 |  | 102.17 |  | 113.30 |  | 111.43 |  | 109.95 |  | 114.13 |  | 105.55 |  | 106.35 |  | 106.62 |  | 108.46 |  |
| Transportation costs |  | (2.39 | ) | (2.40 | ) | (2.30 | ) | (2.90 | ) | (2.51 | ) | (2.30 | ) | (2.37 | ) | (2.29 | ) | (2.43 | ) | (2.34 | ) |
| Operating costs |  | (5.80 | ) | (6.29 | ) | (7.64 | ) | (4.94 | ) | (5.94 | ) | (4.80 | ) | (3.36 | ) | (8.24 | ) | (10.71 | ) | (6.38 | ) |
| Operating netback |  | 105.14 |  | 93.48 |  | 103.36 |  | 103.59 |  | 101.50 |  | 107.03 |  | 99.82 |  | 95.82 |  | 93.48 |  | 99.74 |  |
Other International (dollars per boe)** |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(3) |  | 110.69 |  | 104.62 |  | — |  | — |  | 108.30 |  | 118.84 |  | 109.79 |  | 107.67 |  | 108.34 |  | 110.99 |  |
| Royalties |  | (41.81 | ) | (79.56 | ) | — |  | — |  | (56.70 | ) | (67.13 | ) | (57.50 | ) | (61.02 | ) | (81.09 | ) | (66.93 | ) |
| Transportation costs |  | (0.33 | ) | (0.41 | ) | — |  | — |  | (0.36 | ) | (0.37 | ) | (0.35 | ) | (0.35 | ) | (0.29 | ) | (0.34 | ) |
| Operating costs |  | (3.34 | ) | (3.47 | ) | — |  | — |  | (3.39 | ) | (1.86 | ) | (2.76 | ) | (1.13 | ) | (1.97 | ) | (1.94 | ) |
| Operating netback |  | 65.21 |  | 21.18 |  | — |  | — |  | 47.85 |  | 49.48 |  | 49.18 |  | 45.17 |  | 24.99 |  | 41.78 |  |

Footnotes and definitions, see page 147.

140 SUNCOR ENERGY INC. ANNUAL REPORT 2013

FIVE – YEAR FINANCIAL SUMMARY
(unaudited)

($ millions) |  | 2013 |  | 2012(A) |  | 2011 |  | 2010 |  | 2009 |  |
|  |  |  | (restated) |  |  |  |  |  |  |  |
Revenues and other income |  | 40 297 |  | 38 526 |  | 38 792 |  | 32 604 |  | 25 480 |  |
Net earnings (loss) |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  | 2 040 |  | 468 |  | 2 603 |  | 1 520 |  | 557 |  |
Exploration and Production |  | 1 000 |  | 138 |  | 306 |  | 1 938 |  | 78 |  |
Refining and Marketing |  | 2 022 |  | 2 137 |  | 1 726 |  | 819 |  | 407 |  |
Corporate, Energy Trading and Eliminations |  | (1 151 | ) | (3 | ) | (331 | ) | (448 | ) | 104 |  |
|  | 3 911 |  | 2 740 |  | 4 304 |  | 3 829 |  | 1 146 |  |
Operating earnings |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  | 2 098 |  | 2 025 |  | 2 737 |  | 1 379 |  | 1 048 |  |
Exploration and Production |  | 1 210 |  | 850 |  | 1 358 |  | 1 193 |  | 150 |  |
Refining and Marketing |  | 2 022 |  | 2 152 |  | 1 726 |  | 796 |  | 455 |  |
Corporate, Energy Trading and Eliminations |  | (630 | ) | (180 | ) | (147 | ) | (734 | ) | (538 | ) |
|  | 4 700 |  | 4 847 |  | 5 674 |  | 2 634 |  | 1 115 |  |
Cash flow from (used in) operations |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  | 4 556 |  | 4 407 |  | 4 572 |  | 2 777 |  | 1 251 |  |
Exploration and Production |  | 2 316 |  | 2 227 |  | 2 846 |  | 3 325 |  | 1 280 |  |
Refining and Marketing |  | 2 618 |  | 3 138 |  | 2 574 |  | 1 538 |  | 921 |  |
Corporate, Energy Trading and Eliminations |  | (78 | ) | (39 | ) | (246 | ) | (984 | ) | (653 | ) |
|  | 9 412 |  | 9 733 |  | 9 746 |  | 6 656 |  | 2 799 |  |
Capital and exploration expenditures (including capitalized interest) |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  | 4 311 |  | 4 957 |  | 5 100 |  | 3 709 |  | 2 831 |  |
Exploration and Production |  | 1 483 |  | 1 261 |  | 874 |  | 1 274 |  | 986 |  |
Refining and Marketing |  | 890 |  | 644 |  | 633 |  | 667 |  | 380 |  |
Corporate, Energy Trading and Eliminations |  | 93 |  | 95 |  | 243 |  | 360 |  | 70 |  |
|  | 6 777 |  | 6 957 |  | 6 850 |  | 6 010 |  | 4 267 |  |
Total assets |  | 78 315 |  | 76 401 |  | 74 777 |  | 68 607 |  | 69 746 |  |
Ending capital employed |  |  |  |  |  |  |  |  |  |  |  |
Short-term and long-term debt, less cash and cash equivalents |  | 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 |  |
Less average capitalized costs related to major projects in progress |  | (6 502 | ) | (8 729 | ) | (12 106 | ) | (12 890 | ) | (10 655 | ) |
|  | 40 934 |  | 37 125 |  | 33 470 |  | 33 556 |  | 36 833 |  |
Total Suncor employees (number at year end) |  | 13 946 |  | 13 932 |  | 13 026 |  | 12 076 |  | 12 978 |  |

Footnotes, see page 143.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 141

FIVE – YEAR FINANCIAL SUMMARY(continued)
(unaudited)

($ millions) |  | 2013 |  | 2012(A) |  | 2011 |  | 2010 |  | 2009 |
|  |  |  | (restated) |  |  |  |  |  |  |
Dollars per common share |  |  |  |  |  |  |  |  |  |  |
| Net earnings |  | 2.61 |  | 1.77 |  | 2.74 |  | 2.45 |  | 0.96 |
| Operating earnings |  | 3.13 |  | 3.14 |  | 3.61 |  | 1.69 |  | 0.93 |
| Cash dividends |  | 0.73 |  | 0.50 |  | 0.43 |  | 0.40 |  | 0.30 |
| Cash flow from operations |  | 6.27 |  | 6.30 |  | 6.20 |  | 4.25 |  | 2.34 |
Ratios |  |  |  |  |  |  |  |  |  |  |
Return on capital employed (%)(B) |  | 11.5 |  | 7.2 |  | 13.8 |  | 11.4 |  | 2.6 |
Return on capital employed (%)(C) |  | 9.9 |  | 5.8 |  | 10.1 |  | 8.2 |  | 1.8 |
Debt to debt plus shareholders' equity (%)(D) |  | 22 |  | 22 |  | 22 |  | 26 |  | 29 |
Net debt to cash flow from operations (times)(E) |  | 0.7 |  | 0.7 |  | 0.7 |  | 1.7 |  | 4.8 |
Interest coverage – cash flow basis (times)(F) |  | 16.8 |  | 17.7 |  | 16.4 |  | 11.7 |  | 7.2 |
Interest coverage – net earnings basis (times)(G) |  | 9.5 |  | 7.9 |  | 10.7 |  | 8.8 |  | 3.0 |

(A)
  Effective January 1, 2013, Suncor adopted new and amended accounting standards, described in note 6 of this Annual Report. 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 and 2010 have not been restated in accordance with the respective transitional provisions of the new and amended standards. Annual data for 2009 is presented in accordance with previous Canadian GAAP.
(B)
  Net earnings adjusted for after-tax interest expense and after-tax foreign exchange loss (gain) on U.S. denominated long-term debt for the twelve month period ended; divided by average capital employed. Average capital employed is the sum of shareholders' equity and short-term debt plus long-term debt less cash and cash equivalents, less average capitalized costs related to major projects in progress, on a weighted average basis.
(C)
  Average capital employed including capitalized costs related to major projects in progress.
(D)
  Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders' equity.
(E)
  Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended.
(F)
  Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(G)
  Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

142 SUNCOR ENERGY INC. ANNUAL REPORT 2013

ANNUAL OPERATING SUMMARY
(unaudited)

Oil Sands |  | 2013 |  | 2012 |  | 2011 |  | 2010 |  | 2009 |
Total Production (mbbls/d) |  | 392.5 |  | 359.2 |  | 339.3 |  | 318.2 |  | 306.7 |
Oil Sands Operations |  |  |  |  |  |  |  |  |  |  |
Production (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
| Upgraded product (sweet SCO, sour SCO and diesel) |  | 282.6 |  | 276.7 |  | 279.7 |  | 251.4 |  | 277.9 |
| Non-upgraded bitumen |  | 77.9 |  | 48.1 |  | 25.0 |  | 31.6 |  | 12.7 |
Oil Sands Operations production |  | 360.5 |  | 324.8 |  | 304.7 |  | 283.0 |  | 290.6 |
Bitumen production (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 269.8 |  | 266.2 |  | 287.1 |  | 266.2 |  | 289.6 |
| In Situ – Firebag |  | 143.4 |  | 104.0 |  | 59.5 |  | 53.6 |  | 49.1 |
| In Situ – MacKay River |  | 28.5 |  | 27.0 |  | 30.0 |  | 31.5 |  | 12.4 |
Total bitumen production |  | 441.7 |  | 397.2 |  | 376.6 |  | 351.3 |  | 351.1 |
Sales (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
| Light sweet crude oil |  | 91.5 |  | 93.8 |  | 85.5 |  | 82.3 |  | 99.6 |
| Diesel |  | 23.5 |  | 24.5 |  | 24.3 |  | 20.4 |  | 29.1 |
| Light sour crude oil |  | 166.0 |  | 161.1 |  | 170.6 |  | 145.2 |  | 135.7 |
| Bitumen |  | 76.0 |  | 44.5 |  | 24.0 |  | 31.4 |  | 11.8 |
Total sales |  | 357.0 |  | 323.9 |  | 304.4 |  | 279.3 |  | 276.2 |
Average sales price(1) (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |
| Light sweet crude oil |  | 97.98 |  | 91.17 |  | 98.50 |  | 79.03 |  | 67.26 |
| Other (diesel, light sour crude oil and bitumen) |  | 77.62 |  | 77.83 |  | 84.93 |  | 68.63 |  | 64.18 |
| Average* |  | 82.83 |  | 81.69 |  | 88.74 |  | 71.69 |  | 65.29 |
| Average |  | 82.83 |  | 81.69 |  | 88.74 |  | 69.58 |  | 61.66 |
Operating costs (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |
Cash operating costs*(2) |  | 37.00 |  | 37.05 |  | 39.05 |  | 36.70 |  | 33.95 |
Cash operating costs – In situ bitumen production only*(2) |  | 16.50 |  | 19.40 |  | 25.50 |  | 20.25 |  | 20.25 |
Syncrude |  |  |  |  |  |  |  |  |  |  |
Production (mbbls/d) |  | 32.0 |  | 34.4 |  | 34.6 |  | 35.2 |  | 16.1 |
Average sales price(1) (dollars per barrel) |  | 99.82 |  | 92.69 |  | 101.80 |  | 80.93 |  | 77.36 |
Operating costs (dollars per barrel)**** |  |  |  |  |  |  |  |  |  |  |
Cash operating costs*(2) |  | 43.20 |  | 39.30 |  | 40.45 |  | 36.05 |  | 32.50 |

Footnotes and definitions, see page 147.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 143

ANNUAL OPERATING SUMMARY (continued)
(unaudited)

Exploration and Production |  | 2013 |  | 2012 |  | 2011 |  | 2010 |  | 2009 |
Total Production (mboe/d) |  | 169.9 |  | 189.9 |  | 206.7 |  | 296.9 |  | 149.3 |
Total Average Sales Price(1) (dollars per barrel) |  | 91.44 |  | 84.05 |  | 79.95 |  | 61.06 |  | 76.77 |
North America Onshore |  |  |  |  |  |  |  |  |  |  |
| Production |  |  |  |  |  |  |  |  |  |  |
|  | Natural gas (mmcf/d) |  | 192 |  | 290 |  | 357 |  | 522 |  | 397 |
|  | Natural gas liquids and crude oil (mbbls/d) |  | 5.3 |  | 5.6 |  | 5.1 |  | 8.8 |  | 8.1 |
|  | Total production (mmcfe/d) |  | 224 |  | 323 |  | 388 |  | 575 |  | 446 |
| Average sales price(1) |  |  |  |  |  |  |  |  |  |  |
|  | Natural gas (dollars per mcf) |  | 3.42 |  | 2.17 |  | 3.55 |  | 4.04 |  | 4.10 |
|  | Natural gas* (dollars per mcf) |  | 3.42 |  | 2.17 |  | 3.55 |  | 4.04 |  | 4.08 |
|  | Natural gas liquids and crude oil (dollars per barrel) |  | 81.34 |  | 76.93 |  | 85.30 |  | 67.06 |  | 56.84 |
East Coast Canada |  |  |  |  |  |  |  |  |  |  |
| Production (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
|  | Terra Nova |  | 14.2 |  | 8.8 |  | 16.2 |  | 23.2 |  | 8.7 |
|  | Hibernia |  | 27.1 |  | 26.1 |  | 30.9 |  | 30.9 |  | 11.4 |
|  | White Rose |  | 14.9 |  | 11.6 |  | 18.5 |  | 14.5 |  | 4.2 |
|  | 56.2 |  | 46.5 |  | 65.6 |  | 68.6 |  | 24.3 |
| Average sales price(1) (dollars per barrel) |  | 112.39 |  | 112.15 |  | 108.42 |  | 80.20 |  | 76.86 |
International |  |  |  |  |  |  |  |  |  |  |
| Production (mboe/d) |  |  |  |  |  |  |  |  |  |  |
|  | North Sea |  |  |  |  |  |  |  |  |  |  |
|  |  | Buzzard |  | 55.8 |  | 48.0 |  | 42.9 |  | 55.5 |  | 20.0 |
|  |  | Other North Sea |  | — |  | — |  | 3.8 |  | 23.5 |  | 12.0 |
|  | Other International |  |  |  |  |  |  |  |  |  |  |
|  |  | Libya |  | 20.6 |  | 41.5 |  | 12.1 |  | 35.2 |  | 13.7 |
|  |  | Syria |  | — |  | — |  | 17.6 |  | 11.6 |  | — |
|  |  | Trinidad and Tobago |  | — |  | — |  | — |  | 6.7 |  | 4.9 |
|  | 76.4 |  | 89.5 |  | 76.4 |  | 132.5 |  | 50.6 |
| Average sales price(1) (dollars per boe) |  |  |  |  |  |  |  |  |  |  |
|  | Buzzard |  | 107.44 |  | 106.12 |  | 105.18 |  | 77.91 |  | 69.53 |
|  | Other North Sea |  | — |  | — |  | 92.49 |  | 78.16 |  | 73.52 |
|  | Other International** |  | 107.94 |  | 110.65 |  | 95.76 |  | 70.39 |  | 61.25 |

Footnotes and definitions, see page 147.

144 SUNCOR ENERGY INC. ANNUAL REPORT 2013

ANNUAL OPERATING SUMMARY (continued)
(unaudited)

Refining and Marketing |  | 2013 |  | 2012 |  | 2011 |  | 2010 |  | 2009 |
Total refined product sales (mbbls/d) |  | 542.9 |  | 538.5 |  | 522.7 |  | 549.0 |  | 345.2 |
Total crude oil processed (mbbls/d) |  | 431.3 |  | 431.4 |  | 407.7 |  | 409.6 |  | 397.5 |
Total utilization of refining capacity (%)*** |  | 94 |  | 95 |  | 92 |  | 92 |  | 92 |
Eastern North America |  |  |  |  |  |  |  |  |  |  |
| Refined product sales (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
|  | Transportation fuels |  |  |  |  |  |  |  |  |  |  |
|  | Gasoline |  | 116.0 |  | 124.5 |  | 131.5 |  | 139.8 |  | 91.7 |
|  | Distillate |  | 89.1 |  | 75.5 |  | 80.2 |  | 77.9 |  | 55.1 |
|  | Total transportation fuel sales |  | 205.1 |  | 200.0 |  | 211.7 |  | 217.7 |  | 146.8 |
|  | Petrochemicals |  | 12.6 |  | 12.6 |  | 13.2 |  | 15.8 |  | 5.0 |
|  | Asphalt |  | 16.2 |  | 15.1 |  | 15.1 |  | 17.1 |  | 9.1 |
|  | Other |  | 28.3 |  | 34.0 |  | 33.6 |  | 34.6 |  | 13.2 |
| Total refined product sales |  | 262.2 |  | 261.7 |  | 273.6 |  | 285.2 |  | 174.1 |
| Crude oil supply and refining |  |  |  |  |  |  |  |  |  |  |
|  | Processed at refineries (mbbls/d) |  | 201.7 |  | 197.7 |  | 201.3 |  | 192.0 |  | 186.2 |
|  | Utilization of refining capacity (%)*** |  | 91 |  | 89 |  | 94 |  | 89 |  | 87 |
Western North America |  |  |  |  |  |  |  |  |  |  |
| Refined product sales (mbbls/d) |  |  |  |  |  |  |  |  |  |  |
|  | Transportation fuels |  |  |  |  |  |  |  |  |  |  |
|  | Gasoline |  | 131.4 |  | 128.3 |  | 118.0 |  | 118.8 |  | 81.7 |
|  | Distillate |  | 120.7 |  | 119.5 |  | 110.5 |  | 113.2 |  | 59.8 |
|  | Total transportation fuel sales |  | 252.1 |  | 247.8 |  | 228.5 |  | 232.0 |  | 141.5 |
|  | Asphalt |  | 11.8 |  | 10.1 |  | 7.5 |  | 7.9 |  | 8.2 |
|  | Other |  | 16.8 |  | 18.9 |  | 13.1 |  | 23.9 |  | 21.4 |
| Total refined product sales |  | 280.7 |  | 276.8 |  | 249.1 |  | 263.8 |  | 171.1 |
| Crude oil supply and refining |  |  |  |  |  |  |  |  |  |  |
|  | Processed at refineries (mbbls/d) |  | 229.6 |  | 233.7 |  | 206.4 |  | 217.6 |  | 211.3 |
|  | Utilization of refining capacity (%)*** |  | 96 |  | 100 |  | 91 |  | 95 |  | 97 |
| Retail outlets |  | 1 505 |  | 1 509 |  | 1 732 |  | 1 723 |  | 1 813 |

Footnotes and definitions, see page 147.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 145

OPERATING SUMMARY INFORMATION

Definitions

(1)
  Average sales price – This is calculated before royalties (where applicable) and net of related transportation costs.
(2)
  Cash operating costs – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes and non-production costs), and including operating revenues associated with excess power from cogeneration units.
(3)
  Average price realized – This operating statistic is calculated before transportation costs and royalties and excludes the impact of hedging activities.

Explanatory Notes

*
  Excludes the impact of realized hedging activities.
**
  During the second half of 2013, no sales were recorded in Libya as there were no liftings during the period due to continued political unrest.
***
  Effective January 1, 2013, the Edmonton refinery's nameplate capacity increased to 140 mbbls/d. Effective January 1, 2012, the Montreal and the commerce city refineries' nameplate capacities increased to 137 mbbls/d and 98 mbbls/d, respectively. Comparative utilization percentages have not been restated.
****
  Users are cautioned that Syncrude cash costs per barrel measure may not be fully comparable to similar information calculated by other entities (including Suncor's own cash costs per barrel excluding Syncrude) due to differing operations of each company as well as their respective accounting policy choices.

Abbreviations

mbbls/d | – thousands of barrels per day
mcf | – thousands of cubic feet
mcfe | – thousands of cubic feet equivalent
mmcf/d | – millions of cubic feet per day
mmcfe/d | – millions of cubic feet equivalent per day
boe | – barrels of oil equivalent
mboe/d | – thousands of barrels of oil equivalent per day
SCO | – Synthetic Crude Oil

Metric conversion

Crude oil, refined products, etc. |  | 1m 3 (cubic metre) = approx. 6.29 barrels |  |

146 SUNCOR ENERGY INC. ANNUAL REPORT 2013

SHARE TRADING INFORMATION
(unaudited)

Common shares are listed on the Toronto Stock Exchange and New York Stock Exchange under the symbol SU.

|  | For the Quarter Ended |  | For the Quarter Ended |  |
|  | Mar 31 2013 |  | June 30 2013 |  | Sept 30 2013 |  | Dec 31 2013 |  | Mar 31 2012 |  | June 30 2012 |  | Sept 30 2012 |  | Dec 31 2012 |  |
Share ownership |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Average number outstanding, weighted monthly (thousands)(a) |  | 1 518 466 |  | 1 506 022 |  | 1 497 147 |  | 1 483 596 |  | 1 560 605 |  | 1 554 172 |  | 1 536 334 |  | 1 528 629 |  |
Share price (dollars) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Toronto Stock Exchange |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| High |  | 34.80 |  | 33.30 |  | 37.63 |  | 38.56 |  | 37.28 |  | 33.39 |  | 34.83 |  | 34.99 |  |
| Low |  | 30.22 |  | 27.50 |  | 30.79 |  | 35.21 |  | 30.07 |  | 26.97 |  | 28.43 |  | 31.23 |  |
| Close |  | 30.44 |  | 31.00 |  | 36.83 |  | 37.24 |  | 32.59 |  | 29.44 |  | 32.34 |  | 32.71 |  |
New York Stock Exchange – US$ |  |  |  |  |  |  |  |  |  |  |  |
| High |  | 34.65 |  | 32.48 |  | 36.76 |  | 37.00 |  | 37.37 |  | 33.77 |  | 35.82 |  | 35.18 |  |
| Low |  | 29.75 |  | 26.83 |  | 29.05 |  | 33.13 |  | 29.76 |  | 25.95 |  | 27.80 |  | 31.17 |  |
| Close |  | 30.01 |  | 29.49 |  | 35.78 |  | 35.05 |  | 32.70 |  | 28.95 |  | 32.85 |  | 32.98 |  |
Shares traded (thousands) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Toronto Stock Exchange |  | 198 039 |  | 282 074 |  | 179 207 |  | 161 863 |  | 282 262 |  | 270 745 |  | 199 120 |  | 166 385 |  |
New York Stock Exchange |  | 232 287 |  | 333 004 |  | 236 817 |  | 239 349 |  | 317 314 |  | 327 916 |  | 247 430 |  | 232 118 |  |
Per common share information (dollars) |  |  |  |  |  |  |  |  |  |  |  |
Net earnings (loss) attributable to common shareholders |  | 0.72 |  | 0.45 |  | 1.13 |  | 0.30 |  | 0.93 |  | 0.21 |  | 1.01 |  | (0.38 | ) |
Dividend per common share |  | 0.13 |  | 0.20 |  | 0.20 |  | 0.20 |  | 0.11 |  | 0.13 |  | 0.13 |  | 0.13 |  |

(a)
  The company had approximately 4 953 holders of record of common shares as at January 31, 2014.

Information for Security Holders Outside Canada

Cash dividends paid to shareholders resident in countries other than Canada (non-Canadian shareholders) are subject to Canadian withholding tax. The statutory rate of Canadian withholding tax on dividends is 25%, subject to reduction under an applicable tax treaty between Canada and another country. For example, under the tax treaty between Canada and the United States, the withholding tax rate is generally reduced to 15% on dividends paid to residents of the United States that are eligible for the benefit of that tax treaty. The Canada Revenue Agency has released forms, applicable after 2012, for non-Canadian shareholders to evidence entitlement to a reduced withholding tax rate under a tax treaty. The agents responsible for withholding on dividends will generally need to have a duly completed form from a non-Canadian shareholder on file by a particular dividend record date in order for such agents to withhold at an applicable treaty-reduced rate, rather than the full statutory rate of 25%. Non-Canadian shareholders are encouraged to contact their broker (or other applicable agent) regarding the completion and delivery of these forms.

As shareholders are responsible to ensure compliance with Canadian tax laws and regulations, shareholders are strongly encouraged to seek professional tax and legal counsel with respect to any and all tax matters.

SUNCOR ENERGY INC. ANNUAL REPORT 2013 147

Suncor Energy Inc.
150 - 6 Avenue S.W., Calgary, Alberta, Canada T2P 3E3
T: 403-296-8000

Suncor.com

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EXHIBIT 99.1 2013 Annual Report to Shareholders for the period ended December 31, 2013
1. REPORTING ENTITY AND DESCRIPTION OF THE BUSINESS
2. BASIS OF PREPARATION
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
4. SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGMENTS
5. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS
6. ADOPTION OF NEW AND AMENDED IFRS STANDARDS
7. SEGMENTED INFORMATION
8. OTHER INCOME
9. OPERATING, SELLING AND GENERAL
10. ASSET IMPAIRMENT
11. FINANCING EXPENSES
12. INCOME TAXES
13. EARNINGS PER COMMON SHARE
14. CASH AND CASH EQUIVALENTS
15. SUPPLEMENTAL CASH FLOW INFORMATION
16. INVENTORIES
17. PROPERTY, PLANT AND EQUIPMENT
18. EXPLORATION AND EVALUATION ASSETS
19. OTHER ASSETS
20. GOODWILL AND OTHER INTANGIBLE ASSETS
21. DEBT AND CREDIT FACILITIES
22. OTHER LONG-TERM LIABILITIES
23. PENSIONS AND OTHER POST-RETIREMENT BENEFITS
24. PROVISIONS
25. SHARE CAPITAL
26. SHARE-BASED COMPENSATION
27. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
28. CAPITAL STRUCTURE FINANCIAL POLICIES
29. JOINT ARRANGEMENTS
30. SUBSIDIARIES
31. RELATED PARTY DISCLOSURES
32. COMMITMENTS, CONTINGENCIES AND GUARANTEES
33. VOYAGEUR UPGRADER PROJECT
34. SALE OF NATURAL GAS BUSINESS
35. SUSPENDED EXPLORATORY WELL COSTS
36. SUBSEQUENT EVENT